Annual Statements Open main menu
  1. Annual Statements
  2. » Companies
  3. » Vital Energy, Inc.
  4. » Quarter Report: 2019 March (Form 10-Q)

Vital Energy, Inc. - Quarter Report: 2019 March (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 March 31, 2019
 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)
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class
Trading symbol
Name of each exchange on which registered
Common stock, $0.01 par value
LPI
New York Stock Exchange ("NYSE")
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, if any, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one): 
Large accelerated filer ý
Accelerated filer o
 
 
Non-accelerated filer o
Smaller reporting company o
 
 
Emerging growth company o
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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 April 29, 2019: 236,555,114


LAREDO PETROLEUM, INC.
TABLE OF CONTENTS
 
Page
 

ii
Table of Contents

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, natural gas liquids ("NGL") and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:
•
the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian Basin;
•
our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves;
•
changes in domestic and global production, supply and demand for oil, NGL and natural gas;
•
revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
•
the long-term performance of wells that were completed using different technologies;
•
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;
•
the potential impact on production of oil, NGL and natural gas from our wells due to tighter spacing of our wells;
•
capital requirements for our operations and projects;
•
impacts to our financial statements as a result of impairment write-downs;
•
the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services;
•
the availability and costs of sufficient pipeline and transportation facilities and gathering and processing capacity;
•
our ability to maintain the borrowing capacity under our Fifth Amended and Restated     Senior Secured Credit Facility (as amended, the "Senior Secured Credit Facility") or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;
•
our 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 generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;
•
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 recruit and retain the qualified personnel necessary to operate our business;
•
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;
•
risks related to the geographic concentration of our assets;
•
our ability to hedge and regulations that affect our ability to hedge;
•
changes in the regulatory environment and changes in United States or international legal, tax, political, administrative or economic conditions, including regulations that prohibit or restrict our

iii
Table of Contents

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;
•
competition in the oil and natural gas industry;
•
drilling and operating risks, including risks related to hydraulic fracturing activities; and
•
our ability to comply with federal, state and local regulatory requirements.
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, 2018 (the "2018 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
Table of Contents

Part I

Item 1.    Consolidated Financial Statements (Unaudited)


Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
 
 
March 31, 2019

December 31, 2018
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
44,544

 
$
45,151

Accounts receivable, net
 
107,520

 
94,321

Derivatives
 
7,610

 
39,835

Other current assets
 
13,056

 
13,445

Total current assets
 
172,730

 
192,752

Property and equipment:
 
 
 
 

Oil and natural gas properties, full cost method:
 
 
 
 

Evaluated properties
 
6,951,343

 
6,752,631

Unevaluated properties not being depleted
 
92,467

 
130,957

Less accumulated depletion and impairment
 
(4,913,384
)
 
(4,854,017
)
Oil and natural gas properties, net
 
2,130,426

 
2,029,571

Midstream service assets, net
 
131,118

 
130,245

Other fixed assets, net
 
39,098

 
39,819

Property and equipment, net
 
2,300,642

 
2,199,635

Derivatives
 
5,970

 
11,030

Operating lease right-of-use assets
 
19,035

 
—

Other noncurrent assets, net
 
16,412

 
16,888

Total assets
 
$
2,514,789

 
$
2,420,305

Liabilities and stockholders' equity
 
 
 
 

Current liabilities:
 
 
 
 

Accounts payable and accrued liabilities
 
$
76,644

 
$
69,504

Accrued capital expenditures
 
36,418

 
29,975

Undistributed revenue and royalties
 
51,730

 
48,841

Derivatives
 
11,057

 
7,359

Operating lease liabilities
 
10,896

 
—

Other current liabilities
 
16,877

 
44,786

Total current liabilities
 
203,622

 
200,465

Long-term debt, net
 
1,064,081

 
983,636

Derivatives
 
3,563

 
—

Asset retirement obligations
 
54,555

 
53,387

Operating lease liabilities
 
11,301

 
—

Other noncurrent liabilities
 
6,235

 
8,587

Total liabilities
 
1,343,357

 
1,246,075

Commitments and contingencies
 


 


Stockholders' equity:
 
 
 
 
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2019 and December 31, 2018
 
—

 
—

Common stock, $0.01 par value, 450,000,000 shares authorized and 239,191,487 and 233,936,358 issued and outstanding as of March 31, 2019 and December 31, 2018, respectively
 
2,392

 
2,339

Additional paid-in capital
 
2,381,926

 
2,375,286

Accumulated deficit
 
(1,212,886
)
 
(1,203,395
)
Total stockholders' equity
 
1,171,432

 
1,174,230

Total liabilities and stockholders' equity
 
$
2,514,789

 
$
2,420,305


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

1
Table of Contents

Laredo Petroleum, Inc.
Consolidated statements of operations
(in thousands, except per share data)
(Unaudited)
 
 
Three months ended March 31,
 
 
2019
 
2018
Revenues:






Oil sales

$
129,171


$
150,914

NGL sales
 
32,235

 
28,360

Natural gas sales
 
11,970

 
18,160

Midstream service revenues

2,883


2,359

Sales of purchased oil
 
32,688

 
59,903

Total revenues

208,947


259,696

Costs and expenses:

 
 
 
Lease operating expenses

22,609


21,951

Production and ad valorem taxes
 
7,219

 
11,812

Transportation and marketing expenses
 
4,759

 
—

Midstream service expenses
 
1,603

 
693

Costs of purchased oil
 
32,691

 
60,664

General and administrative

21,519


24,725

Depletion, depreciation and amortization

63,098


45,553

Other operating expenses
 
1,052

 
1,106

Total costs and expenses

154,550


166,504

Operating income

54,397


93,192

Non-operating income (expense):




 
Gain (loss) on derivatives, net

(48,365
)

9,010

Interest expense

(15,547
)

(13,518
)
Loss on disposal of assets, net
 
(939
)
 
(2,617
)
Other income, net

867


453

Non-operating expense, net

(63,984
)

(6,672
)
Income (loss) before income taxes

(9,587
)

86,520

Income tax benefit:




 
Deferred

96


—

Total income tax benefit

96


—

Net income (loss)

$
(9,491
)
 
$
86,520

Net income (loss) per common share:




 
Basic

$
(0.04
)

$
0.36

Diluted

$
(0.04
)
 
$
0.36

Weighted-average common shares outstanding:






Basic

230,476


238,228

Diluted

230,476


239,319

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

2
Table of Contents

Laredo Petroleum, Inc.
Consolidated statements 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, 2018
 
233,936

 
$
2,339

 
$
2,375,286

 
—

 
$
—

 
$
(1,203,395
)
 
$
1,174,230

Restricted stock awards
 
5,986

 
60

 
(60
)
 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(48
)
 
—

 
—

 
—

 
—

 
—

 
—

Stock exchanged for tax withholding
 
—

 
—

 
—

 
683

 
(2,612
)
 
—

 
(2,612
)
Stock exchanged for cost of exercise of stock options
 
—

 
—

 
—

 
18

 
(76
)
 
—

 
(76
)
Retirement of treasury stock
 
(701
)
 
(7
)
 
(2,681
)
 
(701
)
 
2,688

 
—

 
—

Exercise of stock options
 
18

 
—

 
76

 
—

 
—

 
—

 
76

Stock-based compensation
 
—

 
—

 
9,305

 
—

 
—

 
—

 
9,305

Net loss
 
—

 
—

 
—

 
—

 
—

 
(9,491
)
 
(9,491
)
Balance, March 31, 2019
 
239,191

 
$
2,392

 
$
2,381,926

 
—

 
$
—

 
$
(1,212,886
)
 
$
1,171,432

 
 
 
Common Stock
 
Additional
paid-in capital
 
Treasury Stock
(at cost)
 
Accumulated deficit
 
 
 
 
Shares
 
Amount
 
 
Shares
 
Amount
 
 
Total
Balance, December 31, 2017
 
242,521

 
$
2,425

 
$
2,432,262

 
—

 
$
—

 
$
(1,669,108
)
 
$
765,579

Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 13.a)
 
—

 
—

 
—

 
—

 
—

 
141,118

 
141,118

Restricted stock awards
 
3,052

 
30

 
(30
)
 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(13
)
 
—

 
—

 
—

 
—

 
—

 
—

Share repurchases
 
—

 
—

 
—

 
6,728

 
(58,475
)
 
—

 
(58,475
)
Stock exchanged for tax withholding
 
—

 
—

 
—

 
512

 
(4,353
)
 
—

 
(4,353
)
Retirement of treasury stock
 
(7,240
)
 
(72
)
 
(62,756
)
 
(7,240
)
 
62,828

 
—

 
—

Stock-based compensation
 
—

 
—

 
11,441

 
—

 
—

 
—

 
11,441

Net income
 
—

 
—

 
—

 
—

 
—

 
86,520

 
86,520

Balance, March 31, 2018
 
238,320

 
$
2,383

 
$
2,380,917

 
—

 
$
—

 
$
(1,441,470
)
 
$
941,830


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

3
Table of Contents

Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
(Unaudited)
 
 
Three months ended March 31,
 
 
2019
 
2018
Cash flows from operating activities:

 


 

Net income (loss)

$
(9,491
)

$
86,520

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






Deferred income tax benefit

(96
)

—

Depletion, depreciation and amortization

63,098


45,553

Non-cash stock-based compensation, net

7,406


9,339

Mark-to-market on derivatives:






(Gain) loss on derivatives, net

48,365


(9,010
)
Settlements received (paid) for matured derivatives, net

102


(2,236
)
Change in net present value of derivative deferred premiums

95


211

Premiums paid for derivatives

(4,016
)

(4,024
)
Amortization of debt issuance costs

846


793

Amortization of operating lease right-of-use assets
 
3,056

 
—

Other, net

3,779


4,304

(Increase) decrease in accounts receivable
 
(13,373
)
 
1,147

Increase in other current assets
 
(2,769
)
 
(2,483
)
Decrease (increase) in other noncurrent assets
 
57

 
(100
)
Increase in accounts payable and accrued liabilities
 
7,140

 
30,516

Increase in undistributed revenue and royalties
 
2,889

 
2,541

Decrease in other current liabilities
 
(30,637
)
 
(16,226
)
Increase (decrease) in other noncurrent liabilities
 
1,007

 
(374
)
Net cash provided by operating activities
 
77,458

 
146,471

Cash flows from investing activities:






Capital expenditures:






Oil and natural gas properties

(152,729
)

(195,025
)
Midstream service assets

(2,262
)

(3,362
)
Other fixed assets

(505
)

(3,963
)
Proceeds from disposition of equity method investee, net of selling costs
 
—

 
1,655

Proceeds from dispositions of capital assets, net of selling costs

43


1,021

Net cash used in investing activities

(155,453
)

(199,674
)
Cash flows from financing activities:






Borrowings on Senior Secured Credit Facility

80,000


55,000

Share repurchases
 
—

 
(53,714
)
Stock exchanged for tax withholding

(2,612
)

(4,353
)
Net cash provided by (used in) financing activities

77,388


(3,067
)
Net decrease in cash and cash equivalents

(607
)

(56,270
)
Cash and cash equivalents, beginning of period

45,151


112,159

Cash and cash equivalents, end of period

$
44,544


$
55,889

 
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 and basis of presentation
a.    Organization
Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned 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 midstream and marketing services, primarily in the Permian Basin of 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.
b.    Basis of presentation
The 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 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 unaudited 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, 2018 is derived from audited consolidated financial statements. In the opinion of management, the unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of March 31, 2019 and results of operations and cash flows for each of the three months ended March 31, 2019 and 2018.
Certain disclosures have been condensed or omitted from the unaudited consolidated financial statements. Accordingly, the unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2018 Annual Report.
Significant accounting policies
See Note 2 in the 2018 Annual Report for discussion of significant accounting policies and Note 3 for those related to the adoption of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 842, Leases ("ASC 842").
Use of estimates in the preparation of interim unaudited consolidated financial statements
The preparation of the 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.
For further information regarding the use of estimates and assumptions, see Note 2.b in the 2018 Annual Report, Note 3 pertaining to the Company's leases and Note 6.c pertaining to the Company's 2019 performance unit awards.
Note 2—Recently issued or adopted accounting pronouncements
The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the FASB. The discussion of the ASU listed below was determined to be meaningful to the Company's unaudited consolidated financial statements and footnotes during the three months ended March 31, 2019.    
a.    Leases
On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach and applying the optional transition method as of the beginning of the period of adoption. Results for the period beginning after January 1, 2019 are presented under ASC 842, while prior periods are not adjusted and continue to be reported under ASC 840. The Company utilized the transition package of expedients to leases that commenced before the effective date. ASC 842 supersedes previous lease guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term related to its leases. For leases with a term of 12 months or less, a lessee is permitted to make

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


an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. See Note 3 for further discussion of the ASC 842 adoption impact on the Company's unaudited consolidated financial statements.
Note 3—Leases
a.    Impact of ASC 842 adoption
Prior to January 1, 2019, the Company accounted for leases under ASC 840 and did not record any right-of-use assets or corresponding lease liabilities. Upon the adoption of ASC 842 on January 1, 2019, the Company recognized $22.1 million in operating lease right-of-use assets and $25.3 million in operating lease liabilities on the unaudited consolidated balance sheets for operating leases with a term greater than 12 months. The difference between the two balances of $3.2 million is mainly due to free rent and lease build-out incentives that were recorded as deferred lease liabilities under ASC 840. These deferred lease liabilities are subtracted from the right-of-use asset opening balance under ASC 842. The transition did not result in a material impact to the unaudited consolidated statements of operations nor was there a related impact to the unaudited consolidated statements of stockholders' equity.
The Company utilized the modified retrospective approach in adopting the new standard and applied the optional transition method as of the beginning of the period of adoption, along with the transition package of practical expedients, and implemented certain accounting policy decisions which include: (i) short-term lease recognition exemption, (ii) establishing a balance sheet recognition capitalization threshold, (iii) not evaluating existing or expired land easements that were not previously accounted for as leases under ASC 840 and (iv) accounting for certain asset classes at a portfolio level by not separating the lease and non-lease components and accounting for the agreement as a single lease component.
The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company's leases do not provide a readily determinable implicit rate, In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company determines its IBR using both a "credit notching" approach and a "recovery method" approach. The results of these approaches are then weighted equally and averaged in order to determine the concluded IBR. This concluded IBR is utilized to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees, nor any restrictions or covenants included in the Company's lease agreements.
Mineral leases, including oil and natural gas leases granting the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not included in the scope of ASC 842.
The Company has recognized in the unaudited consolidated balance sheets leases of commercial real estate with lease terms extending through 2027 and drilling, completion, production and other equipment leases with lease terms extending through 2020. We have various other drilling, completion and production equipment leases on a short-term basis reflected in our short-term lease costs.
Certain of the Company's leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput, actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets. For our drilling rigs, the variable lease costs include the payments that depend on the performance or usage of the underlying asset, the costs to move and the costs to repair the drilling rigs. For certain of our commercial office buildings, utilities and common area maintenance charges are variable and are included as an operating lease expense. For our equipment leases, the variable lease cost is the amount incurred under our contracts that are beyond the minimum rental fee, inclusive of maintenance.
The Company's short-term lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of March 31, 2019, the Company had an average working interest of 97% in all Laredo-operated currently producing wells in its core operating area.
The Company does not have any significant finance leases.
Certain of the Company's lease asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based, and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities.

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


The Company's material leases do not include options to purchase the leased property.
Of the Company's commercial leases, the Company subleases certain office space to third parties where it is the primary obligor under the head lease. The lease terms on those subleases each contain renewal options that do not extend past the term of the head lease. The subleases do not contain residual value guarantees. Sublease income is recognized based on the contract terms and, upon the adoption of ASC 842, is included as a reduction of lease expense under our head lease.
Lease costs
The table below presents certain information related to the lease costs for the Company's operating leases for the period presented:
(in thousands)
 
Three months ended March 31, 2019
Components of total lease cost:
 
 
Operating lease cost
 
$
3,528

Short-term lease cost
 
46,326

Variable lease cost
 
518

Sublease income
 
(247
)
Total lease cost
 
$
50,125


Other information
See Note 11 for disclosure of cash paid for amounts included in the measurement of lease liabilities and supplemental non-cash adjustments. See Note 15 for disclosure of related-party lease amounts.
Lease terms and discount rates
The table below presents certain information related to the weighted-average remaining lease term and weighted-average discount rate for the Company's operating leases as of the date presented:
 
 
March 31, 2019
Operating leases:
 
 
Weighted-average remaining lease term
 
4.00 years

Weighted-average discount rate
 
8.28
%


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


Maturities of operating lease liabilities
The table below reconciles the undiscounted cash flows for each of the first five years and the total remaining years to the operating lease liabilities recorded on the unaudited consolidated balance sheet as of the date presented:
(in thousands)
 
March 31, 2019
Operating leases:
 
 
Remaining 2019
 
$
12,260

2020
 
3,331

2021
 
3,029

2022
 
2,360

2023
 
1,252

Thereafter
 
4,243

Total minimum lease payments
 
26,475

Less: lease liability expense
 
(4,278
)
Present value of future minimum lease payments
 
22,197

Less: current obligations under leases
 
(10,896
)
Long-term lease obligations
 
$
11,301


Disclosure for the period prior to adoption of ASC 842    
The Company leases office space under operating leases expiring on various dates through 2027. The following table presents future minimum rental payments required:
(in thousands)
 
December 31, 2018
2019
 
$
3,092

2020
 
3,179

2021
 
3,128

2022
 
2,560

2023
 
1,358

Thereafter
 
4,556

  Total future minimum rental payments required
 
$
17,873


The Company subleases office space with $5.9 million of total future minimum rentals to be received as of December 31, 2018. For the period prior to the adoption of ASC 842, rent income is included in "Other income, net" on the unaudited consolidated statements of operations.

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


Note 4—Property and equipment
The following table presents the Company's property and equipment as of the dates presented:
(in thousands)
 
March 31, 2019
 
December 31, 2018
Evaluated oil and natural gas properties
 
$
6,951,343

 
$
6,752,631

Less accumulated depletion and impairment
 
(4,913,384
)
 
(4,854,017
)
Evaluated oil and natural gas properties, net
 
2,037,959

 
1,898,614

 
 
 
 
 
Unevaluated oil and natural gas properties not being depleted
 
92,467

 
130,957

 
 
 
 
 
Midstream service assets
 
175,681

 
172,308

Less accumulated depreciation and impairment
 
(44,563
)
 
(42,063
)
Midstream service assets, net
 
131,118

 
130,245

 
 
 
 
 
Depreciable other fixed assets
 
45,591

 
45,431

Less accumulated depreciation and amortization
 
(24,752
)
 
(23,871
)
Depreciable other fixed assets, net
 
20,839

 
21,560

 
 
 
 
 
Land
 
18,259

 
18,259

 
 
 
 
 
Total property and equipment, net
 
$
2,300,642

 
$
2,199,635


For the three months ended March 31, 2019 and 2018, depletion expense for the Company's evaluated oil and natural gas properties was $8.76 per barrel of oil equivalent ("BOE") sold and $7.34 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 exploring for or developing oil and natural gas properties, 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 following table presents capitalized related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Capitalized related employee costs
 
$
6,682

 
$
6,529


The Company excludes the costs directly associated with the 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 to 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 properties are assessed on a quarterly basis for possible impairment. 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.
    

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


The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in development costs, for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Property acquisition costs:
 
 

 
 

Evaluated
 
$
—

 
$
—

Unevaluated
 
—

 
—

Exploration costs
 
7,505

 
6,137

Development costs
 
152,717

 
149,038

Total costs incurred
 
$
160,222

 
$
155,175


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"). The Company may redeem, at its option, all or part of the March 2023 Notes at any time at a price of 103.125% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption.
b.    January 2022 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The Company may redeem, at its option, all or part of the January 2022 Notes at any time at a price of 101.406% of face value with call premiums declining to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption.
c.    Senior Secured Credit Facility
The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of March 31, 2019, the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion, a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion, with $270.0 million outstanding and was subject to an interest rate of 3.75%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of March 31, 2019 and December 31, 2018, the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility. For additional information see Note 7.d in the 2018 Annual Report. See Note 17.a for discussion of the regular semi-annual borrowing base redetermination of the Senior Secured Credit Facility subsequent to March 31, 2019.

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


d.    Long-term debt, net
The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented:
 
 
March 31, 2019
 
December 31, 2018
(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

 
$
(2,766
)
 
$
447,234

 
$
450,000

 
$
(3,010
)
 
$
446,990

March 2023 Notes
 
350,000

 
(3,153
)
 
346,847

 
350,000

 
(3,354
)
 
346,646

Senior Secured Credit Facility(1)
 
270,000

 
—

 
270,000

 
190,000

 
—

 
190,000

Total
 
$
1,070,000

 
$
(5,919
)
 
$
1,064,081

 
$
990,000

 
$
(6,364
)
 
$
983,636

______________________________________________________________________________
(1)
Debt issuance costs, net related to our Senior Secured Credit Facility of $6.6 million and $7.0 million as of March 31, 2019 and December 31, 2018, respectively, are reported in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
Note 6—Stockholders' equity and Equity Incentive Plan
a.   Share repurchase program
In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the year ended December 31, 2018, the Company repurchased 11,048,742 shares of common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. There were no share repurchases under this program during the three months ended March 31, 2019.
b.   Treasury stock
Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result (i) from share repurchases under the share repurchase program, (ii) from the withholding of shares of stock to satisfy tax withholding obligations that arise upon the lapse of restrictions on restricted stock awards and the exercise of stock options at the awardee's election and (iii) share repurchases to cover the cost of the exercise of stock options at the awardee's election.
c.   Equity Incentive Plan
The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The Equity Incentive Plan provides for the issuance of up to 24,350,000 shares of Laredo's common stock. On March 20, 2019, the Company's compensation committee recommended, and the Company's board of directors adopted, subject to stockholder approval, an amendment (the "Second Amendment") to the Equity Incentive Plan to, among other things, increase the number of shares of common stock available for issuance under the Equity Incentive Plan by 5,500,000 shares, which would bring the total available shares to issue to 29,850,000. The Company is seeking stockholder approval of the Second Amendment at its 2019 Annual Meeting of Stockholders on May 16, 2019.
The Company recognizes the fair value of stock-based compensation awards and performance unit 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 awards and are included in "General and administrative" on the unaudited consolidated statements of operations. The Company's performance unit awards are accounted for as liability awards and are included in "General and administrative" on the unaudited consolidated statements of operations and the corresponding liabilities are included in "Other noncurrent liabilities" on the unaudited consolidated balance sheets. The Company capitalizes a portion of stock-based compensation and performance unit award compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation and performance unit award compensation is included in "Evaluated properties" on the unaudited consolidated balance sheets.

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


Restricted stock awards
All service vesting restricted stock awards are treated as issued and outstanding in the unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33%, 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Stock awards granted to non-employee directors vest immediately on the grant date.
The following table reflects the restricted stock award activity for the three months ended March 31, 2019:
(in thousands, except for weighted-average grant-date fair value)
 
Restricted
stock
awards
 
Weighted-average
grant-date fair value
(per award)
Outstanding as of December 31, 2018
 
4,196

 
$
9.91

Granted
 
5,986

 
$
3.43

Forfeited
 
(48
)
 
$
6.25

Vested(1)
 
(2,261
)
 
$
10.05

Outstanding as of March 31, 2019
 
7,873

 
$
4.96

_____________________________________________________________________________
(1)
The total intrinsic value of vested restricted stock awards for the three months ended March 31, 2019 was $8.6 million.
The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of March 31, 2019, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $34.3 million. Such cost is expected to be recognized over a weighted-average period of 2.34 years.
Stock option awards
Stock option awards granted under the Equity Incentive Plan vest and become exercisable in four equal installments on each of the four anniversaries of the grant date. As of March 31, 2019, the 2,466,022 outstanding stock option awards have a weighted-average exercise price of $12.64 per award and a weighted-average remaining contractual term of 3.05 years. There were de minimis exercises and expirations or cancellations of stock option awards during the three months ended March 31, 2019. There were no grants or forfeits of stock option awards during the three months ended March 31, 2019.
The Company utilizes the Black-Scholes option pricing model to determine the fair value of 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 expected volatility. As of March 31, 2019, unrecognized stock-based compensation related to stock option awards expected to vest was $3.0 million. Such cost is expected to be recognized over a weighted-average period of 1.35 years.
Performance share awards
Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include: (i) the relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation") and (iii) the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, which is the Company's three-year return on average capital employed ("ROACE Percentage"), the grant-date fair value is equal to the Company's closing stock price on the grant date, and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated probability of how many shares are to be awarded for the three-year performance period. Such estimated shares, if earned, are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria.    
    

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


The following table reflects the performance share award activity for the three months ended March 31, 2019:
(in thousands, except for weighted-average grant-date fair value)
 
Performance
share
awards
 
Weighted-average
grant-date fair value
(per award)
Outstanding as of December 31, 2018
 
3,436

 
$
13.74

Vested(1)
 
(1,503
)
 
$
17.68

Outstanding as of March 31, 2019
 
1,933

 
$
10.68

______________________________________________________________________________
(1)
The performance share awards granted on May 25, 2016 had a performance period of January 1, 2016 to December 31, 2018 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of 2019.
As of March 31, 2019, unrecognized stock-based compensation related to the performance share awards expected to vest was $9.1 million. Such cost is expected to be recognized over a weighted-average period of 1.56 years.
Stock-based compensation expense
The following has been recorded to stock-based compensation expense for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Restricted stock award compensation
 
$
5,323

 
$
6,045

Stock option award compensation
 
818

 
1,069

Performance share award compensation
 
3,164

 
4,327

Total stock-based compensation, gross
 
9,305

 
11,441

Less amounts capitalized in evaluated oil and natural gas properties
 
(1,899
)
 
(2,102
)
Total stock-based compensation, net
 
$
7,406

 
$
9,339


See Note 17.d for discussion of the Company's workforce reduction subsequent to March 31, 2019.
Performance unit awards
Performance unit awards, which the Company has determined are liability awards, are subject to a combination of market, performance and service vesting criteria and can be settled in cash, stock or a combination of cash and stock at the election of the Company's board of directors. For portions of awards with market criteria, which include the RTSR Performance Percentage (as defined above) and the ATSR Appreciation (as defined above), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and is re-measured on the last day of each reporting period until settlement, with the associated expense adjusted, in accordance with GAAP. For portions of awards with performance criteria, which is the ROACE Percentage (as defined above), the grant-date fair value is equal to the Company's closing stock price on the grant date, and subsequently the fair value is equal to the Company's closing stock price on the last day of each reporting period until settlement, with the associated expense adjusted, in accordance with GAAP. Additionally, the associated expense related to awards with performance criteria fluctuates and is adjusted based on an estimated probability of payout that will be awarded for the three-year performance period as of the last day of each reporting period until settlement. The performance unit award compensation expense is recognized on a straight-line basis over the three-year requisite service period of the awards. These awards are accounted for as liability awards as the current election by the Company's board of directors is to settle the awards in cash, and if earned, are expected to be paid in the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria.
    

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


The following table reflects the performance unit award activity for the three months ended March 31, 2019:
(in thousands)
 
Performance unit awards
Outstanding as of December 31, 2018
 
—

Granted(1)
 
2,813

Outstanding as of March 31, 2019
 
2,813

______________________________________________________________________________
(1)
The amount potentially payable in cash at the end of the requisite service period for the performance unit awards granted on February 28, 2019 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit granted at the maturity date. In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. These awards have a performance period of January 1, 2019 to December 31, 2021.
As of March 31, 2019, unrecognized performance unit award compensation related to the performance unit awards expected to vest was $8.2 million. Such cost is expected to be recognized over a weighted-average period of 2.92 years.
The assumptions used to estimate the fair value of the performance unit awards as of the date presented are as follows:
 
 
March 31, 2019(1)
(.25) RTSR Factor + (.25) ATSR Factor fair value assumptions:
 
 
Remaining performance period
 
2.76 years

Risk-free interest rate(2)
 
2.20
%
Dividend yield
 
—
%
Expected volatility(3)
 
55.13
%
Closing stock price on March 29, 2019
 
$
3.09

Fair value per performance unit award (market criteria)
 
$
3.18

 
 
 
(.50) ROACE Factor fair value assumption:
 
 
Closing stock price on March 29, 2019
 
$
3.09

Fair value per performance unit award (performance criteria)
 
$
3.09

 
 
 
Combined fair value per performance unit award
 
$
3.14

______________________________________________________________________________
(1)
The $3.14 per unit fair value consists of a (i) $3.18 per unit fair value, determined utilizing a Monte Carlo simulation on March 31, 2019, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $3.09 per unit fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on March 29, 2019 and based on a 100% estimated probability of payout to be awarded for the three-year performance period as of March 31, 2019.
(2)
The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on March 29, 2019.
(3)
The Company utilized its own historical volatility in order to develop the expected volatility.




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


Performance unit award compensation expense
The following has been recorded to performance unit award compensation expense for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Performance unit award compensation, gross
 
$
238

 
$
—

Less amounts capitalized in evaluated oil and natural gas properties
 
(46
)
 
—

Total performance unit award compensation, net
 
$
192

 
$
—


Note 7—Derivatives
Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of the Company's anticipated production. By removing a 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. See Notes 2.f and 9 in the 2018 Annual Report for discussion of the Company's accounting policies for derivatives and information on the transaction types and settlement indexes, respectively.





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


The following table summarizes open derivative positions as of March 31, 2019, for derivatives that were entered into through March 31, 2019, for the settlement periods presented:
 
 
Remaining year 2019
 
Year 2020
 
Year 2021
Oil:
 
 
 
 

 
 
Puts:
 
 

 
 

 
 
Volume (Bbl)
 
6,050,000

 
366,000

 
—

Weighted-average floor price ($/Bbl)
 
$
47.45

 
$
45.00

 
$
—

Volume with deferred premium (Bbl)
 
3,575,000

 
—

 
—

Weighted-average deferred premium price ($/Bbl)
 
$
3.21

 
$
—

 
$
—

Swaps:
 
 

 
 

 
 
Volume (Bbl)
 
495,000

 
695,400

 
—

Weighted-average price ($/Bbl)
 
$
53.45

 
$
52.18

 
$
—

Collars:
 
 

 
 

 
 
Volume (Bbl)
 
—

 
1,134,600

 
912,500

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

 
$
45.00

 
$
45.00

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

 
$
76.13

 
$
71.00

Totals:
 
 
 
 
 
 
Total volume with floor price (Bbl)
 
6,545,000

 
2,196,000

 
912,500

Weighted-average floor price ($/Bbl)
 
$
47.91

 
$
47.27

 
$
45.00

Total volume with ceiling price (Bbl)
 
495,000

 
1,830,000

 
912,500

Weighted-average ceiling price ($/Bbl)
 
$
53.45

 
$
67.03

 
$
71.00

Basis Swaps:
 
 
 
 
 
 
WTI Midland to WTI NYMEX:
 
 
 
 
 
 
Volume (Bbl)
 
1,840,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(2.89
)
 
$
—

 
$
—

WTI Midland to WTI formula basis:
 
 
 
 
 
 
Volume (Bbl)
 
552,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(4.37
)
 
$
—

 
$
—

WTI Houston to WTI Midland:
 
 
 
 
 
 
Volume (Bbl)
 
910,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
7.30

 
$
—

 
$
—

NGL:
 
 
 
 
 
 
Swaps - Purity Ethane:
 
 
 
 
 
 
Volume (Bbl)
 
1,787,500

 
366,000

 
912,500

Weighted-average price ($/Bbl)
 
$
14.22

 
$
13.60

 
$
12.01

Swaps - Non-TET Propane:
 
 
 
 
 
 
Volume (Bbl)
 
1,430,000

 
1,244,400

 
730,000

Weighted-average price ($/Bbl)
 
$
27.97

 
$
26.58

 
$
25.52

Swaps - Non-TET Normal Butane:
 
 
 
 
 
 
Volume (Bbl)
 
550,000

 
439,200

 
255,500

Weighted-average price ($/Bbl)
 
$
30.73

 
$
28.69

 
$
27.72

Swaps - Non-TET Isobutane:
 
 
 
 
 
 
Volume (Bbl)
 
137,500

 
109,800

 
67,525

Weighted-average price ($/Bbl)
 
$
31.08

 
$
29.99

 
$
28.79

Swaps - Non-TET Natural Gasoline:
 
 
 
 
 
 
Volume (Bbl)
 
467,500

 
402,600

 
237,250

Weighted-average price ($/Bbl)
 
$
45.80

 
$
45.15

 
$
44.31

TABLE CONTINUES ON NEXT PAGE
 
 
 
 
 
 


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


 
 
Remaining year 2019
 
Year 2020
 
Year 2021
Total NGL volume (Bbl)
 
4,372,500

 
2,562,000

 
2,202,775

Natural gas:
 
 

 
 

 
 
Henry Hub NYMEX Swaps:
 
 

 
 

 
 
Volume (MMBtu)
 
29,425,000

 
23,790,000

 
14,052,500

Weighted-average price ($/MMBtu)
 
$
3.09

 
$
2.72

 
$
2.63

Basis Swaps:
 
 

 
 

 
 
Volume (MMBtu)
 
29,425,000

 
32,574,000

 
23,360,000

Weighted-average price ($/MMBtu)
 
$
(1.51
)
 
$
(0.76
)
 
$
(0.47
)

See Note 8.a for the fair value measurement of derivatives. See Note 17.c for the Company's subsequent hedge restructuring and corresponding summary of open derivative positions as of March 31, 2019 for derivative terminations and trade activity through May 1, 2019.

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


Note 8—Fair value measurements
See Note 10 in the 2018 Annual Report for discussion of the Company's accounting policies for fair value measurements.
a.    Fair value measurement on a recurring basis
The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in "Derivatives" on the unaudited consolidated balance sheets as of the dates presented:
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total gross fair value
 
Amounts offset
 
Net fair value presented on the unaudited consolidated balance sheets
As of March 31, 2019:
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
4,911

 
$
—

 
$
4,911

 
$
(5,242
)
 
$
(331
)
NGL derivatives
 
—

 
7,541

 
—

 
7,541

 
(6,210
)
 
1,331

Natural gas derivatives
 
—

 
19,694

 
—

 
19,694

 
(5,943
)
 
13,751

Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
(7,141
)
 
(7,141
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
2,432

 
$
—

 
$
2,432

 
$
(646
)
 
$
1,786

NGL derivatives
 
—

 
2,518

 
—

 
2,518

 
(1,506
)
 
1,012

Natural gas derivatives
 
—

 
3,446

 
—

 
3,446

 
(274
)
 
3,172

Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
(11,996
)
 
$
—

 
$
(11,996
)
 
$
5,242

 
$
(6,754
)
NGL derivatives
 
—

 
(5,871
)
 
—

 
(5,871
)
 
6,210

 
339

Natural gas derivatives
 
—

 
(5,082
)
 
—

 
(5,082
)
 
5,943

 
861

Oil derivative deferred premiums
 
—

 
—

 
(12,644
)
 
(12,644
)
 
7,141

 
(5,503
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
(2,991
)
 
$
—

 
$
(2,991
)
 
$
646

 
$
(2,345
)
NGL derivatives
 
—

 
(3,916
)
 
—

 
(3,916
)
 
1,506

 
(2,410
)
Natural gas derivatives
 
—

 
918

 
—

 
918

 
274

 
1,192

Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Net derivative asset (liability) positions
 
$
—

 
$
11,604

 
$
(12,644
)
 
$
(1,040
)
 
$
—

 
$
(1,040
)

18
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, 2018:
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
44,425

 
$
—

 
$
44,425

 
$
(7,907
)
 
$
36,518

NGL derivatives
 
—

 
1,974

 
—

 
1,974

 
—

 
1,974

Natural gas derivatives
 
—

 
18,991

 
—

 
18,991

 
(3,267
)
 
15,724

Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
(14,381
)
 
(14,381
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
10,626

 
$
—

 
$
10,626

 
$
—

 
$
10,626

NGL derivatives
 
—

 
1,024

 
—

 
1,024

 
—

 
1,024

Natural gas derivatives
 
—

 
108

 
—

 
108

 
(728
)
 
(620
)
Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
(9,059
)
 
$
—

 
$
(9,059
)
 
$
7,907

 
$
(1,152
)
NGL derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Natural gas derivatives
 
—

 
(7,290
)
 
—

 
(7,290
)
 
3,267

 
(4,023
)
Oil derivative deferred premiums
 
—

 
—

 
(16,565
)
 
(16,565
)
 
14,381

 
(2,184
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

NGL derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Natural gas derivatives
 
—

 
(728
)
 
—

 
(728
)
 
728

 
—

Oil derivative deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Net derivative asset (liability) positions
 
$
—

 
$
60,071

 
$
(16,565
)
 
$
43,506

 
$
—

 
$
43,506


Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price(s), appropriate risk-adjusted discount rates and forward price curve models for substantially similar instruments generated from a compilation of data gathered from third parties.
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 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. The deferred premiums are included in "Derivatives" on the unaudited consolidated balance sheets, and as of March 31, 2019, their input rates range from 2.31% to 3.32% with a net fair value weighted-average rate of 2.74%.

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


The following table presents payments required for derivative deferred premiums as of March 31, 2019 for the periods presented:
(in thousands)
 
March 31, 2019
Remaining 2019
 
$
11,486

2020
 
1,295

  Total
 
$
12,781


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

Three months ended March 31,
(in thousands)

2019
 
2018
Balance of Level 3 at beginning of period

$
(16,565
)
 
$
(28,683
)
Change in net present value of derivative deferred premiums(1)

(95
)
 
(211
)
Total purchases and settlements of derivative deferred premiums:

 
 
 
Purchases

—

 
(5,422
)
Settlements

4,016

 
4,024

Balance of Level 3 at end of period

$
(12,644
)
 
$
(30,292
)
____________________________________________________________________________
(1)
These amounts are included in "Interest expense" in the unaudited consolidated statements of operations.
See Note 2.f in the 2018 Annual Report for discussion of the Company's accounting policies for derivatives.
b.    Items not accounted for at fair value
The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.
The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:
 
 
March 31, 2019
 
December 31, 2018
(in thousands)
 
Long-term
debt
 
Fair
value(1)
 
Long-term
debt
 
Fair
value(1)
January 2022 Notes
 
$
450,000

 
$
412,313

 
$
450,000

 
$
402,885

March 2023 Notes
 
350,000

 
312,375

 
350,000

 
316,624

Senior Secured Credit Facility
 
270,000

 
270,112

 
190,000

 
190,054

Total
 
$
1,070,000

 
$
994,800

 
$
990,000

 
$
909,563

______________________________________________________________________________
(1)
The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the March 31, 2019 and December 31, 2018 Level 1 fair value hierarchy quoted market price for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of March 31, 2019 and December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10 in the 2018 Annual Report for information about the fair value hierarchy levels.
Note 9—Net income (loss) per common share
Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. See Note 6.c for additional discussion of these awards. For the three months ended March 31, 2019, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per common share. For the three months ended March 31, 2018, the dilutive effects of these awards were calculated utilizing the treasury stock method. For additional discussion of these dilutive effects, see Note 10 in the first-quarter 2018 Quarterly Report.

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


The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented:
 
 
Three months ended March 31,
(in thousands, except for per share data)
 
2019
 
2018
Net income (loss) (numerator):
 
 
 
 
Net income (loss)—basic and diluted
 
$
(9,491
)
 
$
86,520

Weighted-average common shares outstanding (denominator):
 
 
 
 
Basic(1)
 
230,476


238,228

Dilutive non-vested restricted stock awards
 
—

 
1,064

Dilutive outstanding stock option awards
 
—

 
27

Diluted
 
230,476


239,319

Net income (loss) per common share:
 
 
 
 
Basic
 
$
(0.04
)
 
$
0.36

Diluted
 
$
(0.04
)
 
$
0.36

_____________________________________________________________________________
(1)
Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account share repurchases that occurred during the three months ended March 31, 2018. See Note 6.a for additional discussion of the Company's share repurchase program.
Note 10—Commitments and contingencies
a.    Litigation
From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. See Note 17.b for discussion of a favorable settlement received by the Company, which occurred subsequent to March 31, 2019, in connection with the Company's damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement.
b.    Drilling contracts
The Company has committed to several drilling rig contracts with third parties to facilitate the Company's drilling plans. Certain of these contracts are for terms of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the three months ended March 31, 2019 or 2018. As the Company's current drilling rig contracts are considered leases under the scope of ASC 842, the present value of the future commitment as of March 31, 2019 related to drilling contracts with an initial term greater than 12 months is included in "Operating lease liabilities" under "Current liabilities" on the unaudited consolidated balance sheet as of March 31, 2019. The future commitment of $2.2 million as of March 31, 2019 related to drilling contracts with a term less than 12 months is not recorded in the unaudited consolidated balance sheets. See Note 3.a for further discussion of the impact of the ASC 842 adoption. Management does not currently anticipate the early termination of these contracts in 2019.
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 firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $0.5 million and $0.1 million during the three months ended March 31, 2019 and 2018, respectively. These firm transportation payments on excess pipeline capacity and other contractual penalties are netted with the respective revenue stream in the unaudited

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


consolidated statements of operations. Future commitments of $358.5 million as of March 31, 2019 are not recorded in the unaudited consolidated balance sheets.
d.    Sand purchase and supply agreement
During the second quarter of 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of March 31, 2019, under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $1.1 million at the end of the contract period.
e.    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.
f.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of March 31, 2019 or December 31, 2018.
Note 11—Supplemental cash flow and non-cash information
The following table presents supplemental cash flow and non-cash information:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Supplemental cash flow information:
 
 
 
 
Capitalized interest
 
$
242

 
$
255

Supplemental non-cash investing information:
 
 
 
 
Increase (decrease) in accrued capital expenditures
 
$
6,443

 
$
(43,336
)
Capitalized stock-based compensation in evaluated oil and natural gas properties
 
$
1,899

 
$
2,102

Capitalized asset retirement costs
 
$
271

 
$
130

Supplemental non-cash financing information:
 
 
 
 
Increase in accrued stock repurchases
 
$
—

 
$
4,761


The following table presents supplemental cash flow and non-cash information related to leases:
(in thousands)
 
Three months ended March 31, 2019
Supplemental cash paid for amounts included in the measurement of lease liabilities information:
 
 
Operating cash flows for operating leases
 
$
3,564

Supplemental non-cash adjustments information:
 
 
Right-of-use assets obtained in exchange for operating lease liabilities
 
$
22,090


See Note 3 for discussion of the Company's leases.

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


Note 12—Asset retirement obligations
See Note 2.k in the 2018 Annual Report for discussion of the Company's accounting policies for asset retirement obligations.
The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Liability at beginning of period
 
$
56,882

 
$
55,506

Liabilities added due to acquisitions, drilling, midstream service asset construction and other
 
271

 
130

Accretion expense
 
1,052

 
1,106

Liabilities settled due to plugging and abandonment or removed due to sale
 
(447
)
 
(440
)
Liability at end of period
 
$
57,758

 
$
56,302


Note 13—Revenue recognition
a.    Impact of ASC 606 adoption on the Medallion Sale
Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion (the "Medallion Sale"). LMS' total net cash proceeds before taxes for its 49% ownership interest in Medallion were $831.3 million.
LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018.
At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018.
In adopting ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to Global Infrastructure Partners ("GIP"), (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the 2018 beginning balance of accumulated deficit, presented on the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption. See Notes 4.c and 5.a in the 2018 Annual Report for further discussion of the Medallion Sale, the TA and the adoption of ASC 606.
b.    Revenue recognition
Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and

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


water delivery, recycling and takeaway and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition can be found in Note 5.b in the 2018 Annual Report.
Note 14—Income taxes
The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carryforwards totaling $1.9 billion and state of Oklahoma net operating loss carryforwards totaling $36.0 million as of March 31, 2019, which begin expiring in 2026 and 2032, respectively. Due to the enactment of Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), $157.2 million of the federal net operating loss carryforward will not expire but may be limited in future periods. As of March 31, 2019, the Company believes it is more likely than not that a portion of the net operating loss carryforwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of March 31, 2019, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carryforward from expiring unused and future projections of Oklahoma sourced income. As of March 31, 2019, a total valuation allowance of $239.0 million has been recorded against the net deferred tax asset, resulting in a net Texas deferred tax liability of $5.0 million, which is included in "Other noncurrent liabilities" on the unaudited consolidated balance sheets.
The Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale in 2017. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over a five-year period. Therefore, as of March 31, 2019, a receivable has been recorded in the amount of $4.1 million, of which $2.1 million is included in "Accounts receivable, net" and $2.0 million is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
Note 15—Related party
The Company has a drilling contract with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.
The drilling contract with H&P is considered a lease under the scope of ASC 842 and, as the initial term is greater than 12 months, it is capitalized as an operating lease and is included in "Operating lease right-of-use-assets." The present value of the future commitment is included in "Operating lease liabilities" under "Current liabilities" on the unaudited consolidated balance sheet as of March 31, 2019.
The following table presents the operating lease liability related to H&P included in the unaudited consolidated balance sheet:
(in thousands)
 
March 31, 2019
Operating lease liabilities
 
$
7,900

The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the unaudited consolidated statements of cash flows:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Capital expenditures for oil and natural gas properties
 
$
2,982

 
$
—


Note 16—Subsidiary guarantors
The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility, subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating (i) balance sheets as of March 31, 2019 and December 31, 2018, (ii) statements of operations for the three months ended March 31, 2019 and 2018 and (iii) statements of cash flows for the three months ended March 31, 2019 and 2018 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 and the consolidation and elimination entries necessary to arrive at the information for the Company on a

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


condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other.
Condensed consolidating balance sheet
March 31, 2019
(in thousands)
 
Laredo

Subsidiary
Guarantors

Intercompany
eliminations

Consolidated
company
Accounts receivable, net
 
$
94,635

 
$
12,885

 
$
—

 
$
107,520

Other current assets
 
63,836

 
1,374

 
—

 
65,210

Oil and natural gas properties, net
 
2,145,399

 
9,076

 
(24,049
)
 
2,130,426

Midstream service assets, net
 
—

 
131,118

 
—

 
131,118

Other fixed assets, net
 
39,061

 
37

 
—

 
39,098

Investment in subsidiaries
 
135,199

 
—

 
(135,199
)
 
—

Other noncurrent assets, net
 
37,245

 
4,172

 
—

 
41,417

Total assets
 
$
2,515,375

 
$
158,662

 
$
(159,248
)
 
$
2,514,789

 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
 
$
57,291

 
$
19,353

 
$
—

 
$
76,644

Other current liabilities
 
125,377

 
1,601

 
—

 
126,978

Long-term debt, net
 
1,064,081

 
—

 
—

 
1,064,081

Other noncurrent liabilities
 
73,145

 
2,509

 
—

 
75,654

Total stockholders' equity
 
1,195,481

 
135,199

 
(159,248
)
 
1,171,432

Total liabilities and stockholders' equity
 
$
2,515,375

 
$
158,662

 
$
(159,248
)
 
$
2,514,789

Condensed consolidating balance sheet
December 31, 2018
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Accounts receivable, net
 
$
83,424

 
$
10,897

 
$
—

 
$
94,321

Other current assets
 
97,045

 
1,386

 
—

 
98,431

Oil and natural gas properties, net
 
2,043,009

 
9,113

 
(22,551
)
 
2,029,571

Midstream service assets, net
 
—

 
130,245

 
—

 
130,245

Other fixed assets, net
 
39,751

 
68

 
—

 
39,819

Investment in subsidiaries
 
128,380

 
—

 
(128,380
)
 
—

Other noncurrent assets, net
 
23,783

 
4,135

 
—

 
27,918

Total assets
 
$
2,415,392

 
$
155,844

 
$
(150,931
)
 
$
2,420,305

 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
 
$
54,167

 
$
15,337

 
$
—

 
$
69,504

Other current liabilities
 
121,297

 
9,664

 
—

 
130,961

Long-term debt, net
 
983,636

 
—

 
—

 
983,636

Other noncurrent liabilities
 
59,511

 
2,463

 
—

 
61,974

Total stockholders' equity
 
1,196,781

 
128,380

 
(150,931
)
 
1,174,230

Total liabilities and stockholders' equity
 
$
2,415,392

 
$
155,844

 
$
(150,931
)
 
$
2,420,305



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


Condensed consolidating statement of operations
For the three months ended March 31, 2019
(in thousands)

Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues

$
173,521


$
54,332


$
(18,906
)

$
208,947

Total costs and expenses

119,735


52,223


(17,408
)

154,550

Operating income

53,786


2,109


(1,498
)

54,397

Interest expense

(15,547
)

—


—


(15,547
)
Other non-operating income (expense), net

(46,328
)

93


(2,202
)

(48,437
)
Income (loss) before income taxes

(8,089
)

2,202


(3,700
)

(9,587
)
Total income tax benefit

96


—


—


96

Net income (loss)

$
(7,993
)

$
2,202


$
(3,700
)

$
(9,491
)
Condensed consolidating statement of operations
For the three months ended March 31, 2018
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues
 
$
197,825

 
$
76,300

 
$
(14,429
)
 
$
259,696

Total costs and expenses
 
105,688

 
74,564

 
(13,748
)
 
166,504

Operating income
 
92,137

 
1,736

 
(681
)
 
93,192

Interest expense
 
(13,518
)
 
—

 
—

 
(13,518
)
Other non-operating income (expense), net
 
8,582

 
(256
)
 
(1,480
)
 
6,846

Income before income taxes
 
87,201

 
1,480

 
(2,161
)
 
86,520

Total income tax
 
—

 
—

 
—

 
—

Net income
 
$
87,201

 
$
1,480

 
$
(2,161
)
 
$
86,520


Condensed consolidating statement of cash flows
For the three months ended March 31, 2019
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash provided by (used in) operating activities
 
$
82,020

 
$
(2,360
)
 
$
(2,202
)
 
$
77,458

Capital expenditures and other, net
 
(160,015
)
 
2,360

 
2,202

 
(155,453
)
Net cash provided by financing activities
 
77,388

 
—

 
—

 
77,388

Net decrease in cash and cash equivalents
 
(607
)
 
—

 
—

 
(607
)
Cash and cash equivalents, beginning of period
 
45,150

 
1

 
—

 
45,151

Cash and cash equivalents, end of period
 
$
44,543

 
$
1

 
$
—

 
$
44,544

Condensed consolidating statement of cash flows
For the three months ended March 31, 2018
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash provided by operating activities
 
$
140,247

 
$
7,704

 
$
(1,480
)
 
$
146,471

Capital expenditures and other, net
 
(193,450
)
 
(7,704
)
 
1,480

 
(199,674
)
Net cash used in financing activities
 
(3,067
)
 
—

 
—

 
(3,067
)
Net decrease in cash and cash equivalents
 
(56,270
)
 
—

 
—

 
(56,270
)
Cash and cash equivalents, beginning of period
 
112,158

 
1

 
—

 
112,159

Cash and cash equivalents, end of period
 
$
55,888

 
$
1

 
$
—

 
$
55,889



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


Note 17—Subsequent events
a.    Senior Secured Credit Facility
On April 30, 2019, pursuant to the regular semi-annual redetermination, the lenders decreased the borrowing base and aggregate elected commitment under the Senior Secured Credit Facility to $1.1 billion each.
b.    Litigation settlement
On April 12, 2019, the Company finalized and received a favorable settlement of $42.5 million in connection with its damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. The Company does not anticipate the receipt of further payments in connection with this matter as this settlement constituted a full and final satisfaction of the Company's claims. Given that this amount is considered a gain contingency, it was not recorded as income during the period ending March 31, 2019, or in any prior period. The Company intends to recognize this settlement amount as other non-operating income in its unaudited consolidated statement of operations for the quarter ending June 30, 2019.
c.    Derivatives
Subsequent to March 31, 2019, the Company completed a hedge restructuring by early terminating puts and collars and entered into new swaps. The Company paid a net termination amount of $5.4 million, that included both the full settlement of the deferred premiums associated with the early-terminated puts, partially offset by the value at the time of termination of the early-terminated puts and collars. The present value of these deferred premium liabilities, classified under Level 3 of the fair value hierarchy, upon their early termination was $7.2 million. See Note 10 in the 2018 Annual Report for information about the fair value hierarchy levels. The following table details the derivatives that were terminated:
 
 
Aggregate volumes (Bbl)
 
Weighted-average floor price ($/Bbl)
 
Weighted-average ceiling price ($/Bbl)
 
Contract period
Oil puts
 
5,087,500

 
$
46.03

 
$
—

 
April 2019 - December 2019
Oil collars
 
1,134,600

 
$
45.00

 
$
76.13

 
January 2020 - December 2020

The following table summarizes open derivative positions as of March 31, 2019, for derivative terminations and trade activity through May 1, 2019, for the settlement periods presented:
 
 
Remaining year 2019
 
Year 2020
 
Year 2021
Oil:
 
 
 
 

 
 
Puts:
 
 

 
 

 
 
Volume (Bbl)
 
962,500

 
366,000

 
—

Weighted-average floor price ($/Bbl)
 
$
55.00

 
$
45.00

 
$
—

Volume with deferred premium (Bbl)
 
962,500

 
—

 
—

Weighted-average deferred premium price ($/Bbl)
 
$
4.39

 
$
—

 
$
—

Swaps:
 
 

 
 

 
 
Volume (Bbl)
 
5,912,500

 
7,173,600

 
—

Weighted-average price ($/Bbl)
 
$
61.31

 
$
59.50

 
$
—

Collars:
 
 

 
 

 
 
Volume (Bbl)
 
—

 
—

 
912,500

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

 
$
—

 
$
45.00

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

 
$
—

 
$
71.00

Totals:
 
 
 
 
 
 
Total volume with floor price (Bbl)
 
6,875,000

 
7,539,600

 
912,500

Weighted-average floor price ($/Bbl)
 
$
60.42

 
$
58.79

 
$
45.00

Total volume with ceiling price (Bbl)
 
5,912,500

 
7,173,600

 
912,500

Weighted-average ceiling price ($/Bbl)
 
$
61.31

 
$
59.50

 
$
71.00

 
 
 
 
 
 
 
TABLE CONTINUES ON NEXT PAGE
 
 
 
 
 
 


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


 
 
Remaining year 2019
 
Year 2020
 
Year 2021
Basis Swaps:
 
 
 
 
 
 
WTI Midland to WTI NYMEX:
 
 
 
 
 
 
Volume (Bbl)
 
1,840,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(2.89
)
 
$
—

 
$
—

WTI Midland to WTI formula basis:
 
 
 
 
 
 
Volume (Bbl)
 
552,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(4.37
)
 
$
—

 
$
—

WTI Houston to WTI Midland:
 
 
 
 
 
 
Volume (Bbl)
 
910,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
7.30

 
$
—

 
$
—

NGL:
 
 
 
 
 
 
Swaps - Purity Ethane:
 
 
 
 
 
 
Volume (Bbl)
 
1,787,500

 
366,000

 
912,500

Weighted-average price ($/Bbl)
 
$
14.22

 
$
13.60

 
$
12.01

Swaps - Non-TET Propane:
 
 
 
 
 
 
Volume (Bbl)
 
1,430,000

 
1,244,400

 
730,000

Weighted-average price ($/Bbl)
 
$
27.97

 
$
26.58

 
$
25.52

Swaps - Non-TET Normal Butane:
 
 
 
 
 
 
Volume (Bbl)
 
550,000

 
439,200

 
255,500

Weighted-average price ($/Bbl)
 
$
30.73

 
$
28.69

 
$
27.72

Swaps - Non-TET Isobutane:
 
 
 
 
 
 
Volume (Bbl)
 
137,500

 
109,800

 
67,525

Weighted-average price ($/Bbl)
 
$
31.08

 
$
29.99

 
$
28.79

Swaps - Non-TET Natural Gasoline:
 
 
 
 
 
 
Volume (Bbl)
 
467,500

 
402,600

 
237,250

Weighted-average price ($/Bbl)
 
$
45.80

 
$
45.15

 
$
44.31

Total NGL volume (Bbl)
 
4,372,500

 
2,562,000

 
2,202,775

Natural gas:
 
 

 
 

 
 
Henry Hub NYMEX Swaps:
 
 

 
 

 
 
Volume (MMBtu)
 
29,425,000

 
23,790,000

 
14,052,500

Weighted-average price ($/MMBtu)
 
$
3.09

 
$
2.72

 
$
2.63

Basis Swaps:
 
 

 
 

 
 
Volume (MMBtu)
 
29,425,000

 
32,574,000

 
23,360,000

Weighted-average price ($/MMBtu)
 
$
(1.51
)
 
$
(0.76
)
 
$
(0.47
)

d.    Workforce reduction
On April 2, 2019, the Company announced the retirement of two of its Senior Officers. Additionally, on April 8, 2019 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the "Plan") that includes a workforce reduction of approximately 20%, which included an Executive Officer. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the Plan in response to recent market conditions and to reduce costs and better position the Company for the future. In connection with the retirements on April 2, 2019 and with the Plan, the Company estimates that it will incur an aggregate of approximately $12.0 million of one-time charges in the second quarter of 2019 comprising of compensation, taxes, professional fees, outplacement and insurance-related expenses.

28
Table of Contents

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 our 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 2018 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 midstream and marketing services, primarily in the Permian Basin of West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.
Our financial and operating performance for the three months ended March 31, 2019 included the following:
•
Oil, NGL and natural gas sales of $173.4 million, compared to $197.4 million for the three months ended March 31, 2018, this decrease in sales is the result of a 26% decrease in average sales price per BOE, partially offset by a 19% increase in MBOE volumes sold;
•
Average daily sales volumes of 75,276 BOE/D, compared to 63,314 BOE/D for the three months ended March 31, 2018;
•
Net loss of $9.5 million, compared to net income of $86.5 million for the three months ended March 31, 2018; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $122.9 million, compared to $143.4 million for the three months ended March 31, 2018. See page 42 for a discussion and reconciliation of Adjusted EBITDA.
Recent developments
Potential future low commodity price impact on our second-quarter 2019 full cost ceiling impairment test
Oil, NGL and natural gas prices decreased in the first quarter of 2019. If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, it is possible we will incur a non-cash full cost ceiling impairment in second-quarter 2019, 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, (viii) revisions to production curves based on additional data and (ix) the inherent significant volatility in the commodity prices for oil, NGL and natural gas recently exemplified by price changes 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 reserves estimation utilized in our quarterly accounting estimates. We use our reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our resource 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 development plans.
Set forth below is a calculation of a potential future impairment of our evaluated oil and natural gas properties. Such implied impairment should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible second-quarter effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario.

29
Table of Contents

Our hypothetical second-quarter 2019 full cost ceiling calculation has been prepared by substituting (i) $56.49 per Bbl for oil, (ii) $20.15 per Bbl for NGL and (iii) $0.92 per Mcf for natural gas (collectively, the "Pro Forma Second-Quarter Prices") for the respective Realized Prices (as defined below) as of March 31, 2019. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the second-quarter 2019 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Second-Quarter 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 for the 12 months ended April 1, 2019. Based solely on the substitution of the Pro Forma Second-Quarter Prices into our March 31, 2019 reserve estimates, we would not have a second-quarter 2019 impairment. Under the same assumptions as above, but reducing the oil price to $56.30 per barrel ("Pro Forma Oil Price"), our full cost ceiling would approximately equal our after-tax net book basis to be recovered, implying a potential impairment of our evaluated oil and natural gas properties if the oil Realized Price applied to our reserves decreased below this Pro Forma Oil Price during second-quarter 2019. We believe that substituting these prices into our March 31, 2019 reserve estimates may help provide users with an understanding of the potential impact on our second-quarter 2019 full cost ceiling test.
See "Part I, Item 1A. Risk Factors—Risks related to our business—As a result of the volatility in prices for oil, NGL and natural gas, we have taken and may be required to take further write-downs of the carrying values of our properties" in our 2018 Annual Report.
Succession plan
We have implemented and been focused on a succession plan, which also included retirements and reductions in force (described below) that included a former Executive Officer and two former Senior Officers. On April 24, 2019, our board of directors announced the appointment of Mikell J. Pigott as President of the Company, effective as of May 28, 2019. The board also appointed Mr. Pigott to become a member of the board, effective May 28, 2019, and to hold office until the 2020 annual meeting of stockholders or until his successor has been duly elected and qualified. As part of our comprehensive succession planning process, Mr. Pigott will succeed Randy A. Foutch, as the Company's Chief Executive Officer during the fourth quarter of 2019. The terms of Mr. Pigott’s offer are included in an exhibit to this Quarterly Report.
Litigation settlement
On April 15, 2019, we finalized and received a favorable settlement of $42.5 million in connection with our damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. We do not anticipate the receipt of further payments in connection with this matter as this settlement constituted a full and final satisfaction of our claims. Given that this amount is considered a gain contingency, it was not recorded as income during the period ending March 31, 2019, or in any prior period. We intend to recognize this settlement amount as other non-operating income in our unaudited consolidated statement of operations for the quarter ending June 30, 2019.
Workforce reduction
On April 2, 2019, we announced the retirement of two of our Senior Officers. Additionally, on April 8, 2019, we committed to a Plan that includes a workforce reduction of approximately 20%, which included an Executive Officer. The reduction in workforce was communicated to employees on April 8, 2019 and implemented immediately, subject to certain administrative procedures. Our board of directors approved the Plan in response to recent market conditions and to reduce costs and better position us for the future. In connection with the retirements on April 2, 2019 and with the Plan, we estimate that we will incur an aggregate of approximately $12.0 million of one-time charges in the second quarter of 2019 comprising of compensation, taxes, professional fees, outplacement and insurance-related expenses.
Core area of operations
The oil and liquids-rich Permian Basin is characterized by multiple target horizons, long-lived reserves, high drilling success rates and high initial production rates. As of March 31, 2019, we had assembled 122,461 net acres in the Permian Basin.
Pricing and reserves
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions, transportation constraints and a variety of additional factors. Historically, 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.

30
Table of Contents

We have entered into a number of derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
The unweighted arithmetic average first-day-of-the-month prices for oil, NGL and natural gas for each month within the 12-month period prior to the end of the reporting period before pricing differentials, adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the prices received at the wellhead ("Realized Prices"), utilized to value our reserves as of March 31, 2019 and March 31, 2018, were $56.72 per Bbl for oil, $20.46 per Bbl for NGL and $1.09 per Mcf for natural gas, and $48.72 per Bbl for oil, $18.83 per Bbl for NGL and $1.97 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of March 31, 2019 or March 31, 2018. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.
Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a relatively new process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we are seeing indications that the oil portion of such reserves may be less than originally anticipated and the decline curves may be steeper than originally anticipated.
Initial production results, production decline rates, well density, completion design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion. Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decreases earnings and increases losses through higher depletion expense. We have experienced increased depletion per BOE sold for first-quarter 2019.
Sources of our revenue
Our revenues are derived from the sale of produced oil, NGL and natural gas, the sale of purchased oil and providing midstream services to third parties, all within the continental United States and do not include the effects of derivatives. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production, pricing differentials and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices, pricing differentials and the amount of volumes purchased. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure. See Notes 2.n and 5.b to our consolidated financial statements in our 2018 Annual Report for additional information regarding our revenue recognition policies.
The following table presents our sources of revenue as a percentage of total revenues:
 
 
Three months ended March 31,
 
 
2019
 
2018
Oil sales
 
62
%
 
58
%
NGL sales
 
15
%
 
11
%
Natural gas sales
 
6
%
 
7
%
Midstream service revenues
 
1
%
 
1
%
Sales of purchased oil
 
16
%
 
23
%
Total
 
100
%
 
100
%

31
Table of Contents

Results of operations
For the three months ended March 31, 2019 as compared to the three months ended March 31, 2018
Oil, NGL and natural gas sales volumes, revenues and prices
The following table presents information regarding our oil, NGL and natural gas sales volumes, revenues and average sales prices:
 
 
Three months ended March 31,
 
 
2019
 
2018
Sales volumes:
 
 


 

Oil (MBbl)
 
2,534


2,439

NGL (MBbl)
 
2,099

 
1,563

Natural gas (MMcf)
 
12,849


10,173

Oil equivalents (MBOE)(1)(2)
 
6,775


5,698

Average daily sales volumes (BOE/D)(2)
 
75,276


63,314

% Oil(2)
 
37
%

43
%
Sales revenues (in thousands):
 



 
Oil
 
$
129,171


$
150,914

NGL
 
32,235

 
28,360

Natural gas
 
11,970


18,160

Total oil, NGL and natural gas sales revenues
 
$
173,376


$
197,434

Average sales prices(2):
 



 
Oil, without derivatives ($/Bbl)(3)
 
$
50.97


$
61.87

NGL, without derivatives ($/Bbl)(3)
 
$
15.36


$
18.14

Natural gas, without derivatives ($/Mcf)(3)
 
$
0.93


$
1.79

Average price, without derivatives ($/BOE)(3)
 
$
25.59


$
34.65

Oil, with derivatives ($/Bbl)(4)
 
$
47.66


$
58.53

NGL, with derivatives ($/Bbl)(4)
 
$
15.33


$
18.11

Natural gas, with derivatives ($/Mcf)(4)
 
$
1.11


$
1.85

Average price, with derivatives ($/BOE)(4)
 
$
24.68


$
33.34

_____________________________________________________________________________
(1)
BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)
The numbers 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 received when control passes to the purchaser/customer adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(4)
Price reflects the after-effects of our derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to derivatives that settled during the respective periods.
    

32
Table of Contents

The following table presents settlements (paid) received for matured derivatives and premiums paid previously or upon settlement attributable to derivatives that matured during the periods utilized in our calculation of the average sales prices with derivatives presented above:        
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Settlements (paid) received for matured derivatives:
 





Oil
 
$
(2,095
)

$
(3,736
)
NGL
 
(57
)
 
(47
)
Natural gas
 
2,254


1,547

Total
 
$
102


$
(2,236
)
Premiums paid previously or upon settlement attributable to derivatives that matured during the respective period:
 





Oil
 
$
(6,300
)

$
(4,403
)
Natural gas
 
—


(841
)
Total
 
$
(6,300
)

$
(5,244
)
 
Changes in average sales prices without derivatives and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2019 and 2018:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net
effect of change
2018 Revenues
 
$
150,914

 
$
28,360

 
$
18,160


$
197,434

Effect of changes in average sales prices
 
(27,602
)
 
(5,847
)
 
(10,967
)
 
(44,416
)
Effect of changes in sales volumes
 
5,859

 
9,722

 
4,777

 
20,358

2019 Revenues
 
$
129,171

 
$
32,235

 
$
11,970

 
$
173,376

Oil sales revenue. Our oil sales revenue is a function of oil production volumes sold and average oil sales prices received for those volumes. The decrease in oil sales revenue of $21.7 million, or 14%, for the three months ended March 31, 2019 as compared to the same period in 2018 is due to an 18% decrease in average oil sales prices and was partially offset by a 4% increase in oil sales volumes.
NGL sales revenue. Our NGL sales revenue is a function of NGL production volumes sold and average NGL sales prices received for those volumes. The increase in NGL sales revenue of $3.9 million, or 14%, for the three months ended March 31, 2019 as compared to the same period in 2018 is due to a 34% increase in NGL sales volumes and was partially offset by a 15% decrease in average NGL sales prices.
Natural gas sales revenue. Our natural gas sales revenue is a function of natural gas production volumes sold and average natural gas sales prices received for those volumes. The decrease in natural gas sales revenue of $6.2 million, or 34%, for the three months ended March 31, 2019 as compared to the same period in 2018 is due to a 48% decrease in average natural gas sales prices and was partially offset by a 26% increase in natural gas sales volumes.
The following table presents midstream service and sales of purchased oil revenues:
 
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Midstream service revenues
 
$
2,883

 
$
2,359

Sales of purchased oil
 
$
32,688

 
$
59,903

Midstream service revenues. Our midstream service revenues increased by $0.5 million, or 22%, for the three months ended March 31, 2019, as compared to the same period in 2018. These revenues fluctuate and will vary due to oil throughput fees and the level of services provided to third parties.
Sales of purchased oil. These revenues are a function of the volumes and prices of purchased oil sold to customers and are offset by the costs of purchased oil. Sales of purchased oil decreased by $27.2 million, or 45%, for the three months ended March 31, 2019 as compared to the same period in 2018 mainly due to a decrease in the volumes of purchased oil sold. We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a gross basis as we act as the principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser/customer at the delivery point

33
Table of Contents

based on the price received. The transportation costs associated with these transactions are presented as a component of costs of purchased oil. See "—Costs and expenses - Costs of purchased oil."
Costs and expenses
The following table presents information regarding costs and expenses and average costs and expenses per BOE sold:
 
 
Three months ended March 31,
(in thousands except for per BOE sold data)
 
2019
 
2018
Costs and expenses:
 
 

 
 

Lease operating expenses
 
$
22,609

 
$
21,951

Production and ad valorem taxes
 
7,219

 
11,812

Transportation and marketing expenses
 
4,759

 
—

Midstream service expenses
 
1,603

 
693

Costs of purchased oil
 
32,691

 
60,664

General and administrative:
 
 
 
 
Cash
 
14,113

 
15,386

Non-cash stock-based compensation, net
 
7,406

 
9,339

Depletion, depreciation and amortization
 
63,098

 
45,553

Other operating expenses
 
1,052

 
1,106

Total costs and expenses
 
$
154,550

 
$
166,504

Average costs and expenses per BOE sold(1):






Lease operating expenses

$
3.34


$
3.85

Production and ad valorem taxes
 
1.07

 
2.07

Transportation and marketing expenses
 
0.70

 
—

Midstream service expenses
 
0.24

 
0.12

General and administrative:
 
 
 
 
Cash
 
2.08


2.70

Non-cash stock-based compensation, net
 
1.09


1.64

Depletion, depreciation and amortization
 
9.31


7.99

Total costs and expenses
 
$
17.83


$
18.37

_____________________________________________________________________________
(1)
Average costs and expenses per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $0.7 million, or 3%, for the three months ended March 31, 2019 compared to the same period in 2018. On a per BOE sold basis, lease operating expenses decreased by 13% for the three months ended March 31, 2019 compared to the same period in 2018. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to lease operating expenses.
Production and ad valorem taxes. Production and ad valorem taxes decreased by $4.6 million, or 39%, for the three months ended March 31, 2019 compared to the same period in 2018. The decrease is mainly due to a $4.5 million production tax refund, related to additional marketing costs claimed for fiscal years 2013 through 2016, recorded during the three months ended March 31, 2019. Production taxes, which are established by federal, state or local taxing authorities, are based on and fluctuate in proportion to our oil, NGL and natural gas sales revenue. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.
Transportation and marketing expenses. Transportation and marketing expenses were $4.8 million for the three months ended March 31, 2019. In July 2018, we began recognizing transportation and marketing expense incurred for the delivery of produced oil to the customer in the U.S. Gulf Coast market. We did not have any comparable transactions during the same period in 2018.
Midstream service expenses. Midstream service expenses increased by $0.9 million, or 131%, for the three months ended March 31, 2019 compared to the same period in 2018. This increase is mainly due to an increase in water service costs during the three months ended March 31, 2019, which corresponds to a similar increase in water service revenue included in

34
Table of Contents

midstream service revenues during the same period. Midstream service expenses are 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.
Costs of purchased oil. Costs of purchased oil decreased by $28.0 million, or 46%, for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to a decrease in the volumes of purchased oil. These are costs incurred for obtaining oil from third parties and, in some cases, transporting such oil utilized in our marketing activities.
General and administrative ("G&A"). Total G&A decreased by $3.2 million, or 13%, for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to decreases in stock-based compensation, net and professional fees. Stock-based compensation, net, decreased by $1.9 million, or 21%, for the three months ended March 31, 2019 compared to the same period in 2018. See Note 6.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our stock-based compensation.
Depletion, depreciation and amortization ("DD&A"). The following table presents the components of our DD&A expense:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Depletion of evaluated oil and natural gas properties
 
$
59,370

 
$
41,817

Depreciation of midstream service assets
 
2,501

 
2,405

Depreciation and amortization of other fixed assets
 
1,227

 
1,331

Total DD&A
 
$
63,098

 
$
45,553

DD&A increased by $17.5 million, or 39%, for the three months ended March 31, 2019 compared to the same period in 2018. This increase is mainly due to (i) the previous reduction in our December 31, 2018 reserve volume, (ii) an increase in the depletion base and (iii) an increase in production volumes sold. Depletion per BOE increased 19% for the three months ended March 31, 2019 compared to the same period in 2018. For further discussion of our depletion per BOE see "—Pricing and reserves."
Non-operating income (expense). The following table presents the components of non-operating income (expense):
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Gain (loss) on derivatives, net
 
$
(48,365
)
 
$
9,010

Interest expense
 
(15,547
)
 
(13,518
)
Loss on disposal of assets, net
 
(939
)
 
(2,617
)
Other income, net
 
867

 
453

Non-operating expense, net
 
$
(63,984
)
 
$
(6,672
)
Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net:
(in thousands)
 
Three months ended March 31, 2019 compared to 2018
Decrease in fair value of derivatives outstanding
 
$
(59,713
)
Change in settlements received (paid) for matured derivatives, net
 
2,338

Total change in gain (loss) on derivatives, net
 
$
(57,375
)
The decrease in fair value of derivatives outstanding is the result of new and expiring contracts and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if no new contracts are entered into, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. Settlements received or paid for matured derivatives are based on the settlement prices of our matured derivatives compared to the prices specified in the derivative contracts. See Notes 7 and 8.a 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.
Interest expense. Interest expense increased by $2.0 million, or 15%, for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to an increase in the amount outstanding on our Senior Secured Credit Facility.
Loss on disposal of assets, net. Loss on disposal of assets, net decreased by $1.7 million for the three months ended March 31, 2019 compared to the same period in 2018. From time to time, we dispose of inventory, midstream service assets

35
Table of Contents

and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.
Income tax. Income tax benefit for the three months ended March 31, 2019 was $0.1 million. We are subject to federal and state income taxes and the Texas franchise tax. As of March 31, 2019, we determined it was more likely than not that our deferred tax assets were not realizable through future net income. We maintain a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized and, as of March 31, 2019, we have recorded a total valuation allowance of $239.0 million against our federal and Oklahoma deferred tax assets. As such, the effective tax rates for our operations were 1% and 0% for the three months ended March 31, 2019 and 2018, respectively. For further discussion of our valuation allowance, see Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
Liquidity and capital resources
Historically, 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 the Medallion Sale and other asset dispositions. We believe cash flows from operations and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund our expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, infrastructure development and investments in Medallion until its sale on October 30, 2017.
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 and equity repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. For further discussion of our financing activities included elsewhere in this Quarterly Report, see: (i) Note 5 for our debt instruments and (ii) Note 6.a and "Part II. Item 2. Purchases of Equity Securities" below for our $200.0 million share repurchase program authorized by our board of directors and commenced in February 2018. We also continuously look for other opportunities to maximize shareholder value.
Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where we produce and where we sell such commodities, we engage in derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of our anticipated production. By removing a 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. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.
See Note 17.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our hedge restructuring, which occurred subsequent to March 31, 2019, and corresponding summary of open derivative positions as of March 31, 2019 for derivative terminations and trade activity through May 1, 2019.
See Note 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a summary of open derivative positions as of March 31, 2019 for derivatives that were entered into through March 31, 2019.
We continually seek to maintain a financial profile that provides operational flexibility. As of March 31, 2019, we had cash and cash equivalents of $44.5 million and available capacity under the Senior Secured Credit Facility of $915.3 million, resulting in total liquidity of $959.8 million. As of April 30, 2019, we had cash and cash equivalents of $85.0 million and available capacity under the Senior Secured Credit Facility of $815.3 million, resulting in total liquidity of $900.3 million. We believe that our operating cash flow, the receipt of the litigation settlement proceeds and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our planned capital expenditure budget and, at our discretion, to fund our share repurchase program, pay down debt or increase our planned capital expenditure budget. We expect 2019 to be a transitional year as we tailor our operational cadence and corporate cost structure, including G&A expense, to balance capital expenditures and cash flow from operations. We have aligned personnel costs with activity levels with a recent reduction in force. We have restructured our oil hedges, securing additional cash flow to increase activity and substantially accelerating the time frame in which we expect to generate free cash flow while growing oil production.

36
Table of Contents

Cash flows
The following table presents our cash flows:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Net cash provided by operating activities
 
$
77,458

 
$
146,471

Net cash used in investing activities
 
(155,453
)
 
(199,674
)
Net cash provided by (used in) financing activities
 
77,388

 
(3,067
)
Net decrease in cash and cash equivalents
 
$
(607
)
 
$
(56,270
)
Cash flows from operating activities
Net cash provided by operating activities decreased by $69.0 million, or 47%, for the three months ended March 31, 2019, compared to the same period in 2018, mainly due to decreased revenues along with a decrease of $52.2 million from net working capital changes. The decrease in revenues is due to the decrease in average sales prices for oil, NGL and natural gas partially offset by increased sales volumes of all production streams. See "—Results of operations" for additional discussion of changes in our revenues.
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, mitigated to the extent of our derivatives' exposure, and sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations 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 risks related to our business, see "Part I. Item 1A. Risk Factors" in our 2018 Annual Report.
Cash flows from investing activities
Net cash used in investing activities decreased by $44.2 million, or 22%, for the three months ended March 31, 2019, compared to the same period in 2018, and is mainly attributable to a decrease in capital expenditures on oil and natural gas properties.
The following table presents the components of our cash flows from investing activities:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Capital expenditures:
 
 
 
 
Oil and natural gas properties
 
(152,729
)
 
(195,025
)
Midstream service assets
 
(2,262
)
 
(3,362
)
Other fixed assets
 
(505
)
 
(3,963
)
Proceeds from disposition of equity method investee, net of selling costs
 
—

 
1,655

Proceeds from dispositions of capital assets, net of selling costs
 
43

 
1,021

Net cash used in investing activities
 
$
(155,453
)
 
$
(199,674
)
Capital expenditure budget
Our goal is to achieve cash flow neutrality, and therefore, our capital spending in 2019 will ultimately be influenced by commodity price changes, as well as any changes in service costs and drilling and completions efficiencies. Due to the increased cash flow secured from the successful execution of our WTI NYMEX hedge restructuring and litigation settlement proceeds received discussed herein, both of which occurred subsequent to March 31, 2019, during the second quarter of 2019, we adjusted our expected capital expenditures, excluding non-budgeted acquisitions, to $465.0 million for calendar year 2019, an increase of $100.0 million from the previously announced level. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture

37
Table of Contents

opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
Cash flows from financing activities
Net cash used in financing activities decreased by $80.5 million for the three months ended March 31, 2019, compared to the same period in 2018, and is mainly attributable to first-quarter 2018 share repurchases under our share repurchase program that commenced in February 2018 and increased borrowings on our Senior Secured Credit Facility. During the year ended December 31, 2018, we repurchased 11,048,742 shares of common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. There were no share repurchases under this program during the three months ended March 31, 2019. As of March 31, 2019, we had authorization remaining to repurchase until its expiration in February 2020, $102.9 million of common stock.
For further discussion of our financing activities included elsewhere in this Quarterly Report, see: (i) Note 5 for our debt instruments and (ii) Note 6.a and "Part II. Item 2. Purchases of Equity Securities" below for our $200.0 million share repurchase program authorized by our board of directors and commenced in February 2018.
The following table presents the components of our cash flows from financing activities:
 
 
Three months ended March 31,
(in thousands)
 
2019
 
2018
Borrowings on Senior Secured Credit Facility
 
$
80,000

 
$
55,000

Share repurchases
 
—

 
(53,714
)
Stock exchanged for tax withholding
 
(2,612
)
 
(4,353
)
Net cash provided by (used in) financing activities
 
$
77,388

 
$
(3,067
)
Debt
As of March 31, 2019, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.
Senior Secured Credit Facility. The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of March 31, 2019, the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion, a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion, with $270.0 million outstanding and was subject to an interest rate of 3.75%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of March 31, 2019 and December 31, 2018, we had one letter of credit of $14.7 million outstanding under the Senior Secured Credit Facility. For additional information, see Note 7.d in the 2018 Annual Report. See Note 17.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the regular semi-annual borrowing base redetermination of the Senior Secured Credit Facility subsequent to March 31, 2019.
Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of March 31, 2019:
(in millions, except for interest rates)
 
Principal
 
Interest rate
January 2022 Notes
 
$
450.0

 
5.625
%
March 2023 Notes
 
350.0

 
6.250
%
Total senior unsecured notes
 
$
800.0

 
 
See Notes 5.a and 5.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes and January 2022 Notes, respectively.

38
Table of Contents

Obligations and commitments
As of March 31, 2019, our contractual obligations included our January 2022 Notes, March 2023 Notes, firm sale and transportation commitments, Senior Secured Credit Facility, asset retirement obligations, operating lease liabilities, derivative deferred premiums, a short-term drilling contract and a sand purchase and supply agreement. From December 31, 2018 to March 31, 2019, the material changes in our contractual obligations included (i) an increase of $80.0 million in outstanding borrowings on our Senior Secured Credit Facility, (ii) a decrease of $23.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January and March of 2019, (iii) a decrease of $7.4 million for firm sale and transportation commitments due to our fulfillment of contractual commitments, (iv) a decrease of $4.0 million in derivative deferred premiums due to premiums paid for derivatives and (v) a decrease of $2.8 million for our in-basin sand purchase and supply agreement due to purchases made.
Due to the adoption of FASB ASC 842 during the three months ended March 31, 2019, we have recorded contracts previously recognized as off balance sheet operating leases, with a term greater than 12 months, as right-of-use assets and lease liabilities. As of March 31, 2019, we have recorded on our unaudited consolidated balance sheets included elsewhere in this Quarterly Report total operating lease liabilities of $22.2 million, which includes our current drilling rig contract with an initial term greater than 12 months. The future commitment of $2.2 million as of March 31, 2019 related to our drilling contract with a term less than 12 months is not recorded in the unaudited consolidated balance sheets included elsewhere in this Quarterly Report. This represents an increase of $22.2 million in total operating lease liabilities and a decrease of $14.3 million in unrecorded drilling contracts commitments from December 31, 2018 to March 31, 2019.
See Notes 3, 5, 7, 8, 10, 12 and 17.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.
Non-GAAP financial measure
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 is a non-GAAP financial measure that we define as net income or loss plus adjustments for income taxes, depletion, depreciation and amortization, non-cash stock-based compensation, net, accretion expense, mark-to-market on derivatives, premiums paid for derivatives, interest expense, gains or losses on disposal of assets and other non-recurring income and expenses. 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, 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, the 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.

39
Table of Contents

The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
 
 
Three months ended March 31,
(in thousands)
 
2019

2018
Net income (loss)
 
$
(9,491
)

$
86,520

Plus:
 
 
 
 
Deferred income tax benefit
 
(96
)

—

Depletion, depreciation and amortization
 
63,098


45,553

Non-cash stock-based compensation, net
 
7,406


9,339

Accretion expense
 
1,052


1,106

Mark-to-market on derivatives:
 
 
 
 
(Gain) loss on derivatives, net

48,365


(9,010
)
Settlements received (paid) for matured derivatives, net

102


(2,236
)
Premiums paid for derivatives
 
(4,016
)

(4,024
)
Interest expense
 
15,547


13,518

Loss on disposal of assets, net

939


2,617

Adjusted EBITDA
 
$
122,906


$
143,383

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.
There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2019. See our critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 2018 Annual Report. Furthermore, see Notes 3 and 6.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the impact of the adoption of ASC 842 and estimates pertaining to our 2019 performance unit awards, respectively.
Recent issued or adopted accounting pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. See Note 3 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion related to the adoption of ASC 842.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than firm sale and transportation commitments and our sand purchase and supply agreement, which are described in "—Obligations and commitments." In addition, we have certain operating leases with a term less than or equal to 12 months that we have made an accounting policy election to not record on the unaudited consolidated balance sheets. See Notes 3 and 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our leases and commitments and contingencies, respectively.


40
Table of Contents

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 derivative 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, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where we produce and where we sell such commodities, we engage in derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of our anticipated production. By removing a 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.
During a significant portion of 2018, Midland market crude oil prices experienced an increased discount to WTI Cushing and WTI Houston prices. These discounts have narrowed in 2019, however they remain volatile. During a significant portion of 2018 and the first quarter of 2019, the West Texas WAHA market natural gas prices experienced an increased discount to Henry Hub NYMEX prices and continues to remain volatile. The discounts are primarily due to limited pipeline capacity constraining transportation of crude oil and natural gas out of the Permian Basin to major market hubs including, but not limited to, Cushing, Oklahoma and the United States Gulf Coast. These pipeline constraints may continue to affect Midland market crude oil prices and West Texas WAHA market natural gas prices until further transportation capacity becomes operational or until basin-wide crude oil and natural gas production decreases from its current levels. We will continue to pursue avenues to attempt to protect our oil and natural gas value from basin differentials by securing crude oil transportation capacity, which enables us to sell oil in multiple markets, and entering into basis-swap derivatives, which provides pricing protection.
The fair values of our open derivative contracts are largely determined by forward price curves of the relevant indices. As of March 31, 2019, a 10% change in the forward curves associated with our derivatives would have changed our unaudited consolidated balance sheet's net derivative position to the following amounts:
(in thousands)
 
10% Increase
 
10% Decrease
Net (liability) asset derivative position
 
$
(46,647
)
 
$
45,720

As of March 31, 2019 and December 31, 2018, the net derivative positions were a liability of $1.0 million and an asset of $43.5 million, respectively. See Notes 7, 8.a and 17.b to 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 our January 2022 Notes and March 2023 Notes bear interest at fixed rates. The maturity years, outstanding balances and interest rates on our long-term debt as of March 31, 2019 were as follows:
 
 
Maturity year
(in millions except for interest rates)
 
2022
 
2023(1)
Senior Secured Credit Facility
 
$
—

 
$
270.0

Floating interest rate
 
—
%
 
3.750
%
January 2022 Notes
 
$
450.0

 
$
—

Fixed interest rate
 
5.625
%
 
—
%
March 2023 Notes
 
$
—

 
$
350.0

Fixed interest rate
 
—
%
 
6.250
%
_____________________________________________________________________________
(1)
The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the applicable Early Maturity Date, the Senior Secured Credit Facility will mature on such Early Maturity Date.
Counterparty and customer credit risk
See Note 10 to our unaudited consolidated financial statements and "Part II, Item 1. Legal Proceedings" included elsewhere in this Quarterly Report and Note 13 in the 2018 Annual Report for additional disclosures regarding credit risk. See Notes 2.e and

41
Table of Contents

5 in the 2018 Annual Report for additional information regarding our accounts receivable and revenue recognition, respectively. See Notes 7, 8.a and 17.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

42
Table of Contents

Item 4.    Controls and Procedures
Evaluation of disclosure controls and procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of March 31, 2019. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Evaluation of changes in internal control over financial reporting
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

43
Table of Contents

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 do not currently believe that any such legal proceedings 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 2018 Annual Report. There have been no material changes in our risk factors from those described in the 2018 Annual Report. The risks described in such reports 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.

44
Table of Contents

Item 2.    Purchases of Equity Securities
The following table summarized purchases of common stock by Laredo:
Period
 
Total number of shares purchased(1)
 
Weighted-average price paid per share
 
Total number of shares purchased as
part of publicly announced plans(2)
 
Maximum value that may yet be purchased under the program as of the respective period-end date (2)
January 1, 2019 - January 31, 2019
 
18,230

 
$
4.18

 
—

 
$
102,945,283

February 1, 2019 - February 28, 2019
 
681,136

 
$
3.83

 
—

 
$
102,945,283

March 1, 2019 - March 31, 2019
 
1,448

 
$
3.43

 
—

 
$
102,945,283

Total
 
700,814

 
 
 
—

 
 
______________________________________________________________________________
(1)
Included in these amounts are (i) 18,107 shares exchanged for the cost of exercise of stock options and (ii) 682,707 shares withheld by us to satisfy tax withholding obligations that arose upon the lapse of restrictions on restricted stock awards and the exercise of stock options.
(2)
In February 2018, our board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of shares repurchased, if any, will depend upon several factors, including market conditions, business conditions, the trading price of our common stock and the nature of other investment opportunities available to us.
Item 3.    Defaults Upon Senior Securities
None.
Item 4.    Mine Safety Disclosures
Not applicable.
Item 5.    Other Information
Not applicable.



45
Table of Contents

Item 6.    Exhibits
Exhibit Number
 
Description

 

 

 

 

 

 

 

 

 

 

 

 

 

 
101.SCH*

 
XBRL Schema Document.
101.CAL*

 
XBRL Calculation Linkbase Document.
101.DEF*

 
XBRL Definition Linkbase Document.
101.LAB*

 
XBRL Labels Linkbase Document.
101.PRE*

 
XBRL Presentation Linkbase Document.
XML

 
Extracted XBRL Instance Document.
______________________________________________________________________________
*
Filed herewith.
**
Furnished herewith.
#
Management contract or compensatory plan or arrangement.




46
Table of Contents

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 
 
LAREDO PETROLEUM, INC.
 
 
 
Date: May 2, 2019
By:
/s/ Randy A. Foutch
 
 
Randy A. Foutch
 
 
Chairman and Chief Executive Officer
 
 
(principal executive officer)
 
 
 
Date: May 2, 2019
By:
/s/ Michael T. Beyer
 
 
Michael T. Beyer

 
 
Senior Vice President and Chief Financial Officer
 
 
(principal financial officer & principal accounting officer)

47