Annual Statements Open main menu
  1. Annual Statements
  2. » Companies
  3. » Vital Energy, Inc.
  4. » Quarter Report: 2016 June (Form 10-Q)

Vital Energy, Inc. - Quarter Report: 2016 June (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
 ý      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended June 30, 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 August 1, 2016: 240,124,869


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 United States 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 United States Gulf Coast to refine all of the light sweet crude oil being produced in the United States, 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;

iii

•
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses, assets and properties;
•
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.
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)
 
 
June 30, 2016

December 31, 2015
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
19,309

 
$
31,154

Accounts receivable, net
 
88,543

 
87,699

Derivatives
 
88,965

 
198,805

Other current assets
 
14,445

 
14,574

Total current assets
 
211,262

 
332,232

Property and equipment:
 
 
 
 

Oil and natural gas properties, full cost method:
 
 
 
 

Evaluated properties
 
5,309,151

 
5,103,635

Unevaluated properties not being depleted
 
114,507

 
140,299

Less accumulated depletion and impairment
 
(4,448,482
)
 
(4,218,942
)
Oil and natural gas properties, net
 
975,176

 
1,024,992

Midstream service assets, net
 
128,052

 
131,725

Other fixed assets, net
 
40,951

 
43,538

Property and equipment, net
 
1,144,179

 
1,200,255

Derivatives
 
32,680

 
77,443

Investment in equity method investee
 
213,616

 
192,524

Other assets, net
 
8,414

 
10,833

Total assets
 
$
1,610,151

 
$
1,813,287

Liabilities and stockholders’ equity
 
 
 
 

Current liabilities:
 
 
 
 

Accounts payable
 
$
14,500

 
$
14,181

Undistributed revenue and royalties
 
25,452

 
34,540

Accrued capital expenditures
 
39,860

 
61,872

Derivatives
 
1,480

 
—

Other current liabilities
 
72,520

 
106,222

Total current liabilities
 
153,812

 
216,815

Long-term debt, net
 
1,392,877

 
1,416,226

Derivatives
 
3,740

 
—

Asset retirement obligations
 
46,716

 
44,759

Other noncurrent liabilities
 
3,844

 
4,040

Total liabilities
 
1,600,989

 
1,681,840

Commitments and contingencies
 


 


Stockholders’ equity:
 
 
 
 
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2016 and December 31, 2015
 
—

 
—

Common stock, $0.01 par value, 450,000,000 shares authorized and 227,197,566 and 213,808,003 issued and outstanding as of June 30, 2016 and December 31, 2015, respectively
 
2,272

 
2,138

Additional paid-in capital
 
2,216,036

 
2,086,652

Accumulated deficit
 
(2,209,146
)
 
(1,957,343
)
Total stockholders’ equity
 
9,162

 
131,447

Total liabilities and stockholders’ equity
 
$
1,610,151

 
$
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 June 30,
 
Six months ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Revenues:






 
 

 
 

Oil, NGL and natural gas sales

$
102,526


$
125,554


$
175,668


$
243,672

Midstream service revenues

1,632


1,726


3,433


3,035

Sales of purchased oil
 
42,615

 
55,051

 
74,229

 
86,318

Total revenues

146,773


182,331


253,330


333,025

Costs and expenses:

 
 
 
 
 
 
 
Lease operating expenses

19,225


29,206


39,743


61,586

Production and ad valorem taxes
 
7,982

 
9,500

 
14,417

 
18,586

Midstream service expenses
 
1,178

 
1,597

 
1,787

 
3,171

Minimum volume commitments

—


3,579


—


5,235

Costs of purchased oil
 
44,012

 
54,417

 
76,958

 
85,617

General and administrative

20,502


23,208

 
39,953

 
45,063

Restructuring expenses
 
—

 
—

 
—

 
6,042

Accretion of asset retirement obligations

860


593


1,704


1,172

Depletion, depreciation and amortization

34,177


72,112


75,655


144,054

Impairment expense

963


489,599


162,027


490,477

Total costs and expenses

128,899


683,811


412,244


861,003

Operating income (loss)

17,874


(501,480
)

(158,914
)

(527,978
)
Non-operating income (expense):




 
 
 
 
 
Loss on derivatives, net

(68,518
)

(63,899
)

(50,633
)

(744
)
Income from equity method investee

3,696


2,914


5,994


2,481

Interest expense

(23,512
)

(23,970
)

(47,217
)

(56,384
)
Interest and other income

11


173


110


296

Loss on early redemption of debt
 
—

 
(31,537
)
 
—

 
(31,537
)
Write-off of debt issuance costs

(842
)

—

 
(842
)
 
—

Loss on disposal of assets, net

(141
)

(1,081
)

(301
)

(1,843
)
Non-operating expense, net

(89,306
)

(117,400
)

(92,889
)

(87,731
)
Loss before income taxes

(71,432
)

(618,880
)

(251,803
)

(615,709
)
Income tax benefit:












Deferred

—


221,846


—


218,203

Total income tax benefit

—


221,846


—


218,203

Net loss

$
(71,432
)
 
$
(397,034
)

$
(251,803
)

$
(397,506
)
Net loss per common share:







 




Basic

$
(0.33
)

$
(1.88
)

$
(1.17
)
 
$
(2.13
)
Diluted

$
(0.33
)
 
$
(1.88
)

$
(1.17
)
 
$
(2.13
)
Weighted-average common shares outstanding:







 

 
 

Basic

217,564


211,078


214,562

 
186,886

Diluted

217,564


211,078


214,562

 
186,886

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

2


Laredo Petroleum, Inc.
Consolidated statement of stockholders' equity
(in thousands)
(Unaudited) 
 
 
Common Stock
 
Additional
paid-in capital
 
Treasury Stock
(at cost)
 
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
 
2,968

 
30

 
(30
)
 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(221
)
 
(2
)
 
2

 
—

 
—

 
—

 
—

Vested restricted stock exchanged for tax withholding
 
—

 
—

 
—

 
288

 
(1,541
)
 
—

 
(1,541
)
Retirement of treasury stock
 
(288
)
 
(3
)
 
(1,538
)
 
(288
)
 
1,541

 
—

 
—

Exercise of employee stock options
 
6

 
—

 
67

 
—

 
—

 
—

 
67

Equity issuance, net of offering costs
 
10,925

 
109

 
119,201

 
—

 
—

 
—

 
119,310

Stock-based compensation
 
—

 
—

 
11,682

 
—

 
—

 
—

 
11,682

Net loss
 
—

 
—

 
—

 
—

 
—

 
(251,803
)
 
(251,803
)
Balance, June 30, 2016
 
227,198

 
$
2,272

 
$
2,216,036

 
—

 
$
—

 
$
(2,209,146
)
 
$
9,162

 
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)
 
 
Six months ended June 30,
 
 
2016
 
2015
Cash flows from operating activities:

 


 

Net loss

$
(251,803
)

$
(397,506
)
Adjustments to reconcile net loss to net cash provided by operating activities:






Deferred income tax benefit

—


(218,203
)
Depletion, depreciation and amortization

75,655


144,054

Impairment expense

162,027


490,477

Loss on early redemption of debt
 
—

 
31,537

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

9,911


11,056

Mark-to-market on derivatives:






Loss on derivatives, net

50,633


744

Cash settlements received for matured derivatives, net

113,319


109,737

Cash settlements received for early terminations of derivatives, net

80,000


—

Change in net present value of deferred premiums paid for derivatives

133


88

Cash premiums paid for derivatives

(84,263
)

(2,670
)
Amortization of debt issuance costs

2,187


2,501

Write-off of debt issuance costs

842

 
—

Income from equity method investee

(5,994
)

(2,481
)
Cash settlement of performance unit awards
 
(6,394
)
 
(2,738
)
Other, net

2,009


3,012

(Increase) decrease in accounts receivable
 
(844
)
 
16,586

Increase in other assets
 
(117
)
 
(9,097
)
Increase (decrease) in accounts payable
 
319

 
(15,744
)
Decrease in undistributed revenues and royalties
 
(9,088
)
 
(20,699
)
Increase (decrease) in other accrued liabilities
 
295

 
(28,341
)
(Decrease) increase in other noncurrent liabilities
 
(196
)
 
318

Increase in fair value of performance unit awards
 
—

 
1,674

Net cash provided by operating activities
 
138,631

 
114,305

Cash flows from investing activities:






Capital expenditures:






Oil and natural gas properties

(197,042
)

(374,508
)
Midstream service assets

(3,425
)

(34,137
)
Other fixed assets

(832
)

(6,541
)
Investment in equity method investee
 
(42,681
)
 
(14,495
)
Proceeds from dispositions of capital assets, net of costs

350


35

Net cash used in investing activities

(243,630
)

(429,646
)
Cash flows from financing activities:






Borrowings on Senior Secured Credit Facility

120,000


300,000

Payments on Senior Secured Credit Facility

(144,682
)

(475,000
)
Issuance of March 2023 Notes
 
—


350,000

Redemption of January 2019 Notes
 
—

 
(576,200
)
Proceeds from issuance of common stock, net of offering costs
 
119,310

 
754,163

Purchase of treasury stock

(1,541
)

(2,591
)
Proceeds from exercise of employee stock options

67


—

Payments for debt issuance costs

—


(6,759
)
Net cash provided by financing activities

93,154


343,613

Net (decrease) increase in cash and cash equivalents

(11,845
)

28,272

Cash and cash equivalents, beginning of period

31,154


29,321

Cash and cash equivalents, end of period

$
19,309


$
57,593

 
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: (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 delivery and takeaway 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 June 30, 2016, results of operations for the three and six months ended June 30, 2016 and 2015 and cash flows for the six months ended June 30, 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 oil, NGL and natural gas and purchased oil 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)
 
June 30, 2016
 
December 31, 2015
Oil, NGL and natural gas sales
 
$
42,629

 
$
25,582

Joint operations, net(1)
 
18,425

 
21,375

Sales of purchased oil and other products
 
15,000

 
11,775

Matured derivatives
 
12,223

 
27,469

Other
 
266

 
1,498

Total
 
$
88,543

 
$
87,699

______________________________________________________________________________
(1)
Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both June 30, 2016 and December 31, 2015.
e.    Derivatives
The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL 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)
 
June 30, 2016
 
December 31, 2015
Evaluated oil and natural gas properties
 
$
5,309,151

 
$
5,103,635

Less accumulated depletion and impairment
 
(4,448,482
)
 
(4,218,942
)
Evaluated oil and natural gas properties, net
 
860,669

 
884,693

 
 
 
 
 
Unevaluated properties not being depleted
 
114,507

 
140,299

 
 
 
 
 
Midstream service assets
 
148,227

 
147,811

Less accumulated depreciation
 
(20,175
)
 
(16,086
)
Midstream service assets, net
 
128,052

 
131,725

 
 
 
 
 
Depreciable other fixed assets
 
46,255

 
46,799

Less accumulated depreciation and amortization
 
(20,218
)
 
(18,169
)
Depreciable other fixed assets, net
 
26,037

 
28,630

 
 
 
 
 
Land
 
14,914

 
14,908

 
 
 
 
 
Total property and equipment, net
 
$
1,144,179

 
$
1,200,255

For the three months ended June 30, 2016 and 2015, depletion expense was $7.06 per barrel of oil equivalent ("BOE") sold and $16.19 per BOE sold, respectively. For the six months ended June 30, 2016 and 2015, depletion expense was $8.01 per BOE sold and $16.13 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, NGL 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
 
 
June 30, 2016
 
March 31, 2016
 
December 31, 2015
 
September 30, 2015
 
June 30, 2015
Benchmark Prices
 
 
 
 
 
 
 
 
 
 
   Oil ($/Bbl)
 
$
39.63

 
$
42.77

 
$
46.79

 
$
55.73

 
$
68.17

   NGL ($/Bbl)
 
$
17.08

 
$
17.51

 
$
18.75

 
$
21.87

 
$
26.73

   Natural gas ($/MMBtu)
 
$
2.17

 
$
2.31

 
$
2.47

 
$
2.89

 
$
3.22

Realized Prices
 
 
 
 
 
 
 
 
 
 
   Oil ($/Bbl)
 
$
37.96

 
$
41.33

 
$
45.58

 
$
54.28

 
$
66.68

   NGL ($/Bbl)
 
$
10.80

 
$
11.25

 
$
12.50

 
$
15.25

 
$
19.56

   Natural gas ($/Mcf)
 
$
1.64

 
$
1.75

 
$
1.89

 
$
2.30

 
$
2.62

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 (Level 2).
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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Inventory impairments:
 
 
 
 
 
 
 
 
Materials and supplies(1)
 
$
963

 
$
1,553

 
$
963

 
$
2,320

Line-fill(2)
 
—

 
—

 
—

 
111

Total inventory impairments
 
$
963

 
$
1,553

 
$
963

 
$
2,431

______________________________________________________________________________
(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 $6.8 million of debt issuance costs during the six months ended June 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the six months ended June 30, 2016. The Company had total debt issuance costs of $20.9 million and $23.9 million, net of accumulated amortization of $19.2 million and $17.0 million, as of June 30, 2016 and December 31, 2015, respectively.
The Company wrote-off approximately $0.8 million of debt issuance costs during the six months ended June 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. During the six months ended June 30, 2015, the Company wrote-off approximately $6.6 million of debt issuance costs as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. 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 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)
 
June 30, 2016
Remaining 2016

$
2,092

2017

4,238

2018

4,068

2019

2,915

2020

3,005

Thereafter

4,585

Total

$
20,903

i.    Other current assets and liabilities
Other current assets consist of the following components for the periods presented:
(in thousands)
 
June 30, 2016
 
December 31, 2015
Inventory(1)
 
$
6,986

 
$
6,974

Prepaid expenses and other
 
7,459

 
7,600

Total other current assets
 
$
14,445

 
$
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)
 
June 30, 2016
 
December 31, 2015
Accrued interest payable
 
$
24,161

 
$
24,208

Costs of purchased oil payable
 
15,629

 
12,189

Lease operating expense payable
 
11,570

 
13,205

Accrued compensation and benefits
 
8,720

 
14,342

Capital contribution payable to equity method investee(1)
 
—

 
27,583

Other accrued liabilities
 
12,440

 
14,695

Total other current liabilities
 
$
72,520

 
$
106,222

______________________________________________________________________________
(1)
See Notes 14 and 15 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 assets and perform other remediation of the sites where such pipeline 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 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)
 
Six months ended June 30, 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
 
253

 
2,236

Accretion expense
 
1,704

 
2,423

Liabilities settled upon plugging and abandonment
 
(526
)
 
(146
)
Liabilities removed due to sale of property
 
—

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

 
11,600

Liability at end of period
 
$
47,737

 
$
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 June 30, 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:
 
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
Non-cash investing information:
 
 
 
 
Change in accrued capital expenditures
 
$
(22,012
)
 
$
(53,209
)
Change in accrued capital contribution to equity method investee(1)
 
$
(27,583
)
 
$
27,917

Capitalized asset retirement cost
 
$
253

 
$
1,402

Supplemental cash flow information:
 
 
 
 
Capitalized interest
 
$
115

 
$
178

______________________________________________________________________________
(1)
See Notes 14 and 15 for additional discussion regarding our equity method investee.
Note 3—Equity offerings
On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. See Note 19.e for discussion regarding the completion of an equity offering subsequent to June 30, 2016.
On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities

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

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.
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 periods presented:
(in thousands)
 
Three months ended June 30, 2015
 
Six months ended June 30, 2015
Oil, NGL and natural gas sales
 
$
1,970

 
$
4,048

Expenses(1)
 
2,098

 
4,710

_____________________________________________________________________________
(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 June 30, 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 and an aggregate elected commitment of $815.0 million with $110.3 million outstanding and was subject to an interest rate of 2.00%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 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 June 30, 2016 or 2015.
See Note 19.a for discussion of additional borrowings and payments on the Senior Secured Credit Facility subsequent to June 30, 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:
 
 
June 30, 2016
 
December 31, 2015
(in thousands)
 
Long-term
debt
 
Fair
value
 
Long-term
debt
 
Fair
value
January 2022 Notes
 
$
450,000

 
$
426,564

 
$
450,000

 
$
388,301

May 2022 Notes
 
500,000

 
501,250

 
500,000

 
460,000

March 2023 Notes
 
350,000

 
349,965

 
350,000

 
301,000

Senior Secured Credit Facility
 
110,318

 
110,261

 
135,000

 
134,993

Total value of debt
 
$
1,410,318

 
$
1,388,040

 
$
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 June 30, 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 June 30, 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:
 
 
June 30, 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

 
$
(5,451
)
 
$
444,549

 
$
450,000

 
$
(5,939
)
 
$
444,061

May 2022 Notes
 
500,000

 
(6,624
)
 
493,376

 
500,000

 
(7,066
)
 
492,934

March 2023 Notes
 
350,000

 
(5,366
)
 
344,634

 
350,000

 
(5,769
)
 
344,231

Senior Secured Credit Facility(1)
 
110,318

 
—

 
110,318

 
135,000

 
—

 
135,000

Total
 
$
1,410,318

 
$
(17,441
)
 
$
1,392,877

 
$
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. In the second quarter of 2016, shareholders approved an increase in the maximum number of shares of the Company's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 shares (the "Amendment").
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. Historically, 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 six months ended June 30, 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
 
2,968

 
$
12.27

Forfeited
 
(221
)
 
$
15.16

Vested(1)
 
(1,124
)
 
$
16.06

Outstanding as of June 30, 2016
 
4,162

 
$
12.92

______________________________________________________________________________
(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 June 30, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $44.3 million. Such cost is expected to be recognized over a weighted-average period of 2.26 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 six months ended June 30, 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
 
1,016

 
$
4.18

 

Exercised
 
(6
)
 
$
11.93

 

Expired or canceled
 
(35
)
 
$
22.40

 

Forfeited
 
(229
)
 
$
13.62

 

Outstanding as of June 30, 2016
 
2,524

 
$
12.69

 
8.06
Vested and exercisable at end of period(1)
 
916

 
$
19.49

 
6.41
Expected to vest at end of period(2)
 
1,600

 
$
8.75

 
9.02
_____________________________________________________________________________
(1)
The vested and exercisable options as of June 30, 2016 had no aggregate intrinsic value.
(2)
The restricted stock options expected to vest as of June 30, 2016 had $6.1 million 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 June 30, 2016, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $13.5 million. Such cost is expected to be recognized over a weighted-average period of 2.55 years.
    

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

The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options granted on May 25, 2016 are as follows:
 
 
April 1, 2016
 
May 25, 2016
Risk-free interest rate(1)
 
1.44
%
 
1.58
%
Expected option life(2)
 
6.25 years

 
6.25 years

Expected volatility(3)
 
61.34
%
 
61.94
%
Fair value per stock option
 
$
4.44

 
$
9.75

(1)
United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.
(2)
As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
(3)
The Company utilized its own historical volatility in order to develop the expected volatility.     
In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
Full years of continuous employment
 
Incremental percentage of
option exercisable
 
Cumulative percentage of
option exercisable
Less than one
 
—
%
 
—
%
One
 
25
%
 
25
%
Two
 
25
%
 
50
%
Three
 
25
%
 
75
%
Four
 
25
%
 
100
%
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.
c.    Performance share awards
The performance share awards granted to management in the second quarter of 2016 (the "2016 Performance Share Awards"), 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 1,742,469 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 475,518 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 210,126 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.
    
    

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

The following table reflects the performance share award activity for the six months ended June 30, 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
 
1,801

 
$
17.71

Forfeited
 
(247
)
 
$
19.69

Vested
 
—

 
$
—

Outstanding as of June 30, 2016
 
2,428

 
$
18.36

As of June 30, 2016, unrecognized stock-based compensation related to the performance share awards was $35.3 million. Such cost is expected to be recognized over a weighted-average period of 2.47 years.
The assumptions used to estimate the fair value of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards granted on May 25, 2016 are as follows:
 
 
April 1, 2016
 
May 25, 2016
Risk-free rate(1)
 
0.87
%
 
1.02
%
Dividend yield
 
—
%
 
—
%
Expected volatility(2)
 
71.54
%
 
74.73
%
Laredo stock closing price on grant date
 
$
7.71

 
$
12.36

Fair value per performance share
 
$
9.83

 
$
17.86

______________________________________________________________________________
(1)
The risk-free rate was derived using a term-matched zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.
(2)
The Company utilized its own historical volatility over a lookback period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.
d.    Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
 
 
Three months ended June 30,

Six months ended June 30,
(in thousands)
 
2016

2015

2016

2015
Restricted stock award compensation
 
$
4,692

 
$
4,520

 
$
8,460

 
$
7,458

Restricted stock option award compensation
 
777

 
1,279

 
1,401


1,949

Restricted performance share award compensation
 
1,593

 
1,378

 
1,821


2,273

Total stock-based compensation, gross
 
7,062

 
7,177

 
11,682


11,680

Less amounts capitalized in oil and natural gas properties
 
(989
)
 
(909
)
 
(1,771
)
 
(624
)
Total stock-based compensation, net of amounts capitalized
 
$
6,073

 
$
6,268

 
$
9,911

 
$
11,056

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.

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

For the three and six months ended June 30, 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 the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of June 30, 2015, compensation expense for the three and six months ended June 30, 2015 was $0.7 million and $1.7 million, respectively.
Note 7—Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.
The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of June 30, 2016 or December 31, 2015.
The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit for the periods presented consisted of the following:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)

2016
 
2015
 
2016
 
2015
Current taxes

$
—

 
$
—


$
—

 
$
—

Deferred taxes

—

 
221,846

 
—

 
218,203

Income tax benefit

$
—

 
$
221,846


$
—

 
$
218,203

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

Three months ended June 30,
 
Six months ended June 30,
(in thousands)

2016
 
2015
 
2016
 
2015
Income tax benefit computed by applying the statutory rate

$
25,001

 
$
216,608

 
$
88,131

 
$
215,498

State income tax and change in valuation allowance

(541
)
 
5,776

 
187

 
5,867

Non-deductible stock-based compensation

—

 
(15
)
 
—

 
(106
)
Stock-based compensation tax deficiency

(190
)
 
(381
)
 
(4,012
)
 
(2,838
)
Increase in deferred tax valuation allowance

(24,323
)
 
(11
)
 
(84,218
)
 
(16
)
Other items

53

 
(131
)
 
(88
)
 
(202
)
Income tax benefit

$
—

 
$
221,846

 
$
—

 
$
218,203

 
For the three and six months ended June 30, 2016, the effective tax rate was not meaningful due to the valuation allowance recorded. For the three and six months ended June 30, 2015, the effective tax rate was 36% and 35%, respectively. 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 six months ended June 30, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable 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, NGL and natural gas reserves, (iv) its ability to use tax planning

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

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, NGL 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 six months ended June 30, 2016, an additional valuation allowance of $83.7 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 and six months ended June 30, 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 and six months ended June 30, 2016, certain stock options were exercised. No stock options were exercised during the three and six months ended June 30, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax expense.
The following table presents the tax impact of these shortfalls for the periods presented:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Vesting of restricted stock
 
$
(182
)
 
$
(388
)
 
$
(4,057
)
 
$
(2,889
)
Exercise of restricted stock options
 
(10
)
 
—

 
(10
)
 
—

Tax expense due to shortfalls
 
$
(192
)
 
$
(388
)
 
$
(4,067
)
 
$
(2,889
)
Significant components of the Company's net deferred tax asset for the periods presented are as follows:
(in thousands)
 
June 30, 2016
 
December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets
 
$
282,612

 
$
306,997

Net operating loss carry-forward
 
528,625

 
479,022

Derivatives
 
(41,577
)
 
(98,675
)
Stock-based compensation
 
9,340

 
11,597

Equity method investee
 
(25,612
)
 
(31,711
)
Accrued bonus
 
2,544

 
4,763

Capitalized interest
 
2,173

 
2,525

Other
 
2,901

 
2,820

Net deferred tax asset before valuation allowance
 
761,006

 
677,338

Valuation allowance
 
(761,006
)
 
(677,338
)
Net deferred tax asset
 
$
—

 
$
—

The Company had federal net operating loss carry-forwards totaling $1.5 billion and state of Oklahoma net operating loss carry-forwards totaling $41.0 million as of June 30, 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 June 30, 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.

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

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 June 30, 2016, the Company had 25 open derivative contracts with financial institutions that extend from July 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 (loss) 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 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 six months ended June 30, 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 six months ended June 30, 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
    
    

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

During the six months ended June 30, 2016, the following derivatives were entered into:
 
 
Aggregate volumes
 
Floor price
 
Ceiling 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
Put(3)
 
600,000

 
$
40.00

 
$
—

 
     May 2016 - December 2016
Swap
 
1,095,000

 
$
52.12

 
$
—

 
January 2018 - December 2018
Natural gas (volumes in MMBtu):(4)
 
 
 
 
 
 
 
 
Put
 
8,040,000

 
$
2.50

 
$
—

 
January 2017 - December 2017
Put
 
8,220,000

 
$
2.50

 
$
—

 
January 2018 - December 2018
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)
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 $1.2 million in deferred premiums associated with this contract.
(4)
There are $5.1 million in deferred premiums associated with these contracts.

The following represents cash settlements received for derivatives, net for the periods presented:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Cash settlements received for matured derivatives, net
 
$
47,382

 
$
46,596

 
$
113,319

 
$
109,737

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

 
—

 
80,000

 
—

Cash settlements received for derivatives, net
 
$
47,382

 
$
46,596

 
$
193,319

 
$
109,737

_____________________________________________________________________________
(1)
The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
    
    

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

The following table summarizes open positions as of June 30, 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)
 
1,098,000

 
1,049,375

 
1,049,375

Weighted-average price ($/Bbl)
 
$
42.95

 
$
60.00

 
$
60.00

Swaps:
 
 

 
 

 
 

Hedged volume (Bbl)
 
791,200

 
—

 
1,095,000

Weighted-average price ($/Bbl)
 
$
84.82

 
$
—

 
$
52.12

Collars:
 
 

 
 

 
 

Hedged volume (Bbl)
 
1,833,500

 
2,628,000

 
—

Weighted-average floor price ($/Bbl)
 
$
73.98

 
$
60.00

 
$
—

Weighted-average ceiling price ($/Bbl)
 
$
89.62

 
$
97.22

 
$
—

Totals:
 
 
 
 
 
 
Total volume hedged with floor price (Bbl)
 
3,722,700

 
3,677,375

 
2,144,375

Weighted-average floor price ($/Bbl)
 
$
67.13

 
$
60.00

 
$
55.98

Total volume hedged with ceiling price (Bbl)
 
2,624,700

 
2,628,000

 
1,095,000

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

 
$
97.22

 
$
52.12

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)
 
9,384,000

 
10,731,000

 
4,635,500

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

 
$
2.76

 
$
2.50

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

 
$
3.53

 
$
3.60

Totals:
 
 
 
 
 
 
Total volume hedged with floor price (MMBtu)
 
9,384,000

 
18,771,000

 
12,855,500

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

 
$
2.65

 
$
2.50

Total volume hedged with ceiling price (MMBtu)
 
9,384,000

 
10,731,000

 
4,635,500

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

 
$
3.53

 
$
3.60

_______________________________________________________________________________
(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

22
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 or six months ended June 30, 2016 or 2015.

23
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 June 30, 2016:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
93,057

 
$
—

 
$
93,057

 
$
(515
)
 
$
92,542

Natural gas derivatives
 
—

 
3,458

 
—

 
3,458

 
(1,165
)
 
2,293

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(5,467
)
 
(5,467
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(403
)
 
(403
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
33,181

 
$
—

 
$
33,181

 
$
—

 
$
33,181

Natural gas derivatives
 
—

 
2,724

 
—

 
2,724

 
(2,724
)
 
—

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(501
)
 
(501
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
515

 
$
515

Natural gas derivatives
 
—

 
(739
)
 
—

 
(739
)
 
1,165

 
426

Oil deferred premiums
 
—

 
—

 
(6,784
)
 
(6,784
)
 
5,467

 
(1,317
)
Natural gas deferred premiums
 
—

 
—

 
(1,507
)
 
(1,507
)
 
403

 
(1,104
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
(1,820
)
 
$
—

 
$
(1,820
)
 
$
—

 
$
(1,820
)
Natural gas derivatives
 
—

 
(774
)
 
—

 
(774
)
 
2,724

 
1,950

Oil deferred premiums
 
—

 
—

 
(501
)
 
(501
)
 
501

 
—

Natural gas deferred premiums
 
—

 
—

 
(3,870
)
 
(3,870
)
 
—

 
(3,870
)
Net derivative position
 
$
—

 
$
129,087

 
$
(12,662
)
 
$
116,425

 
$
—

 
$
116,425


24
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.

25
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)
 
June 30, 2016
Remaining 2016
 
$
5,407

2017
 
5,354

2018
 
2,100

  Total
 
$
12,861

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

Three months ended June 30,
 
Six months ended June 30,
(in thousands)

2016
 
2015
 
2016
 
2015
Balance of Level 3 at beginning of period

$
(13,054
)
 
$
(8,882
)
 
$
(14,619
)

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

(61
)
 
(45
)
 
(133
)

(88
)
Total purchases and settlements:

 
 
 
 
 



Purchases

(1,960
)
 
(4,409
)
 
(6,072
)

(5,384
)
Settlements(1)

2,413

 
1,249

 
8,162


2,670

Balance of Level 3 at end of period

$
(12,662
)
 
$
(12,087
)
 
$
(12,662
)

$
(12,087
)
_____________________________________________________________________________
(1)
The amount for the six months ended June 30, 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 and inventory, 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 and inventory are classified as Level 3, based on the use of internally developed cash flow models. See Note 2.g for discussion regarding the Company's impairment of (i) materials and supplies for the three months ended June 30, 2016 and the three and six months ended June 30, 2015 and (ii) line-fill for the six months ended June 30, 2015.
The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.f for discussion regarding the prices used in the calculation of discounted cash flows and the Company's first-quarter 2016 and second-quarter 2015 full cost ceiling impairments.
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 and six months ended June 30, 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.

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

The following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands, except for per share data)
 
2016
 
2015
 
2016
 
2015
Net loss (numerator):
 
 
 
 
 
 

 
 

Net loss—basic and diluted
 
$
(71,432
)
 
$
(397,034
)
 
$
(251,803
)
 
$
(397,506
)
Weighted-average common shares outstanding (denominator):
 
 
 
 
 
 
 
 
Basic
 
217,564


211,078

 
214,562

 
186,886

Diluted
 
217,564


211,078

 
214,562

 
186,886

Net loss per share:
 
 
 
 
 
 
 
 

Basic
 
$
(0.33
)
 
$
(1.88
)
 
$
(1.17
)
 
$
(2.13
)
Diluted
 
$
(0.33
)
 
$
(1.88
)
 
$
(1.17
)
 
$
(2.13
)
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 contract

The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. One of these contracts is for a term of multiple months and contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. The future commitment of $3.0 million as of June 30, 2016 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2016.

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 $400.2 million as of June 30, 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

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

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.
 
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 six months ended June 30, 2015 related to the RIF. There were no comparative amounts recorded in the six months ended June 30, 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 $16.0 million and $42.7 million during the three and six months ended June 30, 2016, respectively, and $14.5 million during the six months ended June 30, 2015, 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 June 30, 2016.
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 reflected in the unaudited consolidated

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

statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee."
During the six months ended June 30, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the three months ended June 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.
During the three months ended June 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.
Note 15—Related Parties
a.    Medallion
The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Midstream service revenues
 
$
—

 
$
390

 
$
—

 
$
487

Minimum volume commitments
 
—

 
3,579

 
—

 
5,235

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)
 
June 30, 2016
 
December 31, 2015
Accounts receivable, net
 
$
—

 
$
1,163

Other assets, net(1)
 
1,025

 
1,025

Other current liabilities(2)
 
102

 
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' accrued line-fill purchase in Medallion's pipeline as of June 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.
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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016

2015
 
2016
 
2015
Oil, NGL and natural gas sales
 
$
18,112

 
$
34,012

 
$
35,917

 
$
53,643

Midstream service revenues
 
102

 
—

 
237

 
—

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)
 
June 30, 2016

December 31, 2015
Accounts receivable, net
 
$
9,337

 
$
6,097


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

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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016

2015
 
2016
 
2015
Lease operating expenses
 
$
526

 
$
391

 
$
1,001

 
$
776

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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016

2015
Capital expenditures:
 
 
 
 
 
 
 
 
Midstream service assets
 
$
—

 
$
18

 
$
20

 
$
64

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)
 
June 30, 2016
 
December 31, 2015
Accounts payable
 
$
—

 
$
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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Capital expenditures:
 
 
 
 
 
 
 
 
Oil and natural gas properties
 
$
—

 
$
177

 
$
—

 
$
2,434

Note 16—Segments
The Company operates in two business segments: (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 delivery and takeaway in and around Laredo's primary production corridors.

30
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 June 30, 2016:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
102,526

 
$
—

 
$
—

 
$
102,526

Midstream service revenues
 
—

 
11,138

 
(9,506
)
 
1,632

Sales of purchased oil
 
—

 
42,615

 
—

 
42,615

Total revenues
 
102,526

 
53,753

 
(9,506
)
 
146,773

Lease operating expenses, including production tax
 
29,793

 
—

 
(2,586
)
 
27,207

Midstream service expenses
 
—

 
6,572

 
(5,394
)
 
1,178

Costs of purchased oil
 
—

 
44,012

 
—

 
44,012

General and administrative(1)
 
18,818

 
1,684

 
—

 
20,502

Depletion, depreciation and amortization(2)
 
31,969

 
2,208

 
—

 
34,177

Impairment expense
 
963

 
—

 
—

 
963

Other operating costs and expenses(3)
 
806

 
54

 
—

 
860

Operating income (loss)
 
$
20,177

 
$
(777
)
 
$
(1,526
)
 
$
17,874

Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
3,696

 
$
—

 
$
3,696

Interest expense(4)
 
$
(22,050
)
 
$
(1,462
)
 
$
—

 
$
(23,512
)
Capital expenditures
 
$
(92,089
)
 
$
(1,488
)
 
$
—

 
$
(93,577
)
Gross property and equipment(6)
 
$
5,484,416

 
$
366,858

 
$
(4,604
)
 
$
5,846,670

Three months ended June 30, 2015:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
125,679

 
$
221


$
(346
)
 
$
125,554

Midstream service revenues
 
—

 
4,362


(2,636
)
 
1,726

Sales of purchased oil
 
—

 
55,051


—

 
55,051

Total revenues
 
125,679

 
59,634

 
(2,982
)
 
182,331

Lease operating expenses, including production tax
 
41,423

 
—


(2,717
)
 
38,706

Midstream service expenses, including minimum volume commitments
 
4,399

 
998


(221
)
 
5,176

Costs of purchased oil
 
—

 
54,417


—

 
54,417

General and administrative(1)
 
21,347

 
1,861


—

 
23,208

Depletion, depreciation and amortization(2)
 
69,987

 
2,125


—

 
72,112

Impairment expense
 
489,599

 
—

 
—

 
489,599

Other operating costs and expenses(3)
 
548

 
45


—

 
593

Operating income (loss)
 
$
(501,624
)
 
$
188

 
$
(44
)
 
$
(501,480
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
2,914


$
—

 
$
2,914

Interest expense(4)
 
$
(22,845
)
 
$
(1,125
)

$
—

 
$
(23,970
)
Loss on early redemption of debt(5)
 
$
(30,056
)
 
$
(1,481
)
 
$
—

 
$
(31,537
)
Capital expenditures
 
$
(133,259
)
 
$
(13,841
)

$
—

 
$
(147,100
)
Gross property and equipment(6)
 
$
5,170,912

 
$
257,073

 
$
(365
)
 
$
5,427,620

_______________________________________________________________________________
(1)
General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.
(2)
Depletion, depreciation and amortization were actual expenses 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 as of June 30, 2016 and 2015.
(3)
Other operating costs and expenses consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.
(4)
Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 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 as of June 30, 2016 and 2015.
(5)
Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 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 as of June 30, 2015.

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

(6)
Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.
(in thousands)
 
Exploration and production
 
Midstream and marketing
 
Eliminations
 
Consolidated company
Six months ended June 30, 2016:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
175,668

 
$
—

 
$
—

 
$
175,668

Midstream service revenues
 
—

 
22,405

 
(18,972
)
 
3,433

Sales of purchased oil
 
—

 
74,229

 
—

 
74,229

Total revenues
 
175,668

 
96,634

 
(18,972
)
 
253,330

Lease operating expenses, including production tax
 
59,157

 
—

 
(4,997
)
 
54,160

Midstream service expenses
 
—

 
13,081

 
(11,294
)
 
1,787

Costs of purchased oil
 
—

 
76,958

 
—

 
76,958

General and administrative(1)
 
36,497

 
3,456

 
—

 
39,953

Depletion, depreciation and amortization(2)
 
71,261

 
4,394

 
—

 
75,655

Impairment expense
 
162,027

 
—

 
—

 
162,027

Other operating costs and expenses(3)
 
1,598

 
106

 
—

 
1,704

Operating loss
 
$
(154,872
)
 
$
(1,361
)
 
$
(2,681
)
 
$
(158,914
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
5,994

 
$
—

 
$
5,994

Interest expense(4)
 
$
(44,353
)
 
$
(2,864
)
 
$
—

 
$
(47,217
)
Capital expenditures
 
$
(197,874
)
 
$
(3,425
)
 
$
—

 
$
(201,299
)
Gross property and equipment(6)
 
$
5,484,416

 
$
366,858

 
$
(4,604
)
 
$
5,846,670

Six months ended June 30, 2015:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
243,890

 
$
333

 
$
(551
)
 
$
243,672

Midstream service revenues
 
—

 
8,045

 
(5,010
)
 
3,035

Sales of purchased oil
 
—

 
86,318

 
—

 
86,318

Total revenues
 
243,890

 
94,696

 
(5,561
)
 
333,025

Lease operating expenses, including production tax
 
85,268

 
—

 
(5,096
)
 
80,172

Midstream service expenses, including minimum volume commitments
 
4,399

 
4,340

 
(333
)
 
8,406

Costs of purchased oil
 
—

 
85,617

 
—

 
85,617

General and administrative(1)
 
41,125

 
3,938

 
—

 
45,063

Depletion, depreciation and amortization(2)
 
140,244

 
3,810

 
—

 
144,054

Impairment expense
 
490,366

 
111

 
—

 
490,477

Other operating costs and expenses(3)
 
6,972

 
242

 
—

 
7,214

Operating loss
 
$
(524,484
)
 
$
(3,362
)
 
$
(132
)
 
$
(527,978
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
2,481

 
$
—

 
$
2,481

Interest expense(4)
 
$
(53,932
)
 
$
(2,452
)
 
$
—

 
$
(56,384
)
Loss on early redemption of debt(5)
 
$
(30,056
)
 
$
(1,481
)
 
$
—

 
$
(31,537
)
Capital expenditures
 
$
(380,872
)
 
$
(34,314
)
 
$
—

 
$
(415,186
)
Gross property and equipment(6)
 
$
5,170,912

 
$
257,073

 
$
(365
)
 
$
5,427,620

_______________________________________________________________________________
(1)
General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.
(2)
Depletion, depreciation and amortization were actual expenses 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 as of June 30, 2016 and 2015.
(3)
Other operating costs and expenses consist of accretion of asset retirement obligations for the six months ended June 30, 2016 and 2015 and restructuring expense for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.
(4)
Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 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 as of June 30, 2016 and 2015.

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

(5)
Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 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 as of June 30, 2015.
(6)
Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 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 June 30, 2016 and December 31, 2015, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2016 and 2015 and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 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 six months ended June 30, 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
June 30, 2016
(Unaudited)
(in thousands)
 
Laredo

Subsidiary
Guarantors

Intercompany
eliminations

Consolidated
company
Accounts receivable, net
 
$
73,429

 
$
15,114

 
$
—

 
$
88,543

Other current assets
 
120,982

 
1,737

 
—

 
122,719

Total oil and natural gas properties, net
 
970,445

 
9,335

 
(4,604
)
 
975,176

Total midstream service assets, net
 
—

 
128,052

 
—

 
128,052

Total other fixed assets, net
 
40,701

 
250

 
—

 
40,951

Investment in subsidiaries and equity method investee
 
348,623

 
213,616

 
(348,623
)
 
213,616

Total other long-term assets
 
37,526

 
3,568

 
—

 
41,094

Total assets
 
$
1,591,706

 
$
371,672

 
$
(353,227
)
 
$
1,610,151

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
12,934

 
$
1,566

 
$
—

 
$
14,500

Other current liabilities
 
120,756

 
18,556

 
—

 
139,312

Long-term debt, net
 
1,392,877

 
—

 
—

 
1,392,877

Other long-term liabilities
 
51,373

 
2,927

 
—

 
54,300

Stockholders' equity
 
13,766

 
348,623

 
(353,227
)
 
9,162

Total liabilities and stockholders' equity
 
$
1,591,706

 
$
371,672

 
$
(353,227
)
 
$
1,610,151




33
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 June 30, 2016
(Unaudited)
(in thousands)

Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues

$
102,511


$
53,768


$
(9,506
)

$
146,773

Total costs and expenses

84,137


52,742


(7,980
)

128,899

Operating income

18,374


1,026


(1,526
)

17,874

Interest expense and other, net

(23,501
)

—


—


(23,501
)
Other non-operating income (expense)

(64,779
)

3,692


(4,718
)

(65,805
)
Income (loss) before income tax

(69,906
)

4,718


(6,244
)

(71,432
)
Income tax

—


—


—


—

Net income (loss)

$
(69,906
)

$
4,718


$
(6,244
)

$
(71,432
)

Condensed consolidating statement of operations
For the six months ended June 30, 2016
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues
 
$
175,633

 
$
96,669

 
$
(18,972
)
 
$
253,330

Total costs and expenses
 
334,201

 
94,334

 
(16,291
)
 
412,244

Operating income (loss)
 
(158,568
)
 
2,335

 
(2,681
)
 
(158,914
)
Interest expense and other, net
 
(47,107
)
 
—

 
—

 
(47,107
)
Other non-operating income (expense)
 
(43,447
)
 
5,983

 
(8,318
)
 
(45,782
)
Income (loss) before income tax
 
(249,122
)
 
8,318

 
(10,999
)
 
(251,803
)
Income tax
 
—

 
—

 
—

 
—

Net income (loss)
 
$
(249,122
)
 
$
8,318

 
$
(10,999
)
 
$
(251,803
)

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

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

Subsidiary
Guarantors

Intercompany
eliminations

Consolidated
company
Total revenues
 
$
125,687

 
$
59,626

 
$
(2,982
)
 
$
182,331

Total costs and expenses
 
629,359

 
57,390

 
(2,938
)
 
683,811

Operating income (loss)
 
(503,672
)
 
2,236

 
(44
)
 
(501,480
)
Interest expense and other, net
 
(23,797
)
 
—

 
—

 
(23,797
)
Other non-operating income (expense)
 
(91,367
)
 
2,914

 
(5,150
)
 
(93,603
)
Income (loss) before income tax
 
(618,836
)
 
5,150

 
(5,194
)
 
(618,880
)
Deferred income tax benefit
 
221,846

 
—

 
—

 
221,846

Net income (loss)
 
$
(396,990
)
 
$
5,150

 
$
(5,194
)
 
$
(397,034
)
Condensed consolidating statement of operations
For the six months ended June 30, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues
 
$
243,833

 
$
94,753

 
$
(5,561
)

$
333,025

Total costs and expenses
 
772,667

 
93,765

 
(5,429
)

861,003

Operating income (loss)
 
(528,834
)
 
988

 
(132
)
 
(527,978
)
Interest expense and other, net
 
(56,088
)
 
—

 
—


(56,088
)
Other non-operating income (expense)
 
(30,655
)
 
2,481

 
(3,469
)

(31,643
)
Income (loss) before income tax
 
(615,577
)
 
3,469

 
(3,601
)
 
(615,709
)
Deferred income tax benefit
 
218,203

 
—

 
—


218,203

Net income (loss)
 
$
(397,374
)
 
$
3,469

 
$
(3,601
)
 
$
(397,506
)
Condensed consolidating statement of cash flows
For the six months ended June 30, 2016
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by operating activities
 
$
139,610

 
$
7,339

 
$
(8,318
)
 
$
138,631

Change in investment between affiliates
 
(47,069
)
 
38,751

 
8,318

 
—

Capital expenditures and other
 
(197,540
)
 
(46,090
)
 
—

 
(243,630
)
Net cash flows provided by financing activities
 
93,154

 
—

 
—

 
93,154

Net decrease in cash and cash equivalents
 
(11,845
)
 
—

 
—

 
(11,845
)
Cash and cash equivalents at beginning of period
 
31,153

 
1

 
—

 
31,154

Cash and cash equivalents at end of period
 
$
19,308

 
$
1

 
$
—

 
$
19,309







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

Condensed consolidating statement of cash flows
For the six months ended June 30, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by (used in) operating activities
 
$
136,092

 
$
(18,318
)
 
$
(3,469
)
 
$
114,305

Change in investment between affiliates
 
(70,472
)
 
67,003

 
3,469

 
—

Capital expenditures and other
 
(380,961
)
 
(48,685
)
 
—

 
(429,646
)
Net cash flows provided by financing activities
 
343,613

 
—

 
—

 
343,613

Net increase in cash and cash equivalents
 
28,272

 
—

 
—

 
28,272

Cash and cash equivalents at beginning of period
 
29,320

 
1

 
—

 
29,321

Cash and cash equivalents at end of period
 
$
57,592

 
$
1

 
$
—

 
$
57,593

Note 18—Recent accounting pronouncements
In March, April and May 2016, the Financial Accounting Standards Board ("FASB"), issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are 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.
In March 2016, the FASB issued new guidance in Topic 323, Investments—Equity Method and Joint Ventures, to eliminate the requirement to retroactively adopt the equity method of accounting when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. The amendments in this update should be applied prospectively upon their effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. 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 March 2016, the 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.
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

36
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 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.

37
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Note 19—Subsequent events
a.   Senior Secured Credit Facility
On July 12, 2016, the Company borrowed $94.7 million on the Senior Secured Credit Facility, after which the outstanding balance under the Senior Secured Credit Facility was $205.0 million. On July 19, 2016, the Company completed the July 2016 Equity Offering (as defined below) and applied the net proceeds to the outstanding balance under the Senior Secured Credit Facility, reducing the balance to $70.0 million.
b.  Medallion contribution
Subsequent to June 30, 2016, the Company approved, and on July 29, 2016 contributed, $16.0 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. 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 June 30, 2016, the Company entered into the following new derivative contracts:
 
 
Aggregate volumes
 
Price
 
Contract period
Oil (volumes in Bbl):(1)
 
 
 
 
 
 
Swap
 
1,003,750

 
$
51.90

 
January 2017 - December 2017
Swap
 
1,003,750

 
$
51.17

 
January 2017 - December 2017
NGL (volumes in Bbl):
 
 
 
 
 
 
Swap(2)
 
444,000

 
$
11.24

 
January 2017 - December 2017
Swap(3)
 
375,000

 
$
22.26

 
January 2017 - December 2017
_____________________________________________________________
(1)
The associated derivatives will be settled based on the WTI NYMEX index oil price.
(2)
The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.
(3)
The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.
d.   Acquisition of proved and unproved oil and natural gas properties
Subsequent to June 30, 2016, the Company entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within the Company's core development area (which includes production of approximately 300 net BOE/D from existing vertical wells) for an aggregate purchase price of $125.0 million. On July 13 and July 18, 2016, the Company closed portions of this acquisition for approximately $92.7 million and $1.65 million, respectively. The closings on the remaining interests, which are subject to certain preferential purchase rights and consents, are expected to occur as such rights and consents are satisfied or obtained during the third and fourth quarters of 2016.
e.   July equity offering
On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of approximately $136.3 million, after underwriting discounts, commissions and offering expenses. The Company used the net proceeds from the July 2016 Equity Offering to repay borrowings under its Senior Secured Credit Facility as discussed above in Note 19.a. The Company granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds to the Company of approximately $20.5 million, after underwriting discounts, commissions and offering expenses.



38
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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Property acquisition costs:
 
 

 
 

 
 

 
—

Evaluated
 
$
—

 
$
—

 
$
—

 
$
—

Unevaluated
 
—


—

 
—

 
—

Exploration
 
19,769


3,841

 
27,032

 
8,354

Development costs(1)
 
70,806


110,518

 
152,692

 
317,190

Total costs incurred
 
$
90,575


$
114,359

 
$
179,724

 
$
325,544

____________________________________________________________________________
(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 June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively.



39

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 June 30, 2016 included the following:
•
Oil, NGL and natural gas sales of $102.5 million, compared to $125.6 million for the three months ended June 30, 2015;
•
Average daily sales volumes of 47,667 BOE/D, compared to 46,532 BOE/D for the three months ended June 30, 2015;
•
Net loss of $71.4 million, compared to net loss of $397.0 million, including a non-cash full cost ceiling impairment of $488.0 million, for the three months ended June 30, 2015; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $107.8 million, compared to $117.9 million for the three months ended June 30, 2015. See page 55 for a reconciliation of adjusted EBITDA.
Our financial and operating performance for the six months ended June 30, 2016 included the following:
•
Oil, NGL and natural gas sales of $175.7 million, compared to $243.7 million for the six months ended June 30, 2015;
•
Average daily sales volumes of 46,935 BOE/D, compared to 47,007 BOE/D for the six months ended June 30, 2015;
•
Net loss of $251.8 million, including a non-cash full cost ceiling impairment of $161.1 million, compared to net loss of $397.5 million, including a non-cash full cost ceiling impairment of $488.0 million, for the six months ended June 30, 2015; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $203.8 million, compared to $236.5 million for the six months ended June 30, 2015. See page 55 for a reconciliation of adjusted EBITDA.
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 June 30, 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 did not exceed the full cost ceiling amount as of June 30, 2016. As such, we did not record a second-quarter non-cash full cost ceiling impairment. 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 impairments in prior periods.

40

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 third 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 third 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 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 third-quarter effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in the following scenario.
Our hypothetical third-quarter 2016 full cost ceiling calculation has been prepared by substituting (a) $36.24 per barrel for oil, (b) $10.97 per barrel for NGL and (c) $1.64 per MMBtu for natural gas (the "Pro Forma Prices") for the respective Realized Prices as of June 30, 2016. 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 August 1, 2016, with the price for August 1, 2016 held constant for the remaining twelfth month of the calculation. Based on these inputs, the implied third-quarter impairment would be $38 million. We believe that substituting the Pro Forma Prices in our June 30, 2016 internal reserve estimates may help provide users with an understanding of the impact of known trends on our September 30, 2016 full cost ceiling test and in preparing our year-end reserve estimates.
Recent developments
Acquisition of proved and unproved oil and natural gas properties
Subsequent to June 30, 2016, we entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within our core development area (which includes production of approximately 300 net barrels of oil equivalent per day from existing vertical wells) for an aggregate purchase price of $125.0 million. As of July 13 and July18, 2016, we have closed portions of this acquisition for $92.7 million and $1.65 million, respectively. The closings on the remaining interests, which are subject to certain preferential purchase rights and consents, are expected to occur as such rights and consents are satisfied or obtained during the third and fourth quarter of 2016.
July 2016 equity offering
On July 19, 2016, we completed the sale of 13,000,000 shares of Laredo's common stock for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses, which were used to repay borrowings under our Senior Secured Credit Facility. We granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds of $20.5 million, after underwriting discounts, commissions and offering expenses.

41

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 June 30, 2016, we had assembled 128,504 net acres in the Permian Basin.
Sources of our revenue
Our revenues are primarily derived from the sale of produced oil, NGL and natural gas within the continental United States and the sale of purchased oil, and our revenues do not include the effects of derivatives. For the three months ended June 30, 2016, our revenues were comprised of sales of 54% produced oil, 10% produced NGL, 6% produced natural gas, 29% purchased oil and 1% midstream services. For the six months ended June 30, 2016, our revenues were comprised of sales of 53% produced oil, 9% produced NGL, 7% produced natural gas, 29% purchased oil and 2% midstream services. 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 and market differentials. 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.

42

Results of operations consolidated
Three and six months ended June 30, 2016 as compared to the three and six months ended June 30, 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 June 30,
 
Six months ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Sales volumes:
 
 


 

 
 

 
 

Oil (MBbl)
 
2,012


1,938

 
4,018

 
4,110

NGL (MBbl)
 
1,153

 
1,095

 
2,219

 
2,084

Natural gas (MMcf)
 
7,038


7,205

 
13,834

 
13,885

Oil equivalents (MBOE)(1)(2)
 
4,338


4,234

 
8,542

 
8,508

Average daily sales volumes (BOE/D)(2)
 
47,667


46,532

 
46,935

 
47,007

% Oil
 
46
%

46
%
 
47
%
 
48
%
Oil, NGL and natural gas revenues (in thousands):
 



 
 
 

 
 

Oil
 
$
79,201


$
98,394

 
$
134,395

 
$
189,009

NGL
 
14,120

 
14,081

 
23,172

 
27,268

Natural gas
 
9,205


13,079

 
18,101

 
27,395

Total revenues
 
$
102,526


$
125,554

 
$
175,668

 
$
243,672

Average sales prices:
 



 
 
 

 
 

Oil, realized ($/Bbl)(3)
 
$
39.37


$
50.77

 
$
33.45

 
$
45.99

NGL, realized ($/Bbl)(3)
 
$
12.24


$
12.85

 
$
10.44

 
$
13.08

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


$
1.82

 
$
1.31

 
$
1.97

Average price, realized ($/BOE)(3)
 
$
23.64


$
29.65

 
$
20.56

 
$
28.64

Oil, hedged ($/Bbl)(4)
 
$
58.86


$
72.39

 
$
57.85

 
$
70.87

NGL, hedged ($/Bbl)(4)
 
$
12.24


$
12.85

 
$
10.44

 
$
13.08

Natural gas, hedged ($/Mcf)(4)
 
$
2.13


$
2.29

 
$
2.10

 
$
2.32

Average price, hedged ($/BOE)(4)
 
$
34.00


$
40.36

 
$
33.33

 
$
41.22

________________________________________________________________________
(1)
BOE is 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 includes 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.
    

43

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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Cash settlements received for matured derivatives:
 





 
 
 
 
Oil
 
$
41,616


$
42,972

 
$
102,308

 
$
104,558

Natural gas
 
5,766


3,624

 
11,011

 
5,179

Total
 
$
47,382


$
46,596

 
$
113,319

 
$
109,737

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





 
 
 
 
Oil
 
$
(2,413
)

$
(1,073
)
 
$
(4,263
)
 
$
(2,318
)
Natural gas
 
—


(176
)
 
—

 
(352
)
Total
 
$
(2,413
)

$
(1,249
)
 
$
(4,263
)
 
$
(2,670
)
 
Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended June 30, 2016 and 2015:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net dollar
effect of change
2015 Revenues
 
$
98,394

 
$
14,081

 
$
13,079


$
125,554

Effect of changes in price
 
(22,921
)
 
(704
)
 
(3,570
)
 
(27,195
)
Effect of changes in volumes
 
3,728

 
743

 
(304
)
 
4,167

2016 Revenues
 
$
79,201

 
$
14,120

 
$
9,205

 
$
102,526

Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the six months ended June 30, 2016 and 2015:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net dollar
effect of change
2015 Revenues
 
$
189,009

 
$
27,268

 
$
27,395

 
$
243,672

Effect of changes in price
 
(50,378
)
 
(5,855
)
 
(9,193
)
 
(65,426
)
Effect of changes in volumes
 
(4,236
)
 
1,759

 
(101
)
 
(2,578
)
2016 Revenues
 
$
134,395

 
$
23,172

 
$
18,101

 
$
175,668

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 $19.2 million, or 20%, for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, is mainly due to a 22% decrease in average oil prices realized, partially offset by a 4% increase in oil production.
The decrease in oil revenue of $54.6 million, or 29%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 27% decrease in average oil prices realized and a 2% decrease in oil production.
See "—Results of operations - midstream and marketing" for a discussion of our revenue from sales of purchased oil.
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. NGL revenue of $14.1 million remained mostly unchanged for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The decrease in natural gas revenue of $3.9 million, or 30%, for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, is mainly due to a 28% decrease in average natural gas prices realized.
The decrease in NGL revenue of $4.1 million, or 15%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 20% decrease in average NGL prices realized, partially offset by a 6% increase in NGL production. The decrease in natural gas revenue of $9.3 million, or 34%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 34% decrease in average natural gas prices realized.

44


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 June 30,

Six months ended June 30,
(in thousands except for per BOE sold data)
 
2016
 
2015

2016

2015
Costs and expenses:
 
 

 
 

 
 

 
 

Lease operating expenses
 
$
19,225

 
$
29,206

 
$
39,743

 
$
61,586

Production and ad valorem taxes
 
7,982

 
9,500

 
14,417

 
18,586

Midstream service expenses
 
1,178

 
1,597

 
1,787

 
3,171

Minimum volume commitments
 
—

 
3,579

 
—

 
5,235

Costs of purchased oil
 
44,012

 
54,417

 
76,958

 
85,617

General and administrative(1)
 
20,502

 
23,208

 
39,953

 
45,063

Restructuring expenses
 
—

 
—

 
—

 
6,042

Accretion of asset retirement obligations
 
860

 
593

 
1,704

 
1,172

Depletion, depreciation and amortization
 
34,177

 
72,112

 
75,655

 
144,054

Impairment expense
 
963

 
489,599

 
162,027

 
490,477

Total
 
$
128,899

 
$
683,811

 
$
412,244

 
$
861,003

Average costs per BOE sold:






 
 
 
 
Lease operating expenses

$
4.43


$
6.90


$
4.65


$
7.24

Production and ad valorem taxes
 
1.84

 
2.24

 
1.69

 
2.18

Midstream service expenses
 
0.27

 
0.38

 
0.21

 
0.37

General and administrative(1)
 
4.73


5.48


4.68


5.30

Depletion, depreciation and amortization
 
7.88


17.03


8.86


16.93

Total
 
$
19.15


$
32.03


$
20.09


$
32.02

________________________________________________________________________
(1)
General and administrative includes non-cash stock-based compensation, net of amounts capitalized, of $6.1 million and $6.3 million for the three months ended June 30, 2016 and 2015, respectively, and $9.9 million and $11.1 million for the six months ended June 30, 2016 and 2015, respectively.
Lease operating expenses. Lease operating expenses, which include workover expenses, decreased by $10.0 million, or 34%, and $21.8 million, or 35%, for the three and six months ended June 30, 2016, respectively, as compared to the same periods in 2015. Previous investments in field infrastructure, primarily in our four production corridors, including water takeaway and recycling facilities and centralized compression, have lowered expenses and reduced well downtime. We continue to focus on the usage and procurement of products and services related to direct operating expenses.
Production and ad valorem taxes. Production and ad valorem taxes decreased by $1.5 million, or 16%, and $4.2 million, or 22%, for the three and six months ended June 30, 2016, respectively, as compared to the same periods in 2015. This change is mainly due to a decrease in production taxes of $1.1 million and $3.3 million for the three and six months ended June 30, 2016 compared to the same periods 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 expenses.
Minimum volume commitments. See "—Results of operations - midstream and marketing" for a discussion of these expenses.
Costs of purchased oil. See "—Results of operations - midstream and marketing" for a discussion of these expenses.
    
    

45


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 June 30, 2016 compared to 2015
 
Six months ended June 30, 2016 compared to 2015
Changes in G&A:
 
 
 
 
Performance unit awards
 
$
(678
)
 
$
(1,674
)
Salaries, benefits and bonuses, net of amounts capitalized
 
(1,610
)
 
(1,424
)
Stock-based compensation, net of amounts capitalized
 
(195
)
 
(1,145
)
Professional fees
 
(714
)
 
(1,104
)
Other
 
491


237

Total changes in G&A
 
$
(2,706
)
 
$
(5,110
)
G&A expense, excluding stock-based compensation, decreased by $2.5 million, or 15%, and $4.0 million, or 12%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. One of the main contributors to these decreases was the expense incurred for our 2013 Performance Unit Awards of $1.0 million and $1.7 million during the three and six months ended June 30, 2015, respectively. There was no comparable expense during the three and six months ended June 30, 2016. The performance criteria of these awards were satisfied on December 31, 2015, were paid during the first quarter of 2016 and were accounted for as liability awards.
Other significant contributors to the decreases in G&A expense, excluding stock-based compensation, are (i) reduced personnel expenses and (ii) a decrease in professional fees primarily due to a decrease in nonrecurring projects.
Stock-based compensation, net of amounts capitalized, decreased by $0.2 million, or 3%, and $1.1 million, or 10%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. As a result of stockholder approval of the Amendment to the LTIP at our 2016 Annual Meeting of Stockholders, on May 25, 2016, the restricted stock awards, restricted stock options and performance awards that were contingent as of March 31, 2016 became granted on May 25, 2016, at which time we began recording expense. 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 were for the first-quarter 2015 RIF that was undertaken to reduce expenses and better position ourselves for future operations in a low commodity price environment. Restructuring expenses of $6.0 million were incurred during the six months ended June 30, 2015. No comparable expenses were recorded during the six months ended June 30, 2016. See Note 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the RIF.

46


Depletion, depreciation and amortization ("DD&A"). The following table provides components of our DD&A expense for the periods presented:
 
 
Three months ended June 30,

Six months ended June 30,
(in thousands except for per BOE sold data)
 
2016
 
2015

2016

2015
Depletion of evaluated oil and natural gas properties
 
$
30,630

 
$
68,545

 
$
68,457

 
$
137,273

Depreciation of midstream service assets
 
2,097

 
1,933

 
4,168

 
3,580

Depreciation and amortization of other fixed assets
 
1,450

 
1,634

 
3,030

 
3,201

Total DD&A
 
$
34,177

 
$
72,112

 
$
75,655

 
$
144,054

DD&A per BOE sold
 
$
7.88

 
$
17.03

 
$
8.86

 
$
16.93

DD&A decreased by $37.9 million, or 53%, and $68.4 million, or 47%, respectively, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, mainly due to our full cost ceiling impairments totaling $2.4 billion during the year ended December 31, 2015 and $161.1 million during the three months ended March 31, 2016.
Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016 and as of June 30, 2015, and as a result, non-cash full cost ceiling impairments of $161.1 million and $488.0 million, respectively, were recorded. For further discussion of our non-cash full cost ceiling impairments, see Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Other less material components of impairment expense for the six months ended June 30, 2016 are $1.0 million for materials and supplies as compared to $2.3 million for materials and supplies and $0.1 million for our line-fill for the six months ended June 30, 2015.
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 June 30,

Six months ended June 30,
(in thousands)
 
2016
 
2015

2016

2015
Non-operating income (expense):
 
 

 
 

 
 

 
 

Loss on derivatives, net
 
$
(68,518
)
 
$
(63,899
)
 
$
(50,633
)
 
$
(744
)
Income from equity method investee
 
3,696

 
2,914

 
5,994

 
2,481

Interest expense
 
(23,512
)
 
(23,970
)
 
(47,217
)
 
(56,384
)
Interest and other income
 
11

 
173

 
110

 
296

Loss on early redemption of debt
 
—

 
(31,537
)
 
—

 
(31,537
)
Write-off of debt issuance costs
 
(842
)
 
—

 
(842
)
 
—

Loss on disposal of assets, net
 
(141
)
 
(1,081
)
 
(301
)
 
(1,843
)
Non-operating expense, net
 
$
(89,306
)
 
$
(117,400
)
 
$
(92,889
)
 
$
(87,731
)
Loss on derivatives, net. The table below shows the changes in the components of loss on derivatives, net for the periods presented:
(in thousands)
 
Three months ended June 30, 2016 compared to 2015
 
Six months ended June 30, 2016 compared to 2015
Changes in loss on derivatives, net:
 
 
 
 
Fair value of derivatives outstanding
 
$
(5,405
)
 
$
(133,471
)
Early terminations of derivatives received
 
—

 
80,000

Cash settlements received for matured derivatives
 
786

 
3,582

Total changes in loss on derivatives, net
 
$
(4,619
)
 
$
(49,889
)
The change in fair value of derivatives outstanding for the three and six months ended June 30, 2016 compared to the same periods 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 loss on derivatives, net for the six months ended June 30, 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

47


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.
Income from equity method investee. Income from equity method investee increased by $0.8 million, or 27%, and $3.5 million, or 142%, for the three and six months ended June 30, 2016 compared to the same periods in 2015. During the six months ended June 30, 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 99,000 barrels of oil per day ("BOPD") and 35,000 BOPD for the three months ended June 30, 2016 and 2015, respectively, and 91,000 BOPD and 25,000 BOPD during the six months ended June 30, 2016 and 2015, respectively.
Interest expense. The table below shows the changes in the significant components of interest expense for the periods presented:
(in thousands)
 
Three months ended June 30, 2016 compared to 2015
 
Six months ended June 30, 2016 compared to 2015
Changes in interest expense:
 
 

 
 

January 2019 Notes
 
$
(867
)
 
$
(13,865
)
March 2023 Notes
 
—

 
4,679

Senior Secured Credit Facility, net of capitalized interest
 
426

 
200

Other
 
(17
)
 
(181
)
Total change in interest expense
 
$
(458
)
 
$
(9,167
)
Interest expense decreased by $0.5 million, or 2%, and $9.2 million, or 16%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. These decreases are 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 by $0.9 million and $1.5 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 as a result of lower losses related to the sales and write-off of materials and supplies and other fixed assets during 2016 as compared to 2015.
Income tax benefit. The fluctuations in loss before income tax benefit are shown in the table below:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Loss before income taxes
 
$
(71,432
)
 
$
(618,880
)
 
$
(251,803
)
 
$
(615,709
)
Income tax benefit
 
—

 
221,846

 
—

 
218,203

Net loss
 
$
(71,432
)
 
$
(397,034
)
 
$
(251,803
)
 
$
(397,506
)
During the year ended December 31, 2015, we recorded a valuation allowance against our net deferred tax asset due to uncertainties in the timing of the realization of our deferred tax assets. Because of continued uncertainties in the oil and gas markets, we recorded an additional valuation allowance of $83.7 million during the six months ended June 30, 2016. Due to the recording of these valuation allowances, our effective rates for the current year are not comparable to prior years. For the three and six months ended June 30, 2015, our effective tax rate was 36% and 35%, respectively. 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 and six months ended June 30, 2016 and 2015, certain shares related to restricted stock awards vested at times when our stock price was lower than the fair value of those shares on the grant date. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three and six months ended June 30, 2016, certain stock options were exercised, for which the income tax deduction related to the options' intrinsic value is less than the expense previously recognized for book purposes. There were no stock options exercised during the three and six months ended June 30, 2015. As a result of these differences in book compensation expense and related tax deduction, the tax impact of these shortfalls decreased by $0.2 million and increased by $1.2 million for the three and six months ended June 30, 2016 compared to the same periods in 2015.

48


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 June 30, 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 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 June 30,
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
 
2016
 
2015
Natural gas sales
 
$
—

 
$
221

 
$
—

 
$
333

Midstream service revenues
 
11,138

 
4,362

 
22,405

 
8,045

Sales of purchased oil
 
42,615

 
55,051

 
74,229

 
86,318

Total revenues
 
53,753

 
59,634

 
96,634

 
94,696

Midstream service expenses, including minimum volume commitments
 
6,572

 
998

 
13,081

 
4,340

Costs of purchased oil
 
44,012

 
54,417

 
76,958

 
85,617

General and administrative(1)
 
1,684

 
1,861

 
3,456

 
3,938

Depreciation and amortization(2)
 
2,208

 
2,125

 
4,394

 
3,810

Other operating costs and expenses(3)
 
54

 
45

 
106

 
353

Operating income (loss)
 
$
(777
)
 
$
188

 
$
(1,361
)
 
$
(3,362
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
3,696

 
$
2,914

 
$
5,994

 
$
2,481

Interest expense(4)
 
$
(1,462
)
 
$
(1,125
)
 
$
(2,864
)
 
$
(2,452
)
Loss on early redemption of debt(5)
 
$
—

 
$
(1,481
)
 
$
—

 
$
(1,481
)
_______________________________________________________________________________
(1)
G&A expense was allocated based on the number of employees in the midstream and marketing segment as of June 30, 2016 and 2015. Certain components of G&A expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.
(2)
Depreciation and amortization were actual expenses for the midstream and marketing segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the midstream and marketing segment as of June 30, 2016 and 2015.
(3)
Other operating costs and expenses consist of accretion of asset retirement obligations for the three and six months ended June 30, 2016 and 2015 and restructuring expense and impairment for the six months ended June 30, 2015. These are actual costs and expenses and were 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 as of June 30, 2016 and 2015.
(5)
Loss on early redemption of debt 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 as of June 30, 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 $6.8 million and $14.4 million for the three and six months ended June 30, 2016, respectively, compared to the same periods 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 periods.

49


Sales of purchased oil. Sales of purchased oil decreased by $12.4 million and $12.1 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. We purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it 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 $5.6 million and $8.7 million for the three and six months ended June 30, 2016 compared to the same periods 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 decreased by $10.4 million and $8.7 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.
G&A. Our consolidated G&A expense has decreased for the three and six months ended June 30, 2016 compared to the same periods in 2015. See "—Results of operations consolidated" for a discussion of these costs.
Depreciation and amortization. Depreciation and amortization increased by $0.1 million and $0.6 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the continued expansion of our midstream service infrastructure.
Income 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 reflected in the unaudited consolidated statements of operations as "Income 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 $0.3 million and $0.4 million for three and six months ended June 30, 2016, respectively, compared to the same periods 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 in addition to increasing our capital contributions to Medallion compared to prior periods, thereby increasing the interest expense that is allocated to this segment. These increases are slightly offset by significant decreases in our consolidated interest expense. See "—Results of operations consolidated" for a discussion of these decreases.
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 August 2, 2016, we had $745.0 million available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to implement our planned

50


exploration and development activities. We use derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. As of August 3, 2016, approximately 95% of our anticipated oil production for the last six months of 2016 is hedged at a weighted-average floor price of $67.13 per Bbl and approximately 65% of our anticipated natural gas production for the last six months of 2016 is hedged at a weighted-average floor price of $3.00 per MMBtu.
The following table summarizes our hedge positions that were in place as of August 3, 2016 for the calender years presented:
 
 
Remaining year
2016
 
Year
2017
 
Year
2018
Oil positions:(1)(2)
 
 

 
 
 
 

Total volume hedged with floor price (Bbl)
 
3,722,700

 
5,684,875

 
2,144,375

Weighted-average floor price ($/Bbl)
 
$
67.13

 
$
57.01

 
$
55.98

NGL positions:(1)(3)
 
 
 
 
 
 
Total volume hedged with floor price (Bbl)
 
—

 
819,000

 
—

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

 
$
16.28

 
$
—

Natural gas positions:(4)
 
 

 
 

 
 

Total volume hedged with floor price (MMBtu)
 
9,384,000

 
18,771,000

 
12,855,500

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

 
$
2.65

 
$
2.50

_______________________________________________________________________________
(1)
Includes derivatives entered into subsequent to June 30, 2016.
(2)
Oil derivatives are settled based on the WTI NYMEX index oil prices.
(3)
NGL derivatives are settled based on the Mont Belvieu-OPIS prices.
(4)
Natural gas derivatives are settled based on the Inside FERC index prices for West Texas Waha.
The following table presents a projection of estimated cash received in future periods from oil, NGL and natural gas derivative contracts in place as of June 30, 2016 adjusted for any new hedge transactions entered into between July 1, 2016 and August 3, 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, NGL and natural gas hedge cash proceeds(1)
 
$
88,005

 
$
77,513

 
$
23,977

_______________________________________________________________________________
(1)
For this illustration we utilized the July 26, 2016 (i) WTI index oil spot price of $42.92 per Bbl, (ii) Mont Belvieu Purity Ethane-OPIS spot price of $7.77 (converted to $/Bbl), (iii) Mont Belvieu Propane (TET)-OPIS spot price of $19.24 (converted to $/Bbl) and (iv) Waha natural gas spot price of $2.65 per MMBtu. Prices used were 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 for 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.
On May 16, 2016, we completed the sale of 10,925,000 shares of Laredo's common stock for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses.

51


As of June 30, 2016, we had $110.3 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. We had $704.7 million available for borrowings under our Senior Secured Credit Facility and $19.3 million in cash on hand for total available liquidity of $724.0 million as of June 30, 2016.
Subsequent to June 30, 2016, we completed the sale of 13,000,000 shares of Laredo's common stock for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses, which were used to repay borrowings under our Senior Secured Credit Facility. We granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds of $20.5 million, after underwriting discounts, commissions and offering expenses.
As of August 2, 2016, we had $1.4 billion in debt outstanding, $745.0 million available for borrowings under our Senior Secured Credit Facility and $14.6 million in cash on hand for total available liquidity of $759.6 million. A continued decline in oil and natural gas prices will negatively impact our future borrowing base redeterminations.
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:
 
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
Net cash provided by operating activities
 
$
138,631

 
$
114,305

Net cash used in investing activities
 
(243,630
)
 
(429,646
)
Net cash provided by financing activities
 
93,154

 
343,613

Net (decrease) increase in cash and cash equivalents
 
$
(11,845
)
 
$
28,272

Cash flows provided by operating activities
Net cash provided by operating activities was $138.6 million and $114.3 million for the six months ended June 30, 2016 and 2015, respectively. The increase of $24.3 million during the six months ended June 30, 2016 compared to the same period in 2015 was largely due to the price-related decrease in oil, NGL and natural gas revenue during 2015; however, notable cash flow changes consist of (i) a decrease in impairment expense of $328.5 million, (ii) a decrease in depletion, depreciation and amortization expense of $68.4 million, (iii) an increase in loss on derivatives, net of $49.9 million, (iv) an increase in working capital changes of $47.9 million and (v) a decrease of $31.5 million related to our loss on the early redemption of our January 2019 Notes.
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 $243.6 million and $429.6 million for the six months ended June 30, 2016 and 2015, respectively. The decrease of $186.0 million is mainly attributable to a $177.5 million decrease in capital expenditures for oil and natural gas properties and a $30.7 million decrease in capital expenditures for midstream service assets. These changes partially offset by a $28.2 million increase in investment in our equity method investee.

52


Our cash used in investing activities for the periods presented is summarized in the table below:
 
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
Capital expenditures:
 
 
 
 
Oil and natural gas properties
 
$
(197,042
)
 
$
(374,508
)
Midstream service assets
 
(3,425
)
 
(34,137
)
Other fixed assets
 
(832
)
 
(6,541
)
Investment in equity method investee
 
(42,681
)
 
(14,495
)
Proceeds from dispositions of capital assets, net of costs
 
350

 
35

Net cash used in investing activities
 
$
(243,630
)
 
$
(429,646
)
Capital expenditure budget
On May 10, 2016, our board of directors approved an increase to the capital expenditure budget of approximately $75.0 million. Our revised capital expenditure budget is $420.0 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 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 was $93.2 million and $343.6 million for the six months ended June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility and proceeds from our May 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility. For the six months ended June 30, 2015, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility, 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 and redemption of our January 2019 Notes.
Our cash provided by financing activities for the periods presented is summarized in the table below:
 
 
Six months ended June 30,
(in thousands)
 
2016
 
2015
Borrowings on Senior Secured Credit Facility
 
$
120,000

 
$
300,000

Payments on Senior Secured Credit Facility
 
(144,682
)
 
(475,000
)
Issuance of March 2023 Notes
 
—

 
350,000

Redemption of January 2019 Notes
 
—

 
(576,200
)
Proceeds from issuance of common stock, net of offering costs
 
119,310

 
754,163

Purchase of treasury stock
 
(1,541
)
 
(2,591
)
Proceeds from exercise of employee stock options
 
67

 
—

Payments for debt issuance costs
 
—

 
(6,759
)
Net cash provided by financing activities
 
$
93,154

 
$
343,613

Debt
As of June 30, 2016, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

53


Senior Secured Credit Facility. As of June 30, 2016, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million and $110.3 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.
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 covenants as of June 30, 2016 and expect to be in compliance with them for the foreseeable future.
Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of June 30, 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 August 2, 2016, we had a total of $1.3 billion of senior unsecured notes outstanding and $70.0 million outstanding on the Senior Secured Credit Facility.
Obligations and commitments
As of June 30, 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 and office and equipment leases. From December 31, 2015 to June 30, 2016, the material changes in our contractual obligations included (i) a decrease of $42.0 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January, March and May of 2016, (ii) a decrease of $27.6 million in our outstanding capital contribution commitment to our equity method investee due to payments made to Medallion during first-quarter 2016, (iii) a decrease of $25.5 million in our firm sale and transportation commitments, (iv) a decrease of $24.7 million outstanding on our Senior Secured Credit Facility, (v) a decrease of $7.3 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.

54


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 on early terminated 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;
•
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.

55


The following presents a reconciliation of Net loss (GAAP) to Adjusted EBITDA (non-GAAP):
 
 
Three months ended June 30,

Six months ended June 30,
(in thousands)
 
2016

2015

2016

2015
Net loss
 
$
(71,432
)

$
(397,034
)

$
(251,803
)

$
(397,506
)
Plus:
 






 


 

Deferred income tax benefit
 
—


(221,846
)

—


(218,203
)
Depletion, depreciation and amortization
 
34,177


72,112


75,655


144,054

Impairment expense

963


489,599


162,027


490,477

Non-cash stock-based compensation, net of amounts capitalized
 
6,073


6,268


9,911


11,056

Restructuring expenses
 
—

 
—

 
—

 
6,042

Mark-to-market on derivatives:
 
 
 
 
 
 
 
 
Loss on derivatives, net

68,518


63,899


50,633


744

Cash settlements received for matured derivatives, net

47,382


46,596


113,319


109,737

Cash settlements received for early terminations of derivatives, net

—


—


80,000


—

Premiums paid for derivatives
 
(2,413
)

(1,249
)

(84,263
)

(2,670
)
Interest expense
 
23,512


23,970


47,217


56,384

Write-off of debt issuance costs
 
842

 
—

 
842

 
—

Loss on disposal of assets, net

141


1,081


301


1,843

Loss on early redemption of debt
 
—

 
31,537

 
—

 
31,537

Buyout of minimum volume commitment
 
—

 
3,014

 
—

 
3,014

Adjusted EBITDA
 
$
107,763


$
117,947


$
203,839


$
236,509

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, NGL 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 six months ended June 30, 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.
Recent accounting pronouncements
See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.

56


Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, a drilling contract commitment 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.

57


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 June 30, 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
 
$
80,867

 
$
158,740

As of June 30, 2016 and December 31, 2015, the fair values of our open derivative contracts were $116.4 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 June 30, 2016, we had $110.3 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 June 30, 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
 
$
110.3

 
$
—

 
$
—

 
$
110.3

Average interest rate
 
2.000
%
 
—
%
 
—
%
 
2.000
%
Counterparty and customer credit risk
As of June 30, 2016, our principal exposures to credit risk are through receivables of (i) $121.6 million from the fair values of our open derivative contracts, (ii) $42.6 million from the sale of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (iii) $18.4 million from joint-interest partners, (iv) $15.0 million from sales of purchased oil and other products and (v) $12.2 million from matured derivatives.
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

58


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.

59


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 June 30, 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 June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

60


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
April 1, 2016 - April 30, 2016
 
5,228

 
$
9.38

 
—

 
—

May 1, 2016 - May 31, 2016
 
1,360

 
$
12.07

 
—

 
—

June 1, 2016 - June 30, 2016
 
5,099

 
$
12.28

 
—

 
—

Total
 
11,687

 
 
 
 
 
 
______________________________________________________________________________
(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.

61


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 United Kingdom ("UK") who are currently designated by the United States ("US") under the Specially Designated Global Terrorist ("SDGT") sanctions program. The accounts held by each customer were blocked after the customer’s designation and have remained blocked and dormant through the first half of 2016. Revenue generated by Santander UK on these accounts in the first half of 2016 was £7.31 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.
(b) An Iranian national, resident in the UK, who is currently designated by the US under the Iranian Financial Sanctions Regulations ("IFSR") and the Weapons of Mass Destruction Proliferators Sanctions Regulations, held a mortgage with Santander UK that was issued prior to any such designation. The mortgage account was redeemed and closed on April 13, 2016. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continued to receive repayment installments prior to redemption. In the first half of 2016, total revenue generated by Santander UK in connection with the mortgage was £434.64 whilst net profits were negligible relative to the overall profits of Banco Santander SA. 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 held two investment accounts with Santander ISA Managers Limited. The funds within both accounts were invested in the same portfolio fund. The accounts remained frozen until the investments were closed on May 12, 2016 and checks issued to customer on May 13, 2016. Total revenue in the first half of 2016 generated by Santander UK in connection with the investment accounts was £7.60 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.
(c) A UK national designated by the US under the SDGT sanctions program holds a Santander UK current account. The account remained in arrears through the first half of 2016 (£1,344.01 in debit) and is currently being managed by Santander UK Collections & Recoveries department.
(d) In addition, during the first half 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 US under the SDGT and IFSR sanctions programs. During the first half of 2016, related revenue generated by Santander UK was £129.21 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.




62


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#

 
Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of March 30, 2016 (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.2#

 
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.3#

 
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.4#

 
Form of Performance Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
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.
#     Management Contract



63


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: August 4, 2016
By:
/s/ Randy A. Foutch
 
 
Randy A. Foutch
 
 
Chairman and Chief Executive Officer
 
 
(principal executive officer)
 
 
 
Date: August 4, 2016
By:
/s/ Richard C. Buterbaugh
 
 
Richard C. Buterbaugh
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 
 
 
 
By:
 
Date: August 4, 2016
By:
/s/ Michael T. Beyer
 
 
Michael T. Beyer
 
 
Vice President - Controller and Chief Accounting Officer
 
 
(principal accounting officer)
 
 
 
 
 
 

64


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#

 
Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of March 30, 2016 (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.2#

 
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.3#

 
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
10.4#

 
Form of Performance Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
 
 
 
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.
#     Management Contract



65