View Filing Data

Oil and natural gas properties, full cost method:

198,805

194,601

Other current assets

14,574

14,402

Total current assets

332,232

365,253

Evaluated properties

5,103,635

4,446,781

Unevaluated properties not being depleted

140,299

342,731

Less accumulated depletion, depreciation, amortization and impairment

(4,218,942)

(1,586,237)

Oil and natural gas properties, net

1,024,992

3,203,275

Midstream service assets, net

131,725

108,462

43,538

42,345

1,200,255

3,354,082

Investment in equity method investee

77,443

117,788

192,524

58,288

Other assets, net

10,833

15,290

Undistributed revenue and royalties

1,813,287

3,910,701

Current liabilities:

Accounts payable

14,181

39,008

34,540

65,438

Accrued capital expenditures

61,872

148,241

Other current liabilities

115

106,222

101,032

Total current liabilities

216,815

353,834

Deferred income taxes, net

1,416,226

1,779,447

176,945

^[1]

Asset retirement obligations

44,759

31,042

Other noncurrent liabilities

4,040

6,232

Commitments and contingencies

1,681,840

2,347,500

Stockholders' equity:

Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2015 and 2014

Common stock, $0.01 par value, 450,000,000 shares authorized, and 213,808,003 and 143,686,491 issued, at December 31, 2015 and 2014, respectively

2,138

1,437

Additional paid-in capital

2,086,652

1,309,171

(Accumulated deficit) retained earnings

(1,957,343)

252,593

Total stockholders' equity

131,447

1,563,201

Total liabilities and stockholders' equity

$ 1,813,287

$ 3,910,701

[1]	See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	450,000,000	450,000,000
Common stock issued	213,808,003	143,686,491

Consolidated statements of operations - USD ($)
shares in Thousands, $ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Revenues:

$ 431,734

$ 737,203

$ 664,844

6,548

2,245

413

Production and ad valorem taxes

168,358

54,437

Total revenues

606,640

793,885

665,257

Costs and expenses:

Lease operating expenses

108,341

96,503

79,136

32,892

50,312

42,396

Midstream service expenses

5,846

5,429

3,368

Minimum volume commitments

5,235

2,552

891

174,338

53,967

Drilling rig fees

527

Accretion of asset retirement obligations

^[1]

90,425

106,044

89,696

Restructuring expenses

6,042

2,423

1,787

1,475

^[2]

277,724

246,474

233,944

2,374,888

3,904

Total costs and expenses

3,078,154

567,499

450,906

Commodity derivatives, net

(2,471,514)

226,386

214,351

Gain (loss) on derivatives:

214,291

327,920

79,902

Interest rate derivatives, net

(24)

6,799

(192)

Interest and other income

^[3]

(103,219)

(121,173)

(100,327)

426

294

163

Write-off of debt issuance costs

(31,537)

^[4]

(124)

(1,502)

Loss on disposal of assets, net

(2,127)

(3,252)

(1,508)

Non-operating income (expense), net

84,633

203,473

(23,267)

Income (loss) from continuing operations before income taxes

(2,386,881)

429,859

191,084

Income tax benefit (expense):

Deferred

176,945

(164,286)

(74,507)

Income (loss) from continuing operations

^[5]

176,945

(164,286)

(74,507)

(2,209,936)

265,573

116,577

1,423

Income (loss) from continuing operations (in dollars per share)

$ (2,209,936)

$ 265,573

$ 118,000

Basic:

$ (11.10)

$ 1.88

$ 0.88

Income from discontinued operations, net of tax (in dollars per share)

0.00

0.01

Income (loss) from continuing operations (in dollars per share)

(11.10)

1.88

0.89

Diluted:

(11.10)

1.85

0.87

Income from discontinued operations, net of tax (in dollars per share)

0.00

0.01

Weighted average common shares outstanding:

$ (11.10)

$ 1.85

$ 0.88

Basic (in shares)

^[6]

199,158

141,312

132,490

Diluted (in shares)

199,158

143,554

134,378

[1]	General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013.
[2]	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.
[3]	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.
[4]	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.
[5]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%
[6]	For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering.

Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	(Accumulated deficit) retained earnings
Balance at beginning of year (in shares) at Dec. 31, 2012		128,298		8
Balance at beginning of year at Dec. 31, 2012	$ 831,723	$ 1,283	$ 961,424	$ (4)	$ (130,980)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,469
Restricted stock awards		$ 15	(15)
Restricted stock forfeitures (in shares)		(229)
Restricted stock forfeitures		$ (2)	2
Vested restricted stock exchanged for tax withholding (in shares)				95
Vested restricted stock exchanged for tax withholding	(2,083)			$ (2,083)
Retirement of treasury stock (in shares)		(95)		(103)
Retirement of treasury stock		$ (1)	(2,086)	$ 2,087
Exercise of employee stock options (in shares)		104
Exercise of employee stock options	2,050	$ 1	2,049
Equity issuance, net of offering costs (in shares)		13,000
Equity issuance, net of offering costs	298,104	$ 130	297,974
Equity issued for acquisition, net of offering costs (in shares)		124
Equity issued for acquisition, net of offering costs	3,029	$ 1	3,028
Stock-based compensation	21,433		21,433
Net income (loss)	118,000				118,000
Balance at end of year (in shares) at Dec. 31, 2013		142,671		0
Balance at end of year at Dec. 31, 2013	1,272,256	$ 1,427	1,283,809	$ 0	(12,980)
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,234
Restricted stock awards		$ 12	(12)
Restricted stock forfeitures (in shares)		(148)
Restricted stock forfeitures		$ (1)	1
Vested restricted stock exchanged for tax withholding (in shares)				166
Vested restricted stock exchanged for tax withholding	(4,242)			$ (4,242)
Retirement of treasury stock (in shares)		(166)		(166)
Retirement of treasury stock		$ (2)	(4,240)	$ 4,242
Exercise of employee stock options (in shares)		95
Exercise of employee stock options	1,885	$ 1	1,884
Stock-based compensation	27,729		27,729
Net income (loss)	265,573				265,573
Balance at end of year (in shares) at Dec. 31, 2014		143,686		0
Balance at end of year at Dec. 31, 2014	1,563,201	$ 1,437	1,309,171	$ 0	252,593
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		1,902
Restricted stock awards		$ 19	(19)
Restricted stock forfeitures (in shares)		(553)
Restricted stock forfeitures		$ (6)	6
Vested restricted stock exchanged for tax withholding (in shares)				227
Vested restricted stock exchanged for tax withholding	(2,811)			$ (2,811)
Retirement of treasury stock (in shares)		(227)		(227)
Retirement of treasury stock		$ (2)	(2,809)	$ 2,811
Equity issued for acquisition, net of offering costs (in shares)		69,000
Equity issued for acquisition, net of offering costs	754,163	$ 690	753,473
Stock-based compensation	26,830		26,830
Net income (loss)	(2,209,936)				(2,209,936)
Balance at end of year (in shares) at Dec. 31, 2015		213,808		0
Balance at end of year at Dec. 31, 2015	$ 131,447	$ 2,138	$ 2,086,652	$ 0	$ (1,957,343)

Consolidated statements of cash flows - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Cash flows from operating activities:

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

$ (2,209,936)

$ 265,573

$ 118,000

Deferred income tax (benefit) expense

(176,945)

164,286

75,288

277,724

246,474

234,571

2,374,888

3,904

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

31,537

^[1]

Bad debt expense

255

342

653

24,509

23,079

21,433

Accretion of asset retirement obligations

2,423

1,787

1,475

Mark-to-market on derivatives:

Gain on derivatives, net

(214,291)

(327,920)

(79,878)

Cash settlements received for matured derivatives, net

255,281

28,241

3,745

Cash settlements received for early terminations and modification of derivatives, net

76,660

6,008

Change in net present value of deferred premiums paid for derivatives

203

220

462

Cash premiums paid for derivatives

(5,167)

(7,419)

(10,277)

Amortization of debt issuance costs

4,727

5,137

5,023

Write-off of debt issuance costs

124

1,502

Loss on disposal of assets, net

2,127

3,252

1,508

(Income) loss on equity method investee

(6,799)

192

(29)

Cash settlement of performance unit awards

(2,738)

(2,080)

Other, net

403

(230)

Decrease (increase) in accounts receivable

38,975

(49,953)

6,825

Increase in other assets

(2,309)

(16,688)

(7,438)

(Decrease) increase in accounts payable

(24,827)

23,006

(32,581)

(Decrease) increase in undistributed revenues and royalties

(30,898)

30,314

(941)

(Decrease) increase in other accrued liabilities

(26,996)

23,837

16,458

Increase in other noncurrent liabilities

119

2,825

499

Increase in fair value of performance unit awards

4,081

601

4,733

Net cash provided by operating activities

315,947

498,277

364,729

Capital expenditures:

Acquisitions of oil and natural gas properties

(6,493)

(33,710)

Acquisition of mineral interests

(7,305)

Investment in equity method investee

(588,017)

(1,251,757)

(702,349)

Midstream service assets

(35,459)

(60,548)

(24,409)

Other fixed assets

(9,125)

(27,444)

(16,257)

(99,855)

(55,164)

(3,287)

Proceeds from dispositions of capital assets, net of costs

64,949

1,750

450,128

Net cash used in investing activities

(667,507)

(1,406,961)

(329,884)

Cash flows from financing activities:

Borrowings on Senior Secured Credit Facility

310,000

300,000

230,000

Payments on Senior Secured Credit Facility

(475,000)

(395,000)

Redemption of January 2019 Notes

(576,200)

Proceeds from issuance of common stock, net of offering costs

754,163

298,104

Purchase of treasury stock

(2,811)

(4,242)

(2,083)

Proceeds from exercise of employee stock options

1,885

2,050

Payments for debt issuance costs

(6,759)

(7,791)

(2,987)

Net cash provided by financing activities

353,393

739,852

130,084

Net increase (decrease) in cash and cash equivalents

1,833

(168,832)

164,929

Cash and cash equivalents, beginning of period

29,321

198,153

33,224

Cash and cash equivalents, end of period

31,154

29,321

198,153

March 2023 Notes

Cash flows from financing activities:

Issuance of long-term debt

350,000

January 2022 Notes

Cash flows from financing activities:

Issuance of long-term debt

$ 0

$ 450,000

$ 0

[1]

Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.

Organization	12 Months Ended
Organization	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization The Company (defined below) is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below). Laredo Petroleum, Inc. ("Laredo"), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc."), a Delaware corporation, and Laredo Inc's subsidiaries, Laredo Petroleum Texas, LLC ("Laredo Texas"), a Texas limited liability company, Laredo Gas Services, LLC ("Laredo Gas"), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. ("Laredo Dallas"), a Delaware corporation. Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc.'s subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc. at the time of the internal corporate reorganization, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("LMS"). Laredo Inc. merged with and into Laredo with Laredo surviving and changing its name to "Laredo Petroleum, Inc." (the events described in this paragraph collectively, the "Internal Consolidation"). On October 24, 2014, Laredo formed Garden City Minerals, LLC ("GCM"), a Delaware limited liability company, for the purpose of holding its mineral interests. GCM is wholly owned by Laredo. GCM and LMS (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company," (i) when used in the present tense, prospectively or from October 24, 2014, refers to Laredo, LMS and GCM collectively; (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and LMS collectively; and (iii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in and around Laredo's primary production corridors, (ii) water takeaway in and around Laredo's primary production corridors and (iii) oil and natural gas takeaway optionality in the field coupled with firm service commitments to maximize Laredo's oil, natural gas liquids ("NGL") and natural gas revenues.

Basis of presentation and significant accounting policies

12 Months Ended

Dec. 31, 2015

Basis of presentation and significant accounting policies

a. Basis of presentation

The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying 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. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See Note 15 for additional discussion of the Company's equity method investment.

b. Use of estimates in the preparation of consolidated financial statements

The preparation of the accompanying 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.

Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

c. Reclassifications

Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2015 presentation. These reclassifications had no impact to previously reported net income, stockholders' equity or cash flows. See Notes 7 and 14 for discussion regarding reclassifications related to the Company's early adoption of new guidance related to the classification of income taxes. See Notes 2.k, 5.h and 14 for discussion regarding the Company's early adoption of new guidance related to the presentation of deferred loan costs.

d. Cash and cash equivalents

The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 11 for discussion regarding the Company's exposure to credit risk.

e. Accounts receivable

The Company sells produced and purchased oil, NGL and natural gas to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consisted of the following components as of December 31:



(in thousands)	2015		2014
Matured derivatives	$	27,469	$	16,098
Oil, NGL and natural gas sales	25,582		57,070
Joint operations, net⁽¹⁾	21,375		33,808
Purchased oil and other product sales	11,775		18,917
Other	1,498		1,036
Total	$	87,699	$	126,929

_____________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively.

f. Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives.

Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives.

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's commodity derivatives.

g. Oil and natural gas properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated. Approximately $140.3 million and $342.7 million of such costs were excluded from the depletion base as of December 31, 2015 and 2014, respectively. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion and impairment for oil and natural gas properties was $4.2 billion and $1.6 billion for the years ended December 31, 2015 and 2014, respectively. Depletion expense for oil and natural gas properties was $263.7 million, $237.1 million and $228.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $16.13, $20.21 and $20.34 for the years ended December 31, 2015, 2014 and 2013, respectively.

The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. Per the Securities and Exchange Commission ("SEC") guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

In the event the unamortized cost of evaluated oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:



	For the quarters ended								For the years ended⁽¹⁾
	December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015		December 31, 2014		December 31, 2013
Benchmark Prices
Oil ($/Bbl)	$	46.79	$	55.73	$	68.17	$	79.21	$	91.48	$	93.52
NGL ($/Bbl)	18.75		21.87		26.73		31.25		—		—
Natural gas ($/MMBtu)	2.47		2.89		3.22		3.73		4.25		3.57
Realized Prices
Oil ($/Bbl)	45.58		54.28		66.68		77.72		89.57		92.26
NGL ($/Bbl)	12.50		15.25		19.56		23.75		—		—
Natural gas ($/Mcf)	1.89		2.30		2.62		3.09		6.39		5.52
Non-cash full cost ceiling impairment (in thousands)	$	975,011	$	906,420	$	488,046	$	—	$	—	$	—

_____________________________________________________________________________


(1)	For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.

Full cost ceiling impairment expense for the year ended December 31, 2015 in the consolidated statements of operations was $2.4 billion. The amount is included in the "Impairment expense" line item in the consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 17.

h. Midstream service assets

Midstream service assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of impairment. See Note 2.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation expense from continuing operations for midstream service assets was $7.5 million, $4.3 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Midstream service assets consist of the following as of December 31:



(in thousands)	2015			2014
Midstream service assets	$	147,811		$	117,052
Less accumulated depreciation	(16,086		)	(8,590		)
Total, net	$	131,725		$	108,462

i. Other fixed assets

Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation and amortization expense from continuing operations for other fixed assets was $6.5 million, $5.1 million and $4.4 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Other fixed assets consist of the following as of December 31:



(in thousands)	2015			2014
Computer hardware and software	$	12,148		$	13,495
Vehicles	9,266			7,802
Leasehold improvements	7,710			6,867
Real estate and buildings	7,618			4,908
Aircraft	4,952			4,952
Other	5,105			4,909
Depreciable total	46,799			42,933
Less accumulated depreciation and amortization	(18,169		)	(13,820		)
Depreciable total, net	28,630			29,113
Land	14,908			13,232
Total, net	$	43,538		$	42,345

j. Long-lived assets, materials and supplies and line-fill

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Materials and supplies used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. During the years ended December 31, 2015 and 2014, the Company reduced materials and supplies by $2.8 million and $1.8 million, respectively, in order to reflect the balance at LCM. These adjustments are included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's exploration and production segment presented in Note 17. The Company determined an LCM adjustment was not necessary for materials and supplies during the year ended December 31, 2013.

The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the years ended December 31, 2015 and 2014, the Company recorded LCM adjustments of $1.3 million and $2.1 million, respectively, related to its line-fill, which is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17.

For the year ended December 31, 2015, the Company recorded an impairment, based on an internally developed cash flow model, of $1.3 million related to its compressed natural gas station. This amount is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17. There were no comparable impairments recorded for the years ended December 31, 2014 or 2013.

k. Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the year ended December 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). The Company capitalized $7.8 million of debt issuance costs during the year ended December 31, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). The Company capitalized $3.0 million of debt issuance costs during the year ended December 31, 2013. The Company had total debt issuance costs of $23.9 million and $28.5 million, net of accumulated amortization of $17.0 million and $19.4 million, as of December 31, 2015 and 2014, respectively.

The Company wrote-off approximately $6.6 million of debt issuance costs during the year ended December 31, 2015 as a result of the early redemption of the January 2019 Notes (as defined below), which is included in the consolidated statements of operations in the "Loss on early redemption of debt" line item. During the year ended December 31, 2014, $0.1 million of debt issuance costs were written-off as a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes. During the year ended December 31, 2013, $1.5 million of debt issuance costs were written off as a result of changes in the borrowing base of the Senior Secured Credit Facility due to the Anadarko Basin Sale (as defined below). Debt issuance costs written-off during the years ended December 31, 2014 and 2013 are included in the consolidated statements of operations in the "Write-off of debt issuance costs" line item. See Notes 4.d, 5.b, 5.c, 5.e and 5.f for definition of and information regarding the Anadarko Basin Sale, March 2023 Notes, January 2022 Notes, January 2019 Notes and Senior Secured Credit Facility, respectively.

During the year ended December 31, 2015, the Company early-adopted new guidance that seeks to simplify the presentation of debt issuance costs and has applied its provisions retrospectively. The adoption of this standard resulted in $18.8 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes being presented in "Long-term debt, net" rather than the past presentation in "Other assets, net" within its consolidated balance sheets as of December 31, 2015 and December 31, 2014, respectively. Other than this reclassification of the December 31, 2014 amount, the adoption of this standard did not have an impact on the Company's consolidated financial statements. Debt issuance costs related to the Senior Secured Credit Facility remain presented in "Other assets, net" on the Company's consolidated balance sheets. See Notes 5.h and 14 for additional discussion of debt issuance costs.

Future amortization expense of debt issuance costs as of the period presented is as follows:



(in thousands)	December 31, 2015
2016	$	4,503
2017	4,575
2018	4,349
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	23,932

l. Other current liabilities

Other current liabilities consist of the following components as of December 31:



(in thousands)	2015		2014
Capital contribution payable to equity method investee⁽¹⁾	$	27,583	$	—
Accrued interest payable	24,208		37,689
Accrued compensation and benefits	14,342		13,034
Lease operating expense payable	13,205		11,963
Costs of purchased oil	12,189		20,114
Other accrued liabilities	14,695		18,232
Total other current liabilities	$	106,222	$	101,032

_____________________________________________________________________________


(1)	See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee.

m. Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

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

The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates are reasonably determinable.

The following reconciles the Company's asset retirement obligation liability as of December 31:



(in thousands)	2015			2014
Liability at beginning of year	$	32,198		$	21,743
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	2,236			6,370
Accretion expense	2,423			1,787
Liabilities settled upon plugging and abandonment	(146		)	(450		)
Liabilities removed due to sale of property	(2,005		)	—
Revision of estimates⁽¹⁾	11,600			2,748
Liability at end of year	$	46,306		$	32,198

_____________________________________________________________________________


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

n. Fair value measurements

The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.g for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives.

o. Treasury stock

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

p. Revenue recognition

Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2015 or 2014. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million.

Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership.

q. Fees received for the operation of jointly-owned oil and natural gas properties

The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.

The following amounts have been recorded for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Fees received for the operation of jointly-owned oil and natural gas properties	$	3,125	$	3,265	$	3,398

r. Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and performance unit awards. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.

s. Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. See Note 7 for detail of amounts recorded in the consolidated financial statements and discussion regarding the valuation allowance taken in 2015.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2015, 2014 or 2013.

t. 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 December 31, 2015 or 2014.

u. Supplemental disclosures of cash flow and non-cash investing and financing information

The following table summarizes the supplemental disclosure of cash flow information for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Cash paid for interest, net of $236, $150 and $255 of capitalized interest, respectively	$	112,457	$	104,936	$	95,622

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Change in accrued capital expenditures	$	(86,369	)	$	31,913		$	(5,284	)
Change in accrued capital contribution to equity method investee	27,583			(2,597		)	2,597
Capitalized asset retirement cost	13,836			9,118			6,790
Capitalized stock-based compensation	2,321			4,650			—
Equity issued in connection with acquisition	—			—			3,029

Equity offering	12 Months Ended
Equity offering	Dec. 31, 2015
Equity [Abstract]
Equity offering	Equity offerings a. March 2015 Equity Offering On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts and commissions and offering expenses, from the March 2015 Equity Offering. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of the Company's stock during the year ended December 31, 2014. b. August 2013 Equity Offering On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "August 2013 Equity Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net proceeds of $298.1 million, after underwriting discounts and commissions and offering expenses, from the August 2013 Equity Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the Selling Stockholders.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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-Number Topic 4
-Section C

Acquisitions and divestitures

Acquisitions and divestitures

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

a. 2015 Divestiture of non-strategic assets

On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Oil, NGL and natural gas sales	$	5,138	$	19,337	$	24,187
Expenses⁽¹⁾	5,791		11,082		11,826

_____________________________________________________________________________


(1)	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

b. Summary of 2014 and 2013 acquisitions

The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.

The following table presents the Company's 2014 and 2013 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note C in the Company's 2013 Annual Report on Form 10-K and Note 3 in the Company's 2014 Annual Report on Form 10-K.



(in thousands)	Accounting treatment	Cash consideration		Common stock issued⁽²⁾
August 28, 2014 acquisition of leasehold interests	Acquisition of assets	$	192,484	$	—
June 23, 2014 acquisition of evaluated and unevaluated oil and natural gas properties	Acquisition method	1,800		—
June 11, 2014 acquisition of evaluated and unevaluated oil and natural gas properties	Acquisition method	4,693		—
February 25, 2014 acquisition of mineral interests	Acquisition of assets	7,305		—
September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties⁽¹⁾	Acquisition method	33,710		3,029

_____________________________________________________________________________


(1)	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.

(2)

In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). In accordance with federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 9.

c. 2013 divestiture of Dalhart Basin acreage

On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million, subject to customary closing adjustments.

d. 2013 divestiture of Anadarko assets

On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.

The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the period presented:



(in thousands)	For the year ended December 31, 2013
Revenues	$	59,631
Expenses⁽¹⁾	46,357

_____________________________________________________________________________


(1)	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net" during the year ended December 31, 2013.

The following represents operating results from discontinued operations for the period presented:



(in thousands)	For the year ended December 31, 2013
Revenues:
Midstream service revenue	$	4,020
Total revenues from discontinued operations	4,020
Cost and expenses:
Midstream service expense, net	1,189
Depreciation and amortization	627
Total costs and expenses from discontinued operations	1,816
Non-operating expense, net	—
Income (loss) from discontinued operations before income tax	2,204
Income tax (expense) benefit	(781		)
Income (loss) from discontinued operations	$	1,423

Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

a. Interest expense

The following amounts have been incurred and charged to interest expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Cash payments for interest	$	112,693		$	105,086		$	95,877
Amortization of debt issuance costs and other adjustments	4,243			4,433			4,926
Change in accrued interest	(13,481		)	11,804			(221		)
Interest costs incurred	103,455			121,323			100,582
Less capitalized interest	(236		)	(150		)	(255		)
Total interest expense	$	103,219		$	121,173		$	100,327

b. March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"), and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 with interest accruing at a rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors 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 Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility (as defined below), or liquidation or dissolution (collectively, the "Releases").

The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.e for additional discussion of this early redemption.

The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to March 15, 2016, the Company may redeem all, but not less than all, of the March 2023 Notes at a redemption price equal to 110% of the principal amount of the March 2023 Notes plus any accrued and unpaid interest to, but not including, the date of redemption.

c. January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"), and entered into an Indenture (the "2014 Indenture") among Laredo, LMS as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-annually in cash in arrears on January 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 the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.

The January 2022 Notes were issued pursuant to the 2014 Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes.

Laredo will have the option to redeem all or part of the January 2022 Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, the Company may redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the January 2022 Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the January 2022 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering.

d. May 2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.

The May 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the "2012 Indenture"), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture.

Laredo will have the option to redeem the May 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1, 2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any, to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the May 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Laredo may also be required to make an offer to purchase the May 2022 Notes upon a change of control triggering event.

e. January 2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.

The January 2019 Notes were issued under and were governed by an indenture dated January 20, 2011 (as supplemented, the "2011 Indenture") among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales.

On April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.

f. Senior Secured Credit Facility

As of December 31, 2015, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion and an aggregate elected commitment of $1.0 billion with $135.0 million outstanding and was subject to an interest rate of 1.90%. The borrowing base is subject to a semi-annual redetermination occurring each May 1 and November 1 based on the financial institutions' evaluation of the Company's oil and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 0.5% to 1.5% and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one-month, two-month, three-month, six-month or, to the extent available, 12-month interest periods (and in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.5% to 2.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility.

The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantor's assets and stock, including oil, NGL and natural gas properties, constituting at least 80% of the present value of the Company's evaluated reserves. Further, the Company is subject to various financial and non-financial ratios on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of net interest expense plus letter of credit fees of not less than 2.50 to 1.00, in each case for the four quarters then ending. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company was in compliance with these covenants 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 $20.0 million. No letters of credit were outstanding as of December 31, 2015 or 2014.

g. Fair value of debt

The Company has not elected to account for its debt at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented:



	December 31, 2015				December 31, 2014
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2019 Notes⁽¹⁾	$	—	$	—	$	551,295	$	550,000
January 2022 Notes	450,000		388,301		450,000		396,014
May 2022 Notes	500,000		460,000		500,000		467,529
March 2023 Notes	350,000		301,000		—		—
Senior Secured Credit Facility	135,000		134,993		300,000		300,279
Total value of debt	$	1,435,000	$	1,284,294	$	1,801,295	$	1,713,822

_____________________________________________________________________________


(1)	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.

The fair values of the debt outstanding on the January 2019 Notes, the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the December 31, 2015 and 2014 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2015 and 2014 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

h. Debt issuance costs

The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the consolidated balance sheets as of the periods presented:



	December 31, 2015							December 31, 2014
(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 2019 Notes⁽¹⁾	$	—	$	—		$	—	$	551,295	$	(7,031	)	$	544,264
January 2022 Notes	450,000		(5,939		)	444,061		450,000		(6,916		)	443,084
May 2022 Notes	500,000		(7,066		)	492,934		500,000		(7,901		)	492,099
March 2023 Notes	350,000		(5,769		)	344,231		—		—			—
Senior Secured Credit Facility⁽²⁾	135,000		—			135,000		300,000		—			300,000
Total	$	1,435,000	$	(18,774	)	$	1,416,226	$	1,801,295	$	(21,848	)	$	1,779,447

_____________________________________________________________________________


(1)	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.


(2)	Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets.

Employee compensation

12 Months Ended

Dec. 31, 2015

Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares.

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets.

a. Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, for reasons other than death and disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then 20% annually thereafter, (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in year three, (iv) fully on the first anniversary of the grant date and (v) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.

The following table reflects the outstanding restricted stock awards for the years ended December 31, 2015, 2014 and 2013:



(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2012	1,195		$	15.06
Granted	1,469		$	18.17
Forfeited	(229	)	$	18.47
Vested⁽¹⁾	(636	)	$	18.69
Outstanding as of December 31, 2013	1,799		$	19.17
Granted	1,234		$	25.68
Forfeited	(148	)	$	22.56
Vested⁽¹⁾	(680	)	$	19.13
Outstanding as of December 31, 2014	2,205		$	22.63
Granted	1,902		$	11.98
Forfeited	(553	)	$	20.48
Vested⁽¹⁾	(1,015	)	$	22.32
Outstanding as of December 31, 2015	2,539		$	15.26

_____________________________________________________________________________


(1)	The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards.

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2015, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $21.6 million. Such cost is expected to be recognized over a weighted-average period of 1.74 years.

b. Restricted stock option awards

Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the years ended December 31, 2015, 2014 and 2013:



(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2012	459		$	24.11	10
Granted	1,019		$	17.34
Exercised⁽¹⁾	(104	)	$	20.79
Expired or canceled	(12	)	$	24.11
Forfeited	(133	)	$	19.88
Outstanding as of December 31, 2013	1,229		$	19.32	8.82
Granted	336		$	25.60
Exercised⁽¹⁾	(95	)	$	19.93
Expired or canceled	(30	)	$	21.15
Forfeited	(73	)	$	19.68
Outstanding as of December 31, 2014	1,367		$	20.76	8.17
Granted	632		$	11.93
Exercised	—		$	—
Expired or canceled	(82	)	$	19.92
Forfeited	(139	)	$	18.17
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Vested and exercisable at end of period⁽²⁾	545		$	20.77	6.94
Expected to vest at end of period⁽³⁾	1,219		$	16.51	8.34

_____________________________________________________________________________


(1)	The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards.


(2)	The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value.


(3)	The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and is recognizing the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2015, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $7.0 million. Such cost is expected to be recognized over a weighted-average period of 2.35 years.

The assumptions used to estimate the fair value of restricted stock options granted are as follows:



	February 27, 2015			February 27, 2014			February 15, 2013			February 3, 2012
Risk-free interest rate⁽¹⁾	1.70		%	1.88		%	1.19		%	1.14		%
Expected option life⁽²⁾	6.25 years			6.25 years			6.25 years			6.25 years
Expected volatility⁽³⁾	52.59		%	53.21		%	58.89		%	59.98		%
Fair value per stock option	$	6.15		$	13.41		$	9.67		$	13.52

_____________________________________________________________________________


(1)	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.


(2)	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(3)	The Company utilized its own volatility in order to develop the expected volatility for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:



Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.

c. Performance share awards

The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.

The 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017 and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. During the year ended December 31, 2015, the Company granted 602,501 2015 Performance Share Awards and all remain outstanding as of December 31, 2015. The 271,667 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met. No 2014 Performance Share Awards were forfeited during the years ended December 31, 2015 or 2014.

As of December 31, 2015, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $9.9 million. Such cost is expected to be recognized over a weighted-average period of 1.86 years.

The assumptions used to estimate the fair value of the Performance Share Awards granted are as follows:



	February 27, 2015			February 27, 2014
Risk-free rate⁽¹⁾	0.95		%	0.63		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	53.78		%	38.21		%
Laredo stock closing price as of the grant date	$	11.93		$	25.60
Fair value per performance share	$	16.23		$	28.56

_____________________________________________________________________________


(1)	The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.

d. Stock-based compensation award expense

The following has been recorded to stock-based compensation expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Restricted stock award compensation	$	17,534		$	21,982		$	17,084
Restricted stock option award compensation	4,074			3,639			4,349
Restricted performance share award compensation	5,222			2,108			—
Total stock-based compensation, gross	26,830			27,729			21,433
Less amounts capitalized in oil and natural gas properties	(2,321		)	(4,650		)	—
Total stock-based compensation, net of amounts capitalized	$	24,509		$	23,079		$	21,433

During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications recognized during the year ended December 31, 2013 was $4.7 million.

e. Performance unit awards

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation was based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period was recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service had already been provided.

The 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100 per unit during the first quarter of 2015.

The following table reflects the outstanding performance unit awards for the periods presented:



(in thousands)	2013 Performance Unit Awards⁽²⁾		2012 Performance Unit Awards ⁽³⁾
Outstanding at December 31, 2012	—		47
Granted	58		—
Forfeited	(4	)	(9	)
Vested⁽¹⁾	(10	)	(11	)
Outstanding at December 31, 2013	44		27
Vested	—		(27	)
Outstanding at December 31, 2014	44		—
Vested	(44	)	—
Outstanding at December 31, 2015	—		—

_____________________________________________________________________________


(1)	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.


(2)	The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016.


(3)	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.

The liability related to the 2013 Performance Unit Awards as of December 31, 2015 was $6.4 million and represents the cash payment made in the first quarter of 2016. The fair value of the 2013 Performance Unit Awards as of December 31, 2014 was $3.5 million. The liability related to the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million and represents the cash payment made in the first quarter of 2015. The fair values of the 2013 Performance Unit Awards and 2012 Performance Unit Awards as of December 31, 2013 were $5.7 million and $3.8 million, respectively.

The following has been recorded to performance unit award compensation expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
2013 Performance Unit Award compensation expense	$	4,081	$	409	$	2,863
2012 Performance Unit Award compensation expense	—		192		1,870
Total performance unit award compensation expense	$	4,081	$	601	$	4,733

Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is recognized in "General and administrative" in the Company's consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" on the consolidated balance sheets.

f. Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.

The following table presents the cost recognized for the Company's defined contribution plan for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Contributions	$	1,847	$	2,202	$	1,886

Income taxes

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Income Taxes

Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit (expense) attributable to income (loss) from continuing operations for the periods presented consisted of the following:



	For the years ended December 31,
(in thousands)	2015		2014			2013
Current taxes:
Federal	$	—	$	—		$	—
State	—		—			—
Deferred taxes:
Federal	152,590		(147,445		)	(64,034		)
State	24,355		(16,841		)	(10,473		)
Income tax benefit (expense)	$	176,945	$	(164,286	)	$	(74,507	)

The following presents the comprehensive benefit (expense) for income taxes for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014			2013
Comprehensive benefit (expense) for income taxes allocable to:
Continuing operations	$	176,945	$	(164,286	)	$	(74,507	)
Discontinued operations	—		—			(781		)
Comprehensive benefit (expense) for income taxes	$	176,945	$	(164,286	)	$	(75,288	)

Income tax benefit (expense) attributable to income (loss) from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2015 and 2014 and 34% for the year ended December 31, 2013 to pre-tax earnings as a result of the following:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Income tax benefit (expense) computed by applying the statutory rate	$	835,408		$	(150,450	)	$	(64,969	)
State income tax, net of federal tax benefit and increase in valuation allowance	13,975			(11,099		)	(7,532		)
Non-deductible stock-based compensation	(256		)	(509		)	(1,070		)
Stock-based compensation tax deficiency	(3,274		)	(266		)	(559		)
Increase in deferred tax valuation allowance	(668,702		)	(1,139		)	(63		)
Other items	(206		)	(823		)	(314		)
Income tax benefit (expense)	$	176,945		$	(164,286	)	$	(74,507	)

The effective tax rate for the Company's continuing operations was 7%, 38% and 39% for the years ended December 31, 2015, 2014 and 2013, respectively. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2015, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, therefore a valuation allowance of $676.0 million was recorded.

The impact of significant discrete items is separately recognized in the year in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the years ended December 31, 2015, 2014 and 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the years ended December 31, 2014 and 2013, certain restricted stock options were exercised. There were no comparable exercise of stock options during the year ended December 31, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax benefit (expense) attributable to continuing operations.

The following table presents the tax impact of these shortfalls for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Vesting of restricted stock	$	3,334	$	112	$	425
Exercise of restricted stock options	—		158		150
Tax expense due to shortfalls	$	3,334	$	270	$	575

Significant components of the Company's net deferred tax liability as of December 31 are as follows:



(in thousands)	2015			2014
Oil and natural gas properties, midstream service assets and other fixed assets	$	306,997		$	(424,712	)
Net operating loss carry-forward	479,022			353,724
Derivatives	(98,675		)	(121,365		)
Stock-based compensation	11,597			10,718
Equity method investee	(31,711		)	(2,331		)
Accrued bonus	4,763			3,256
Capitalized interest	2,525			3,049
Materials and supplies impairment	1,647			642
Other	1,173			1,373
Net deferred tax asset (liability) before valuation allowance	677,338			(175,646		)
Valuation allowance	(677,338		)	(1,299		)
Net deferred tax asset (liability)	$	—		$	(176,945	)

Deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 are as follows:



(in thousands)	2015		2014⁽¹⁾			Offset⁽¹⁾			2014 new presentation⁽¹⁾
Deferred tax asset	$	—	$	—		$	—		$	—
Deferred tax liability:
Current	—		(71,191		)	71,191			—
Noncurrent	—		(105,754		)	(71,191		)	(176,945		)
Deferred tax liability	$	—	$	(176,945	)	$	—		$	(176,945	)
Net deferred tax liability	$	—	$	(176,945	)	$	—		$	(176,945	)

_____________________________________________________________________________


(1)	See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.

The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of the period presented:



(in thousands)	December 31, 2015
2026	$	2,741
2027	38,651
2028	228,661
2029	101,932
2030	80,963
Thereafter	915,642
Total	$	1,368,590

The Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of December 31, 2015. These carry-forwards begin expiring in 2026. As of December 31, 2015, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2015, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.

The Company's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of December 31, 2015, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.

The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2015, a valuation allowance of $677.3 million has been recorded against the deferred tax asset.

Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a consolidated basis. Following the Internal Consolidation, the surviving entities file a single return. The Company's income tax returns for the years 2012 through 2015 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

Derivatives

12 Months Ended

Dec. 31, 2015

a. Commodity derivatives

The Company engages in derivative transactions such as puts, swaps, collars and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of December 31, 2015, the Company had 18 open derivative contracts with financial institutions that extend from January 2016 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the consolidated statements of operations in the "Gain (loss) on derivatives" line items.

Each put transaction has an established floor price. The Company pays the counterparty a premium, which can be deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.

Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

Each basis swap transaction has an established fixed basis differential corresponding to two index prices. Depending on the difference of the two index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume.

During the first quarter of 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract that hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.

During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap	2,386,800	$	4.31	August 2013 - December 2013
Swap	3,978,500	$	4.36	January 2014 - December 2014

The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:



	Aggregate volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015

The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Cash settlements received for matured commodity derivatives	$	255,281	$	28,241	$	4,046
Cash settlements paid for matured interest rate swaps	—		—		(301		)
Early terminations and modification of commodity derivatives received⁽¹⁾	—		76,660		6,008
Cash settlements received for derivatives, net	$	255,281	$	104,901	$	9,753

_____________________________________________________________________________


(1)	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts.

The following table summarizes open positions as of December 31, 2015, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:



	Year 2016		Year 2017
Oil positions:⁽¹⁾
Puts:
Hedged volume (Bbl)	1,296,000		—
Weighted-average price ($/Bbl)	$	45.00	$	—
Swaps:
Hedged volume (Bbl)	1,573,800		—
Weighted-average price ($/Bbl)	$	84.82	$	—
Collars:
Hedged volume (Bbl)	3,654,000		2,628,000
Weighted-average floor price ($/Bbl)	$	73.99	$	77.22
Weighted-average ceiling price ($/Bbl)	$	89.63	$	97.22
Totals:
Total volume hedged with floor price (Bbl)	6,523,800		2,628,000
Weighted-average floor price ($/Bbl)	$	70.84	$	77.22
Total volume hedged with ceiling price (Bbl)	5,227,800		2,628,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	97.22
Natural gas positions:⁽²⁾
Collars:
Hedged volume (MMBtu)	18,666,000		5,475,000
Weighted-average floor price ($/MMBtu)	$	3.00	$	3.00
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	4.00

_____________________________________________________________________________


(1)	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").


(2)	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

b. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. In prior periods, interest rate derivative agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference, and conversely, the counterparties were required to pay the Company if LIBOR was higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments were recorded in current earnings. In prior years, the Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate derivatives were in place as of December 31, 2015 or 2014.

c. Balance sheet presentation

In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net basis as "Derivatives" on the consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.

By using derivatives to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Fair value measurements

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair value measurements

The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate derivatives, at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows:



Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2015, 2014 or 2013.

a. Fair value measurement on a recurring basis

The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:



(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248



(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of December 31, 2014:
Assets
Current:
Oil derivatives	$	—	$	190,303	$	—		$	190,303		$	—		$	190,303
Natural gas derivatives	—		9,647		—			9,647			—			9,647
Oil deferred premiums	—		—		—			—			(4,653		)	(4,653		)
Natural gas deferred premiums	—		—		—			—			(696		)	(696		)
Noncurrent:
Oil derivatives	$	—	$	117,963	$	—		$	117,963		$	—		$	117,963
Natural gas derivatives	—		3,646		—			3,646			—			3,646
Oil deferred premiums	—		—		—			—			(3,821		)	(3,821		)
Natural gas deferred premiums	—		—		—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,768		)	(4,768		)	4,653			(115		)
Natural gas deferred premiums	—		—		(696		)	(696		)	696			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(3,821		)	(3,821		)	3,821			—
Natural gas deferred premiums	—		—		—			—			—			—
Net derivative position	$	—	$	321,559	$	(9,285	)	$	312,274		$	—		$	312,274

These items are included as "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of commodity derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.

The Company's deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

The following table presents actual cash payments required for deferred premiums for the calendar years presented:



(in thousands)	December 31, 2015
2016	$	8,629
2017	5,796
2018	426
Total	$	14,851

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



	For the years ended December 31,
(in thousands)	2015			2014			2013
Balance of Level 3 at beginning of period	$	(9,285	)	$	(12,684	)	$	(24,709	)
Change in net present value of deferred premiums for derivatives	(203		)	(220		)	(462		)
Total purchases and settlements:
Purchases	(10,298		)	(3,800		)	—
Settlements⁽¹⁾	5,167			7,419			12,487
Balance of Level 3 at end of period	$	(14,619	)	$	(9,285	)	$	(12,684	)

_____________________________________________________________________________


(1)	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

b. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. See Note 2.j for discussion of the Company's impairment of line-fill, materials and supplies and other fixed assets for the periods presented.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.g for discussion regarding the prices used in the calculation of discounted cash flows and the Company's second, third and fourth-quarter 2015 full cost ceiling impairments.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Net income (loss) per share

Net income (loss) per share

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the year ended December 31, 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per share.

The effects of the Company's then outstanding restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and in February 2012 to purchase 280,626 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income per share for each of the years ended December 31, 2014 and 2013, because the exercise prices of these options were greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive.

The effect of the Company's outstanding restricted stock options that were granted in February 2013 to purchase 750,338 shares of common stock at $17.34 per share was excluded from the calculation of diluted net income per share for the years ended December 31, 2014 and 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeded the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive. For the year ended December 31, 2014, the 2014 Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore the 2014 Performance Share Awards were excluded from the calculation of diluted net income per share. There were no outstanding performance share awards in 2013.

The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented:



	For the years ended December 31,
(in thousands, except for per share data)	2015			2014		2013
Net income (loss) (numerator):
Income (loss) from continuing operations—basic and diluted	$	(2,209,936	)	$	265,573	$	116,577
Income from discontinued operations, net of tax—basic and diluted	—			—		1,423
Net income (loss)—basic and diluted	$	(2,209,936	)	$	265,573	$	118,000
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic⁽¹⁾	199,158			141,312		132,490
Non-vested restricted stock awards	—			2,242		1,888
Weighted-average common shares outstanding—diluted	199,158			143,554		134,378
Net income (loss) per share:
Basic:
Income (loss) from continuing operations	$	(11.10	)	$	1.88	$	0.88
Income from discontinued operations, net of tax	—			—		0.01
Net income (loss) per share	$	(11.10	)	$	1.88	$	0.89

Diluted:
Income (loss) from continuing operations	$	(11.10	)	$	1.85	$	0.87
Income from discontinued operations, net of tax	—			—		0.01
Net income (loss) per share	$	(11.10	)	$	1.85	$	0.88

_____________________________________________________________________________

(1)

For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering.

Credit risk	12 Months Ended
Credit risk	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Credit Risk	Credit risk The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in prior periods, its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.f, 8 and 9 for additional information regarding the Company's derivatives. For the year ended December 31, 2015, the Company had two customers that accounted for 37.5% and 20.3% of total oil, NGL and natural gas sales, with each customer accounting for 35.3% and 23.7%, respectively, of oil, NGL and natural gas sales accounts receivable, and two other customers accounting for 18.5% and 10.7% of oil, NGL and natural gas sales accounts receivable as of December 31, 2015. For the year ended December 31, 2014, the Company had two customers that accounted for 36.0% and 13.7% of total oil, NGL and natural gas sales, with each customer accounting for 16.4% and 22.5%, respectively, of oil, NGL and natural gas sales accounts receivable, and three other customers accounting for 13.5%, 12.5% and 11.6% of oil, NGL and natural gas sales accounts receivable as of December 31, 2014. For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7% of total oil, NGL and natural gas sales, with two of the three customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts receivable as of December 31, 2013. These customers and percentages reported are related to the Company's exploration and production segment, see Note 17. As of December 31, 2015, the Company had two partners whose joint operations accounts receivable accounted for 18.9% and 17.1% of the Company's total joint operations accounts receivable. As of December 31, 2014, the Company had two partners whose joint operations accounts receivable accounted for 20.5% and 13.2% of the Company's total joint operations accounts receivable. These customers and percentages reported are related to the Company's exploration and production segment, see Note 17. For the year ended December 31, 2015, the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 99.6% of purchased oil and other product sales receivable as of December 31, 2015. For the year ended December 31, 2014, the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 97.3% of purchased oil and other product sales receivable as of December 31, 2014. There were no comparable sales of purchased oil for the year ended December 31, 2013 and correspondingly, there was no purchased oil and other product sales receivable as of December 31, 2013. The customer and percentages reported relate to the Company's midstream and marketing segment, see Note 17. The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had cash balances on deposit with certain banks as of December 31, 2015, which exceeded the balance insured by the FDIC in the amount of $51.3 million. Management believes that the risk of loss is mitigated by the banks' reputation and financial position.

Commitments and contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

a. Lease commitments

The Company leases office space under operating leases expiring on various dates through 2027. Minimum annual lease commitments for the calendar years presented are:



(in thousands)	December 31, 2015
2016	$	3,087
2017	3,244
2018	3,160
2019	2,408
2020	1,294
Thereafter	8,217
Total	$	21,410

The following has been recorded to rent expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Rent expense	$	2,880	$	3,042	$	1,923

The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the consolidated statements of operations in the "General and administrative" line item.

b. Litigation

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

c. Drilling contracts

The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million which were recorded for the year ended December 31, 2014 on the consolidated statements of operations as "Drilling rig fees." No comparable amounts were recorded in the years ended December 31, 2015 or 2013. Future commitments of $10.3 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2016 that would result in a substantial penalty.

d. Firm sale and transportation commitments

The Company has committed to deliver for sale or transportation fixed volumes under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $425.7 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the three most recent years, and management expects such production will continue to exceed the Company's future commitments. However, in certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments.

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. Other commitments

See Notes 2.u, 16.a and 19.b for the amount of and discussion regarding outstanding commitments to the Company's non-consolidated variable interest entity ("VIE").

Restructuring	12 Months Ended
Restructuring	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring	Restructuring Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the year ended December 31, 2015 related to the RIF. There were no comparative amounts recorded in the years ended December 31, 2014 or 2013.

Recently issued accounting standards

12 Months Ended

Dec. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently issued accounting standards

In November 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 740, Income Taxes, which seeks to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. For public business entities, the amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company has early-adopted this standard as of December 31, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of deferred income taxes from the current liabilities "Deferred income taxes" to the noncurrent liabilities "Deferred income taxes" within the consolidated balance sheets.

The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:



(in thousands)	September 30, 2015			June 30, 2015			March 31, 2015			December 31, 2014
Noncurrent assets:
Decrease in deferred income taxes	$	(68,069	)	$	(45,089	)	$	—		$	—
Decrease in total assets	(68,069		)	(45,089		)	—			—
Current liabilities:
Decrease in deferred income taxes	$	(68,069	)	$	(45,089	)	$	(73,753	)	$	(71,191	)
Decrease in total current liabilities	(68,069		)	(45,089		)	(73,753		)	(71,191		)
Noncurrent liabilities:
Increase in deferred income taxes	$	—		$	—		$	73,753		$	71,191
Decrease in total liabilities	(68,069		)	(45,089		)	—			—

See Note 7 for additional discussion of the December 31, 2014 consolidated balance sheet presentation reclassification.

In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In April 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest, which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of (i) the unamortized debt issuance costs related to the Company's senior unsecured notes from noncurrent assets "Debt issuance costs, net" to noncurrent liabilities "Long-term debt, net" and (ii) the unamortized debt issuance costs related to the Company's Senior Secured Credit Facility from noncurrent assets "Debt issuance costs, net" to noncurrent assets "Other assets, net" within the consolidated balance sheets. See Notes 2.k and 5.h for additional discussion of debt issuance costs.

The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:



(in thousands)	June 30, 2015			March 31, 2015			December 31, 2014
Noncurrent assets:
Decrease in debt issuance costs, net	$	(26,158	)	$	(33,513	)	$	(28,463	)
Increase in other assets, net	6,068			6,873			6,615
Decrease in total assets	(20,090		)	(26,640		)	(21,848		)
Noncurrent liabilities:
Decrease in long-term debt, net	$	(20,090	)	$	(26,640	)	$	(21,848	)
Decrease in total liabilities	(20,090		)	(26,640		)	(21,848		)

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e725-108305

Equity Method Investments and Joint Ventures [Abstract]

Variable interest entity

12 Months Ended

Dec. 31, 2015

Variable Interest Entity

Variable interest entity

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

LMS contributed $99.9 million and $55.2 million during the years ended December 31, 2015 and 2014, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together, "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to December 31, 2015.

LMS holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the consolidated balance sheets as "Investment in equity method investee."

During the year ended December 31, 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production and began recognizing revenue due to its main pipeline becoming operational.

During the year ended December 31, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled. See Note 16.a for discussion of items included in the consolidated financial statements related to Medallion.

The following table summarizes items included in Medallion's consolidated statements of operations, which are not recorded in the Company's consolidated financial statements, for the periods presented:



	For the years ended December 31,
(in thousands)	2015⁽³⁾		2014			2013
Total revenues	$	34,288	$	4,623		$	892
Gross profit⁽¹⁾	29,826		4,623			892
Income (loss) from continuing operations	13,821		(333		)	54
Net income (loss)⁽²⁾	13,821		(333		)	54

_____________________________________________________________________________


(1)	Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013.


(2)	As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments.


(3)	Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016.

The following table summarizes items included in Medallion's consolidated balance sheets, which are not recorded in the Company's consolidated financial statements, as of the periods presented:



	December 31,
(in thousands)	2015⁽¹⁾		2014
Assets:
Current assets	$	78,411	$	25,777
Noncurrent assets	329,956		112,753
Total assets	$	408,367	$	138,530
Liabilities:
Current liabilities	$	15,461	$	19,522
Noncurrent liabilities	—		—
Total liabilities	$	15,461	$	19,522

_____________________________________________________________________________


(1)	Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016.

Related Parties

12 Months Ended

Dec. 31, 2015

Related Parties

a. Medallion

The following table summarizes items included in the consolidated statements of operations related to Medallion for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Midstream service revenues	$	487	$	—	$	—
Minimum volume commitments	5,235		2,552		891
Interest and other income	158		—		—

The following table summarizes items included in the consolidated balance sheets related to Medallion as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts receivable, net	$	1,163	$	—
Other assets, net⁽¹⁾	1,025		1,110
Other current liabilities⁽²⁾	27,583		3,443

_____________________________________________________________________________


(1)	Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

(2)

Amounts included in "Other current liabilities" above for the year ended December 31, 2015 represents LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to December 31, 2015. "Other current liabilities" above for the year ended December 31, 2014 represents LMS's minimum volume commitment payable to Medallion. See Note 15 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion.

b. Targa Resources Corp.

The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015.

The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa and included in the consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Oil, NGL and natural gas sales	$	99,992	$	96,100	$	74,245
Midstream service revenues	590		—		—

The following table summarizes the amounts included in accounts receivable, net from Targa in the consolidated balance sheets as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts receivable, net	$	6,097	$	12,869

c. Archrock Partners, L.P.

The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P., ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.

The following table summarizes the lease operating expenses related to Archrock included in the consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Lease operating expenses	$	1,477	$	975	$	51

The following table summarizes the capital expenditures related to Archrock included in the consolidated statements of cash flows for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Capital expenditures:
Oil and natural gas properties	$	—	$	57	$	—
Midstream service assets	64		833		—

The following table summarizes the amounts included in accounts payable from Archrock in the consolidated balance sheets as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts payable	$	13	$	—

d. Helmerich & Payne, Inc.

The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.

The following table summarizes the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Capital expenditures:
Oil and natural gas properties	$	2,434	$	9,518	$	9,943

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

Segments

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segments

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

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

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:



(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Year ended December 31, 2015:
Oil, NGL and natural gas sales	$	432,711		$	1,692		$	(2,669	)	$	431,734
Midstream service revenues	—			27,965			(21,417		)	6,548
Sales of purchased oil	—			168,358			—			168,358
Total revenues	432,711			198,015			(24,086		)	606,640
Lease operating expenses, including production tax	151,918			—			(10,685		)	141,233
Midstream service expenses, including minimum volume commitments	4,399			18,393			(11,711		)	11,081
Costs of purchased oil	—			174,338			—			174,338
General and administrative⁽¹⁾	82,251			8,174			—			90,425
Depletion, depreciation and amortization⁽²⁾	269,631			8,093			—			277,724
Impairment expense	2,372,296			2,592			—			2,374,888
Other operating costs and expenses⁽³⁾	8,123			342			—			8,465
Operating loss	$	(2,455,907	)	$	(13,917	)	$	(1,690	)	$	(2,471,514	)
Other financial information:
Income from equity method investee	$	—		$	6,799		$	—		$	6,799
Interest expense⁽⁴⁾	$	(98,040	)	$	(5,179	)	$	—		$	(103,219	)
Loss on early redemption of debt⁽⁵⁾	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Income tax benefit⁽⁶⁾	$	171,952		$	4,993		$	—		$	176,945
Capital expenditures	$	(597,086	)	$	(35,515	)	$	—		$	(632,601	)
Gross property and equipment⁽⁸⁾	$	5,302,716		$	345,183		$	(1,923	)	$	5,645,976

Year ended December 31, 2014:
Oil, NGL and natural gas sales	$	738,455		$	1,660		$	(2,912	)	$	737,203
Midstream service revenues	—			7,838			(5,593		)	2,245
Sales of purchased oil	—			54,437			—			54,437
Total revenues	738,455			63,935			(8,505		)	793,885
Lease operating expenses, including production tax	153,427			—			(6,612		)	146,815
Midstream service expenses, including minimum volume commitments	—			9,641			(1,660		)	7,981
Costs of purchased oil	—			53,967			—			53,967
General and administrative⁽¹⁾	99,075			6,969			—			106,044
Depletion, depreciation and amortization⁽²⁾	241,834			4,640			—			246,474
Impairment expense	1,802			2,102			—			3,904
Other operating costs and expenses⁽³⁾	2,248			66			—			2,314
Operating income (loss)	$	240,069		$	(13,450	)	$	(233	)	$	226,386
Other financial information:
Loss from equity method investee	$	—		$	(192	)	$	—		$	(192	)
Interest expense⁽⁴⁾	$	(117,560	)	$	(3,613	)	$	—		$	(121,173	)
Income tax (expense) benefit⁽⁶⁾	$	(170,551	)	$	6,265		$	—		$	(164,286	)
Capital expenditures⁽⁷⁾	$	(1,279,142	)	$	(60,607	)	$	—		$	(1,339,749	)
Gross property and equipment⁽⁸⁾	$	4,841,895		$	179,355		$	(233	)	$	5,021,017

Year ended December 31, 2013:
Oil, NGL and natural gas sales	$	664,844		$	—		$	—		$	664,844
Midstream service revenues	328			8,824			(8,739		)	413
Total revenues	665,172			8,824			(8,739		)	665,257
Lease operating expenses, including production tax	130,152			—			(8,620		)	121,532
Midstream service expenses, including minimum volume commitments	2,807			1,571			(119		)	4,259
General and administrative⁽¹⁾	86,951			2,745			—			89,696
Depletion, depreciation and amortization⁽²⁾	231,703			2,241			—			233,944
Other operating costs and expenses⁽³⁾	1,475			—			—			1,475
Operating income	$	212,084		$	2,267		$	—		$	214,351
Other financial information:
Income from equity method investee	$	—		$	29		$	—		$	29
Interest expense⁽⁴⁾	$	(98,680	)	$	(1,647	)	$	—		$	(100,327	)
Income tax expense⁽⁶⁾	$	(73,476	)	$	(1,031	)	$	—		$	(74,507	)
Capital expenditures⁽⁷⁾	$	(718,606	)	$	(24,409	)	$	—		$	(743,015	)
Gross property and equipment⁽⁸⁾	$	3,516,406		$	58,706		$	—		$	3,575,112

_____________________________________________________________________________

(1)

General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013.


(2)	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.


(3)	Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015, accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated.


(4)	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.


(5)	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.


(6)	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% for the years ended December 31, 2015, 2014 and 2013.


(7)	Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013.


(8)	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015, 2014 and 2013, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015, 2014 and 2013.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Subsidiary guarantors

12 Months Ended

Dec. 31, 2015

Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2015 and 2014, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2015, 2014 and 2013, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2014, certain midstream service assets were transferred from Laredo to LMS at historical cost.

Condensed consolidating balance sheet

December 31, 2015



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Total oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		131,725		—			131,725
Total other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Total other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating balance sheet

December 31, 2014



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	107,860	$	19,069	$	—		$	126,929
Other current assets	238,300		24		—			238,324
Total oil and natural gas properties, net	3,196,231		7,277		(233		)	3,203,275
Total midstream service assets, net	—		108,462		—			108,462
Total other fixed assets, net	42,046		299		—			42,345
Investment in subsidiaries and equity method investee	163,349		58,288		(163,349		)	58,288
Total other long-term assets	128,582		4,496		—			133,078
Total assets	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701

Accounts payable	$	38,453	$	555	$	—		$	39,008
Other current liabilities	283,026		31,800		—			314,826
Long-term debt, net	1,779,447		—		—			1,779,447
Other long-term liabilities	212,008		2,211		—			214,219
Stockholders' equity	1,563,434		163,349		(163,582		)	1,563,201
Total liabilities and stockholders' equity	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701

Condensed consolidating statement of operations

For the year ended December 31, 2015



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	432,478		$	198,248		$	(24,086	)	$	606,640
Total operating costs and expenses	2,897,272			203,278			(22,396		)	3,078,154
Loss from operations	(2,464,794		)	(5,030		)	(1,690		)	(2,471,514		)
Interest expense and other, net	(102,793		)	—			—			(102,793		)
Other non-operating income	182,396			6,708			(1,678		)	187,426
Income (loss) from continuing operations before income tax	(2,385,191		)	1,678			(3,368		)	(2,386,881		)
Income tax benefit	176,945			—			—			176,945
Income (loss) from continuing operations	(2,208,246		)	1,678			(3,368		)	(2,209,936		)
Net income (loss)	$	(2,208,246	)	$	1,678		$	(3,368	)	$	(2,209,936	)

Condensed consolidating statement of operations

For the year ended December 31, 2014



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	738,446		$	63,944		$	(8,505	)	$	793,885
Total operating costs and expenses	505,455			70,316			(8,272		)	567,499
Income (loss) from operations	232,991			(6,372		)	(233		)	226,386
Interest expense and other, net	(120,879		)	—			—			(120,879		)
Other non-operating income (expense)	317,980			(339		)	6,711			324,352
Income (loss) from continuing operations before income tax	430,092			(6,711		)	6,478			429,859
Income tax expense	(164,286		)	—			—			(164,286		)
Income (loss) from continuing operations	265,806			(6,711		)	6,478			265,573
Net income (loss)	$	265,806		$	(6,711	)	$	6,478		$	265,573

Condensed consolidating statement of operations

For the year ended December 31, 2013



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total operating revenues	$	665,172		$	8,824	$	(8,739	)	$	665,257
Total operating costs and expenses	455,972			3,673		(8,739		)	450,906
Income from operations	209,200			5,151		—			214,351
Interest expense and other, net	(100,164		)	—		—			(100,164		)
Other non-operating income	84,861			2,268		(10,232		)	76,897
Income from continuing operations before income tax	193,897			7,419		(10,232		)	191,084
Income tax expense	(74,507		)	—		—			(74,507		)
Income from continuing operations	119,390			7,419		(10,232		)	116,577
Income (loss) from discontinued operations, net of tax	(1,390		)	2,813		—			1,423
Net income	$	118,000		$	10,232	$	(10,232	)	$	118,000

Condensed consolidating statement of cash flows

For the year ended December 31, 2015



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	316,838		$	787		$	(1,678	)	$	315,947
Change in investments between affiliates	(136,252		)	134,574			1,678			—
Capital expenditures and other	(532,146		)	(135,361		)	—			(667,507		)
Net cash flows provided by financing activities	353,393			—			—			353,393
Net increase in cash and cash equivalents	1,833			—			—			1,833
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	31,153		$	1		$	—		$	31,154

Condensed consolidating statement of cash flows

For the year ended December 31, 2014



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided (used) by operating activities	$	496,955		$	(5,389	)	$	6,711		$	498,277
Change in investments between affiliates	(113,449		)	120,160			(6,711		)	—
Capital expenditures and other	(1,292,191		)	(114,770		)	—			(1,406,961		)
Net cash flows provided by financing activities	739,852			—			—			739,852
Net (decrease) increase in cash and cash equivalents	(168,833		)	1			—			(168,832		)
Cash and cash equivalents at beginning of period	198,153			—			—			198,153
Cash and cash equivalents at end of period	$	29,320		$	1		$	—		$	29,321

Condensed consolidating statement of cash flows

For the year ended December 31, 2013



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
Change in investments between affiliates	23,986			(34,218		)	10,232			—
Capital expenditures and other	(348,339		)	18,455			—			(329,884		)
Net cash flows provided by financing activities	130,084			—			—			130,084
Net increase in cash and cash equivalents	164,929			—			—			164,929
Cash and cash equivalents at beginning of period	33,224			—			—			33,224
Cash and cash equivalents at end of period	$	198,153		$	—		$	—		$	198,153

Subsequent events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent events

a. Senior Secured Credit Facility

On January 14, 2016, the Company borrowed $35.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $170.0 million at February 16, 2016.

b. Medallion capital call

On January 15 and February 16, 2016, the Company made additional capital contributions to Medallion of $12.7 million and $8.3 million, respectively, which represent LMS's remaining commitment for the extension from Medallion's Garden City Station to Midland and Upton counties, Texas and a portion of the commitment for the southern extension from Medallion's Reagan Station further into Reagan County, Texas.

c. New commodity derivative contracts

Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts:



	Aggregate volumes	Floor price		Contract period
Natural gas (volumes in MMBtu):⁽¹⁾
Put	8,040,000	$	2.50	January 2017 - December 2017
Put	8,220,000	$	2.50	January 2018 - December 2018

_____________________________________________________________________________


(1)	The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts.

Supplemental oil, NGL and natural gas disclosures

12 Months Ended

Dec. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental oil, NGL and natural gas disclosures

a. Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Property acquisition costs:
Evaluated	$	—	$	3,873	$	9,652
Unevaluated	—		9,925		27,087
Exploration⁽¹⁾	20,697		242,284		48,763
Development costs⁽²⁾	500,577		1,049,317		654,452
Total costs incurred	$	521,274	$	1,305,399	$	739,954

_____________________________________________________________________________


(1)	The Company acquired significant leasehold interests during the year ended December 31, 2014.


(2)	The costs incurred for oil, NGL and natural gas development activities include $13.4 million, $6.9 million and $6.8 million in asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively.

b. Capitalized oil, NGL and natural gas costs

Aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment are presented below:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Capitalized costs:
Evaluated properties	$	5,103,635		$	4,446,781		$	3,276,578
Unevaluated properties not being depleted	140,299			342,731			208,085
	5,243,934			4,789,512			3,484,663
Less accumulated depletion and impairment	(4,218,942		)	(1,586,237		)	(1,349,315		)
Net capitalized costs	$	1,024,992		$	3,203,275		$	2,135,348

The following table shows a summary of the oil, NGL and natural gas property costs not being depleted as of December 31, 2015, by year in which such costs were incurred:



(in thousands)	2015		2014		2013		2012 and prior		Total
Unevaluated properties not being depleted	$	12,640	$	110,955	$	9,293	$	7,411	$	140,299

Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil, NGL and natural gas leaseholds where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation.

c. Results of oil, NGL and natural gas producing activities

The results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) are presented below:



	For the years ended December 31,
(in thousands)	2015			2014		2013
Revenues:
Oil, NGL and natural gas sales	$	431,734		$	737,203	$	664,844
Production costs:
Lease operating expenses	108,341			96,503		79,136
Production and ad valorem taxes	32,892			50,312		42,396
	141,233			146,815		121,532
Other costs:
Depletion	263,666			237,067		227,992
Accretion of asset retirement obligations	2,236			1,721		1,475
Impairment expense	2,369,477			—		—
Income tax (benefit) expense⁽¹⁾	(164,141		)	126,576		112,984
Results of operations	$	(2,180,737	)	$	225,024	$	200,861

_____________________________________________________________________________

(1)

During the year ended December 31, 2015, the Company recorded a valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the year ended December 31, 2015, income tax benefit is computed utilizing the Company's effective rate of 7%, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax benefit for the period. For the years ended December 31, 2014 and 2013, income tax expense is computed utilizing the statutory rate.

d. Net proved oil, NGL and natural gas reserves - (unaudited)

Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2015, 2014 and 2013. In accordance with SEC regulations, reserves as of December 31, 2015, 2014 and 2013 were estimated using the Realized Prices (which are the Benchmark Prices adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead), see Note 2.g. The Company's reserves as of December 31, 2015 are reported in three streams: oil, NGL and natural gas. The Company's reserves as of December 31, 2014 and 2013 are reported in two streams: oil and liquids-rich natural gas with the economic value of the NGLs in the Company's natural gas included in the wellhead natural gas price. This change impacts the comparability of 2015 with prior periods. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil, NGL and natural gas properties. Accordingly, the estimates may change as future information becomes available.

The following tables provide an analysis of the changes in estimated reserve quantities of oil, NGL and natural gas for the year ended December 31, 2015 and of oil and liquids-rich natural gas for the years ended December 31, 2014 and 2013, all of which are located within the United States.



	Year ended December 31, 2015
	Oil (MBbl)		NGL (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	140,190		—		642,794		247,322
Revisions of previous estimates⁽¹⁾	(88,900	)	35,477		(424,546	)	(124,180	)
Extensions, discoveries and other additions	10,511		5,865		36,074		22,388
Sales of reserves in place	(1,552	)	(1,008	)	(5,554	)	(3,486	)
Production	(7,610	)	(4,267	)	(26,816	)	(16,346	)
End of year	52,639		36,067		221,952		125,698
Proved developed reserves:
Beginning of year	56,975		—		291,493		105,557
End of year	40,944		29,349		180,613		100,395
Proved undeveloped reserves:
Beginning of year	83,215		—		351,301		141,765
End of year	11,695		6,718		41,339		25,303

_____________________________________________________________________________

(1)

The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three-stream production. For periods prior to January 1, 2015, the Company presented its reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability to prior periods.



	Year ended December 31, 2014
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	111,498		552,702		203,615
Revisions of previous estimates	(10,134	)	(67,350	)	(21,359	)
Extensions, discoveries and other additions	45,554		185,909		76,539
Purchases of reserves in place	173		498		256
Production	(6,901	)	(28,965	)	(11,729	)
End of year	140,190		642,794		247,322
Proved developed reserves:
Beginning of year	37,878		203,082		71,725
End of year	56,975		291,493		105,557
Proved undeveloped reserves:
Beginning of year	73,620		349,620		131,890
End of year	83,215		351,301		141,765



	Year ended December 31, 2013
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	98,141		542,946		188,632
Revisions of previous estimates	(17,956	)	15,710		(15,338	)
Extensions, discoveries and other additions	37,850		192,229		69,888
Purchases of reserves in place	170		1,454		412
Sale of reserves in place	(1,220	)	(165,289	)	(28,768	)
Production	(5,487	)	(34,348	)	(11,211	)
End of year	111,498		552,702		203,615
Proved developed reserves:
Beginning of year	33,316		289,045		81,490
End of year	37,878		203,082		71,725
Proved undeveloped reserves:
Beginning of year	64,825		253,901		107,142
End of year	73,620		349,620		131,890

For the year ended December 31, 2015, the Company's negative revision of 124,180 MBOE of previously estimated quantities is primarily attributable to the removal of 106,883 MBOE due to the combined effect of the removal of 378 proved undeveloped locations and the net effect of reinterpreting 34 undeveloped locations. The 378 locations that were removed were comprised of 182 vertical Wolfberry wells due to lower commodity prices and 196 horizontal wells to better align the timing of their development with the Company's future drilling plans. The remaining 17,297 MBOE of negative revisions is due to a combination of pricing, performance and other changes to the proved developed producing and proved developed non-producing wells. Extensions, discoveries and other additions of 22,388 MBOE during the year ended December 31, 2015, consisted of 19,719 MBOE primarily from the drilling of new wells during the year and 2,669 MBOE from four new horizontal Middle Wolfcamp proved undeveloped locations added during the year.

For the year ended December 31, 2014, the Company's negative revision of 21,359 MBOE of previously estimated quantities is primarily attributable to the removal of 26,017 MBOE due to the combined effect of the removal of 226 proved undeveloped locations and the net effect of reinterpreting 345 undeveloped locations. The 226 locations that were removed were comprised of vertical Wolfberry and horizontal laterals to better align with the proved developed producing wells. The increase of 4,658 MBOE, which offsets the overall negative revision, is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 76,539 MBOE during the year ended December 31, 2014, consisted of 34,782 MBOE primarily from the drilling of new wells during the year and 41,757 MBOE from 113 new horizontal proved undeveloped locations added during the year. Purchases of minerals in place added 256 MBOE from acquisition of proved reserves in the Permian Basin.

For the year ended December 31, 2013, the Company's negative revision of 15,338 MBOE of previously estimated quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved undeveloped locations and the net effect of reinterpreting 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals which were replaced with longer horizontal laterals to better align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December 31, 2013, consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian Basin.

e. Standardized measure of discounted future net cash flows - (unaudited)

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2015, 2014 and 2013 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for gravity, quality, local conditions, fuel and shrinkage and/or distance from market. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net revenues. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil, NGL and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%. The Company's net book value of evaluated oil, NGL and natural gas properties exceeded the full cost ceiling amount as of June 30, 2015, September 30, 2015 and December 31, 2015. See Note 2.g for discussion of the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded.

The standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves is as follows:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Future cash inflows	$	3,269,184		$	16,663,685		$	13,337,798
Future production costs	(1,321,471		)	(3,616,775		)	(3,059,368		)
Future development costs	(376,701		)	(2,471,985		)	(2,250,950		)
Future income tax expenses	—			(2,827,763		)	(2,150,983		)
Future net cash flows	1,571,012			7,747,162			5,876,497
10% discount for estimated timing of cash flows	(740,265		)	(4,500,434		)	(3,554,293		)
Standardized measure of discounted future net cash flows	$	830,747		$	3,246,728		$	2,322,204

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves are as follows:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Standardized measure of discounted future net cash flows, beginning of year	$	3,246,728		$	2,322,204		$	1,877,456
Changes in the year resulting from:
Sales, less production costs	(290,501		)	(590,388		)	(543,312		)
Revisions of previous quantity estimates	(2,444,322		)	(320,275		)	(190,961		)
Extensions, discoveries and other additions	192,979			1,340,022			1,166,481
Net change in prices and production costs	(1,495,144		)	145,740			313,947
Changes in estimated future development costs	(2,974		)	(22,961		)	921
Previously estimated development costs incurred during the period	162,237			92,135			89,396
Purchases of reserves in place	—			6,100			7,604
Divestitures of reserves in place	(29,149		)	—			(239,148		)
Accretion of discount	424,453			305,325			234,852
Net change in income taxes	997,805			(266,757		)	(259,991		)
Timing differences and other	68,635			235,583			(135,041		)
Standardized measure of discounted future net cash flows, end of year	$	830,747		$	3,246,728		$	2,322,204

Estimates of economically recoverable oil, NGL and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.

Supplemental quarterly financial data (unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Supplemental quarterly financial data (unaudited)

Supplemental quarterly financial data - (unaudited)

The Company's results from continuing operations by quarter for the periods presented are as follows:



	Year ended December 31, 2015
(in thousands, except per share data)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	150,694		$	182,331		$	150,340		$	123,275
Operating loss	(26,498		)	(501,480		)	(927,859		)	(1,015,677		)
Net loss	(472		)	(397,034		)	(847,783		)	(964,647		)
Net loss per common share:
Basic	$	—		$	(1.88	)	$	(4.01	)	$	(4.57	)
Diluted	$	—		$	(1.88	)	$	(4.01	)	$	(4.57	)



	Year ended December 31, 2014
(in thousands, except per share data)	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	173,310		$	183,044		$	200,241	$	237,290
Operating income	60,038			64,561			69,164		32,623
Net income (loss)	(213		)	(18,899		)	83,407		201,278
Net income (loss) per common share:
Basic	$	—		$	(0.13	)	$	0.59	$	1.42
Diluted	$	—		$	(0.13	)	$	0.58	$	1.40

Basis of presentation and significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2015

Use of estimates in the preparation of consolidated financial statements

Basis of presentation

Reclassifications

Cash and cash equivalents

Accounts receivable

Derivative financial instruments

Derivatives

Long-lived assets, materials and supplies and line-fill

The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities.

Midstream service assets

Other fixed assets

These adjustments are included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's exploration and production segment presented in Note 17. The Company determined an LCM adjustment was not necessary for materials and supplies during the year ended December 31, 2013.

Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods.

Asset retirement obligations

Fair value measurements

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows:



Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Treasury stock

Revenue recognition

General and administrative expense

The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.

Equity and stock-based awards

Compensation awards

Income taxes

Environmental

Employee compensation

Credit risk

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in prior periods, its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated.

Recently issued accounting standards

Variable Interest Entity

Acquisitions

Basis of presentation and significant accounting policies (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of components of accounts receivable

Accounts receivable consisted of the following components as of December 31:



(in thousands)	2015		2014
Matured derivatives	$	27,469	$	16,098
Oil, NGL and natural gas sales	25,582		57,070
Joint operations, net⁽¹⁾	21,375		33,808
Purchased oil and other product sales	11,775		18,917
Other	1,498		1,036
Total	$	87,699	$	126,929

_____________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively.

SEC prices used to calculate full cost ceiling value

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:



	For the quarters ended								For the years ended⁽¹⁾
	December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015		December 31, 2014		December 31, 2013
Benchmark Prices
Oil ($/Bbl)	$	46.79	$	55.73	$	68.17	$	79.21	$	91.48	$	93.52
NGL ($/Bbl)	18.75		21.87		26.73		31.25		—		—
Natural gas ($/MMBtu)	2.47		2.89		3.22		3.73		4.25		3.57
Realized Prices
Oil ($/Bbl)	45.58		54.28		66.68		77.72		89.57		92.26
NGL ($/Bbl)	12.50		15.25		19.56		23.75		—		—
Natural gas ($/Mcf)	1.89		2.30		2.62		3.09		6.39		5.52
Non-cash full cost ceiling impairment (in thousands)	$	975,011	$	906,420	$	488,046	$	—	$	—	$	—

_____________________________________________________________________________


(1)	For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.

Schedule of pipeline and gathering assets

Other fixed assets consist of the following as of December 31:



(in thousands)	2015			2014
Computer hardware and software	$	12,148		$	13,495
Vehicles	9,266			7,802
Leasehold improvements	7,710			6,867
Real estate and buildings	7,618			4,908
Aircraft	4,952			4,952
Other	5,105			4,909
Depreciable total	46,799			42,933
Less accumulated depreciation and amortization	(18,169		)	(13,820		)
Depreciable total, net	28,630			29,113
Land	14,908			13,232
Total, net	$	43,538		$	42,345

Midstream service assets consist of the following as of December 31:



(in thousands)	2015			2014
Midstream service assets	$	147,811		$	117,052
Less accumulated depreciation	(16,086		)	(8,590		)
Total, net	$	131,725		$	108,462

Schedule of future amortization expense of deferred loan costs

Future amortization expense of debt issuance costs as of the period presented is as follows:



(in thousands)	December 31, 2015
2016	$	4,503
2017	4,575
2018	4,349
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	23,932

Schedule of components of other current liabilities

Other current liabilities consist of the following components as of December 31:



(in thousands)	2015		2014
Capital contribution payable to equity method investee⁽¹⁾	$	27,583	$	—
Accrued interest payable	24,208		37,689
Accrued compensation and benefits	14,342		13,034
Lease operating expense payable	13,205		11,963
Costs of purchased oil	12,189		20,114
Other accrued liabilities	14,695		18,232
Total other current liabilities	$	106,222	$	101,032

_____________________________________________________________________________


(1)	See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee.

Schedule of reconciliation of asset retirement obligations liability

The following reconciles the Company's asset retirement obligation liability as of December 31:



(in thousands)	2015			2014
Liability at beginning of year	$	32,198		$	21,743
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	2,236			6,370
Accretion expense	2,423			1,787
Liabilities settled upon plugging and abandonment	(146		)	(450		)
Liabilities removed due to sale of property	(2,005		)	—
Revision of estimates⁽¹⁾	11,600			2,748
Liability at end of year	$	46,306		$	32,198

_____________________________________________________________________________


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

Schedule of fees received from operation of jointly owned oil and natural gas properties

The following amounts have been recorded for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Fees received for the operation of jointly-owned oil and natural gas properties	$	3,125	$	3,265	$	3,398

Schedule of Cash Flow, Supplemental Disclosures

The following table summarizes the supplemental disclosure of cash flow information for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Cash paid for interest, net of $236, $150 and $255 of capitalized interest, respectively	$	112,457	$	104,936	$	95,622

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Change in accrued capital expenditures	$	(86,369	)	$	31,913		$	(5,284	)
Change in accrued capital contribution to equity method investee	27,583			(2,597		)	2,597
Capitalized asset retirement cost	13,836			9,118			6,790
Capitalized stock-based compensation	2,321			4,650			—
Equity issued in connection with acquisition	—			—			3,029

Acquisitions and divestitures (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Operating results from discontinued operations



(in thousands)	For the year ended December 31, 2013
Revenues	$	59,631
Expenses⁽¹⁾	46,357

_____________________________________________________________________________


(1)	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

The following represents operating results from discontinued operations for the period presented:



(in thousands)	For the year ended December 31, 2013
Revenues:
Midstream service revenue	$	4,020
Total revenues from discontinued operations	4,020
Cost and expenses:
Midstream service expense, net	1,189
Depreciation and amortization	627
Total costs and expenses from discontinued operations	1,816
Non-operating expense, net	—
Income (loss) from discontinued operations before income tax	2,204
Income tax (expense) benefit	(781		)
Income (loss) from discontinued operations	$	1,423

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Oil, NGL and natural gas sales	$	5,138	$	19,337	$	24,187
Expenses⁽¹⁾	5,791		11,082		11,826

_____________________________________________________________________________


(1)	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Estimated fair value of assets acquired and associated liabilities of acquisition



(in thousands)	Accounting treatment	Cash consideration		Common stock issued⁽²⁾
August 28, 2014 acquisition of leasehold interests	Acquisition of assets	$	192,484	$	—
June 23, 2014 acquisition of evaluated and unevaluated oil and natural gas properties	Acquisition method	1,800		—
June 11, 2014 acquisition of evaluated and unevaluated oil and natural gas properties	Acquisition method	4,693		—
February 25, 2014 acquisition of mineral interests	Acquisition of assets	7,305		—
September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties⁽¹⁾	Acquisition method	33,710		3,029

_____________________________________________________________________________


(1)	The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.

(2)

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

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Schedule of amounts incurred and charged to interest expenses

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

The following amounts have been incurred and charged to interest expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Cash payments for interest	$	112,693		$	105,086		$	95,877
Amortization of debt issuance costs and other adjustments	4,243			4,433			4,926
Change in accrued interest	(13,481		)	11,804			(221		)
Interest costs incurred	103,455			121,323			100,582
Less capitalized interest	(236		)	(150		)	(255		)
Total interest expense	$	103,219		$	121,173		$	100,327

Schedule of carrying amount and fair value of debt instruments

The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented:



	December 31, 2015				December 31, 2014
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2019 Notes⁽¹⁾	$	—	$	—	$	551,295	$	550,000
January 2022 Notes	450,000		388,301		450,000		396,014
May 2022 Notes	500,000		460,000		500,000		467,529
March 2023 Notes	350,000		301,000		—		—
Senior Secured Credit Facility	135,000		134,993		300,000		300,279
Total value of debt	$	1,435,000	$	1,284,294	$	1,801,295	$	1,713,822

_____________________________________________________________________________


(1)	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.

Schedule of net presentation of the Company's long-term debt and debt issuance cost

The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the consolidated balance sheets as of the periods presented:



	December 31, 2015							December 31, 2014
(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 2019 Notes⁽¹⁾	$	—	$	—		$	—	$	551,295	$	(7,031	)	$	544,264
January 2022 Notes	450,000		(5,939		)	444,061		450,000		(6,916		)	443,084
May 2022 Notes	500,000		(7,066		)	492,934		500,000		(7,901		)	492,099
March 2023 Notes	350,000		(5,769		)	344,231		—		—			—
Senior Secured Credit Facility⁽²⁾	135,000		—			135,000		300,000		—			300,000
Total	$	1,435,000	$	(18,774	)	$	1,416,226	$	1,801,295	$	(21,848	)	$	1,779,447

_____________________________________________________________________________


(1)	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.


(2)	Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets.

Employee compensation (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Nonvested Share Activity

The following table reflects the outstanding restricted stock awards for the years ended December 31, 2015, 2014 and 2013:



(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2012	1,195		$	15.06
Granted	1,469		$	18.17
Forfeited	(229	)	$	18.47
Vested⁽¹⁾	(636	)	$	18.69
Outstanding as of December 31, 2013	1,799		$	19.17
Granted	1,234		$	25.68
Forfeited	(148	)	$	22.56
Vested⁽¹⁾	(680	)	$	19.13
Outstanding as of December 31, 2014	2,205		$	22.63
Granted	1,902		$	11.98
Forfeited	(553	)	$	20.48
Vested⁽¹⁾	(1,015	)	$	22.32
Outstanding as of December 31, 2015	2,539		$	15.26

_____________________________________________________________________________


(1)	The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards.

Schedule of Share-based Compensation, Stock Options, Activity

The following table reflects the stock option award activity for the years ended December 31, 2015, 2014 and 2013:



(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2012	459		$	24.11	10
Granted	1,019		$	17.34
Exercised⁽¹⁾	(104	)	$	20.79
Expired or canceled	(12	)	$	24.11
Forfeited	(133	)	$	19.88
Outstanding as of December 31, 2013	1,229		$	19.32	8.82
Granted	336		$	25.60
Exercised⁽¹⁾	(95	)	$	19.93
Expired or canceled	(30	)	$	21.15
Forfeited	(73	)	$	19.68
Outstanding as of December 31, 2014	1,367		$	20.76	8.17
Granted	632		$	11.93
Exercised	—		$	—
Expired or canceled	(82	)	$	19.92
Forfeited	(139	)	$	18.17
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Vested and exercisable at end of period⁽²⁾	545		$	20.77	6.94
Expected to vest at end of period⁽³⁾	1,219		$	16.51	8.34

_____________________________________________________________________________


(1)	The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards.


(2)	The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value.


(3)	The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value.

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions

The assumptions used to estimate the fair value of restricted stock options granted are as follows:



	February 27, 2015			February 27, 2014			February 15, 2013			February 3, 2012
Risk-free interest rate⁽¹⁾	1.70		%	1.88		%	1.19		%	1.14		%
Expected option life⁽²⁾	6.25 years			6.25 years			6.25 years			6.25 years
Expected volatility⁽³⁾	52.59		%	53.21		%	58.89		%	59.98		%
Fair value per stock option	$	6.15		$	13.41		$	9.67		$	13.52

_____________________________________________________________________________


(1)	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.


(2)	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(3)	The Company utilized its own volatility in order to develop the expected volatility for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.

Share Based Compensation Schedule Of Vesting Rights Options



Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan

The following has been recorded to performance unit award compensation expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
2013 Performance Unit Award compensation expense	$	4,081	$	409	$	2,863
2012 Performance Unit Award compensation expense	—		192		1,870
Total performance unit award compensation expense	$	4,081	$	601	$	4,733

The following has been recorded to stock-based compensation expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Restricted stock award compensation	$	17,534		$	21,982		$	17,084
Restricted stock option award compensation	4,074			3,639			4,349
Restricted performance share award compensation	5,222			2,108			—
Total stock-based compensation, gross	26,830			27,729			21,433
Less amounts capitalized in oil and natural gas properties	(2,321		)	(4,650		)	—
Total stock-based compensation, net of amounts capitalized	$	24,509		$	23,079		$	21,433

Schedule of Nonvested Performance-based Units Activity

The following table reflects the outstanding performance unit awards for the periods presented:



(in thousands)	2013 Performance Unit Awards⁽²⁾		2012 Performance Unit Awards ⁽³⁾
Outstanding at December 31, 2012	—		47
Granted	58		—
Forfeited	(4	)	(9	)
Vested⁽¹⁾	(10	)	(11	)
Outstanding at December 31, 2013	44		27
Vested	—		(27	)
Outstanding at December 31, 2014	44		—
Vested	(44	)	—
Outstanding at December 31, 2015	—		—

_____________________________________________________________________________


(1)	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.


(2)	The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016.


(3)	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.

Schedule of Defined Contribution Plans Disclosures

The following table presents the cost recognized for the Company's defined contribution plan for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Contributions	$	1,847	$	2,202	$	1,886

Performance unit awards

Schedule of Share-base Payment Award, Equity Instruments Other Than Options, Valuation Assumptions

The assumptions used to estimate the fair value of the Performance Share Awards granted are as follows:



	February 27, 2015			February 27, 2014
Risk-free rate⁽¹⁾	0.95		%	0.63		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	53.78		%	38.21		%
Laredo stock closing price as of the grant date	$	11.93		$	25.60
Fair value per performance share	$	16.23		$	28.56

_____________________________________________________________________________


(1)	The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.

Income taxes (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of income tax (expense) benefit

The following presents the comprehensive benefit (expense) for income taxes for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014			2013
Comprehensive benefit (expense) for income taxes allocable to:
Continuing operations	$	176,945	$	(164,286	)	$	(74,507	)
Discontinued operations	—		—			(781		)
Comprehensive benefit (expense) for income taxes	$	176,945	$	(164,286	)	$	(75,288	)

Income tax benefit (expense) attributable to income (loss) from continuing operations for the periods presented consisted of the following:



	For the years ended December 31,
(in thousands)	2015		2014			2013
Current taxes:
Federal	$	—	$	—		$	—
State	—		—			—
Deferred taxes:
Federal	152,590		(147,445		)	(64,034		)
State	24,355		(16,841		)	(10,473		)
Income tax benefit (expense)	$	176,945	$	(164,286	)	$	(74,507	)

Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations



	For the years ended December 31,
(in thousands)	2015			2014			2013
Income tax benefit (expense) computed by applying the statutory rate	$	835,408		$	(150,450	)	$	(64,969	)
State income tax, net of federal tax benefit and increase in valuation allowance	13,975			(11,099		)	(7,532		)
Non-deductible stock-based compensation	(256		)	(509		)	(1,070		)
Stock-based compensation tax deficiency	(3,274		)	(266		)	(559		)
Increase in deferred tax valuation allowance	(668,702		)	(1,139		)	(63		)
Other items	(206		)	(823		)	(314		)
Income tax benefit (expense)	$	176,945		$	(164,286	)	$	(74,507	)

Schedule of Income Tax Deficiency from Share-based Compensation

The following table presents the tax impact of these shortfalls for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Vesting of restricted stock	$	3,334	$	112	$	425
Exercise of restricted stock options	—		158		150
Tax expense due to shortfalls	$	3,334	$	270	$	575

Schedule of Deferred Tax Assets and Liabilities

Significant components of the Company's net deferred tax liability as of December 31 are as follows:



(in thousands)	2015			2014
Oil and natural gas properties, midstream service assets and other fixed assets	$	306,997		$	(424,712	)
Net operating loss carry-forward	479,022			353,724
Derivatives	(98,675		)	(121,365		)
Stock-based compensation	11,597			10,718
Equity method investee	(31,711		)	(2,331		)
Accrued bonus	4,763			3,256
Capitalized interest	2,525			3,049
Materials and supplies impairment	1,647			642
Other	1,173			1,373
Net deferred tax asset (liability) before valuation allowance	677,338			(175,646		)
Valuation allowance	(677,338		)	(1,299		)
Net deferred tax asset (liability)	$	—		$	(176,945	)

Deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 are as follows:



(in thousands)	2015		2014⁽¹⁾			Offset⁽¹⁾			2014 new presentation⁽¹⁾
Deferred tax asset	$	—	$	—		$	—		$	—
Deferred tax liability:
Current	—		(71,191		)	71,191			—
Noncurrent	—		(105,754		)	(71,191		)	(176,945		)
Deferred tax liability	$	—	$	(176,945	)	$	—		$	(176,945	)
Net deferred tax liability	$	—	$	(176,945	)	$	—		$	(176,945	)

_____________________________________________________________________________


(1)	See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.

Summary of Operating Loss Carryforwards

The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of the period presented:



(in thousands)	December 31, 2015
2026	$	2,741
2027	38,651
2028	228,661
2029	101,932
2030	80,963
Thereafter	915,642
Total	$	1,368,590

Derivatives (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative contracts transferred to buyers on sale of assets

During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:



	Aggregate volumes	Swap price		Contract period
Natural gas (volumes in MMBtu):
Swap	2,386,800	$	4.31	August 2013 - December 2013
Swap	3,978,500	$	4.36	January 2014 - December 2014

Summary of derivative contracts unwound in connection with sale of assets

The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:



	Aggregate volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015

Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts:



	Aggregate volumes	Floor price		Contract period
Natural gas (volumes in MMBtu):⁽¹⁾
Put	8,040,000	$	2.50	January 2017 - December 2017
Put	8,220,000	$	2.50	January 2018 - December 2018

_____________________________________________________________________________


(1)	The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts.

Schedule of gains and losses on derivative instruments

The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Cash settlements received for matured commodity derivatives	$	255,281	$	28,241	$	4,046
Cash settlements paid for matured interest rate swaps	—		—		(301		)
Early terminations and modification of commodity derivatives received⁽¹⁾	—		76,660		6,008
Cash settlements received for derivatives, net	$	255,281	$	104,901	$	9,753

_____________________________________________________________________________


(1)	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts.

Schedule of notional amounts of outstanding derivative positions

The following table summarizes open positions as of December 31, 2015, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:



	Year 2016		Year 2017
Oil positions:⁽¹⁾
Puts:
Hedged volume (Bbl)	1,296,000		—
Weighted-average price ($/Bbl)	$	45.00	$	—
Swaps:
Hedged volume (Bbl)	1,573,800		—
Weighted-average price ($/Bbl)	$	84.82	$	—
Collars:
Hedged volume (Bbl)	3,654,000		2,628,000
Weighted-average floor price ($/Bbl)	$	73.99	$	77.22
Weighted-average ceiling price ($/Bbl)	$	89.63	$	97.22
Totals:
Total volume hedged with floor price (Bbl)	6,523,800		2,628,000
Weighted-average floor price ($/Bbl)	$	70.84	$	77.22
Total volume hedged with ceiling price (Bbl)	5,227,800		2,628,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	97.22
Natural gas positions:⁽²⁾
Collars:
Hedged volume (MMBtu)	18,666,000		5,475,000
Weighted-average floor price ($/MMBtu)	$	3.00	$	3.00
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	4.00

_____________________________________________________________________________


(1)	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").


(2)	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis

Fair value measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]



(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248



(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of December 31, 2014:
Assets
Current:
Oil derivatives	$	—	$	190,303	$	—		$	190,303		$	—		$	190,303
Natural gas derivatives	—		9,647		—			9,647			—			9,647
Oil deferred premiums	—		—		—			—			(4,653		)	(4,653		)
Natural gas deferred premiums	—		—		—			—			(696		)	(696		)
Noncurrent:
Oil derivatives	$	—	$	117,963	$	—		$	117,963		$	—		$	117,963
Natural gas derivatives	—		3,646		—			3,646			—			3,646
Oil deferred premiums	—		—		—			—			(3,821		)	(3,821		)
Natural gas deferred premiums	—		—		—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,768		)	(4,768		)	4,653			(115		)
Natural gas deferred premiums	—		—		(696		)	(696		)	696			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(3,821		)	(3,821		)	3,821			—
Natural gas deferred premiums	—		—		—			—			—			—
Net derivative position	$	—	$	321,559	$	(9,285	)	$	312,274		$	—		$	312,274

Actual cash payments required for deferred premium contracts

The following table presents actual cash payments required for deferred premiums for the calendar years presented:



(in thousands)	December 31, 2015
2016	$	8,629
2017	5,796
2018	426
Total	$	14,851

Summary of changes in assets classified as Level 3 measurements

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



	For the years ended December 31,
(in thousands)	2015			2014			2013
Balance of Level 3 at beginning of period	$	(9,285	)	$	(12,684	)	$	(24,709	)
Change in net present value of deferred premiums for derivatives	(203		)	(220		)	(462		)
Total purchases and settlements:
Purchases	(10,298		)	(3,800		)	—
Settlements⁽¹⁾	5,167			7,419			12,487
Balance of Level 3 at end of period	$	(14,619	)	$	(9,285	)	$	(12,684	)

_____________________________________________________________________________


(1)	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Net income (loss) per share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share

The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented:



	For the years ended December 31,
(in thousands, except for per share data)	2015			2014		2013
Net income (loss) (numerator):
Income (loss) from continuing operations—basic and diluted	$	(2,209,936	)	$	265,573	$	116,577
Income from discontinued operations, net of tax—basic and diluted	—			—		1,423
Net income (loss)—basic and diluted	$	(2,209,936	)	$	265,573	$	118,000
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic⁽¹⁾	199,158			141,312		132,490
Non-vested restricted stock awards	—			2,242		1,888
Weighted-average common shares outstanding—diluted	199,158			143,554		134,378
Net income (loss) per share:
Basic:
Income (loss) from continuing operations	$	(11.10	)	$	1.88	$	0.88
Income from discontinued operations, net of tax	—			—		0.01
Net income (loss) per share	$	(11.10	)	$	1.88	$	0.89

Diluted:
Income (loss) from continuing operations	$	(11.10	)	$	1.85	$	0.87
Income from discontinued operations, net of tax	—			—		0.01
Net income (loss) per share	$	(11.10	)	$	1.85	$	0.88

_____________________________________________________________________________

(1)

Commitments and contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum annual lease commitments

The Company leases office space under operating leases expiring on various dates through 2027. Minimum annual lease commitments for the calendar years presented are:



(in thousands)	December 31, 2015
2016	$	3,087
2017	3,244
2018	3,160
2019	2,408
2020	1,294
Thereafter	8,217
Total	$	21,410

Schedule of rent expense

The following has been recorded to rent expense for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Rent expense	$	2,880	$	3,042	$	1,923

Recently issued accounting standards (Tables)

12 Months Ended

Dec. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncement, Early Adoption

See Notes 2.k and 5.h for additional discussion of debt issuance costs.

The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:



(in thousands)	June 30, 2015			March 31, 2015			December 31, 2014
Noncurrent assets:
Decrease in debt issuance costs, net	$	(26,158	)	$	(33,513	)	$	(28,463	)
Increase in other assets, net	6,068			6,873			6,615
Decrease in total assets	(20,090		)	(26,640		)	(21,848		)
Noncurrent liabilities:
Decrease in long-term debt, net	$	(20,090	)	$	(26,640	)	$	(21,848	)
Decrease in total liabilities	(20,090		)	(26,640		)	(21,848		)

The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:



(in thousands)	September 30, 2015			June 30, 2015			March 31, 2015			December 31, 2014
Noncurrent assets:
Decrease in deferred income taxes	$	(68,069	)	$	(45,089	)	$	—		$	—
Decrease in total assets	(68,069		)	(45,089		)	—			—
Current liabilities:
Decrease in deferred income taxes	$	(68,069	)	$	(45,089	)	$	(73,753	)	$	(71,191	)
Decrease in total current liabilities	(68,069		)	(45,089		)	(73,753		)	(71,191		)
Noncurrent liabilities:
Increase in deferred income taxes	$	—		$	—		$	73,753		$	71,191
Decrease in total liabilities	(68,069		)	(45,089		)	—			—

Variable interest entity (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments



	For the years ended December 31,
(in thousands)	2015⁽³⁾		2014			2013
Total revenues	$	34,288	$	4,623		$	892
Gross profit⁽¹⁾	29,826		4,623			892
Income (loss) from continuing operations	13,821		(333		)	54
Net income (loss)⁽²⁾	13,821		(333		)	54

_____________________________________________________________________________


(1)	Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013.


(2)	As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments.


(3)	Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016.

The following table summarizes items included in Medallion's consolidated balance sheets, which are not recorded in the Company's consolidated financial statements, as of the periods presented:



	December 31,
(in thousands)	2015⁽¹⁾		2014
Assets:
Current assets	$	78,411	$	25,777
Noncurrent assets	329,956		112,753
Total assets	$	408,367	$	138,530
Liabilities:
Current liabilities	$	15,461	$	19,522
Noncurrent liabilities	—		—
Total liabilities	$	15,461	$	19,522

_____________________________________________________________________________


(1)	Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016.

Related Parties (Tables)

12 Months Ended

Dec. 31, 2015

Oil and gas related party transactions



	For the years ended December 31,
(in thousands)	2015		2014		2013
Oil, NGL and natural gas sales	$	99,992	$	96,100	$	74,245
Midstream service revenues	590		—		—

The following table summarizes the amounts included in accounts receivable, net from Targa in the consolidated balance sheets as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts receivable, net	$	6,097	$	12,869

The following table summarizes the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Capital expenditures:
Oil and natural gas properties	$	2,434	$	9,518	$	9,943

The following table summarizes the lease operating expenses related to Archrock included in the consolidated statements of operations for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Lease operating expenses	$	1,477	$	975	$	51

The following table summarizes the capital expenditures related to Archrock included in the consolidated statements of cash flows for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Capital expenditures:
Oil and natural gas properties	$	—	$	57	$	—
Midstream service assets	64		833		—

The following table summarizes the amounts included in accounts payable from Archrock in the consolidated balance sheets as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts payable	$	13	$	—

The following table summarizes items included in the consolidated statements of operations related to Medallion for the periods presented:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Midstream service revenues	$	487	$	—	$	—
Minimum volume commitments	5,235		2,552		891
Interest and other income	158		—		—

The following table summarizes items included in the consolidated balance sheets related to Medallion as of the periods presented:



	December 31,
(in thousands)	2015		2014
Accounts receivable, net	$	1,163	$	—
Other assets, net⁽¹⁾	1,025		1,110
Other current liabilities⁽²⁾	27,583		3,443

_____________________________________________________________________________


(1)	Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

(2)

Segments (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segment reporting information by segment



(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Year ended December 31, 2015:
Oil, NGL and natural gas sales	$	432,711		$	1,692		$	(2,669	)	$	431,734
Midstream service revenues	—			27,965			(21,417		)	6,548
Sales of purchased oil	—			168,358			—			168,358
Total revenues	432,711			198,015			(24,086		)	606,640
Lease operating expenses, including production tax	151,918			—			(10,685		)	141,233
Midstream service expenses, including minimum volume commitments	4,399			18,393			(11,711		)	11,081
Costs of purchased oil	—			174,338			—			174,338
General and administrative⁽¹⁾	82,251			8,174			—			90,425
Depletion, depreciation and amortization⁽²⁾	269,631			8,093			—			277,724
Impairment expense	2,372,296			2,592			—			2,374,888
Other operating costs and expenses⁽³⁾	8,123			342			—			8,465
Operating loss	$	(2,455,907	)	$	(13,917	)	$	(1,690	)	$	(2,471,514	)
Other financial information:
Income from equity method investee	$	—		$	6,799		$	—		$	6,799
Interest expense⁽⁴⁾	$	(98,040	)	$	(5,179	)	$	—		$	(103,219	)
Loss on early redemption of debt⁽⁵⁾	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Income tax benefit⁽⁶⁾	$	171,952		$	4,993		$	—		$	176,945
Capital expenditures	$	(597,086	)	$	(35,515	)	$	—		$	(632,601	)
Gross property and equipment⁽⁸⁾	$	5,302,716		$	345,183		$	(1,923	)	$	5,645,976

Year ended December 31, 2014:
Oil, NGL and natural gas sales	$	738,455		$	1,660		$	(2,912	)	$	737,203
Midstream service revenues	—			7,838			(5,593		)	2,245
Sales of purchased oil	—			54,437			—			54,437
Total revenues	738,455			63,935			(8,505		)	793,885
Lease operating expenses, including production tax	153,427			—			(6,612		)	146,815
Midstream service expenses, including minimum volume commitments	—			9,641			(1,660		)	7,981
Costs of purchased oil	—			53,967			—			53,967
General and administrative⁽¹⁾	99,075			6,969			—			106,044
Depletion, depreciation and amortization⁽²⁾	241,834			4,640			—			246,474
Impairment expense	1,802			2,102			—			3,904
Other operating costs and expenses⁽³⁾	2,248			66			—			2,314
Operating income (loss)	$	240,069		$	(13,450	)	$	(233	)	$	226,386
Other financial information:
Loss from equity method investee	$	—		$	(192	)	$	—		$	(192	)
Interest expense⁽⁴⁾	$	(117,560	)	$	(3,613	)	$	—		$	(121,173	)
Income tax (expense) benefit⁽⁶⁾	$	(170,551	)	$	6,265		$	—		$	(164,286	)
Capital expenditures⁽⁷⁾	$	(1,279,142	)	$	(60,607	)	$	—		$	(1,339,749	)
Gross property and equipment⁽⁸⁾	$	4,841,895		$	179,355		$	(233	)	$	5,021,017

Year ended December 31, 2013:
Oil, NGL and natural gas sales	$	664,844		$	—		$	—		$	664,844
Midstream service revenues	328			8,824			(8,739		)	413
Total revenues	665,172			8,824			(8,739		)	665,257
Lease operating expenses, including production tax	130,152			—			(8,620		)	121,532
Midstream service expenses, including minimum volume commitments	2,807			1,571			(119		)	4,259
General and administrative⁽¹⁾	86,951			2,745			—			89,696
Depletion, depreciation and amortization⁽²⁾	231,703			2,241			—			233,944
Other operating costs and expenses⁽³⁾	1,475			—			—			1,475
Operating income	$	212,084		$	2,267		$	—		$	214,351
Other financial information:
Income from equity method investee	$	—		$	29		$	—		$	29
Interest expense⁽⁴⁾	$	(98,680	)	$	(1,647	)	$	—		$	(100,327	)
Income tax expense⁽⁶⁾	$	(73,476	)	$	(1,031	)	$	—		$	(74,507	)
Capital expenditures⁽⁷⁾	$	(718,606	)	$	(24,409	)	$	—		$	(743,015	)
Gross property and equipment⁽⁸⁾	$	3,516,406		$	58,706		$	—		$	3,575,112

_____________________________________________________________________________

(1)


(2)	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.


(3)	Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015, accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated.


(4)	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.


(5)	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.


(6)	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% for the years ended December 31, 2015, 2014 and 2013.


(7)	Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013.


(8)	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015, 2014 and 2013, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015, 2014 and 2013.

Subsidiary guarantors (Tables)

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule of condensed consolidating balance sheet

Condensed consolidating balance sheet

December 31, 2015



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Total oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		131,725		—			131,725
Total other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Total other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating balance sheet

December 31, 2014



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	107,860	$	19,069	$	—		$	126,929
Other current assets	238,300		24		—			238,324
Total oil and natural gas properties, net	3,196,231		7,277		(233		)	3,203,275
Total midstream service assets, net	—		108,462		—			108,462
Total other fixed assets, net	42,046		299		—			42,345
Investment in subsidiaries and equity method investee	163,349		58,288		(163,349		)	58,288
Total other long-term assets	128,582		4,496		—			133,078
Total assets	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701

Accounts payable	$	38,453	$	555	$	—		$	39,008
Other current liabilities	283,026		31,800		—			314,826
Long-term debt, net	1,779,447		—		—			1,779,447
Other long-term liabilities	212,008		2,211		—			214,219
Stockholders' equity	1,563,434		163,349		(163,582		)	1,563,201
Total liabilities and stockholders' equity	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701

Schedule of condensed consolidating statement of operations

Condensed consolidating statement of operations

For the year ended December 31, 2015



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	432,478		$	198,248		$	(24,086	)	$	606,640
Total operating costs and expenses	2,897,272			203,278			(22,396		)	3,078,154
Loss from operations	(2,464,794		)	(5,030		)	(1,690		)	(2,471,514		)
Interest expense and other, net	(102,793		)	—			—			(102,793		)
Other non-operating income	182,396			6,708			(1,678		)	187,426
Income (loss) from continuing operations before income tax	(2,385,191		)	1,678			(3,368		)	(2,386,881		)
Income tax benefit	176,945			—			—			176,945
Income (loss) from continuing operations	(2,208,246		)	1,678			(3,368		)	(2,209,936		)
Net income (loss)	$	(2,208,246	)	$	1,678		$	(3,368	)	$	(2,209,936	)

Condensed consolidating statement of operations

For the year ended December 31, 2014



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	738,446		$	63,944		$	(8,505	)	$	793,885
Total operating costs and expenses	505,455			70,316			(8,272		)	567,499
Income (loss) from operations	232,991			(6,372		)	(233		)	226,386
Interest expense and other, net	(120,879		)	—			—			(120,879		)
Other non-operating income (expense)	317,980			(339		)	6,711			324,352
Income (loss) from continuing operations before income tax	430,092			(6,711		)	6,478			429,859
Income tax expense	(164,286		)	—			—			(164,286		)
Income (loss) from continuing operations	265,806			(6,711		)	6,478			265,573
Net income (loss)	$	265,806		$	(6,711	)	$	6,478		$	265,573

Condensed consolidating statement of operations

For the year ended December 31, 2013



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total operating revenues	$	665,172		$	8,824	$	(8,739	)	$	665,257
Total operating costs and expenses	455,972			3,673		(8,739		)	450,906
Income from operations	209,200			5,151		—			214,351
Interest expense and other, net	(100,164		)	—		—			(100,164		)
Other non-operating income	84,861			2,268		(10,232		)	76,897
Income from continuing operations before income tax	193,897			7,419		(10,232		)	191,084
Income tax expense	(74,507		)	—		—			(74,507		)
Income from continuing operations	119,390			7,419		(10,232		)	116,577
Income (loss) from discontinued operations, net of tax	(1,390		)	2,813		—			1,423
Net income	$	118,000		$	10,232	$	(10,232	)	$	118,000

Schedule of condensed consolidating statement of cash flows

Condensed consolidating statement of cash flows

For the year ended December 31, 2015



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	316,838		$	787		$	(1,678	)	$	315,947
Change in investments between affiliates	(136,252		)	134,574			1,678			—
Capital expenditures and other	(532,146		)	(135,361		)	—			(667,507		)
Net cash flows provided by financing activities	353,393			—			—			353,393
Net increase in cash and cash equivalents	1,833			—			—			1,833
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	31,153		$	1		$	—		$	31,154

Condensed consolidating statement of cash flows

For the year ended December 31, 2014



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided (used) by operating activities	$	496,955		$	(5,389	)	$	6,711		$	498,277
Change in investments between affiliates	(113,449		)	120,160			(6,711		)	—
Capital expenditures and other	(1,292,191		)	(114,770		)	—			(1,406,961		)
Net cash flows provided by financing activities	739,852			—			—			739,852
Net (decrease) increase in cash and cash equivalents	(168,833		)	1			—			(168,832		)
Cash and cash equivalents at beginning of period	198,153			—			—			198,153
Cash and cash equivalents at end of period	$	29,320		$	1		$	—		$	29,321

Condensed consolidating statement of cash flows

For the year ended December 31, 2013



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	359,198		$	15,763		$	(10,232	)	$	364,729
Change in investments between affiliates	23,986			(34,218		)	10,232			—
Capital expenditures and other	(348,339		)	18,455			—			(329,884		)
Net cash flows provided by financing activities	130,084			—			—			130,084
Net increase in cash and cash equivalents	164,929			—			—			164,929
Cash and cash equivalents at beginning of period	33,224			—			—			33,224
Cash and cash equivalents at end of period	$	198,153		$	—		$	—		$	198,153

Subsequent events (Tables)

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Schedule of new commodity contracts

The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:



	Aggregate volumes	Floor price		Ceiling price		Contract period
Natural gas (volumes in MMBtu):
Price collar	2,200,000	$	4.00	$	7.05	September 2013 - December 2013
Put	2,200,000	$	4.00	$	—	September 2013 - December 2013
Price collar	3,480,000	$	4.00	$	7.00	January 2014 - December 2014
Price collar	1,800,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,680,000	$	4.00	$	7.05	January 2014 - December 2014
Price collar	1,560,000	$	3.00	$	5.50	January 2014 - December 2014
Price collar	2,520,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015
Price collar	2,400,000	$	3.00	$	6.00	January 2015 - December 2015

Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts:



	Aggregate volumes	Floor price		Contract period
Natural gas (volumes in MMBtu):⁽¹⁾
Put	8,040,000	$	2.50	January 2017 - December 2017
Put	8,220,000	$	2.50	January 2018 - December 2018

_____________________________________________________________________________


(1)	The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental oil, NGL and natural gas disclosures (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of costs incurred in the acquisition, exploration and development of oil and natural gas assets

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:



	For the years ended December 31,
(in thousands)	2015		2014		2013
Property acquisition costs:
Evaluated	$	—	$	3,873	$	9,652
Unevaluated	—		9,925		27,087
Exploration⁽¹⁾	20,697		242,284		48,763
Development costs⁽²⁾	500,577		1,049,317		654,452
Total costs incurred	$	521,274	$	1,305,399	$	739,954

_____________________________________________________________________________


(1)	The Company acquired significant leasehold interests during the year ended December 31, 2014.


(2)	The costs incurred for oil, NGL and natural gas development activities include $13.4 million, $6.9 million and $6.8 million in asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively.

Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment

Aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment are presented below:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Capitalized costs:
Evaluated properties	$	5,103,635		$	4,446,781		$	3,276,578
Unevaluated properties not being depleted	140,299			342,731			208,085
	5,243,934			4,789,512			3,484,663
Less accumulated depletion and impairment	(4,218,942		)	(1,586,237		)	(1,349,315		)
Net capitalized costs	$	1,024,992		$	3,203,275		$	2,135,348

Summary of oil and natural gas property costs not being amortized by year

The following table shows a summary of the oil, NGL and natural gas property costs not being depleted as of December 31, 2015, by year in which such costs were incurred:



(in thousands)	2015		2014		2013		2012 and prior		Total
Unevaluated properties not being depleted	$	12,640	$	110,955	$	9,293	$	7,411	$	140,299

Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)

The results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) are presented below:



	For the years ended December 31,
(in thousands)	2015			2014		2013
Revenues:
Oil, NGL and natural gas sales	$	431,734		$	737,203	$	664,844
Production costs:
Lease operating expenses	108,341			96,503		79,136
Production and ad valorem taxes	32,892			50,312		42,396
	141,233			146,815		121,532
Other costs:
Depletion	263,666			237,067		227,992
Accretion of asset retirement obligations	2,236			1,721		1,475
Impairment expense	2,369,477			—		—
Income tax (benefit) expense⁽¹⁾	(164,141		)	126,576		112,984
Results of operations	$	(2,180,737	)	$	225,024	$	200,861

_____________________________________________________________________________

(1)

Schedule of analysis of change in estimated quantities of oil and natural gas reserves located within United States



	Year ended December 31, 2015
	Oil (MBbl)		NGL (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	140,190		—		642,794		247,322
Revisions of previous estimates⁽¹⁾	(88,900	)	35,477		(424,546	)	(124,180	)
Extensions, discoveries and other additions	10,511		5,865		36,074		22,388
Sales of reserves in place	(1,552	)	(1,008	)	(5,554	)	(3,486	)
Production	(7,610	)	(4,267	)	(26,816	)	(16,346	)
End of year	52,639		36,067		221,952		125,698
Proved developed reserves:
Beginning of year	56,975		—		291,493		105,557
End of year	40,944		29,349		180,613		100,395
Proved undeveloped reserves:
Beginning of year	83,215		—		351,301		141,765
End of year	11,695		6,718		41,339		25,303

_____________________________________________________________________________

(1)



	Year ended December 31, 2014
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	111,498		552,702		203,615
Revisions of previous estimates	(10,134	)	(67,350	)	(21,359	)
Extensions, discoveries and other additions	45,554		185,909		76,539
Purchases of reserves in place	173		498		256
Production	(6,901	)	(28,965	)	(11,729	)
End of year	140,190		642,794		247,322
Proved developed reserves:
Beginning of year	37,878		203,082		71,725
End of year	56,975		291,493		105,557
Proved undeveloped reserves:
Beginning of year	73,620		349,620		131,890
End of year	83,215		351,301		141,765



	Year ended December 31, 2013
	Oil (MBbl)		Gas (MMcf)		MBOE
Proved developed and undeveloped reserves:
Beginning of year	98,141		542,946		188,632
Revisions of previous estimates	(17,956	)	15,710		(15,338	)
Extensions, discoveries and other additions	37,850		192,229		69,888
Purchases of reserves in place	170		1,454		412
Sale of reserves in place	(1,220	)	(165,289	)	(28,768	)
Production	(5,487	)	(34,348	)	(11,211	)
End of year	111,498		552,702		203,615
Proved developed reserves:
Beginning of year	33,316		289,045		81,490
End of year	37,878		203,082		71,725
Proved undeveloped reserves:
Beginning of year	64,825		253,901		107,142
End of year	73,620		349,620		131,890

Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves

The standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves is as follows:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Future cash inflows	$	3,269,184		$	16,663,685		$	13,337,798
Future production costs	(1,321,471		)	(3,616,775		)	(3,059,368		)
Future development costs	(376,701		)	(2,471,985		)	(2,250,950		)
Future income tax expenses	—			(2,827,763		)	(2,150,983		)
Future net cash flows	1,571,012			7,747,162			5,876,497
10% discount for estimated timing of cash flows	(740,265		)	(4,500,434		)	(3,554,293		)
Standardized measure of discounted future net cash flows	$	830,747		$	3,246,728		$	2,322,204

Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves

Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves are as follows:



	For the years ended December 31,
(in thousands)	2015			2014			2013
Standardized measure of discounted future net cash flows, beginning of year	$	3,246,728		$	2,322,204		$	1,877,456
Changes in the year resulting from:
Sales, less production costs	(290,501		)	(590,388		)	(543,312		)
Revisions of previous quantity estimates	(2,444,322		)	(320,275		)	(190,961		)
Extensions, discoveries and other additions	192,979			1,340,022			1,166,481
Net change in prices and production costs	(1,495,144		)	145,740			313,947
Changes in estimated future development costs	(2,974		)	(22,961		)	921
Previously estimated development costs incurred during the period	162,237			92,135			89,396
Purchases of reserves in place	—			6,100			7,604
Divestitures of reserves in place	(29,149		)	—			(239,148		)
Accretion of discount	424,453			305,325			234,852
Net change in income taxes	997,805			(266,757		)	(259,991		)
Timing differences and other	68,635			235,583			(135,041		)
Standardized measure of discounted future net cash flows, end of year	$	830,747		$	3,246,728		$	2,322,204

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=50486907&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=51678428&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Quarterly Financial Information Disclosure [Abstract]

Supplemental quarterly financial data (unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of results of operations by quarter

The Company's results from continuing operations by quarter for the periods presented are as follows:



	Year ended December 31, 2015
(in thousands, except per share data)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	150,694		$	182,331		$	150,340		$	123,275
Operating loss	(26,498		)	(501,480		)	(927,859		)	(1,015,677		)
Net loss	(472		)	(397,034		)	(847,783		)	(964,647		)
Net loss per common share:
Basic	$	—		$	(1.88	)	$	(4.01	)	$	(4.57	)
Diluted	$	—		$	(1.88	)	$	(4.01	)	$	(4.57	)



	Year ended December 31, 2014
(in thousands, except per share data)	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	173,310		$	183,044		$	200,241	$	237,290
Operating income	60,038			64,561			69,164		32,623
Net income (loss)	(213		)	(18,899		)	83,407		201,278
Net income (loss) per common share:
Basic	$	—		$	(0.13	)	$	0.59	$	1.42
Diluted	$	—		$	(0.13	)	$	0.58	$	1.40

Organization (Details)		12 Months Ended
Organization (Details)	Dec. 31, 2013 subsidiary	Dec. 31, 2015 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of subsidiaries \| subsidiary	2
Number of segments \| segment		2

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Accounts receivable

Term of accounts receivable to be considered as past due (in days)

30 days

Term of past due balances to be reviewed individually for collectability (in days)

90 days

Matured derivatives

$ 27,469

$ 16,098

Purchased oil and other product sales

25,582

57,070

Joint operations, net

^[1]

21,375

33,808

11,775

18,917

Other

1,498

1,036

Total

87,699

126,929

Allowance for doubtful accounts of accounts receivable for joint operations

$ 200

$ 800

[1]	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively.

Basis of presentation and significant accounting policies - Oil and natural gas properties (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

USD ($)

$ / bbl

$ / MMBTU

Sep. 30, 2015

$ / bbl

$ / MMBTU

Jun. 30, 2015

$ / bbl

$ / MMBTU

Mar. 31, 2015

$ / bbl

$ / MMBTU

Sep. 30, 2015

USD ($)

^[1]

Jun. 30, 2015

USD ($)

^[1]

Mar. 31, 2015

USD ($)

^[1]

Dec. 31, 2015

USD ($)

$ / Boe

Dec. 31, 2014

USD ($)

$ / bbl

$ / Boe

$ / MMBTU

Dec. 31, 2013

USD ($)

$ / bbl

$ / Boe

$ / MMBTU

Unevaluated properties not being depleted | $

$ 140,299

$ 342,731

$ 208,085

Accumulated depletion | $

(4,200,000)

(1,600,000)

Depletion expense | $

$ 263,700

$ 237,100

$ 228,000

Depletion expense per physical unit of production (in USD per BOE) | $ / Boe

16.13

20.21

20.34

Discount rate used in calculating full cost ceiling (as a percent)

10.00%

Unamortized capitalized | $

$ 975,011

^[1]

$ 906,420

$ 488,046

$ 0

$ 2,400,000

Natural Gas

Benchmark Prices | $ / MMBTU

2.47

2.89

3.22

3.73

4.25

^[1]

3.57

^[1]

Realized Prices | $ / MMBTU

1.89

2.30

2.62

3.09

6.39

^[1]

5.52

^[1]

Crude Oil

Benchmark Prices | $ / bbl

46.79

55.73

68.17

79.21

91.48

^[1]

93.52

^[1]

Realized Prices | $ / bbl

45.58

54.28

66.68

77.72

89.57

^[1]

92.26

^[1]

Natural Gas Liquids

Benchmark Prices | $ / bbl

18.75

21.87

26.73

31.25

Realized Prices | $ / bbl

12.50

15.25

19.56

23.75

[1]	For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.

Basis of presentation and significant accounting policies - Midstream service assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

^[1]

$ 277,724

$ 246,474

$ 233,944

1,200,255

3,354,082

Midstream service assets

Less accumulated depreciation

7,500

4,300

$ 1,500

Midstream Service Assets

147,811

117,052

(16,086)

(8,590)

Midstream service assets | Minimum

$ 131,725

$ 108,462

Midstream service assets | Maximum

10 years

Pipeline and other gas gathering assets and other fixed assets

20 years

[1]	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.

Basis of presentation and significant accounting policies - Other fixed assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Depreciation, depletion and amortization

^[1]

$ 277,724

$ 246,474

$ 233,944

Pipeline and other gas gathering assets and other fixed assets

1,200,255

3,354,082

Other fixed assets

Depreciation, depletion and amortization

6,500

5,100

$ 4,400

Computer hardware and software

43,538

42,345

Pipeline and other gas gathering assets and other fixed assets

Pipeline and other gas gathering assets and other fixed assets

12,148

13,495

Vehicles

Pipeline and other gas gathering assets and other fixed assets

9,266

7,802

Leasehold improvements

Real estate and buildings

7,710

6,867

Pipeline and other gas gathering assets and other fixed assets

Pipeline and other gas gathering assets and other fixed assets

7,618

4,908

Aircraft

Pipeline and other gas gathering assets and other fixed assets

4,952

Other

Pipeline and other gas gathering assets and other fixed assets

5,105

4,909

Depreciable total, net

Less accumulated depreciation

46,799

42,933

(18,169)

(13,820)

Pipeline and other gas gathering assets and other fixed assets

28,630

29,113

Land

Pipeline and other gas gathering assets and other fixed assets

$ 14,908

$ 13,232

Minimum | Other

Pipeline and other gas gathering assets and other fixed assets

3 years

Maximum | Other

10 years

[1]	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.

Basis of presentation and significant accounting policies - Income tax, Long-lived assets and Cash flow disclosure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Materials and supplies
Impairment expense	$ 2,374,888,000	$ 3,904,000	$ 0
Unrecognized tax benefits	0	0	0
Supplemental Cash Flow Information
Cash paid for interest, net of $236, $150 and $255 of capitalized interest, respectively	112,457,000	104,936,000	95,622,000
Capitalized interest	236,000	150,000	255,000
Materials and Supplies \| Nonrecurring \| Level 2
Materials and supplies
Impairment expense	2,800,000	1,800,000
Line-fill \| Nonrecurring \| Level 2
Materials and supplies
Impairment expense	1,300,000	2,100,000
Compressed Natural Gas station \| Nonrecurring \| Level 2
Materials and supplies
Impairment expense	$ 1,300,000	$ 0	$ 0

Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred loan costs
Payments of Debt Issuance Costs	$ 6,759	$ 7,791	$ 2,987
Debt issuance cost, net	23,932	28,500
Accumulated amortization	17,000	19,400
Write-off of debt issuance costs	0	124	$ 1,502
Deferred finance costs	18,774	21,848
Future amortization expense of deferred loan costs
2016	4,503
2017	4,575
2018	4,349
2019	2,915
2020	3,005
Thereafter	4,585
Total	23,932	28,500
January 2011 \| Senior Notes
Deferred loan costs
Write-off of debt issuance costs	6,600
Accounting Standards Update 2015-03 \| Adjustments for New Accounting Principle, Early Adoption
Deferred loan costs
Deferred finance costs	$ 18,800	$ 21,800

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

Capital contribution payable to equity method investee

^[1]

$ 27,583

$ 0

Accrued interest payable

24,208

37,689

Accrued compensation and benefits

14,342

13,034

Lease operating expense payable

13,205

11,963

Other accrued liabilities

12,189

20,114

14,695

18,232

Total other current liabilities

$ 106,222

$ 101,032

[1]	See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee.

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Liability at beginning of year

$ 32,198

$ 21,743

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

2,236

6,370

Accretion expense

2,423

1,787

$ 1,475

Liabilities settled upon plugging and abandonment

(146)

(450)

Liabilities removed due to sale of property

(2,005)

Revision of estimates(1)

^[1]

11,600

2,748

Liability at end of year

$ 46,306

$ 32,198

$ 21,743

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

Basis of presentation and significant accounting policies - Revenue recognition and General and administrative expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue recognition
Value of net underproduced (overproduced) positions arising during the period increasing (decreasing) oil and natural gas sales			$ 30
General and administrative expense
Fees received for the operation of jointly-owned oil and natural gas properties	$ 3,125	$ 3,265	$ 3,398

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Change in accrued capital expenditures	$ (86,369)	$ 31,913	$ (5,284)
Change in accrued capital contribution to equity method investee	27,583	(2,597)	2,597
Capitalized asset retirement cost	13,836	9,118	6,790
Capitalized stock-based compensation	2,321	4,650	0
Equity issued in connection with acquisition	$ 0	$ 0	$ 3,029

Equity offering (Details) - USD ($) $ / shares in Units, $ in Thousands				12 Months Ended
	Mar. 05, 2015	Aug. 27, 2013	Aug. 19, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs	$ 754,200	$ 298,100		$ 754,163	$ 0	$ 298,104
Common Stock
Class of Stock [Line Items]
Stock issued during the period (in shares)	69,000,000		13,000,000		0
Sale of stock by existing shareholders (shares)		1,577,583	3,000,000
Shares issued (dollars per share)	$ 11.05		$ 23.75
Sale of stock, net of underwriting discount (dollars per share)			$ 22.9781
Common Stock \| Warburg Pincus LLC
Class of Stock [Line Items]
Stock issued during the period (in shares)	29,800,000
Ownership percentage	41.00%

Acquisitions and divestitures - 2015 Divestiture of non-strategic assets (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations - Non-strategic Assets $ in Millions	Sep. 15, 2015 USD ($) a property
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land (in acres) \| a	6,060
Number of real estate Properties \| property	123
Sales price	$ 65.5
Total revenues from discontinued operations	$ 64.8

Acquisitions and divestitures - 2015 Divestiture of non-strategic assets - Revenues and Expenses (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

$ 4,020

Non-strategic Assets

$ 5,138

$ 19,337

24,187

Expenses

^[1]

$ 5,791

$ 11,082

$ 11,826

[1]	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Acquisitions and divestitures - Summary of 2014 and 2013 acquisitions (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Aug. 28, 2014

Jun. 23, 2014

Jun. 11, 2014

Feb. 25, 2014

Sep. 06, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Payments to acquire mineral rights

$ 588,017

$ 1,251,757

$ 702,349

7,305

Cash consideration

$ 0

$ 6,493

$ 33,710

Leasehold Interests

Proved and Unproved Oil and Natural Gas Properties

$ 192,484

Common stock issued

^[1]

$ 0

Equity issued for acquisition, net of offering costs (in shares)

Costs incurred

$ 1,800

$ 4,693

Cash consideration

^[2]

$ 33,710

Common stock issued

^[1]

$ 0

3,029

^[2]

Other assets

200

Liabilities assumed

$ 200

123,803

Closing price per share (in dollars per share)

$ 26.21

Proved and Unproved Oil and Natural Gas Properties | Level 3

Lack of marketability discount to share price (as a percent)

6.64%

Proved Oil and Natural Gas Properties

Evaluated oil and natural gas properties

$ 9,700

Unproved Oil and Natural Gas Properties

Evaluated oil and natural gas properties

$ 27,100

Mineral Interests

Payments to acquire mineral rights

$ 7,305

Common stock issued

^[1]

$ 0

[1]

[2]

The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.

Acquisitions and divestitures - 2013 Divestitures (Details) a in Thousands, $ in Millions		12 Months Ended
	Aug. 01, 2013 USD ($)	Dec. 31, 2013 USD ($)	Dec. 20, 2013 USD ($) a property
Dalhart Basin Acreage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land (in acres) \| a			37
Number of real estate Properties \| property			1
Total revenues from discontinued operations			$ 20.4
Andarko Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration net of transaction costs	$ 428.3
Gain on disposal of assets		$ 3.2
EnerVest \| Andarko Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment, gross	400.0
Other Third Parties \| Andarko Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment, gross	38.0
Oil and Gas Properties \| Andarko Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Decrease in oil and gas property full cost	$ 388.0

Acquisitions and divestitures - 2013 Divestitures - Results of operations (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2013

USD ($)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Midstream service revenue

$ 4,020

Total revenues from discontinued operations

4,020

Midstream service expense, net

1,189

Depreciation and amortization

627

Total costs and expenses from discontinued operations

1,816

Non-operating expense, net

Income (loss) from discontinued operations before income tax

2,204

Income tax (expense) benefit

(781)

Income (loss) from discontinued operations

1,423

Andarko Basin

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Expenses

46,357

^[1]

Total revenues from discontinued operations

$ 59,631

[1]	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Debt - Interest expense (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Debt Disclosure [Abstract]

Cash payments for interest

$ 112,693

$ 105,086

$ 95,877

Amortization of debt issuance costs and other adjustments

4,243

4,433

4,926

Change in accrued interest

(13,481)

11,804

(221)

Interest costs incurred

103,455

121,323

100,582

Less capitalized interest

(236)

(150)

(255)

Total interest expense

^[1]

$ 103,219

$ 121,173

$ 100,327

[1]

Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.

Debt - March 2023 Notes (Details) - USD ($)		12 Months Ended
Debt - March 2023 Notes (Details) - USD ($)	Mar. 18, 2015	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Face amount of debt		$ 1,435,000,000	$ 1,801,295,000
Senior Notes \| March 2023 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 350,000,000.0	$ 350,000,000	$ 0
Stated rate (as a percent)	6.25%
Net proceeds from offering	$ 343,600,000
Senior Notes \| March 2023 Notes \| Period 2
Debt Instrument [Line Items]
Percentage of aggregate principal amount, that can be redeemed by equity offering	35.00%
Redemption price (as a percent)	65.00%
Debt instrument redemption principal amount outstanding threshold (in days)	180 days
Redemption start date		Mar. 18, 2015
Redemption end date		Mar. 15, 2018
Senior Notes \| March 2023 Notes \| Period 1
Debt Instrument [Line Items]
Redemption price (as a percent)	110.00%
Redemption start date		Mar. 18, 2015
Redemption end date		Mar. 15, 2016
Senior Notes \| March 2023 Notes \| IPO \| Period 2
Debt Instrument [Line Items]
Redemption price (as a percent)	106.25%

Debt - January 2022 Notes (Details) - USD ($)	Jan. 23, 2014	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Face amount of debt		$ 1,435,000,000	$ 1,801,295,000
Senior Notes \| Senior Note 5.625% due 2022
Debt Instrument [Line Items]
Face amount of debt	$ 450,000,000.0	$ 450,000,000	$ 450,000,000
Stated rate (as a percent)	5.625%
Net proceeds from offering	$ 442,200,000
Senior Notes \| Senior Note 5.625% due 2022 \| Period 2
Debt Instrument [Line Items]
Redemption price (as a percent)	100.00%
Percentage of aggregate principal amount, that can be redeemed by equity offering	35.00%
Debt instrument redemption principal amount outstanding threshold (percentage)	65.00%
Debt instrument redemption principal amount outstanding threshold (in days)	180 days
Senior Notes \| Senior Note 5.625% due 2022 \| Period 3
Debt Instrument [Line Items]
Redemption price (as a percent)	105.625%

Debt - May 2022 Notes (Details) - USD ($)	12 Months Ended
Debt - May 2022 Notes (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Apr. 27, 2012
Debt Instrument [Line Items]
Face amount of debt	$ 1,435,000,000	$ 1,801,295,000
Senior Notes \| Senior Notes 7.375 Percent Due 2022
Debt Instrument [Line Items]
Face amount of debt	$ 500,000,000	$ 500,000,000	$ 500,000,000.0
Stated rate (as a percent)			7.375%
Senior Notes \| May 2022 Notes \| Period 2
Debt Instrument [Line Items]
Redemption price (as a percent)	103.688%
Senior Notes \| May 2022 Notes \| Period 3
Debt Instrument [Line Items]
Redemption price (as a percent)	102.458%
Senior Notes \| May 2022 Notes \| Period 4
Debt Instrument [Line Items]
Redemption price (as a percent)	101.229%
Senior Notes \| May 2022 Notes \| Period 5
Debt Instrument [Line Items]
Redemption price (as a percent)	100.00%

Debt - January 2019 Notes (Details) - USD ($)

12 Months Ended

Apr. 06, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Oct. 19, 2011

Jan. 20, 2011

$ 1,435,000,000

$ 1,801,295,000

Senior Notes | January 2011

31,537,000

^[1]

$ 0

Stated rate (as a percent)

$ 350,000,000.0

9.50%

Senior Notes | October 2011

Senior Notes | Senior Notes 9.5 Percent 2019

$ 200,000,000.0

Redemption price (as a percent)

^[2]

$ 0

$ 551,295,000

Repurchased amount

$ 550,000,000.0

104.75%

Senior Notes | October 2011

$ 31,500,000

[1]	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.
[2]	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.

Debt - Senior Secured Credit Facility (Details) - Secured Debt	12 Months Ended
	Dec. 31, 2015 USD ($)
Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves	80.00%
Current ratio requirement (as a percent)	1.00
Consolidated interest coverage ratio	2.50
Letters of credit
Debt Instrument [Line Items]
Borrowing capacity	$ 20,000,000
Letters of credit outstanding	0
Line of Credit
Debt Instrument [Line Items]
Borrowing capacity	2,000,000,000.0
Current borrowing capacity	1,150,000,000
Aggregate elected commitment	1,000,000,000.0
Line of credit	$ 135,000,000
Interest rate (as a percent)	1.90%
Minimum \| Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	0.50%
Minimum \| London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	1.50%
Minimum \| Senior Secured Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.375%
Maximum \| Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	1.50%
Maximum \| London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate (percent)	2.50%
Maximum \| Senior Secured Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.50%

Debt - Fair value of debt (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

Unamortized premium

$ 1,300

Long-term debt | Senior Notes | Senior Notes 9.5 Percent 2019

$ 1,435,000

1,801,295

Long-term debt | Senior Notes | Senior Note 5.625% due 2022

^[1]

551,295

Long-term debt | Senior Notes | Senior Notes 7.375 Percent Due 2022

450,000

Long-term debt | Senior Notes | March 2023 Notes

500,000

Long-term debt | Line of Credit | Secured Debt

350,000

135,000

300,000

Fair value

Fair value | Senior Notes | Senior Notes 9.5 Percent 2019

1,284,294

1,713,822

Fair value | Senior Notes | Senior Note 5.625% due 2022

^[1]

550,000

Fair value | Senior Notes | Senior Notes 7.375 Percent Due 2022

388,301

396,014

Fair value | Senior Notes | March 2023 Notes

460,000

467,529

Fair value | Line of Credit | Secured Debt

301,000

$ 134,993

$ 300,279

[1]	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.

Debt - Debt issuance costs (Details) - USD ($)

Dec. 31, 2015

Mar. 18, 2015

Dec. 31, 2014

Jan. 23, 2014

Apr. 27, 2012

$ 1,435,000,000

$ 1,801,295,000

(18,774,000)

(21,848,000)

Senior Notes | Senior Notes 9.5 Percent 2019

1,416,226,000

1,779,447,000

^[1]

551,295,000

^[1]

(7,031,000)

Senior Notes | Senior Note 5.625% due 2022

^[1]

544,264,000

450,000,000

$ 450,000,000.0

(5,939,000)

(6,916,000)

Senior Notes | Senior Notes 7.375 Percent Due 2022

444,061,000

443,084,000

500,000,000

$ 500,000,000.0

(7,066,000)

(7,901,000)

Senior Notes | March 2023 Notes

492,934,000

492,099,000

350,000,000

$ 350,000,000.0

(5,769,000)

Line of Credit | Secured Debt

344,231,000

^[2]

135,000,000

300,000,000

^[2]

^[2]

$ 135,000,000

$ 300,000,000

[1]	The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.
[2]	Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets.

Employee compensation - Additional Information (Details)

3 Months Ended

12 Months Ended

Mar. 31, 2016

$ / shares

Mar. 31, 2015

$ / shares

Dec. 31, 2015

USD ($)

Dec. 31, 2014

Dec. 31, 2013

USD ($)

employee

$ / shares

Dec. 31, 2012

Incremental compensation cost due to plan modification

$ 4,700,000

Long Term Incentive Plan

Number of shares authorized | shares

10,000,000.0

Restricted stock awards

Unrecognized equity and stock-based compensation expense

$ 21,600,000

Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)

1 year 8 months 25 days

1,902,000

1,234,000

1,469,000

Restricted stock awards | Reorganization Grant Date

2,539,000

2,205,000

1,799,000

1,195,000

Restricted stock awards | Annual Vesting

20.00%

Restricted stock awards | One Year From Grant Date

20.00%

Restricted stock awards | Two Years from Grant Date

33.00%

Restricted stock awards | Three Years from Grant Date

33.00%

Restricted stock awards | Vesting in two years

34.00%

Restricted stock awards | Vesting in three years

50.00%

Restricted stock awards | Vesting one year from grant date

50.00%

Restricted stock awards | Vesting three years from grant date

100.00%

Restricted stock option awards

100.00%

Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)

2 years 4 months 7 days

Intrinsic value, options exercisable

$ 0

Aggregate intrinsic value, vested and expected to vest

$ 0

Requisite service period (in years)

4 years

Unrecognized stock-based compensation expense

$ 7,000,000

Options, life of award (in years)

10 years

Post employment, vested awards expiration period

1 year

Post employment, vested awards expiration period

90 days

Performance unit awards | February 27 2014 and February 27, 2015 | February 2014 Performance Share Awards and February 2015 Performance Share Awards

Unrecognized equity and stock-based compensation expense

$ 9,900,000

Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)

1 year 10 months 8 days

Requisite service period (in years)

3 years

Performance unit awards | February 27, 2015 | February 2015 Performance Share Awards

Performance unit awards | February 27, 2014 | February 2014 Performance Share Awards

602,501

271,667

Performance Unit Awards

Cash paid for performance units (in dollars per share) | $ / shares

$ 100

Performance Unit Awards | Subsequent events

Cash paid for performance units (in dollars per share) | $ / shares

$ 143.75

Performance Unit Awards | February 15, 2013 and February 3, 2012

Cash paid for performance units (in dollars per share) | $ / shares

$ 100.00

Performance Unit Awards | February 3, 2012

^[1]

Cash paid for performance units (in dollars per share) | $ / shares

^[1]

27,000

47,000

$ 100.00

Fair value of awards

$ 3,800,000

$ 2,700,000

Performance Unit Awards | February 15, 2013

^[2]

58,000

Performance Unit Awards | February 15, 2013 | Subsequent events

^[2]

44,000

Fair value of awards

$ 3,500,000

$ 5,700,000

$ 6,400,000

Cash paid for performance units (in dollars per share) | $ / shares

$ 143.75

Officer

Number of employees affected by plan modification | employee

Employee

Number of employees affected by plan modification | employee

401(k) Plan

Tax-deferred contributions of eligible employees as a percentage of their annual compensation

100.00%

Employer matching contribution (as a percent)

6.00%

Percentage of employer contributions vested upon receipt

100.00%

[1]	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.
[2]	The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016.

Employee compensation - Restricted stock awards activity (Details) - Restricted stock awards - $ / shares
shares in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Restricted stock awards

Outstanding at the beginning of the period (in shares)

2,205

1,799

1,195

1,902

1,234

1,469

(553)

(148)

(229)

^[1]

(1,015)

(680)

(636)

Weighted-average grant date fair value (per award)

2,539

2,205

1,799

Outstanding at the beginning of the period (in dollars per share)

$ 22.63

$ 19.17

$ 15.06

Fair value per performance share (in dollars per share)

11.98

25.68

18.17

Forfeited (in dollars per share)

20.48

22.56

18.47

Vested (in dollars per share)

^[1]

22.32

19.13

18.69

Outstanding at the end of the period (in dollars per share)

$ 15.26

$ 22.63

$ 19.17

[1]

The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards.

Employee compensation - Restricted stock option awards activity (Details) - Restricted stock option awards - $ / shares
shares in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Restricted stock option awards

Outstanding at the beginning of the period (in shares)

1,367

1,229

459

Expired or canceled (in shares)

632

336

1,019

Exercised (in shares)

(95)

^[1]

(104)

^[1]

(82)

(30)

(12)

(139)

(73)

(133)

1,778

1,367

1,229

459

Vested, exercisable, and expected to vest at end of period (in shares)

^[2]

545

^[3]

1,219

Weighted-average price (per option)

Outstanding at the end of the period (in dollars per share)

$ 20.76

$ 19.32

$ 24.11

Granted (in dollars per share)

11.93

25.60

17.34

Exercised (in dollars per share)

0.00

19.93

^[1]

20.79

^[1]

Expired or canceled (in dollars per share)

19.92

21.15

24.11

Forfeited (in dollars per share)

18.17

19.68

19.88

Outstanding at end of the period (in dollars per share)

17.86

$ 20.76

$ 19.32

$ 24.11

Vested and exercisable at end of period (in dollars per share)

^[2]

20.77

Vested, exercisable, and expected to vest at end of period (in dollars per share)

^[3]

$ 16.51

Weighted-average remaining contractual term (years)

Outstanding at the end of the period

7 years 10 months 28 days

8 years 2 months 1 day

8 years 9 months 26 days

10 years

Vested and exercisable at the end of the period

^[2]

6 years 11 months 9 days

Vested, exercisable, and expected to vest at end of period

^[3]

8 years 4 months 2 days

[1]	The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards.
[2]	The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value.
[3]	The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value.

Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Restricted stock option awards

12 Months Ended

Dec. 31, 2015

$ / shares

February 27, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

1.70%

^[1]

6 years 3 months

^[2]

52.59%

^[3]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 6.15

February 27, 2014

1.88%

^[1]

6 years 3 months

^[2]

53.21%

^[3]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 13.41

February 15, 2013

1.19%

^[1]

6 years 3 months

^[2]

58.89%

^[3]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 9.67

February 3, 2012

1.14%

^[1]

6 years 3 months

^[2]

59.98%

^[3]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

$ 13.52

[1]	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.
[2]	As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
[3]	The Company utilized its own volatility in order to develop the expected volatility for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.

Employee compensation - Restricted stock option awards full years of continuous employment (Details) - Restricted stock option awards	12 Months Ended
	Dec. 31, 2015
Less than one
Equity and stock-based compensation
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
One
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Two
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Three
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Four
Equity and stock-based compensation
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%

Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares	Feb. 27, 2015	Feb. 27, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as a percent)	0.95%	0.63%
Dividend yield (as a percent)	0.00%	0.00%
Expected volatility (as a percent)	53.78%	38.21%
Share Price (in dollars per share)	$ 11.93	$ 25.60
Fair value per performance share (in dollars per share)	$ 16.23	$ 28.56

Employee compensation - Stock-based compensation award expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity and stock-based compensation
Total stock-based compensation, gross	$ 26,830	$ 27,729	$ 21,433
Less amounts capitalized in oil and natural gas properties	(2,321)	(4,650)	0
Total stock-based compensation, net of amounts capitalized	24,509	23,079	21,433
Restricted stock awards
Equity and stock-based compensation
Total stock-based compensation, gross	17,534	21,982	17,084
Restricted stock option awards
Equity and stock-based compensation
Total stock-based compensation, gross	4,074	3,639	4,349
Performance unit awards
Equity and stock-based compensation
Total stock-based compensation, gross	$ 5,222	$ 2,108	$ 0

Employee compensation - Performance unit awards outstanding (Details) - Performance Unit Awards - shares
shares in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

February 15, 2013

Outstanding at the beginning of the period (in shares)

^[1]

^[1]

^[1]

(4)

^[1]

(44)

(10)

^[2]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

February 3, 2012

Outstanding at the beginning of the period (in shares)

^[3]

^[3]

^[3]

(9)

^[3]

(27)

(11)

^[2]

Income tax benefit (expense)

^[3]

[1]	The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016.
[2]	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
[3]	The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.

Employee compensation - Performance unit award compensation expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$ 24,509	$ 23,079	$ 21,433
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	4,081	601	4,733
February 15, 2013 \| Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	4,081	409	2,863
February 3, 2012 \| Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$ 0	$ 192	$ 1,870

Employee compensation - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Contributions	$ 1,847	$ 2,202	$ 1,886

Income taxes - Income tax benefit (expense) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Current taxes:

Federal

$ 0

State

Deferred taxes:

Federal

152,590

(147,445)

(64,034)

State

24,355

(16,841)

(10,473)

^[1]

$ 176,945

$ (164,286)

$ (74,507)

[1]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%

Income taxes - Comprehensive provision for income taxes (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Comprehensive benefit (expense) for income taxes

Continuing operations

^[1]

$ 176,945

$ (164,286)

$ (74,507)

Discontinued operations

(781)

$ 176,945

$ (164,286)

$ (75,288)

[1]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%

Amount of tax expense (benefit) related to a discontinued operation. Includes, but is not limited to, tax expense (benefit) related to income (loss) from operations during the phase-out period, tax expense (benefit) related to gain (loss) on disposal, tax expense (benefit) related to gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and tax expense (benefit) related to adjustments of a prior period gain (loss) on disposal.

Income taxes - Income tax reconciliation (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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

$ 835,408

$ (150,450)

$ (64,969)

State income tax, net of federal tax benefit and increase in valuation allowance

13,975

(11,099)

(7,532)

Non-deductible stock-based compensation

(256)

(509)

(1,070)

Stock-based compensation tax deficiency

(3,274)

(266)

(559)

Increase in deferred tax valuation allowance

(668,702)

(1,139)

(63)

Other items

(206)

(823)

(314)

Income tax benefit (expense)

^[1]

$ 176,945

$ (164,286)

$ (74,507)

[1]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%

Income taxes - Tax impact of shortfalls (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	$ 3,334	$ 270	$ 575
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	3,334	112	425
Restricted stock option awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock based compensation tax deficiency	$ 0	$ 158	$ 150

Income taxes - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Significant components of deferred tax assets
Oil and natural gas properties, midstream service assets and other fixed assets	$ 306,997	$ (424,712)
Net operating loss carry-forward	479,022	353,724
Derivatives	(98,675)	(121,365)
Stock-based compensation	11,597	10,718
Equity method investee	(31,711)	(2,331)
Accrued bonus	4,763	3,256
Capitalized interest	2,525	3,049
Materials and supplies impairment	1,647	642
Other	1,173	1,373
Net deferred tax asset (liability) before valuation allowance	677,338
Net deferred tax asset (liability) before valuation allowance		(175,646)
Valuation allowance	(677,338)	(1,299)
Net deferred tax asset (liability)	$ 0
Net deferred tax asset (liability)		$ 176,945

Income taxes - Classification (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

New Accounting Pronouncement, Early Adoption [Line Items]

Deferred tax asset

$ 0

^[1]

Current

^[1]

Noncurrent

(176,945)

^[1]

Net deferred tax asset (liability)

^[1]

$ 0

(176,945)

2014 | New Accounting Pronouncement, Early Adoption, Effect

New Accounting Pronouncement, Early Adoption [Line Items]

Deferred tax asset

^[1]

Current

^[1]

(71,191)

Noncurrent

^[1]

(105,754)

Net deferred tax asset (liability)

^[1]

(176,945)

Offset | New Accounting Pronouncement, Early Adoption, Effect

New Accounting Pronouncement, Early Adoption [Line Items]

Deferred tax asset

^[1]

Current

^[1]

71,191

Noncurrent

^[1]

(71,191)

Net deferred tax asset (liability)

^[1]

$ 0

[1]	See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.

Income taxes - Operating losses (Details) - Federal $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 1,368,590
2026
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 2,741
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2026
2027
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 38,651
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2027
2028
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 228,661
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2028
2029
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 101,932
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
2030
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 80,963
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Thereafter
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	$ 915,642

Income taxes - Additional Information (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Income Tax Examination [Line Items]

Federal statutory rate (as a percent)

35.00%

34.00%

Effective tax rate (as a percent)

7.00%

38.00%

39.00%

Valuation allowance

$ 677,338

$ 1,299

Income tax expense

^[1]

(176,945)

$ 164,286

$ 74,507

Additional paid-in-capital credits

4,500

Valuation allowance

676,000

Federal

Income Tax Examination [Line Items]

Net operating loss carry-forwards

1,368,590

OKLAHOMA | State

Income Tax Examination [Line Items]

Net operating loss carry-forwards

$ 40,900

[1]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%

Derivatives - Additional Information (Details) - Derivatives not designated as hedges

3 Months Ended

12 Months Ended

Mar. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

contract

Dec. 31, 2014

USD ($)

contract

Dec. 31, 2013

USD ($)

Sep. 30, 2013

USD ($)

derivative

Number of instruments held | contract

Commodity derivatives

Cash settlements received for early terminations and modifications of derivatives, net

Net proceeds

$ 76,700,000

^[1]

$ 0

$ 76,660,000

$ 6,008,000

Derivatives, deferred premium paid

$ 2,200,000

Interest rate swap

Number of interest rate derivatives | derivative

Interest rate (as a percent)

1.11%

Interest rate cap

Number of interest rate derivatives | derivative

Interest rate (as a percent)

3.00%

Interest rate derivatives

Number of instruments held | contract

Notional amount of derivatives

$ 100,000,000.0

[1]	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts.

Derivatives - Anadarko Basin Sale (Details) - Andarko Basin - Derivatives not designated as hedges - Natural gas derivatives	Dec. 31, 2013 MMBTU $ / MMBTU
Swap August 2013 - December 2013 \| Transferred On Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,386,800
Swap price (in dollars per unit)	4.31
Swap January 2014 - December 2014 \| Transferred On Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	3,978,500
Swap price (in dollars per unit)	4.36
Collar September 2013 - December 2013 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,200,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	7.05
Put September 2013 - December 2013 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,200,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	0.00
Collar January 2014 - December 2014 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	3,480,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	7.00
Collar 2 January 2014 - December 2014 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	1,800,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	7.05
Collar 3 January 2014 - December 2014 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	1,680,000
Floor price (in dollars per unit)	4.00
Ceiling price (in dollars per unit)	7.05
Collar 4 January 2014 - December 2014 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	1,560,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	5.50
Collar January 2015 - December 2015 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,520,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00
Collar 2 January 2015 - December 2015 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,400,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00
Collar 3 January 2015 - December 2015 \| Unwound on Divestiture
Derivative [Line Items]
Aggregate volumes (in Bbls/MMBtu) \| MMBTU	2,400,000
Floor price (in dollars per unit)	3.00
Ceiling price (in dollars per unit)	6.00

Derivatives - Gain (Loss) on Derivatives (Details) - Derivatives not designated as hedges - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Commodity derivatives

Derivative Instruments, Gain (Loss) [Line Items]

Cash settlements received for matured commodity derivatives

$ 255,281

$ 28,241

$ 4,046

Early terminations and modification of commodity derivatives received

^[1]

76,660

6,008

Interest rate swap

Derivative Instruments, Gain (Loss) [Line Items]

Cash settlements paid for matured interest rate swaps

(301)

Derivative

Derivative Instruments, Gain (Loss) [Line Items]

Cash settlements received for derivatives, net

$ 255,281

$ 104,901

$ 9,753

[1]	During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts.

Derivatives - Open Positions (Details) - Derivatives not designated as hedges

12 Months Ended

Dec. 31, 2015

MMBTU

$ / bbl

$ / MMBTU

bbl

Short | Crude Oil | Options Held

1,296,000

^[1]

Short | Crude Oil | Swaps

45.00

^[1]

1,573,800

^[1]

Short | Crude Oil | Collars

84.82

^[1]

Short | Natural Gas | Collars

3,654,000

^[1]

Hedged volume (MMBtu) | MMBTU

18,666,000

^[2]

Short | Minimum | Crude Oil

6,523,800

^[1]

Short | Minimum | Crude Oil | Collars

70.84

^[1]

Short | Minimum | Natural Gas | Collars

73.99

^[1]

Short | Maximum | Crude Oil

3.00

^[2]

5,227,800

^[1]

Short | Maximum | Crude Oil | Collars

88.18

^[1]

Short | Maximum | Natural Gas | Collars

89.63

^[1]

Long | Crude Oil | Options Held

5.60

^[2]

^[1]

0.00

^[1]

Long | Crude Oil | Swaps

Long | Crude Oil | Collars

^[1]

Long | Natural Gas | Collars

2,628,000

^[1]

Hedged volume (MMBtu) | MMBTU

5,475,000

^[2]

Long | Minimum | Crude Oil

2,628,000

^[1]

Long | Minimum | Crude Oil | Collars

77.22

^[1]

Long | Minimum | Natural Gas | Collars

77.22

^[1]

Long | Maximum | Crude Oil

3.00

^[2]

2,628,000

^[1]

Long | Maximum | Crude Oil | Collars

97.22

^[1]

Long | Maximum | Natural Gas | Collars

97.22

^[1]

Changes in assets classified as Level 3 measurements

4.00

^[2]

[1]	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").
[2]	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	$ 198,805	$ 194,601
Net fair value presented on the consolidated balance sheets	77,443	117,788
Liabilities, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	(115)
Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position		312,274
Recurring \| Level 1
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position		0
Recurring \| Level 2
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position		321,559
Recurring \| Level 3
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position		(9,285)
Fair value \| Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position		312,274
Crude Oil \| Recurring \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	194,940	190,303
Net fair value presented on the consolidated balance sheets	80,302	117,963
Liabilities, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	0
Net fair value presented on the consolidated balance sheets	0	0
Crude Oil \| Recurring \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	(9,301)	(4,653)
Net fair value presented on the consolidated balance sheets	(4,877)	(3,821)
Liabilities, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	(115)
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas \| Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	276,248
Natural Gas \| Recurring \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	13,166	9,647
Net fair value presented on the consolidated balance sheets	2,459	3,646
Liabilities, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	0
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas \| Recurring \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	(696)
Net fair value presented on the consolidated balance sheets	(441)	0
Liabilities, Fair Value Disclosure [Abstract]
Net fair value presented on the consolidated balance sheets	0	0
Net fair value presented on the consolidated balance sheets	0	0
Natural Gas \| Recurring \| Level 1
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	0
Natural Gas \| Recurring \| Level 2
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	290,867
Natural Gas \| Recurring \| Level 3
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	(14,619)
Natural Gas \| Fair value \| Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	276,248
Current: \| Crude Oil \| Recurring \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Current: \| Crude Oil \| Recurring \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(9,301)	(4,653)
Current: \| Crude Oil \| Recurring \| Level 1 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 1 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 2 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	194,940	190,303
Current: \| Crude Oil \| Recurring \| Level 2 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 3 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 3 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Fair value \| Recurring \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	194,940	190,303
Current: \| Crude Oil \| Fair value \| Recurring \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Current: \| Natural Gas \| Recurring \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	(696)
Current: \| Natural Gas \| Recurring \| Level 1 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 1 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 2 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	13,166	9,647
Current: \| Natural Gas \| Recurring \| Level 2 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 3 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 3 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Fair value \| Recurring \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	13,166	9,647
Current: \| Natural Gas \| Fair value \| Recurring \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Noncurrent: \| Crude Oil \| Recurring \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(4,877)	(3,821)
Noncurrent: \| Crude Oil \| Recurring \| Level 1 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 1 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 2 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	80,302	117,963
Noncurrent: \| Crude Oil \| Recurring \| Level 2 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 3 \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 3 \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Fair value \| Recurring \| Oil Derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	80,302	117,963
Noncurrent: \| Crude Oil \| Fair value \| Recurring \| Oil Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Noncurrent: \| Natural Gas \| Recurring \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(441)	0
Noncurrent: \| Natural Gas \| Recurring \| Level 1 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 1 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 2 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	2,459	3,646
Noncurrent: \| Natural Gas \| Recurring \| Level 2 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 3 \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 3 \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Fair value \| Recurring \| Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	2,459	3,646
Noncurrent: \| Natural Gas \| Fair value \| Recurring \| Natural Gas Deferred Premiums
Assets, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Current: \| Crude Oil \| Recurring \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	9,301	4,653
Current: \| Crude Oil \| Recurring \| Level 1 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 1 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 2 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 2 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 3 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Recurring \| Level 3 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	(9,301)	(4,768)
Current: \| Crude Oil \| Fair value \| Recurring \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Crude Oil \| Fair value \| Recurring \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	(9,301)	(4,768)
Current: \| Natural Gas \| Recurring \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Current: \| Natural Gas \| Recurring \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	0	696
Current: \| Natural Gas \| Recurring \| Level 1 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 1 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 2 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 2 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 3 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Recurring \| Level 3 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	(696)
Current: \| Natural Gas \| Fair value \| Recurring \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Current: \| Natural Gas \| Fair value \| Recurring \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	(696)
Noncurrent: \| Crude Oil \| Recurring \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Noncurrent: \| Crude Oil \| Recurring \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	4,877	3,821
Noncurrent: \| Crude Oil \| Recurring \| Level 1 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 1 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 2 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 2 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 3 \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Recurring \| Level 3 \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	(4,877)	(3,821)
Noncurrent: \| Crude Oil \| Fair value \| Recurring \| Oil Derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Crude Oil \| Fair value \| Recurring \| Oil Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	(4,877)	(3,821)
Noncurrent: \| Natural Gas \| Recurring \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Noncurrent: \| Natural Gas \| Recurring \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Amounts offset	441	0
Noncurrent: \| Natural Gas \| Recurring \| Level 1 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 1 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 2 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 2 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 3 \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Recurring \| Level 3 \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	(441)	0
Noncurrent: \| Natural Gas \| Fair value \| Recurring \| Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	0	0
Noncurrent: \| Natural Gas \| Fair value \| Recurring \| Natural Gas Deferred Premiums
Liabilities, Fair Value Disclosure [Abstract]
Total gross fair value	$ (441)	$ 0

Fair value measurements - Narrative (Details) - Deferred Premiums - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, deferred premium paid		$ 2.2
Minimum \| Recurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	1.69%
Maximum \| Recurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used (as a percent)	3.56%

Fair value measurements - Actual cash payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Fair Value Disclosures [Abstract]
2016	$ 8,629
2017	5,796
2018	426
Total	$ 14,851

Fair value measurements - Roll forward (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Change in net present value of deferred premiums for derivatives

$ 203

$ 220

$ 462

Deferred Premiums

Changes in assets classified as Level 3 measurements

Balance of Level 3 at beginning of period

(9,285)

(12,684)

(24,709)

Change in net present value of deferred premiums for derivatives

(203)

(220)

(462)

Total purchases and settlements:

Purchases

(10,298)

(3,800)

Settlements

^[1]

5,167

7,419

12,487

Balance of Level 3 at end of period

$ (14,619)

$ (9,285)

$ (12,684)

[1]	The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Net income (loss) per share - Narrative (Details) - Restricted stock option awards - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
February 2014 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	336,140	336,140
Options outstanding weighted average exercise price (in dollars per shares)	$ 25.60	$ 25.60
February 2012 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	280,626	280,626
Options outstanding weighted average exercise price (in dollars per shares)	$ 24.11	$ 24.11
February 2013 Awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	750,338	750,338
Options outstanding weighted average exercise price (in dollars per shares)	$ 17.34	$ 17.34

Net income (loss) per share - Calculation of net income per share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Net income (numerator):

Income (loss) from continuing operations—basic and diluted

$ (2,209,936)

$ 265,573

$ 116,577

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

1,423

Net loss

$ (964,647)

$ (847,783)

$ (397,034)

$ (472)

$ 201,278

$ 83,407

$ (18,899)

$ (213)

$ (2,209,936)

$ 265,573

$ 118,000

Weighted-average common shares outstanding (denominator):

Weighted-average common shares outstanding—basic (in shares)

^[1]

199,158

141,312

132,490

Weighted-average common shares outstanding—diluted (in shares)

199,158

143,554

134,378

Net income (loss) per share:

Income (loss) from continuing operations - basic (in dollars per share)

$ (11.10)

$ 1.88

$ 0.88

Income from discontinued operations, net of tax - basic (in dollars per share)

0.00

0.01

Income (loss) from continuing operations - diluted

$ (4.57)

$ (4.01)

$ (1.88)

$ 0.00

$ 1.42

$ 0.59

$ (0.13)

$ 0.00

(11.10)

1.88

0.89

(11.10)

1.85

0.87

Income from discontinued operations, net of tax - diluted

0.00

0.01

Weighted-average common shares outstanding (denominator):

$ (4.57)

$ (4.01)

$ (1.88)

$ 0.00

$ 1.40

$ 0.58

$ (0.13)

$ 0.00

$ (11.10)

$ 1.85

$ 0.88

Restricted stock awards

Non-vested restricted stock awards (in shares)

2,242

1,888

[1]

Credit risk (Details) $ in Millions	12 Months Ended
Credit risk (Details) $ in Millions	Dec. 31, 2015 USD ($) customer partner	Dec. 31, 2014 customer partner	Dec. 31, 2013 customer
Credit risk
Cash balances exceeded by balance insured by FDIC \| $	$ 51.3
Customers \| Total revenues \| Customer one and two
Credit risk
Number of major customers	2	2
Customers \| Total revenues \| Customer one
Credit risk
Concentration risk (as a percent)	37.50%	36.00%	28.30%
Customers \| Total revenues \| Customer two
Credit risk
Concentration risk (as a percent)	20.30%	13.70%	11.70%
Customers \| Total revenues \| Customer three
Credit risk
Concentration risk (as a percent)			11.70%
Customers \| Total revenues \| Customer one, two and three
Credit risk
Number of major customers			3
Customers \| Trade Accounts Receivable \| Customer three, four and five
Credit risk
Number of major customers		3
Customers \| Purchased Oil Sales
Credit risk
Number of major customers	1	1
Concentration risk (as a percent)	100.00%	100.00%
Customers \| Purchased Oil and Other Products Sales
Credit risk
Concentration risk (as a percent)	99.60%	97.30%
Credit Concentration Risk \| Total revenues \| Customer one
Credit risk
Concentration risk (as a percent)		16.40%
Credit Concentration Risk \| Total revenues \| Customer two
Credit risk
Concentration risk (as a percent)		22.50%
Credit Concentration Risk \| Trade Accounts Receivable \| Customer one and two
Credit risk
Number of additional customers			2
Credit Concentration Risk \| Trade Accounts Receivable \| Customer one
Credit risk
Number of major customers	1	1
Concentration risk (as a percent)	35.30%		36.00%
Credit Concentration Risk \| Trade Accounts Receivable \| Customer two
Credit risk
Number of major customers	1	1
Concentration risk (as a percent)	23.70%		15.70%
Credit Concentration Risk \| Trade Accounts Receivable \| Customer three and four
Credit risk
Number of additional customers	2
Credit Concentration Risk \| Trade Accounts Receivable \| Customer three
Credit risk
Concentration risk (as a percent)	18.50%	13.50%
Credit Concentration Risk \| Trade Accounts Receivable \| Customer four
Credit risk
Concentration risk (as a percent)	10.70%	12.50%
Credit Concentration Risk \| Trade Accounts Receivable \| Customer five
Credit risk
Concentration risk (as a percent)		11.60%
Partner Two \| Credit Concentration Risk \| Joint operations accounts receivable
Credit risk
Concentration risk (as a percent)	17.10%	13.20%
Partner One \| Credit Concentration Risk \| Joint operations accounts receivable
Credit risk
Concentration risk (as a percent)	18.90%	20.50%
Partner one and two \| Credit Concentration Risk \| Joint operations accounts receivable
Credit risk
Number of joint interest partners \| partner	2	2

Commitments and contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Lease commitments
2016	$ 3,087
2017	3,244
2018	3,160
2019	2,408
2020	1,294
Thereafter	8,217
Total	21,410
Rent expense
Rent expense	2,880	$ 3,042	$ 1,923
Drilling rig fees	0	$ 527	$ 0
Firm Sale And Transportation Commitments
Rent expense
Future commitments	425,700
Drilling Contracts
Rent expense
Future commitments	$ 10,300

Restructuring (Details) $ in Thousands		12 Months Ended
Restructuring (Details) $ in Thousands	Jan. 20, 2015 employee	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses \| $		$ 6,042	$ 0	$ 0
Reduction in Force
Restructuring Cost and Reserve [Line Items]
Restructuring expenses \| $		$ 6,000
Reduction in Force \| Facility Closing
Restructuring Cost and Reserve [Line Items]
Employee positions eliminated \| employee	75
Reduction in Force \| Contract Termination
Restructuring Cost and Reserve [Line Items]
Employee positions eliminated \| employee	24

Recently issued accounting standards - Income taxes (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

New Accounting Pronouncement, Early Adoption [Line Items]

Decrease in deferred income taxes

$ 1,813,287

$ 3,910,701

^[1]

Total current liabilities

216,815

353,834

Increase in deferred income taxes

176,945

^[1]

Topic 740, Income Taxes | New Accounting Pronouncement, Early Adoption, Effect

$ 1,681,840

2,347,500

New Accounting Pronouncement, Early Adoption [Line Items]

Decrease in deferred income taxes

$ (68,069)

$ (45,089)

$ 0

Decrease in deferred income taxes

(68,069)

(45,089)

(68,069)

(45,089)

(73,753)

(71,191)

Total current liabilities

(68,069)

(45,089)

(73,753)

(71,191)

Increase in deferred income taxes

73,753

71,191

Income (loss) from continuing operations

$ (68,069)

$ (45,089)

$ 0

[1]	See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.

Recently issued accounting standards - Debt issuance costs (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs	$ 18,774			$ 21,848
Subtopic 835-30, Interest-Imputation of Interest \| New Accounting Pronouncement, Early Adoption, Effect \| Decrease in debt issuance costs, net
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs		$ (26,158)	$ (33,513)	(28,463)
Subtopic 835-30, Interest-Imputation of Interest \| New Accounting Pronouncement, Early Adoption, Effect \| Increase in other assets, net
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs		6,068	6,873	6,615
Subtopic 835-30, Interest-Imputation of Interest \| New Accounting Pronouncement, Early Adoption, Effect \| Decrease in total assets
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs		(20,090)	(26,640)	(21,848)
Subtopic 835-30, Interest-Imputation of Interest \| New Accounting Pronouncement, Early Adoption, Effect \| Decrease in long-term debt, net
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs		(20,090)	(26,640)	(21,848)
Subtopic 835-30, Interest-Imputation of Interest \| New Accounting Pronouncement, Early Adoption, Effect \| Decrease in total liabilities
New Accounting Pronouncement, Early Adoption [Line Items]
Debt issuance costs		$ (20,090)	$ (26,640)	$ (21,848)

Variable interest entity (Details) - USD ($) $ in Thousands	12 Months Ended
Variable interest entity (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	$ 99,855	$ 55,164	$ 3,287
Minimum volume commitments	5,235	2,552	$ 891
Variable Interest Entity, Not Primary Beneficiary \| Medallion Gathering And Processing LLC
Schedule of Equity Method Investments [Line Items]
Investment in equity method investee	$ 99,900	$ 55,200
Ownership percentage	49.00%
Ownership percentage held by investment partner	51.00%
Percentage required for key decisions	75.00%
Minimum volume commitments	$ 3,000

Variable Interest entity - Summarized financial information (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Statement of Operations

Total revenues

$ 34,288

^[1]

$ 4,623

$ 892

Gross profit(1)

^[2]

29,826

^[1]

4,623

892

13,821

^[1]

(333)

Net income (loss)(2)

^[3]

13,821

^[1]

(333)

$ 54

Balance Sheet

Current assets

78,411

25,777

Noncurrent assets

329,956

112,753

408,367

^[4]

138,530

Current liabilities

15,461

19,522

Noncurrent liabilities

Medallion Gathering And Processing LLC

$ 15,461

^[4]

$ 19,522

[1]	Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016.
[2]	Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013.
[3]	As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments.
[4]	Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016.

Related Parties - Consolidated statements of operations related to Medallion (Details) - Medallion Gathering And Processing LLC - Equity Method Investee - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 487	$ 0	$ 0
Minimum volume commitments
Related Party Transaction [Line Items]
Related party revenues	5,235	2,552	891
Interest and other income
Related Party Transaction [Line Items]
Related party revenues	$ 158	$ 0	$ 0

Related Parties - Consolidated balance sheets related to Medallion (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

Accounts receivable, net

$ 1,163

$ 0

Medallion Gathering And Processing LLC | Equity Method Investee | Other assets, net(1)

Related party assets and liabilities

^[1]

(1,025)

(1,110)

Medallion Gathering And Processing LLC | Equity Method Investee | Other current liabilities(2)

Related party assets and liabilities

^[2]

$ 27,583

$ 3,443

[1]

Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

[2]

Related Parties - Net oil, NGL and natural gas sales (Details) - Targa Resources Corp. - Affiliated Entity - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil, NGL and natural gas sales
Related Party Transaction [Line Items]
Related party revenues	$ 99,992	$ 96,100	$ 74,245
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 590	$ 0	$ 0

Related Parties - Amounts included in oil, NGL and natural gas sales receivable from Targa (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Targa Resources Corp. \| Affiliated Entity
Related Party Transaction [Line Items]
Accounts receivable, net	$ 6,097	$ 12,869

Related Parties - Lease operating expenses related to Archrock Partners (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Archrock Partners, L.P. \| Affiliated Entity \| Lease Operating Expenses
Related Party Transaction [Line Items]
Lease operating expenses	$ 1,477	$ 975	$ 51

Related Parties - Capitalized oil and natural gas properties related to Archrock Partners (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 588,017	$ 1,251,757	$ 702,349
Midstream service assets	35,459	60,548	24,409
Archrock Partners, L.P. \| Affiliated Entity \| Oil and natural gas properties
Related Party Transaction [Line Items]
Oil and natural gas properties	0	57	0
Archrock Partners, L.P. \| Affiliated Entity \| Midstream service assets
Related Party Transaction [Line Items]
Midstream service assets	$ 64	$ 833	$ 0

Related Parties - Accounts payable from Archrock Partners (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Archrock Partners, L.P. \| Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable	$ 13	$ 0

Related Parties - Capitalized oil and natural gas properties related to H&P (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 588,017	$ 1,251,757	$ 702,349
Archrock Partners, L.P. \| Affiliated Entity \| Oil and natural gas properties
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 2,434	$ 9,518	$ 9,943

Segments - Selected financial information (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 431,734

$ 737,203

$ 664,844

6,548

2,245

413

168,358

54,437

$ 123,275

$ 150,340

$ 182,331

$ 150,694

$ 237,290

$ 200,241

$ 183,044

$ 173,310

606,640

793,885

665,257

Midstream service expenses, including minimum volume commitments

141,233

146,815

121,532

11,081

7,981

4,259

174,338

53,967

^[1]

90,425

106,044

89,696

^[2]

277,724

246,474

233,944

2,374,888

3,904

^[3]

8,465

2,314

1,475

(1,015,677)

$ (927,859)

$ (501,480)

$ (26,498)

32,623

$ 69,164

$ 64,561

$ 60,038

(2,471,514)

226,386

214,351

6,799

(192)

^[4]

(103,219)

(121,173)

(100,327)

(31,537)

^[5]

^[6]

176,945

(164,286)

(74,507)

(632,601)

(1,339,749)

^[7]

(743,015)

^[7]

Operating Segments | Exploration and production

^[8]

5,645,976

5,021,017

5,645,976

5,021,017

3,575,112

432,711

738,455

664,844

328

432,711

738,455

665,172

Midstream service expenses, including minimum volume commitments

151,918

153,427

130,152

4,399

2,807

^[1]

82,251

99,075

86,951

^[2]

269,631

241,834

231,703

2,372,296

1,802

^[3]

8,123

2,248

1,475

(2,455,907)

240,069

212,084

^[4]

(98,040)

(117,560)

(98,680)

^[5]

(30,056)

^[6]

171,952

(170,551)

(73,476)

(597,086)

(1,279,142)

^[7]

(718,606)

^[7]

Operating Segments | Midstream and marketing

^[8]

5,302,716

4,841,895

5,302,716

4,841,895

3,516,406

1,692

1,660

27,965

7,838

8,824

168,358

54,437

198,015

63,935

8,824

Midstream service expenses, including minimum volume commitments

18,393

9,641

1,571

174,338

53,967

^[1]

8,174

6,969

2,745

^[2]

8,093

4,640

2,241

2,592

2,102

^[3]

342

(13,917)

(13,450)

2,267

6,799

(192)

^[4]

(5,179)

(3,613)

(1,647)

^[5]

(1,481)

^[6]

4,993

6,265

(1,031)

(35,515)

(60,607)

^[7]

(24,409)

^[7]

^[8]

345,183

179,355

345,183

179,355

58,706

Eliminations

(2,669)

(2,912)

(21,417)

(5,593)

(8,739)

(24,086)

(8,505)

(8,739)

Midstream service expenses, including minimum volume commitments

(10,685)

(6,612)

(8,620)

(11,711)

(1,660)

(119)

^[1]

^[2]

^[3]

(1,690)

(233)

^[4]

^[5]

^[6]

^[7]

^[8]

$ (1,923)

$ (233)

$ (1,923)

$ (233)

$ 0

[1]	General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013.
[2]	Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.
[3]	Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015, accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated.
[4]	Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.
[5]	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.
[6]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%
[7]	Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013.
[8]	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015, 2014 and 2013, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015, 2014 and 2013.

Segments - Additional information (Details) $ in Thousands	12 Months Ended
Segments - Additional information (Details) $ in Thousands	Dec. 31, 2015 USD ($) segment	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Segment Reporting Information [Line Items]
Number of segments \| segment	2
Investment in equity method investee	$ 192,524	$ 58,288
Midstream and marketing
Segment Reporting Information [Line Items]
Investment in equity method investee	$ 192,500	$ 58,300	$ 5,900
Operating Segments \| Midstream Segment
Segment Reporting Information [Line Items]
Effective tax rate (as a percent)	36.00%

Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary guarantees
Accounts receivable, net	$ 87,699	$ 126,929
Other current assets	244,533	238,324
Total oil and natural gas properties, net	1,024,992	3,203,275
Total midstream service assets, net	131,725	108,462
Other fixed assets, net	43,538	42,345
Investment in subsidiaries and equity method investee	192,524	58,288
Total other long-term assets	88,276	133,078
Total assets	1,813,287	3,910,701
Accounts payable	14,181	39,008
Other current liabilities	202,634	314,826
Long-term debt, net	1,416,226	1,779,447
Other long-term liabilities	48,799	214,219
Stockholders' equity	131,447	1,563,201	$ 1,272,256	$ 831,723
Total liabilities and stockholders' equity	1,813,287	3,910,701
Reportable Legal Entities \| Laredo
Subsidiary guarantees
Accounts receivable, net	74,613	107,860
Other current assets	244,477	238,300
Total oil and natural gas properties, net	1,017,565	3,196,231
Total midstream service assets, net	0	0
Other fixed assets, net	43,210	42,046
Investment in subsidiaries and equity method investee	301,891	163,349
Total other long-term assets	84,360	128,582
Total assets	1,766,116	3,876,368
Accounts payable	12,203	38,453
Other current liabilities	158,283	283,026
Long-term debt, net	1,416,226	1,779,447
Other long-term liabilities	46,034	212,008
Stockholders' equity	133,370	1,563,434
Total liabilities and stockholders' equity	1,766,116	3,876,368
Reportable Legal Entities \| Subsidiary Guarantors
Subsidiary guarantees
Accounts receivable, net	13,086	19,069
Other current assets	56	24
Total oil and natural gas properties, net	9,350	7,277
Total midstream service assets, net	131,725	108,462
Other fixed assets, net	328	299
Investment in subsidiaries and equity method investee	192,524	58,288
Total other long-term assets	3,916	4,496
Total assets	350,985	197,915
Accounts payable	1,978	555
Other current liabilities	44,351	31,800
Long-term debt, net	0	0
Other long-term liabilities	2,765	2,211
Stockholders' equity	301,891	163,349
Total liabilities and stockholders' equity	350,985	197,915
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Total oil and natural gas properties, net	(1,923)	(233)
Total midstream service assets, net	0	0
Other fixed assets, net	0	0
Investment in subsidiaries and equity method investee	(301,891)	(163,349)
Total other long-term assets	0	0
Total assets	(303,814)	(163,582)
Accounts payable	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other long-term liabilities	0	0
Stockholders' equity	(303,814)	(163,582)
Total liabilities and stockholders' equity	$ (303,814)	$ (163,582)

Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 123,275

$ 150,340

$ 182,331

$ 150,694

$ 237,290

$ 200,241

$ 183,044

$ 173,310

$ 606,640

$ 793,885

$ 665,257

3,078,154

567,499

450,906

(1,015,677)

(927,859)

(501,480)

(26,498)

32,623

69,164

64,561

60,038

(2,471,514)

226,386

214,351

(102,793)

(120,879)

(100,164)

Income (loss) from continuing operations before income taxes

187,426

324,352

76,897

(2,386,881)

429,859

191,084

Income (loss) from continuing operations—basic and diluted

^[1]

176,945

(164,286)

(74,507)

(2,209,936)

265,573

116,577

1,423

Reportable Legal Entities | Laredo

$ (964,647)

$ (847,783)

$ (397,034)

$ (472)

$ 201,278

$ 83,407

$ (18,899)

$ (213)

(2,209,936)

265,573

118,000

432,478

738,446

665,172

2,897,272

505,455

455,972

(2,464,794)

232,991

209,200

(102,793)

(120,879)

(100,164)

Income (loss) from continuing operations before income taxes

182,396

317,980

84,861

(2,385,191)

430,092

193,897

Income (loss) from continuing operations—basic and diluted

176,945

(164,286)

(74,507)

(2,208,246)

265,806

119,390

(1,390)

Reportable Legal Entities | Subsidiary Guarantors

(2,208,246)

265,806

118,000

198,248

63,944

8,824

203,278

70,316

3,673

(5,030)

(6,372)

5,151

Income (loss) from continuing operations before income taxes

6,708

(339)

2,268

1,678

(6,711)

7,419

Income (loss) from continuing operations—basic and diluted

1,678

(6,711)

7,419

2,813

Intercompany eliminations

1,678

(6,711)

10,232

(24,086)

(8,505)

(8,739)

(22,396)

(8,272)

(8,739)

(1,690)

(233)

Income (loss) from continuing operations before income taxes

(1,678)

6,711

(10,232)

(3,368)

6,478

(10,232)

Income (loss) from continuing operations—basic and diluted

(3,368)

6,478

(10,232)

$ (3,368)

$ 6,478

$ (10,232)

[1]	Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36%

Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsidiary guarantees
Net cash flows provided by operating activities	$ 315,947	$ 498,277	$ 364,729
Change in investments between affiliates	0	0	0
Capital expenditures and other	(667,507)	(1,406,961)	(329,884)
Net cash flows provided by financing activities	353,393	739,852	130,084
Net increase (decrease) in cash and cash equivalents	1,833	(168,832)	164,929
Cash and cash equivalents, beginning of period	29,321	198,153	33,224
Cash and cash equivalents, end of period	31,154	29,321	198,153
Reportable Legal Entities \| Laredo
Subsidiary guarantees
Net cash flows provided by operating activities	316,838	496,955	359,198
Change in investments between affiliates	(136,252)	(113,449)	23,986
Capital expenditures and other	(532,146)	(1,292,191)	(348,339)
Net cash flows provided by financing activities	353,393	739,852	130,084
Net increase (decrease) in cash and cash equivalents	1,833	(168,833)	164,929
Cash and cash equivalents, beginning of period	29,320	198,153	33,224
Cash and cash equivalents, end of period	31,153	29,320	198,153
Reportable Legal Entities \| Subsidiary Guarantors
Subsidiary guarantees
Net cash flows provided by operating activities	787	(5,389)	15,763
Change in investments between affiliates	134,574	120,160	(34,218)
Capital expenditures and other	(135,361)	(114,770)	18,455
Net cash flows provided by financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	1	0
Cash and cash equivalents, beginning of period	1	0	0
Cash and cash equivalents, end of period	1	1	0
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(1,678)	6,711	(10,232)
Change in investments between affiliates	1,678	(6,711)	10,232
Capital expenditures and other	0	0	0
Net cash flows provided by financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

Subsequent events - Additional Information (Details) - USD ($) $ in Thousands				12 Months Ended
	Feb. 16, 2016	Jan. 15, 2016	Jan. 14, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsequent Event [Line Items]
Capital contribution payable to equity method investee				$ 99,855	$ 55,164	$ 3,287
Secured Debt \| Subsequent events
Subsequent Event [Line Items]
Borrowing capacity			$ 35,000
Line of credit	$ 170,000
Medallion Gathering And Processing LLC \| Subsequent events
Subsequent Event [Line Items]
Capital contribution payable to equity method investee	$ 8,300	$ 12,700

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

January 2017 - December 2017

Subsequent events - New derivative contracts (Details) - Crude Oil - Put - Subsequent events
$ in Millions

Feb. 16, 2016

USD ($)

MMBTU

$ / MMBTU

Subsequent Event [Line Items]

Deferred premium | $

$ 4.3

Subsequent Event [Line Items]

Aggregate volumes (in MMBtu) | MMBTU

8,040,000

^[1]

Floor price (in dollars per unit) | $ / MMBTU

2.5

^[1]

January 2018 - December 2018

Subsequent Event [Line Items]

Aggregate volumes (in MMBtu) | MMBTU

8,220,000

^[1]

Floor price (in dollars per unit) | $ / MMBTU

2.5

^[1]

[1]	The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts.

Supplemental oil, NGL and natural gas disclosures - Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Property acquisition costs:

Evaluated

$ 0

$ 3,873

$ 9,652

Unevaluated

9,925

27,087

Exploration

^[1]

20,697

242,284

48,763

Development costs

^[2]

500,577

1,049,317

654,452

Total costs incurred

521,274

1,305,399

739,954

Asset Retirement Obligation Costs

Property acquisition costs:

Total costs incurred

$ 13,400

$ 6,900

$ 6,800

[1]	The Company acquired significant leasehold interests during the year ended December 31, 2014.
[2]	The costs incurred for oil, NGL and natural gas development activities include $13.4 million, $6.9 million and $6.8 million in asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively.

Supplemental oil, NGL and natural gas disclosures - Capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011
Aggregate capitalized costs related to oil and natural gas production activities
Evaluated properties	$ 5,103,635	$ 4,446,781	$ 3,276,578
Unevaluated properties not being depleted	140,299	342,731	208,085
Capitalized costs	5,243,934	4,789,512	3,484,663
Less accumulated depletion and impairment	(4,218,942)	(1,586,237)	(1,349,315)
Net capitalized costs	1,024,992	3,203,275	2,135,348
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	12,640	110,955	9,293	$ 7,411
Unproved properties, cummulative cost	$ 140,299	$ 342,731	$ 208,085

Supplemental oil, NGL and natural gas disclosures - Results of oil, NGL and natural gas producing activities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Revenues:

Production and ad valorem taxes

$ 431,734

$ 737,203

$ 664,844

Production costs:

Lease operating expenses

108,341

96,503

79,136

32,892

50,312

42,396

Total production costs

141,233

146,815

121,532

Other costs:

Depletion

263,666

237,067

227,992

Accretion of asset retirement obligations

2,236

1,721

1,475

Effective tax rate (as a percent)

2,369,477

Income tax expense

^[1]

(164,141)

126,576

112,984

Results of operations

$ (2,180,737)

$ 225,024

$ 200,861

7.00%

38.00%

39.00%

[1]

Supplemental oil, NGL and natural gas disclosures - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2015 MBoe MMcf MBbls	Dec. 31, 2014 MBoe MMcf MBbls	Dec. 31, 2013 MBoe MMcf MBbls
Proved developed and undeveloped reserves:
Beginning of year (MBOE) \| MBoe	247,322	203,615	188,632
Revisions (Provisions) of previous estimates (MBOE) \| MBoe	(124,180)	(21,359)	(15,338)
Extensions, discoveries and other additions (MBOE) \| MBoe	22,388	76,539	69,888
Purchases of reserves in place (MBOE) \| MBoe		256	412
Sales of reserves in place (MBOE) \| MBoe	(3,486)		(28,768)
Production (MBOE) \| MBoe	(16,346)	(11,729)	(11,211)
End of year (MBOE) \| MBoe	125,698	247,322	203,615
Proved developed reserves:
Beginning of year (energy) \| MBoe	105,557	71,725	81,490
End of year (energy) \| MBoe	100,395	105,557	71,725
Proved undeveloped reserves:
Beginning of year (energy) \| MBoe	141,765	131,890	107,142
End of year (energy) \| MBoe	25,303	141,765	131,890
Oil (MBbls)
Proved developed and undeveloped reserves:
Beginning of year	140,190	111,498	98,141
Revisions of previous estimates	(88,900)	(10,134)	(17,956)
Extensions, discoveries and other additions	10,511	45,554	37,850
Purchases of reserves in place		173	170
Sales of reserves in place	(1,552)		(1,220)
Production	(7,610)	(6,901)	(5,487)
End of year	52,639	140,190	111,498
Proved developed reserves:
Beginning of year (volume)	56,975	37,878	33,316
End of year (volume)	40,944	56,975	37,878
Proved undeveloped reserves:
Beginning of year (volume)	83,215	73,620	64,825
End of year (volume)	11,695	83,215	73,620
Natural Gas Liquids
Proved developed and undeveloped reserves:
Beginning of year	0
Revisions of previous estimates	35,477
Extensions, discoveries and other additions	5,865
Sales of reserves in place	(1,008)
Production	(4,267)
End of year	36,067	0
Proved developed reserves:
Beginning of year (volume)	0
End of year (volume)	29,349	0
Proved undeveloped reserves:
Beginning of year (volume)	0
End of year (volume)	6,718	0
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning of year \| MMcf	642,794	552,702	542,946
Revisions of previous estimates \| MMcf	(424,546)	(67,350)	15,710
Extensions, discoveries and other additions \| MMcf	36,074	185,909	192,229
Purchases of reserves in place \| MMcf		498	1,454
Sales of reserves in place \| MMcf	(5,554)		(165,289)
Production \| MMcf	(26,816)	(28,965)	(34,348)
End of year \| MMcf	221,952	642,794	552,702
Proved developed reserves:
Beginning of year (volume) \| MMcf	291,493	203,082	289,045
End of year (volume) \| MMcf	180,613	291,493	203,082
Proved undeveloped reserves:
Beginning of year (volume) \| MMcf	351,301	349,620	253,901
End of year (volume) \| MMcf	41,339	351,301	349,620

Supplemental oil, NGL and natural gas disclosures - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2015 MBoe location	Dec. 31, 2014 MBoe location	Dec. 31, 2013 MBoe location
Net proved oil and natural gas reserves
Percentage of proved reserves estimated by independent reserve engineers	100.00%	100.00%	100.00%
Revisions (Provisions) of previous estimates (MBOE)	124,180	21,359	15,338
Extensions, discoveries and other additions (MBOE)	22,388	76,539	69,888
Number of proved and undeveloped locations removed \| location	378	226	174
Number of proved and undeveloped locations removed, Wolfberry wells \| location	182
Number of proved and undeveloped locations removed, Horizontal wells \| location	196
Number of proved undeveloped locations redetermined \| location	34	345	501
Number of locations in new proved undeveloped locations \| location	4	113
Purchases of reserves in place (MBOE)		256	412
Permian Basin
Net proved oil and natural gas reserves
Number of locations in new proved undeveloped locations \| location			85
Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	2,669	41,757	47,643
Proved Undeveloped Properties \| Permian Basin
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)			45,510
Removal Of Proved And Undeveloped Locations and Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions (Provisions) of previous estimates (MBOE)	106,883	26,017	11,944
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	19,719	34,782	22,245
Performance, Pricing and Other Changes
Net proved oil and natural gas reserves
Revisions (Provisions) of previous estimates (MBOE)	(17,297)	(4,658)	(3,394)

Supplemental oil, NGL and natural gas disclosures - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 3,269,184	$ 16,663,685	$ 13,337,798
Future production costs	(1,321,471)	(3,616,775)	(3,059,368)
Future development costs	(376,701)	(2,471,985)	(2,250,950)
Future income tax expenses	0	(2,827,763)	(2,150,983)
Future net cash flows	1,571,012	7,747,162	5,876,497
10% discount for estimated timing of cash flows	(740,265)	(4,500,434)	(3,554,293)
Standardized measure of discounted future net cash flows	$ 830,747	$ 3,246,728	$ 2,322,204	$ 1,877,456

Supplemental oil, NGL and natural gas disclosures - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 3,246,728	$ 2,322,204	$ 1,877,456
Changes in the year resulting from:
Sales, less production costs	(290,501)	(590,388)	(543,312)
Revisions of previous quantity estimates	(2,444,322)	(320,275)	(190,961)
Extensions, discoveries and other additions	192,979	1,340,022	1,166,481
Net change in prices and production costs	(1,495,144)	145,740	313,947
Changes in estimated future development costs	(2,974)	(22,961)	921
Previously estimated development costs incurred during the period	162,237	92,135	89,396
Purchases of reserves in place	0	6,100	7,604
Divestitures of reserves in place	(29,149)	0	(239,148)
Accretion of discount	424,453	305,325	234,852
Net change in income taxes	997,805	(266,757)	(259,991)
Timing differences and other	68,635	235,583	(135,041)
Standardized measure of discounted future net cash flows, end of year	$ 830,747	$ 3,246,728	$ 2,322,204

Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Revenues	$ 123,275	$ 150,340	$ 182,331	$ 150,694	$ 237,290	$ 200,241	$ 183,044	$ 173,310	$ 606,640	$ 793,885	$ 665,257
Operating loss	(1,015,677)	(927,859)	(501,480)	(26,498)	32,623	69,164	64,561	60,038	(2,471,514)	226,386	214,351
Net loss	$ (964,647)	$ (847,783)	$ (397,034)	$ (472)	$ 201,278	$ 83,407	$ (18,899)	$ (213)	$ (2,209,936)	$ 265,573	$ 118,000
Net income (loss) per common share:
Basic (in dollars per share)	$ (4.57)	$ (4.01)	$ (1.88)	$ 0.00	$ 1.42	$ 0.59	$ (0.13)	$ 0.00	$ (11.10)	$ 1.88	$ 0.89
Diluted (in dollars per share)	$ (4.57)	$ (4.01)	$ (1.88)	$ 0.00	$ 1.40	$ 0.58	$ (0.13)	$ 0.00	$ (11.10)	$ 1.85	$ 0.88

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.