DENBURY RESOURCES INC, 10-Q filed on 11/7/2016
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2016
Oct. 31, 2016
Document And Company Information [Abstract]
 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2016 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
DNR 
 
Current Fiscal Year End Date
--12-31 
 
Entity Registrant Name
Denbury Resources Inc. 
 
Entity Central Index Key
0000945764 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
398,405,338 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
Current assets
 
 
Cash and cash equivalents
$ 3,273 
$ 2,812 
Accrued production receivable
102,880 
100,413 
Trade and other receivables, net
45,019 
87,093 
Derivative assets
307 
142,846 
Other current assets
11,238 
10,005 
Total current assets
162,717 
343,169 
Oil and natural gas properties (using full cost accounting)
 
 
Proved properties
10,333,768 
10,245,195 
Unevaluated properties
929,056 
894,948 
CO2 properties
1,186,572 
1,187,458 
Pipelines and plants
2,287,622 
2,293,219 
Other property and equipment
393,616 
408,194 
Less accumulated depletion, depreciation, amortization and impairment
(10,641,296)
(9,653,205)
Net property and equipment
4,489,338 
5,375,809 
Other assets
164,746 
166,555 
Total assets
4,816,801 
5,885,533 
Current liabilities
 
 
Accounts payable and accrued liabilities
173,770 
253,197 
Oil and gas production payable
74,046 
87,337 
Derivative liabilities
74,229 
Current maturities of long-term debt (including future interest payable of $50,974 and $0, respectively - see Note 2)
83,200 1
32,481 1
Total current liabilities
405,245 
373,015 
Long-term liabilities
 
 
Long-term debt, net of current portion (including future interest payable on $203,686 and $0, respectively - see Note 2)
2,903,051 
3,245,114 
Asset retirement obligations
132,950 
138,919 
Deferred tax liabilities, net
505,689 
852,089 
Other liabilities
22,522 
27,484 
Total long-term liabilities
3,564,212 
4,263,606 
Commitments and contingencies (Note 7)
   
   
Stockholders' equity
 
 
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
Common stock, $.001 par value, 600,000,000 shares authorized; 401,996,605 and 354,541,626 shares issued, respectively
402 
355 
Paid-in capital in excess of par
2,527,787 
2,353,549 
Accumulated deficit
(1,633,264)
(1,058,954)
Treasury stock, at cost, 3,889,297 and 3,124,311 shares, respectively
(47,581)
(46,038)
Total stockholders' equity
847,344 
1,248,912 
Total liabilities and stockholders' equity
$ 4,816,801 
$ 5,885,533 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
Stockholders' equity
 
 
Preferred stock, par value
$ 0.001 
$ 0.001 
Preferred stock, shares authorized
25,000,000 
25,000,000 
Preferred stock, shares issued
Preferred stock, shares outstanding
Common stock, par value
$ 0.001 
$ 0.001 
Common stock, shares authorized
600,000,000 
600,000,000 
Common stock, shares issued
401,996,605 
354,541,626 
Treasury stock, shares
3,889,297 
3,124,311 
Future interest payable on 9% Senior Secured Second Lien Notes
 
 
Debt Instrument [Line Items]
 
 
Current maturities of long-term debt
$ 50,974 
$ 0 
Long-term debt, net of current portion
$ 203,686 
$ 0 
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Revenues and other income
 
 
 
 
Oil, natural gas, and related product sales
$ 239,930 
$ 290,388 
$ 674,401 
$ 954,749 
CO2 sales and transportation fees
6,253 
9,144 
19,147 
23,268 
Interest income and other income
7,802 
4,068 
10,429 
9,926 
Total revenues and other income
253,985 
303,600 
703,977 
987,943 
Expenses
 
 
 
 
Lease operating expenses
106,522 
113,902 
308,988 
387,156 
Marketing and plant operating expenses
14,452 
14,458 
40,645 
40,358 
CO2 discovery and operating expenses
861 
1,017 
2,539 
2,909 
Taxes other than income
20,401 
25,607 
59,997 
85,841 
General and administrative expenses
24,643 
32,907 
81,089 
117,134 
Interest, net of amounts capitalized of $6,875, $8,081, $18,944, and $25,228, respectively
24,778 
39,225 
103,007 
119,187 
Depletion, depreciation, and amortization
55,012 
121,406 
198,919 
419,304 
Commodity derivatives expense (income)
(21,224)
(92,028)
99,811 
(126,178)
Gain on debt extinguishment
(7,826)
(115,095)
Write-down of oil and natural gas properties
75,521 
1,760,600 
810,921 
3,612,600 
Impairment of goodwill
1,261,512 
1,261,512 
Other expenses
36,232 
Total expenses
293,140 
3,278,606 
1,627,053 
5,919,823 
Loss before income taxes
(39,155)
(2,975,006)
(923,076)
(4,931,880)
Income tax benefit
(14,565)
(730,880)
(332,625)
(1,431,509)
Net loss
$ (24,590)
$ (2,244,126)
$ (590,451)
$ (3,500,371)
Net loss per common share
 
 
 
 
Basic
$ (0.06)
$ (6.41)
$ (1.60)
$ (10.01)
Diluted
$ (0.06)
$ (6.41)
$ (1.60)
$ (10.01)
Dividends declared per common share
$ 0 
$ 0.0625 
$ 0 
$ 0.1875 
Weighted average common shares outstanding
 
 
 
 
Basic
388,572 
350,052 
368,863 
349,787 
Diluted
388,572 
350,052 
368,863 
349,787 
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Expenses
 
 
 
 
Capitalized interest
$ 6,875 
$ 8,081 
$ 18,944 
$ 25,228 
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net loss
$ (24,590)
$ (2,244,126)
$ (590,451)
$ (3,500,371)
Other comprehensive income, net of income tax:
 
 
 
 
Interest rate lock derivative contracts reclassified to income, net of tax of $0, $11, $0, and $32, respectively
17 
52 
Total other comprehensive income
17 
52 
Comprehensive loss
$ (24,590)
$ (2,244,109)
$ (590,451)
$ (3,500,319)
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Other comprehensive income, net of income tax:
 
 
 
 
Tax for interest rate lock derivative contracts reclassified to income
$ 0 
$ 11 
$ 0 
$ 32 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Cash flows from operating activities
 
 
Net loss
$ (590,451)
$ (3,500,371)
Adjustments to reconcile net loss to cash flows from operating activities
 
 
Depletion, depreciation, and amortization
198,919 
419,304 
Write-down of oil and natural gas properties
810,921 
3,612,600 
Impairment of goodwill
1,261,512 
Deferred income taxes
(331,574)
(1,432,572)
Stock-based compensation
9,682 
22,637 
Commodity derivatives expense (income)
99,811 
(126,178)
Receipt on settlements of commodity derivatives
116,958 
433,293 
Gain on debt extinguishment
(115,095)
Debt issuance costs and discounts
15,541 
6,810 
Other, net
(3,271)
(7,457)
Changes in assets and liabilities, net of effects from acquisitions
 
 
Accrued production receivable
(2,207)
57,867 
Trade and other receivables
35,911 
37,463 
Other current and long-term assets
(8,434)
(1,771)
Accounts payable and accrued liabilities
(57,830)
(53,124)
Oil and natural gas production payable
(13,290)
(26,478)
Other liabilities
(6,232)
(4,138)
Net cash provided by operating activities
159,359 
699,397 
Cash flows from investing activities
 
 
Oil and natural gas capital expenditures
(176,631)
(364,948)
Acquisitions of oil and natural gas properties
(560)
(21,171)
CO2 capital expenditures
(467)
(21,894)
Pipelines and plants capital expenditures
(2,881)
(25,767)
Net proceeds from sales of oil and natural gas properties and equipment
47,232 
327 
Other
(700)
5,913 
Net cash used in investing activities
(134,007)
(427,540)
Cash flows from financing activities
 
 
Bank repayments
(1,362,500)
(1,491,000)
Bank borrowings
1,447,500 
1,306,000 
Repurchases of senior subordinated notes
(76,708)
Pipeline financing and capital lease debt repayments
(21,510)
(25,638)
Cash dividends paid
(478)
(65,422)
Other
(11,195)
(6,738)
Net cash provided by (used in) financing activities
(24,891)
(282,798)
Net increase (decrease) in cash and cash equivalents
461 
(10,941)
Cash and cash equivalents at beginning of period
2,812 
23,153 
Cash and cash equivalents at end of period
$ 3,273 
$ 12,212 
Condensed Consolidated Statement of Changes in Stockholders' Equity (Unaudited) (USD $)
In Thousands, except Share data
Total
Common Stock ($.001 Par Value)
Paid-In Capital in Excess of Par
Retained Earnings (Accumulated Deficit)
Treasury Stock (at cost)
Beginning balance at Dec. 31, 2015
$ 1,248,912 
$ 355 
$ 2,353,549 
$ (1,058,954)
$ (46,038)
Beginning balance, shares at Dec. 31, 2015
354,541,626 
354,541,626 
 
 
3,124,311 
Cumulative effect of accounting change
15,657 
 
(415)
16,072 
 
Issued or purchased pursuant to stock compensation plans, shares
 
6,693,717 
 
 
 
Issued or purchased pursuant to stock compensation plans, value
(7)
 
 
Issued pursuant to directors' compensation plan, shares
 
31,930 
 
 
 
Issued pursuant to directors' compensation plan, value
50 
 
50 
 
 
Issued as part of debt exchange, shares
 
40,729,332 
 
 
 
Issued as part of debt exchange, value
160,491 
40 
160,451 
 
 
Stock-based compensation
14,159 
 
14,159 
 
 
Tax withholding - stock compensation, shares
 
 
 
 
764,986 
Tax withholding - stock compensation, value
(1,543)
 
 
 
(1,543)
Dividends adjustments
69 
 
 
69 
 
Net loss
(590,451)
 
 
(590,451)
 
Ending balance at Sep. 30, 2016
$ 847,344 
$ 402 
$ 2,527,787 
$ (1,633,264)
$ (47,581)
Ending balance, shares at Sep. 30, 2016
401,996,605 
401,996,605 
 
 
3,889,297 
Basis of Presentation
Basis of Presentation and Significant Accounting Policies
Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2016, our consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, our consolidated cash flows for the nine months ended September 30, 2016 and 2015, and our consolidated statement of changes in stockholders’ equity for the nine months ended September 30, 2016.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, (1) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (2) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.

Net Loss per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock, stock appreciation rights (“SARs”), and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
Basic weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, SARs and performance-based equity awards
 

 

 

 

Diluted weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787



Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share (although time-vesting restricted stock is issued and outstanding upon grant).

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
SARs
 
6,091

 
9,118

 
6,590

 
9,858

Restricted stock and performance-based equity awards
 
9,178

 
4,988

 
6,053

 
3,392



Write-Down of Oil and Natural Gas Properties

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves has followed a precipitous and continuing decline in oil prices throughout 2015 and the first nine months of 2016, and the average has declined from $59.21 per Bbl for the third quarter of 2015 to $41.68 per Bbl for the third quarter of 2016. In addition, the average first-day-of-the-month NYMEX natural gas price used in estimating our proved reserves was $3.04 per MMBtu for the third quarter of 2015 and $2.36 per MMBtu for the third quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $75.5 million, $479.4 million, and $256.0 million during the three months ended September 30, June 30, and March 31, 2016, respectively, and $1.8 billion, $1.7 billion, and $146.2 million during the three months ended September 30, June 30, and March 31, 2015, respectively.

2015 Impairment of Goodwill

We are required to test goodwill for impairment on an interim basis when we determine that it is more likely than not that the fair value of our reporting unit is less than its carrying amount. We recorded a goodwill impairment charge of $1.3 billion during the three months ended September 30, 2015, to fully impair the carrying value of our goodwill.

Recent Accounting Pronouncements

Recently Adopted

Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.

Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows.

Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs of $32.8 million associated with our previously issued senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows for any periods.

Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of these standards will have on our consolidated financial statements.

Going Concern. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. The amendments in this ASU will be effective beginning in the fourth quarter of 2016, and for annual and interim periods thereafter. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations or cash flows.
Long-Term Debt
Long-Term Debt
Note 2. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Senior Secured Bank Credit Agreement
 
$
260,000


$
175,000

9% Senior Secured Second Lien Notes due 2021
 
614,919



6⅜% Senior Subordinated Notes due 2021
 
215,144


400,000

5½% Senior Subordinated Notes due 2022
 
772,912


1,250,000

4⅝% Senior Subordinated Notes due 2023
 
622,297


1,200,000

Other Subordinated Notes, including premium of $4 and $7, respectively
 
2,254


2,257

Pipeline financings
 
205,208


211,766

Capital lease obligations
 
55,189


71,324

Total debt principal balance
 
2,747,923


3,310,347

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
254,660

 

Issuance costs on senior subordinated notes
 
(16,332
)

(32,752
)
Total debt, net of debt issuance costs on senior subordinated notes
 
2,986,251


3,277,595

Less: current maturities of long-term debt (1)
 
(83,200
)

(32,481
)
Long-term debt and capital lease obligations
 
$
2,903,051


$
3,245,114



(1)
Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of September 30, 2016 include $51.0 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months. See 2016 Senior Subordinated Notes Exchange below for further discussion.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior secured second lien notes and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. In October 2016, as part of our semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with the next such redetermination scheduled for May 2017.

In order to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with maintenance financial covenants in this low oil price environment, we entered into three amendments to the Bank Credit Agreement between May 2015 and April 2016 that modified the Bank Credit Agreement as follows:

for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio);
for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0;
beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first, second, and third quarters of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019;
allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements), with $385.1 million of future incurrence available as of September 30, 2016;
limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and
limits the amount spent on repurchases or other redemptions of our senior subordinated notes to $225 million, with up to $148.3 million of this capacity remaining available as of September 30, 2016.

Additionally, such amendments made the following changes to the Bank Credit Agreement: (1) increased the applicable margin for ABR Loans and LIBOR Loans by 75 basis points such that the margin for ABR Loans now ranges from 1% to 2% per annum and the margin for LIBOR Loans now ranges from 2% to 3% per annum, (2) increased the commitment fee rate to 0.50%, and (3) provided for semiannual scheduled redeterminations of the borrowing base in May and November of each year. As of September 30, 2016, we were in compliance with all debt covenants under the Bank Credit Agreement. The weighted average interest rate on borrowings outstanding as of September 30, 2016, under the Bank Credit Agreement was 2.8%.

The above description of our Bank Credit Agreement financial covenants and the changes provided for within the three amendments are qualified by the express language and defined terms contained in the Bank Credit Agreement, the First Amendment to the Bank Credit Agreement dated May 4, 2015, the Second Amendment to the Bank Credit Agreement dated February 17, 2016, and the Third Amendment to the Bank Credit Agreement dated April 18, 2016, each of which are filed as exhibits to our periodic reports filed with the SEC.

2016 Senior Subordinated Notes Exchange

During May 2016, we entered into privately negotiated exchange agreements to exchange a total of $1,057.8 million of our existing senior subordinated notes for $614.9 million principal amount of our 2021 Senior Secured Notes plus 40.7 million shares of Denbury common stock, resulting in a net reduction from these exchanges of $442.9 million in our debt principal. The exchanged notes consisted of $175.1 million principal amount of our 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”), $411.0 million principal amount of our 5½% Senior Subordinated Notes due 2022 (“2022 Notes”), and $471.7 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 (“2023 Notes”).

In accordance with FASC 470-60, the exchanges were accounted for as a troubled debt restructuring due to the level of concession provided by our lenders. Under this guidance, future interest applicable to the 2021 Senior Secured Notes is recorded as debt up to the point that the principal and future interest of the new notes is equal to the principal amount of the extinguished notes, rather than recognizing a gain on extinguishment for this amount. As a result, $254.7 million of future interest on the 2021 Senior Secured Notes was recorded as debt, which will be reduced as semiannual interest payments are made, with the remaining $22.8 million of future interest to be recognized as interest expense over the term of these notes. Therefore, future interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations on the 2021 Senior Secured Notes will be significantly lower than the actual cash interest payments. In addition, we recognized a gain of $12.0 million as a result of this debt exchange during the nine months ended September 30, 2016, which is included in “Gain on debt extinguishment” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

9% Senior Secured Second Lien Notes due 2021

In May 2016, we issued $614.9 million of 2021 Senior Secured Notes.  The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of $1,057.8 million of existing senior subordinated notes (see 2016 Senior Subordinated Notes Exchange above).  The 2021 Senior Secured Notes mature on May 15, 2021, and interest is payable semiannually in arrears on May 15 and November 15 of each year, beginning November 15, 2016.  We may redeem the 2021 Senior Secured Notes in whole or in part at our option beginning December 15, 2018, at a redemption price of 109% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2021 Senior Secured Notes (the “Indenture”).  Prior to December 15, 2018, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Senior Secured Notes at a price of 109% of par with the proceeds of certain equity offerings.  In addition, at any time prior to December 15, 2018, we may redeem the 2021 Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest.  The 2021 Senior Secured Notes are not subject to any sinking fund requirements.

The Indenture contains customary covenants that restrict our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (as defined in the Indenture) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment).

The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

2016 Repurchases of Senior Subordinated Notes

During the first quarter of 2016, we repurchased a total of $152.3 million of our outstanding long-term indebtedness, consisting of $4.0 million principal amount of our 2021 Notes, $42.3 million principal amount of our 2022 Notes, and $106.0 million principal amount of our 2023 Notes in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. During the third quarter of 2016, we repurchased an additional $29.6 million of senior subordinated notes in open-market transactions, consisting of $5.8 million principal amount of our 2021 Notes and $23.8 million principal amount of our 2022 Notes, for a total purchase price of $21.2 million, excluding accrued interest. In connection with these series of transactions, we recognized a $103.1 million gain on extinguishment, net of unamortized debt issuance costs written off, during the nine months ended September 30, 2016. As of November 2, 2016, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on repurchases or other redemptions of our senior subordinated notes.
Income Taxes
Income Tax Disclosure
Note 3. Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. As of September 30, 2016, we had $34.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $33.6 million during 2015 and an additional $0.9 million during the first quarter of 2016, which reduced the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.

As of September 30, 2016, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during the fourth quarter of 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of September 30, 2016.

In connection with the privately negotiated exchange agreements to exchange a portion of our existing senior subordinated notes for 2021 Senior Secured Notes, we realized a tax gain due to the concession extended by our note holders during the second quarter of 2016. This tax gain was offset by net operating losses and other deferred tax asset attributes.
Stockholders' Equity
Stockholders' Equity
Note 4. Stockholders’ Equity

Dividends Declared During 2015

During the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share, with dividends totaling $65.4 million paid to stockholders during the nine months ended September 30, 2015. In September 2015, in light of the continuing low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.
Commodity Derivative Contracts
Commodity Derivative Contracts
Note 5. Commodity Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2016, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of September 30, 2016, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
Months
 
Index Price
 
Volume (Barrels per day)
 
Contract Prices ($/Bbl)
Range (1)
 
Weighted Average Price
Swap
 
Sold Put
 
Floor
 
Ceiling
Oil Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
26,000
 
$
36.25
45.40

 
$
38.70

 
$

 
$

 
$

Oct – Dec
 
LLS
 
7,000
 
 
37.24
41.00

 
39.16

 

 

 

2016 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
4,000
 
$
40.00
54.00

 
$

 
$

 
$
40.00

 
$
53.48

Oct – Dec
 
LLS
 
4,000
 
 
40.00
56.00

 

 

 
40.00

 
55.79

2017 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
22,000
 
$
41.15
45.45

 
$
42.67

 
$

 
$

 
$

Jan – Mar
 
LLS
 
10,000
 
 
42.35
46.15

 
43.77

 

 

 

Apr – June
 
NYMEX
 
22,000
 
 
41.20
46.50

 
43.99

 

 

 

Apr – June
 
LLS
 
7,000
 
 
42.65
46.65

 
45.35

 

 

 

2017 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
4,000
 
$
40.00
55.40

 
$

 
$

 
$
40.00

 
$
54.80

Jan – Mar
 
LLS
 
3,000
 
 
40.00
57.35

 

 

 
40.00

 
57.23

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July – Sept
 
NYMEX
 
7,500
 
$
40.00
70.25

 
$

 
$
30.00

 
$
40.00

 
$
69.77

July – Sept
 
LLS
 
1,000
 
 
41.00
69.25

 

 
31.00

 
41.00

 
69.25



(1)
Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
(2)
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.
Fair Value Measurements
Fair Value Measurements
Note 6. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2016, instruments in this category include non-exchange-traded costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $43 thousand in the fair value of these instruments as of September 30, 2016.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
 
 
Fair Value Measurements Using:
In thousands
 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
302

 
$
5

 
$
307

Total Assets
 
$

 
$
302

 
$
5

 
$
307

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
73,699

 
$
530

 
$
74,229

Total Liabilities
 
$

 
$
73,699

 
$
530

 
$
74,229

 
 
 
 
 
 
 
 
 
December 31, 2015
 
 

 
 

 
 

 
 

Assets
 
 

 
 

 
 

 
 

Oil derivative contracts – current
 
$

 
$
90,012

 
$
52,834

 
$
142,846

Total Assets
 
$

 
$
90,012

 
$
52,834

 
$
142,846



Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2016 and 2015:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
Fair value of Level 3 instruments, beginning of period
 
$
240

 
$
112,358

 
$
52,834

 
$
188,446

Fair value gains (losses) on commodity derivatives
 
2,402

 
21,089

 
(2,134
)
 
38,872

Receipts on settlements of commodity derivatives
 
(3,167
)
 
(50,573
)
 
(51,225
)
 
(144,444
)
Fair value of Level 3 instruments, end of period
 
$
(525
)
 
$
82,874

 
$
(525
)
 
$
82,874

 
 
 
 
 
 
 
 
 
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date
 
$
891

 
$
15,332

 
$
(525
)
 
$
25,456



We utilize an income approach to value our Level 3 costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
 
 
Fair Value at
9/30/2016
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
(525
)
 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2016
 
20.8%-40.8%


Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes and senior subordinated notes are based on quoted market prices. The estimated fair value of the principal amount of our debt as of September 30, 2016 and December 31, 2015, excluding pipeline financing and capital lease obligations, was $2,010.3 million and $1,119.0 million, respectively, which increase is primarily driven by an increase in quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Commitments and Contingencies
Commitments and Contingencies
Note 7. Commitments and Contingencies

Commitments

In the second quarter of 2016, we amended our CO2 offtake agreement with Mississippi Power Company (“MSPC”), which amendment included increasing our offtake percentage from 70% to 100% of CO2 quantities produced and lowering the base price related to the cost of CO2, deliveries of which are currently expected to begin in late 2016 or early 2017. Based on the amended terms in the agreement, we concluded for accounting purposes that the agreement contains an embedded lease related to the pipeline owned by MSPC used to transport CO2 to Denbury. We currently plan to record a capital lease on the balance sheet of approximately $110 million upon lease commencement.

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Settlement of NGS Sub Corp., Evolution, et al v. Denbury Onshore, LLC

During the second quarter of 2016, we settled the case brought by Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”) involving the Delhi Field in northeastern Louisiana, resolving all outstanding disputes and claims the parties had or may have had against each other, including pending litigation claims.

Under the terms of the settlement agreement, (1) we paid Evolution $27.5 million in cash on June 30, 2016; (2) effective July 1, 2016, Denbury conveyed to Evolution 25% of the interests in the Mengel Sand Interval, a separate interval within the Delhi Unit which we purchased for approximately $6.5 million in late 2014, and which interval is not currently producing; (3) effective July 1, 2016, we were credited with an additional 0.2226% overriding royalty interest in the Holt-Bryant interval (the currently producing interval of the Delhi Unit); (4) the parties reached agreement as to the ownership of certain field assets, and established future CO2 pipeline transportation charges following the end of the current ten-year fixed price arrangement set to expire in 2019; (5) Evolution waived and released any claims it may have to any insurance proceeds that may be received as a result of existing claims made by Denbury with respect to the June 2013 incident at Delhi Field; and (6) on July 11, 2016, the Court dismissed with prejudice the pending Delhi Field litigation between the parties. The cash payment was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations in the second quarter of 2016.
Additional Balance Sheet Details
Additional Balance Sheet Details
Note 8. Additional Balance Sheet Details

Trade and Other Receivables, Net
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Trade accounts receivable, net
 
$
24,890

 
$
40,146

Commodity derivative settlement receivables
 
433

 
25,994

Other receivables
 
19,696

 
20,953

Total
 
$
45,019

 
$
87,093



Accounts Payable and Accrued Liabilities
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Accrued interest
 
$
30,099

 
$
48,908

Accounts payable
 
27,875

 
30,477

Accrued lease operating expenses
 
26,656

 
37,549

Accrued compensation
 
25,813

 
46,780

Taxes payable
 
25,386

 
32,438

Accrued exploration and development costs
 
6,309

 
20,892

Other
 
31,632

 
36,153

Total
 
$
173,770

 
$
253,197

Basis of Presentation (Policies)
9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Accounting Policies [Abstract]
 
 
Organization and Nature of Operations
 
Interim Financial Statements - Basis of Accounting, Policy
 
Interim Financial Statements - Use of Estimates
 
Reclassifications
 
Net Loss per Common Share
 
Oil and Natural Gas Properties Policy
 
Goodwill policy
 
Recent Accounting Pronouncements
 
Commodity Derivative Contracts
 
Fair Value Measurements
 
Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2016, our consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, our consolidated cash flows for the nine months ended September 30, 2016 and 2015, and our consolidated statement of changes in stockholders’ equity for the nine months ended September 30, 2016.
Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, (1) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (2) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.
Net Loss per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock, stock appreciation rights (“SARs”), and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
Basic weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, SARs and performance-based equity awards
 

 

 

 

Diluted weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787



Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share (although time-vesting restricted stock is issued and outstanding upon grant).

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
SARs
 
6,091

 
9,118

 
6,590

 
9,858

Restricted stock and performance-based equity awards
 
9,178

 
4,988

 
6,053

 
3,392

Write-Down of Oil and Natural Gas Properties

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves has followed a precipitous and continuing decline in oil prices throughout 2015 and the first nine months of 2016, and the average has declined from $59.21 per Bbl for the third quarter of 2015 to $41.68 per Bbl for the third quarter of 2016. In addition, the average first-day-of-the-month NYMEX natural gas price used in estimating our proved reserves was $3.04 per MMBtu for the third quarter of 2015 and $2.36 per MMBtu for the third quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $75.5 million, $479.4 million, and $256.0 million during the three months ended September 30, June 30, and March 31, 2016, respectively, and $1.8 billion, $1.7 billion, and $146.2 million during the three months ended September 30, June 30, and March 31, 2015, respectively.
2015 Impairment of Goodwill

We are required to test goodwill for impairment on an interim basis when we determine that it is more likely than not that the fair value of our reporting unit is less than its carrying amount. We recorded a goodwill impairment charge of $1.3 billion during the three months ended September 30, 2015, to fully impair the carrying value of our goodwill.
Recent Accounting Pronouncements

Recently Adopted

Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.

Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows.

Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs of $32.8 million associated with our previously issued senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows for any periods.

Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of these standards will have on our consolidated financial statements.

Going Concern. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. The amendments in this ASU will be effective beginning in the fourth quarter of 2016, and for annual and interim periods thereafter. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations or cash flows.
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2016, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2016, instruments in this category include non-exchange-traded costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $43 thousand in the fair value of these instruments as of September 30, 2016.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
Basis of Presentation (Tables)
The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
Basic weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, SARs and performance-based equity awards
 

 

 

 

Diluted weighted average common shares outstanding
 
388,572

 
350,052

 
368,863

 
349,787

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
SARs
 
6,091

 
9,118

 
6,590

 
9,858

Restricted stock and performance-based equity awards
 
9,178

 
4,988

 
6,053

 
3,392

Long-Term Debt (Tables)
Components of Long-Term Debt
The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Senior Secured Bank Credit Agreement
 
$
260,000


$
175,000

9% Senior Secured Second Lien Notes due 2021
 
614,919



6⅜% Senior Subordinated Notes due 2021
 
215,144


400,000

5½% Senior Subordinated Notes due 2022
 
772,912


1,250,000

4⅝% Senior Subordinated Notes due 2023
 
622,297


1,200,000

Other Subordinated Notes, including premium of $4 and $7, respectively
 
2,254


2,257

Pipeline financings
 
205,208


211,766

Capital lease obligations
 
55,189


71,324

Total debt principal balance
 
2,747,923


3,310,347

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
254,660

 

Issuance costs on senior subordinated notes
 
(16,332
)

(32,752
)
Total debt, net of debt issuance costs on senior subordinated notes
 
2,986,251


3,277,595

Less: current maturities of long-term debt (1)
 
(83,200
)

(32,481
)
Long-term debt and capital lease obligations
 
$
2,903,051


$
3,245,114

Commodity Derivative Contracts (Tables)
Commodity derivative contracts not classified as hedging instruments
The following table summarizes our commodity derivative contracts as of September 30, 2016, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
Months
 
Index Price
 
Volume (Barrels per day)
 
Contract Prices ($/Bbl)
Range (1)
 
Weighted Average Price
Swap
 
Sold Put
 
Floor
 
Ceiling
Oil Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
26,000
 
$
36.25
45.40

 
$
38.70

 
$

 
$

 
$

Oct – Dec
 
LLS
 
7,000
 
 
37.24
41.00

 
39.16

 

 

 

2016 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
4,000
 
$
40.00
54.00

 
$

 
$

 
$
40.00

 
$
53.48

Oct – Dec
 
LLS
 
4,000
 
 
40.00
56.00

 

 

 
40.00

 
55.79

2017 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
22,000
 
$
41.15
45.45

 
$
42.67

 
$

 
$

 
$

Jan – Mar
 
LLS
 
10,000
 
 
42.35
46.15

 
43.77

 

 

 

Apr – June
 
NYMEX
 
22,000
 
 
41.20
46.50

 
43.99

 

 

 

Apr – June
 
LLS
 
7,000
 
 
42.65
46.65

 
45.35

 

 

 

2017 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
4,000
 
$
40.00
55.40

 
$

 
$

 
$
40.00

 
$
54.80

Jan – Mar
 
LLS
 
3,000
 
 
40.00
57.35

 

 

 
40.00

 
57.23

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July – Sept
 
NYMEX
 
7,500
 
$
40.00
70.25

 
$

 
$
30.00

 
$
40.00

 
$
69.77

July – Sept
 
LLS
 
1,000
 
 
41.00
69.25

 

 
31.00

 
41.00

 
69.25



(1)
Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
(2)
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.
Fair Value Measurements (Tables)
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
 
 
Fair Value Measurements Using:
In thousands
 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
302

 
$
5

 
$
307

Total Assets
 
$

 
$
302

 
$
5

 
$
307

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
73,699

 
$
530

 
$
74,229

Total Liabilities
 
$

 
$
73,699

 
$
530

 
$
74,229

 
 
 
 
 
 
 
 
 
December 31, 2015
 
 

 
 

 
 

 
 

Assets
 
 

 
 

 
 

 
 

Oil derivative contracts – current
 
$

 
$
90,012

 
$
52,834

 
$
142,846

Total Assets
 
$

 
$
90,012

 
$
52,834

 
$
142,846

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2016 and 2015:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2016
 
2015
 
2016
 
2015
Fair value of Level 3 instruments, beginning of period
 
$
240

 
$
112,358

 
$
52,834

 
$
188,446

Fair value gains (losses) on commodity derivatives
 
2,402

 
21,089

 
(2,134
)
 
38,872

Receipts on settlements of commodity derivatives
 
(3,167
)
 
(50,573
)
 
(51,225
)
 
(144,444
)
Fair value of Level 3 instruments, end of period
 
$
(525
)
 
$
82,874

 
$
(525
)
 
$
82,874

 
 
 
 
 
 
 
 
 
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date
 
$
891

 
$
15,332

 
$
(525
)
 
$
25,456

The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
 
 
Fair Value at
9/30/2016
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
(525
)
 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2016
 
20.8%-40.8%
Additional Balance Sheet Details (Tables)
Trade and Other Receivables, Net
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Trade accounts receivable, net
 
$
24,890

 
$
40,146

Commodity derivative settlement receivables
 
433

 
25,994

Other receivables
 
19,696

 
20,953

Total
 
$
45,019

 
$
87,093

Accounts Payable and Accrued Liabilities
 
 
September 30,
 
December 31,
In thousands
 
2016
 
2015
Accrued interest
 
$
30,099

 
$
48,908

Accounts payable
 
27,875

 
30,477

Accrued lease operating expenses
 
26,656

 
37,549

Accrued compensation
 
25,813

 
46,780

Taxes payable
 
25,386

 
32,438

Accrued exploration and development costs
 
6,309

 
20,892

Other
 
31,632

 
36,153

Total
 
$
173,770

 
$
253,197

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Weighted average shares used in the basic and diluted net income per common share
 
 
 
 
Basic weighted average common shares outstanding
388,572 
350,052 
368,863 
349,787 
Potentially dilutive securities
 
 
 
 
Restricted stock, SARs and performance-based equity awards
Diluted weighted average common shares outstanding
388,572 
350,052 
368,863 
349,787 
Basis of Presentation (Antidilutive Securities) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
SARs
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
6,091 
9,118 
6,590 
9,858 
Restricted stock and performance-based equity awards
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
9,178 
4,988 
6,053 
3,392 
Basis of Presentation (Details Textuals) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Sep. 30, 2016
Sep. 30, 2015
Accounting Policies [Abstract]
 
 
 
 
 
 
 
 
Write-down of oil and natural gas properties
$ 75,521 
$ 479,400 
$ 256,000 
$ 1,760,600 
$ 1,700,000 
$ 146,200 
$ 810,921 
$ 3,612,600 
Oil
 
 
 
 
 
 
 
 
Average Sales Price and Production Costs Per Unit of Production [Line Items]
 
 
 
 
 
 
 
 
Oil and Natural Gas Prices
41.68 
 
 
59.21 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
Average Sales Price and Production Costs Per Unit of Production [Line Items]
 
 
 
 
 
 
 
 
Oil and Natural Gas Prices
2.36 
 
 
3.04 
 
 
 
 
Basis of Presentation Basis of Presentation (Details Textuals 2) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Income Statement [Abstract]
 
 
 
 
Goodwill, Impairment Loss
$ 0 
$ 1,261,512 
$ 0 
$ 1,261,512 
Basis of Presentation Basis of Presentation (Details Textuals 3) (USD $)
Sep. 30, 2016
Dec. 31, 2015
Jan. 1, 2016
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits
Jan. 1, 2016
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate
Dec. 31, 2015
ASU 2015-03 and ASU 2015-15 Simplifying the Presentation of Debt Issuance Costs
Dec. 31, 2015
ASU 2015-17 Simplifying the Presentation of Deferred Income Taxes
New Accounting Pronouncement, Early Adoption [Line Items]
 
 
 
 
 
 
Retained Earnings (Accumulated Deficit)
$ (1,633,264,000)
$ (1,058,954,000)
$ 15,700,000 
$ 400,000 
 
 
Additional Paid-in Capital
2,527,787,000 
2,353,549,000 
 
(400,000)
 
 
Current deferred tax assets, Net
 
 
 
 
 
(1,500,000)
Deferred Tax Liabilities, Net
 
 
(14,800,000)
 
 
 
Other Assets, Current
11,238,000 
10,005,000 
800,000 
 
(32,752,000)
 
Deferred Tax Liabilities, Net, Current
 
 
 
 
 
1,500,000 
Long-term Debt, Excluding Current Maturities
 
 
 
 
$ 32,752,000 
 
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
May 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
 
Senior Secured Bank Credit Agreement
$ 260,000 
 
$ 175,000 
9% Senior Secured Second Lien Notes due 2021
614,919 
614,900 
Pipeline financings
205,208 
 
211,766 
Capital Lease Obligations
55,189 
 
71,324 
Total debt principal balance
2,747,923 
 
3,310,347 
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021
254,660 
 
Issuance costs on senior subordinated notes
(16,332)
 
(32,752)
Total debt, net of debt issuance costs on senior subordinated notes
2,986,251 
 
3,277,595 
Less: current maturities of long-term debt
(83,200)1
 
(32,481)1
Long-term debt and capital lease obligations
2,903,051 
 
3,245,114 
9% Senior Secured Second Lien Notes Due 2021
 
 
 
Debt Instrument [Line Items]
 
 
 
9% Senior Secured Second Lien Notes due 2021
 
614,900 
 
Less: current maturities of long-term debt
(51,000)
 
 
Debt Instrument, Interest Rate, Stated Percentage
9.00% 
 
 
6 3/8% Senior Subordinated Notes due 2021
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
215,144 
 
400,000 
Debt Instrument, Interest Rate, Stated Percentage
6.375% 
 
 
5 1/2% Senior Subordinated Notes due 2022
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
772,912 
 
1,250,000 
Debt Instrument, Interest Rate, Stated Percentage
5.50% 
 
 
4 5/8% Senior Subordinated Notes due 2023
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
622,297 
 
1,200,000 
Debt Instrument, Interest Rate, Stated Percentage
4.625% 
 
 
Other Subordinated Notes
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
2,254 
 
2,257 
Including premium of
$ 4 
 
$ 7 
Long-Term Debt (Details Textuals) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended 6 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended
May 31, 2016
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Jul. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2016
Debt Instrument, Redemption, Period One
Sep. 30, 2016
Initial Redemption Period With Proceeds From Equity Offering
Sep. 30, 2016
Initial Redemption Period With Make Whole Premium
Sep. 30, 2016
Year 2016
Sep. 30, 2016
Year 2017
Sep. 30, 2016
Q1
Year 2018
Sep. 30, 2016
Q1
Year 2019
Sep. 30, 2016
Q2
Year 2018
Sep. 30, 2016
Q3
Year 2018
Sep. 30, 2016
Q4
Year 2018
Sep. 30, 2016
Line of Credit
Sep. 30, 2016
6 3/8% Senior Subordinated Notes due 2021
Jul. 30, 2016
6 3/8% Senior Subordinated Notes due 2021
Mar. 31, 2016
6 3/8% Senior Subordinated Notes due 2021
Sep. 30, 2016
5 1/2% Senior Subordinated Notes due 2022
Jul. 30, 2016
5 1/2% Senior Subordinated Notes due 2022
Mar. 31, 2016
5 1/2% Senior Subordinated Notes due 2022
Sep. 30, 2016
4 5/8% Senior Subordinated Notes due 2023
Mar. 31, 2016
4 5/8% Senior Subordinated Notes due 2023
May 31, 2016
9% Senior Secured Second Lien Notes Due 2021
Sep. 30, 2016
Notes Exchange [Member]
Sep. 30, 2016
Cash and Cash Equivalents [Member]
Line of Credit
Sep. 30, 2016
Maximum Outstanding Credit Facility Balance [Member]
Line of Credit
Sep. 30, 2016
Senior Subordinated Notes [Member]
Sep. 30, 2016
Senior Subordinated Notes [Member]
Line of Credit
Sep. 30, 2016
Base Rate [Member]
Line of Credit
Minimum
Sep. 30, 2016
Base Rate [Member]
Line of Credit
Maximum
Sep. 30, 2016
London Interbank Offered Rate (LIBOR) [Member]
Line of Credit
Minimum
Sep. 30, 2016
London Interbank Offered Rate (LIBOR) [Member]
Line of Credit
Maximum
Long Term Debt (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest in guarantor subsidiaries
 
100.00% 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Bank Credit Facility [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit, Borrowing Base
 
$ 1,050,000,000.00 
 
$ 1,050,000,000.00 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Current Borrowing Capacity
 
1,050,000,000 
 
1,050,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average interest rate on Bank Credit Facility
 
 
 
2.80% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Net Debt to Consolidated EBITDAX Requirement
 
 
 
 
 
 
 
 
 
 
 
 
 
6.0 
4.25 
5.5 
5.0 
5.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Debt to Consolidated EBITDAX
 
 
 
 
 
 
 
 
 
 
 
3.0 
3.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated EBITDAX to Consolidated Interest Charges
 
 
 
 
 
 
 
 
 
 
 
1.25 
1.25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum amount of junior lien debt permitted
 
1,000,000,000.0 
 
1,000,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit Facility Covenants
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
225,000,000 
250,000,000 
 
225,000,000 
 
 
 
 
Interest Rate Margins on Bank Credit Facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.00% 
2.00% 
2.00% 
3.00% 
Remaining junior lien debt allowed to be incurred
 
 
 
385,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior subordinated notes available for repurchase
 
148,300,000 
 
148,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subordinated Debt [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Amount Exchanged
1,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
175,100,000 
 
 
411,000,000 
 
 
471,700,000 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued as part of debt exchange
40,700,000 
401,996,605 
 
401,996,605 
 
 
 
354,541,626 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Extinguishment of Debt, Amount
442,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on debt extinguishment
 
7,826,000 
115,095,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,000,000 
 
 
103,100,000 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
29,600,000 
152,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,800,000 
4,000,000 
 
23,800,000 
42,300,000 
 
106,000,000 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Amount
 
 
 
 
 
21,200,000 
55,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Secured Debt [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9% Senior Secured Second Lien Notes due 2021
614,900,000 
614,919,000 
 
614,919,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
614,900,000 
 
 
 
 
 
 
 
 
 
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021
 
254,660,000 
 
254,660,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Payable
 
$ 22,800,000 
 
$ 22,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
 
 
 
109.00% 
109.00% 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Percentage of Principal Amount Available To Be Redeemed
 
 
 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Debt to EBITDA requirement
 
 
 
2.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Income Tax Disclosure [Abstract]
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
$ 34.5 
 
 
Deferred Tax Assets, Valuation Allowance
 
0.9 
33.6 
Unrecognized Tax Benefits
$ 5.4 
 
 
Stockholders' Equity (Details Textuals) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Sep. 30, 2016
Sep. 30, 2015
Stockholders' Equity Note [Abstract]
 
 
 
 
 
 
Dividends declared per common share
$ 0 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0 
$ 0.1875 
Cash dividend payment
 
 
 
 
$ 478 
$ 65,422 
Commodity Derivative Contracts (Details)
Sep. 30, 2016
Swap |
Year 2016 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
26,000 
Weighted average swap price
38.70 
Swap |
Year 2016 |
Q4 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
36.25 
Swap |
Year 2016 |
Q4 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
45.40 
Swap |
Year 2016 |
Q4 |
LLS
 
Derivative [Line Items]
 
Volume per Day
7,000 
Weighted average swap price
39.16 
Swap |
Year 2016 |
Q4 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
37.24 
Swap |
Year 2016 |
Q4 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
41.00 
Swap |
Year 2017 |
Q1 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
22,000 
Weighted average swap price
42.67 
Swap |
Year 2017 |
Q1 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
41.15 
Swap |
Year 2017 |
Q1 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
45.45 
Swap |
Year 2017 |
Q1 |
LLS
 
Derivative [Line Items]
 
Volume per Day
10,000 
Weighted average swap price
43.77 
Swap |
Year 2017 |
Q1 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
42.35 
Swap |
Year 2017 |
Q1 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
46.15 
Swap |
Year 2017 |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
22,000 
Weighted average swap price
43.99 
Swap |
Year 2017 |
Q2 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
41.20 
Swap |
Year 2017 |
Q2 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
46.50 
Swap |
Year 2017 |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per Day
7,000 
Weighted average swap price
45.35 
Swap |
Year 2017 |
Q2 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
42.65 
Swap |
Year 2017 |
Q2 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
46.65 
Collar |
Year 2016 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
4,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
54.00 
Weighted average floor price
40.00 
Weighted average ceiling price
53.48 
Collar |
Year 2016 |
Q4 |
LLS
 
Derivative [Line Items]
 
Volume per Day
4,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
56.00 
Weighted average floor price
40.00 
Weighted average ceiling price
55.79 
Collar |
Year 2017 |
Q1 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
4,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
55.40 
Weighted average floor price
40.00 
Weighted average ceiling price
54.80 
Collar |
Year 2017 |
Q1 |
LLS
 
Derivative [Line Items]
 
Volume per Day
3,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
57.35 
Weighted average floor price
40.00 
Weighted average ceiling price
57.23 
Three-way Collar |
Year 2017 |
Q3 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
7,500 
Derivative, Floor Price
40.00 
Derivative, Cap Price
70.25 
Weighted average sold put price
30.00 
Weighted average floor price
40.00 
Weighted average ceiling price
69.77 
Three-way Collar |
Year 2017 |
Q3 |
LLS
 
Derivative [Line Items]
 
Volume per Day
1,000 
Derivative, Floor Price
41.00 
Derivative, Cap Price
69.25 
Weighted average sold put price
31.00 
Weighted average floor price
41.00 
Weighted average ceiling price
69.25 
Fair Value Measurements (Fair Value Hierarchy Table) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
$ 307 
$ 142,846 
Total Assets
307 
142,846 
Oil derivative contracts - current liability
74,229 
Total Liabilities
74,229 
 
Quoted Prices in Active Markets (Level 1)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
Total Assets
Oil derivative contracts - current liability
 
Total Liabilities
 
Significant Other Observable Inputs (Level 2)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
302 
90,012 
Total Assets
302 
90,012 
Oil derivative contracts - current liability
73,699 
 
Total Liabilities
73,699 
 
Significant Unobservable Inputs (Level 3)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
52,834 
Total Assets
52,834 
Oil derivative contracts - current liability
530 
 
Total Liabilities
$ 530 
 
Fair Value Measurements (Level 3 Fair Value Measurements) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2016
Sep. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Fair value of Level 3 instruments, beginning of period
$ 240 
$ 112,358 
$ 52,834 
$ 188,446 
Fair value gains (losses) on commodity derivatives
2,402 
21,089 
(2,134)
38,872 
Receipts on settlements of commodity derivatives
(3,167)
(50,573)
(51,225)
(144,444)
Fair value of Level 3 instruments, end of period
(525)
82,874 
(525)
82,874 
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date
$ 891 
$ 15,332 
$ (525)
$ 25,456 
Fair Value Measurements (Level 3 Valuation Techniques) (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2016
Jun. 30, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Dec. 31, 2014
Sep. 30, 2016
Income Approach Valuation Technique
Sep. 30, 2016
Income Approach Valuation Technique
Minimum
Sep. 30, 2016
Income Approach Valuation Technique
Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
 
 
 
 
 
 
 
 
 
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs
$ (525)
$ 240 
$ 52,834 
$ 82,874 
$ 112,358 
$ 188,446 
$ (525)
 
 
Expected Volatility Range
 
 
 
 
 
 
 
20.80% 
40.80% 
Fair Value Measurements (Details Textuals) (USD $)
Sep. 30, 2016
Dec. 31, 2015
Fair Value Disclosures [Abstract]
 
 
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs
$ 43,000 
 
Debt, Fair Value
$ 2,010,300,000 
$ 1,119,000,000 
Commitments and Contingencies (Details) (USD $)
0 Months Ended 3 Months Ended
Jun. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2014
Sep. 30, 2016
Jul. 1, 2016
Dec. 31, 2015
Other Commitments [Line Items]
 
 
 
 
 
 
 
Capital Lease Obligations
 
 
 
 
$ 55,189,000 
 
$ 71,324,000 
CO2 Offtake Percentage
 
100.00% 
70.00% 
 
 
 
 
Litigation settlement, amount
27,500,000 
 
 
 
 
 
 
Working Interest Conveyed In Litigation Settlement
 
 
 
 
 
25.00% 
 
Payments to Acquire Oil and Gas Property
 
 
 
6,500,000 
 
 
 
Additional Overriding Royalty Interest Acquired in Oil and Gas Properties
 
 
 
 
 
0.2226% 
 
Scenario, Forecast [Member]
 
 
 
 
 
 
 
Other Commitments [Line Items]
 
 
 
 
 
 
 
Capital Lease Obligations
 
 
 
 
$ 110,000,000 
 
 
Additional Balance Sheet Details Additional Balance Sheet Details (Trade Receivable, net) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
Receivables [Abstract]
 
 
Trade accounts receivable, net
$ 24,890 
$ 40,146 
Commodity derivative settlement receivables
433 
25,994 
Other receivables
19,696 
20,953 
Total
$ 45,019 
$ 87,093 
Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Dec. 31, 2015
Accounts Payable and Accrued Liabilities, Current [Abstract]
 
 
Accrued interest
$ 30,099 
$ 48,908 
Accounts payable
27,875 
30,477 
Accrued lease operating expenses
26,656 
37,549 
Accrued compensation
25,813 
46,780 
Taxes payable
25,386 
32,438 
Accrued exploration and development costs
6,309 
20,892 
Other
31,632 
36,153 
Total
$ 173,770 
$ 253,197