DENBURY RESOURCES INC, 10-Q filed on 11/7/2017
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2017
Oct. 31, 2017
Document And Company Information [Abstract]
 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
DNR 
 
Current Fiscal Year End Date
--12-31 
 
Entity Central Index Key
0000945764 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Registrant Name
Denbury Resources Inc. 
 
Entity Common Stock, Shares Outstanding
 
402,170,359 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Current assets
 
 
Cash and cash equivalents
$ 57 
$ 1,606 
Accrued production receivable
121,346 
124,936 
Trade and other receivables, net
55,318 
43,900 
Derivative assets
60 
Other current assets
10,811 
10,684 
Total current assets
187,592 
181,126 
Oil and natural gas properties (using full cost accounting)
 
 
Proved properties
10,694,674 
10,419,827 
Unevaluated properties
957,060 
927,819 
CO2 properties
1,190,190 
1,188,467 
Pipelines and plants
2,285,092 
2,285,812 
Other property and equipment
371,114 
378,776 
Less accumulated depletion, depreciation, amortization and impairment
(11,350,956)
(11,212,327)
Net property and equipment
4,147,174 
3,988,374 
Other assets
106,163 
105,078 
Total assets
4,440,929 
4,274,578 
Current liabilities
 
 
Accounts payable and accrued liabilities
183,063 
200,266 
Oil and gas production payable
69,737 
80,585 
Derivative liabilities
16,746 
69,279 
Current maturities of long-term debt (including future interest payable of $50,490 and $50,349, respectively - see Note 3)
85,002 1
83,366 1
Total current liabilities
354,548 
433,496 
Long-term liabilities
 
 
Long-term debt, net of current portion (including future interest payable of $153,196 and $178,476, respectively - see Note 3)
3,057,439 
2,909,732 
Asset retirement obligations
155,749 
146,807 
Derivative liabilities
4,263 
Deferred tax liabilities, net
329,724 
293,878 
Other liabilities
21,759 
22,217 
Total long-term liabilities
3,568,934 
3,372,634 
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; 407,622,526 and 402,334,655 shares issued, respectively
408 
402 
Paid-in capital in excess of par
2,550,347 
2,534,670 
Accumulated deficit
(1,982,592)
(2,018,989)
Treasury stock, at cost, 5,382,584 and 3,906,877 shares, respectively
(50,716)
(47,635)
Total stockholders' equity
517,447 
468,448 
Total liabilities and stockholders' equity
$ 4,440,929 
$ 4,274,578 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Debt Instrument [Line Items]
 
 
Current maturities of long-term debt
$ 85,002 1
$ 83,366 1
Long-term Debt and Capital Lease Obligations
3,057,439 
2,909,732 
Stockholders' equity
 
 
Preferred stock, par value (actual)
$ 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 (actual)
$ 0.001 
$ 0.001 
Common stock, shares authorized
600,000,000 
600,000,000 
Common stock, shares issued
407,622,526 
402,334,655 
Treasury stock, shares
5,382,584 
3,906,877 
Future interest payable on 9% Senior Secured Second Lien Notes
 
 
Debt Instrument [Line Items]
 
 
Current maturities of long-term debt
50,490 
50,349 
Long-term Debt and Capital Lease Obligations
$ 153,196 
$ 178,476 
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Revenues and other income
 
 
 
 
Oil, natural gas, and related product sales
$ 259,030 
$ 239,930 
$ 776,088 
$ 674,401 
CO2 sales and transportation fees
6,590 
6,253 
18,533 
19,147 
Interest income and other income
939 
7,802 
8,576 
10,429 
Total revenues and other income
266,559 
253,985 
803,197 
703,977 
Expenses
 
 
 
 
Lease operating expenses
117,768 
106,522 
342,926 
308,988 
Marketing and plant operating expenses
11,816 
14,452 
39,758 
40,645 
CO2 discovery and operating expenses
1,346 
861 
2,452 
2,539 
Taxes other than income
20,233 
20,401 
62,848 
59,997 
General and administrative expenses
27,273 
24,643 
81,303 
81,089 
Interest, net of amounts capitalized of $9,416, $6,875, $22,217, and $18,944, respectively
24,546 
24,778 
75,785 
103,007 
Depletion, depreciation, and amortization
52,101 
55,012 
154,448 
198,919 
Commodity derivatives expense (income)
25,263 
(21,224)
(9,712)
99,811 
Gain on debt extinguishment
(7,826)
(115,095)
Write-down of oil and natural gas properties
75,521 
810,921 
Other expenses
36,232 
Total expenses
280,346 
293,140 
749,808 
1,627,053 
Income (loss) before income taxes
(13,787)
(39,155)
53,389 
(923,076)
Income tax provision (benefit)
(14,229)
(14,565)
17,018 
(332,625)
Net income (loss)
$ 442 
$ (24,590)
$ 36,371 
$ (590,451)
Net income (loss) per common share
 
 
 
 
Basic
$ 0.00 
$ (0.06)
$ 0.09 
$ (1.60)
Diluted
$ 0.00 
$ (0.06)
$ 0.09 
$ (1.60)
Weighted average common shares outstanding
 
 
 
 
Basic
392,013 
388,572 
390,448 
368,863 
Diluted
393,023 
388,572 
392,625 
368,863 
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Expenses
 
 
 
 
Capitalized interest
$ 9,416 
$ 6,875 
$ 22,217 
$ 18,944 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Cash flows from operating activities
 
 
Net income (loss)
$ 36,371 
$ (590,451)
Adjustments to reconcile net income (loss) to cash flows from operating activities
 
 
Depletion, depreciation, and amortization
154,448 
198,919 
Write-down of oil and natural gas properties
810,921 
Deferred income taxes
35,846 
(331,574)
Stock-based compensation
12,215 
9,682 
Commodity derivatives expense (income)
(9,712)
99,811 
Receipt (payment) on settlements of commodity derivatives
(38,618)
116,958 
Gain on debt extinguishment
(115,095)
Debt issuance costs and discounts
4,801 
15,541 
Other, net
(112)
(3,271)
Changes in assets and liabilities, net of effects from acquisitions
 
 
Accrued production receivable
3,590 
(2,207)
Trade and other receivables
(13,604)
35,911 
Other current and long-term assets
(4,734)
(8,434)
Accounts payable and accrued liabilities
(22,736)
(57,830)
Oil and natural gas production payable
(10,848)
(13,290)
Other liabilities
(4,048)
(6,232)
Net cash provided by operating activities
142,859 
159,359 
Cash flows from investing activities
 
 
Oil and natural gas capital expenditures
(197,982)
(176,631)
Acquisitions of oil and natural gas properties
(91,124)
(560)
Net proceeds from sales of oil and natural gas properties and equipment
1,412 
47,232 
Other
(6,314)
(4,048)
Net cash used in investing activities
(294,008)
(134,007)
Cash flows from financing activities
 
 
Bank repayments
(1,188,000)
(1,362,500)
Bank borrowings
1,382,000 
1,447,500 
Interest payments on senior secured notes treated as a reduction of debt
(25,139)
Repurchases of senior subordinated notes
(76,708)
Pipeline financing and capital lease debt repayments
(20,523)
(21,510)
Other
1,262 
(11,673)
Net cash provided by (used in) financing activities
149,600 
(24,891)
Net increase (decrease) in cash and cash equivalents
(1,549)
461 
Cash and cash equivalents at beginning of period
1,606 
2,812 
Cash and cash equivalents at end of period
$ 57 
$ 3,273 
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, 2016 (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, 2017, our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and our consolidated cash flows for the nine months ended September 30, 2017 and 2016.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (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 and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Basic weighted average common shares outstanding
 
392,013

 
388,572

 
390,448

 
368,863

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock and performance-based equity awards
 
1,010

 

 
2,177

 

Diluted weighted average common shares outstanding
 
393,023

 
388,572

 
392,625

 
368,863



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 income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Stock appreciation rights
 
4,551

 
6,091

 
4,793

 
6,590

Restricted stock and performance-based equity awards
 
9,891

 
9,178

 
6,259

 
6,053



2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, 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. We have not recorded a ceiling test write-down during the first nine months of 2017.

Recent Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements.

Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows.

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. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.
Asset Acquisition and Assets Held for Sale
Asset Acquisition
Note 2. Asset Acquisition and Assets Held for Sale

Asset Acquisition

On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $71.5 million, before customary closing adjustments. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties.

Assets Held for Sale

We began actively marketing for sale certain non-productive surface acreage in the Houston area during July 2017, which we currently anticipate selling during 2018. As of September 30, 2017, the carrying value of the land held for sale was $33.1 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.
Long-Term Debt
Long-Term Debt
Note 3. 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
 
2017
 
2016
Senior Secured Bank Credit Agreement
 
$
495,000

 
$
301,000

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

 
614,919

6⅜% Senior Subordinated Notes due 2021
 
215,144

 
215,144

5½% Senior Subordinated Notes due 2022
 
772,912

 
772,912

4⅝% Senior Subordinated Notes due 2023
 
622,297

 
622,297

Other Subordinated Notes, including premium of $1 and $3, respectively
 
2,251

 
2,253

Pipeline financings
 
195,258

 
202,671

Capital lease obligations
 
34,542

 
48,718

Total debt principal balance
 
2,952,323

 
2,779,914

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
203,686

 
228,825

Issuance costs on senior secured second lien and senior subordinated notes
 
(13,568
)
 
(15,641
)
Total debt, net of debt issuance costs
 
3,142,441

 
2,993,098

Less: current maturities of long-term debt (1)
 
(85,002
)
 
(83,366
)
Long-term debt and capital lease obligations
 
$
3,057,439

 
$
2,909,732



(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, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and our 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 (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019 and semiannual borrowing base redeterminations in May and November of each year. As part of our fall 2017 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 2018. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 4.3% as of September 30, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

In May 2017, we entered into a Fourth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to amend certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased the applicable margin for ABR Loans and LIBOR Loans by 50 basis points, such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum. In November 2017, we entered into a Fifth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we can incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;
A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and
A requirement to maintain a current ratio of 1.0 to 1.0.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.

2016 Senior Subordinated Notes Exchange

During May 2016, in privately negotiated transactions, we exchanged 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. As a result of this debt exchange, we recognized a gain of $12.0 million during the nine months ended September 30, 2016, which is included in “Gain on debt extinguishment” in the accompanying Consolidated Statements of Operations.

2016 Repurchases of Senior Subordinated Notes

During the first and third quarters of 2016, we repurchased a total of $181.9 million of our outstanding long-term indebtedness in open-market transactions for a total purchase price of $76.7 million, excluding accrued interest. In connection with these 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 6, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on open market or other repurchases or redemptions of our senior subordinated notes.
Income Taxes
Income Tax Disclosure
Note 4. 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. Our income taxes are based on an estimated statutory rate of approximately 38% in 2017 and 2016. Our effective tax rate for the three months ended September 30, 2017, differed from our estimated statutory rate, primarily due to the impact of recognizing a tax benefit of $8.6 million in the current quarter for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall (tax deduction less than book expense) of $2.1 million. With pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these items had a significant impact on the current quarter’s effective tax rate.
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, fixed-price swaps enhanced with a sold put, and basis swaps. 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, 2017, 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, 2017, 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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
12,000
 
$
48.40
50.13

 
$
49.76

 
$

 
$

 
$

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
14,000
 
$
40.00
70.20

 
$

 
$
31.07

 
$
41.07

 
$
65.79

Oct – Dec
 
LLS
 
1,000
 
 
41.00
70.25

 

 
31.00

 
41.00

 
70.25

2017 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
1,000
 
$
40.00
70.00

 
$

 
$

 
$
40.00

 
$
70.00

2018 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Dec
 
NYMEX
 
15,500
 
$
50.00
50.40

 
$
50.13

 
$

 
$

 
$

2018 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Dec
 
NYMEX
 
15,000
 
$
45.00
56.60

 
$

 
$
36.50

 
$
46.50

 
$
53.88

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017 Basis Swaps (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dec
 
Argus LLS
 
5,000
 
$
4.15

4.15

 
$
4.15

 
$

 
$

 
$

2018 Basis Swaps (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – June
 
Argus LLS
 
2,500
 
$
3.13

3.15

 
$
3.13

 
$

 
$

 
$



(1)
Ranges presented for fixed-price swaps and basis 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.
(3)
The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.
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 basis 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, 2017, instruments in this category include non-exchange-traded 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 $100 thousand in the fair value of these instruments as of September 30, 2017.

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, 2017
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
58

 
$
2

 
$
60

Total Assets
 
$

 
$
58

 
$
2

 
$
60

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
(16,746
)
 
$

 
$
(16,746
)
Oil derivative contracts – long-term
 

 
(4,263
)
 

 
(4,263
)
Total Liabilities
 
$

 
$
(21,009
)
 
$

 
$
(21,009
)
 
 
 
 
 
 
 
 
 
December 31, 2016
 
 

 
 

 
 

 
 

Liabilities
 
 

 
 

 
 

 
 

Oil derivative contracts – current
 
$

 
$
(68,753
)
 
$
(526
)
 
$
(69,279
)
Total Liabilities
 
$

 
$
(68,753
)
 
$
(526
)
 
$
(69,279
)


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, 2017 and 2016:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Fair value of Level 3 instruments, beginning of period
 
$
99

 
$
240

 
$
(526
)
 
$
52,834

Fair value gains (losses) on commodity derivatives
 
(97
)
 
2,402

 
528

 
(2,134
)
Receipts on settlements of commodity derivatives
 

 
(3,167
)
 

 
(51,225
)
Fair value of Level 3 instruments, end of period
 
$
2

 
$
(525
)
 
$
2

 
$
(525
)
 
 
 
 
 
 
 
 
 
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
 
$
(71
)
 
$
891

 
$
54

 
$
(525
)


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
9/30/2017
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
2

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017
 
15.4% – 33.4%


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 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of September 30, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $1,996.6 million and $2,327.8 million, respectively. 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

The Company has a CO2 offtake agreement with Mississippi Power Company (“MSPC”), providing for our purchase of CO2 generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO2 from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO2 from this facility for the foreseeable future.

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.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility.  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are capped at $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium to the third-party purchaser under the helium supply contract.  In a case originally filed in November 2014 by APMTG Helium, LLC, the third-party helium purchaser, after a week of trial during February 2017 on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed until November 27, 2017. The Company plans to continue to vigorously defend its position and pursue its claim, but we are unable to predict at this time the outcome of this dispute.
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
 
2017
 
2016
Trade accounts receivable, net
 
$
15,319

 
$
20,084

Federal income tax receivable
 
11,687

 

Other receivables
 
28,312

 
23,816

Total
 
$
55,318

 
$
43,900

Basis of Presentation (Policies)
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, 2016 (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, 2017, our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and our consolidated cash flows for the nine months ended September 30, 2017 and 2016
Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (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 and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Basic weighted average common shares outstanding
 
392,013

 
388,572

 
390,448

 
368,863

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock and performance-based equity awards
 
1,010

 

 
2,177

 

Diluted weighted average common shares outstanding
 
393,023

 
388,572

 
392,625

 
368,863



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 income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Stock appreciation rights
 
4,551

 
6,091

 
4,793

 
6,590

Restricted stock and performance-based equity awards
 
9,891

 
9,178

 
6,259

 
6,053

2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, 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. We have not recorded a ceiling test write-down during the first nine months of 2017.
Recent Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements.

Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows.

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. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.
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, fixed-price swaps enhanced with a sold put, and basis swaps. 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, 2017, 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 basis 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, 2017, instruments in this category include non-exchange-traded 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 $100 thousand in the fair value of these instruments as of September 30, 2017.

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 income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Basic weighted average common shares outstanding
 
392,013

 
388,572

 
390,448

 
368,863

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock and performance-based equity awards
 
1,010

 

 
2,177

 

Diluted weighted average common shares outstanding
 
393,023

 
388,572

 
392,625

 
368,863

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Stock appreciation rights
 
4,551

 
6,091

 
4,793

 
6,590

Restricted stock and performance-based equity awards
 
9,891

 
9,178

 
6,259

 
6,053

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
 
2017
 
2016
Senior Secured Bank Credit Agreement
 
$
495,000

 
$
301,000

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

 
614,919

6⅜% Senior Subordinated Notes due 2021
 
215,144

 
215,144

5½% Senior Subordinated Notes due 2022
 
772,912

 
772,912

4⅝% Senior Subordinated Notes due 2023
 
622,297

 
622,297

Other Subordinated Notes, including premium of $1 and $3, respectively
 
2,251

 
2,253

Pipeline financings
 
195,258

 
202,671

Capital lease obligations
 
34,542

 
48,718

Total debt principal balance
 
2,952,323

 
2,779,914

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
203,686

 
228,825

Issuance costs on senior secured second lien and senior subordinated notes
 
(13,568
)
 
(15,641
)
Total debt, net of debt issuance costs
 
3,142,441

 
2,993,098

Less: current maturities of long-term debt (1)
 
(85,002
)
 
(83,366
)
Long-term debt and capital lease obligations
 
$
3,057,439

 
$
2,909,732



(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, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.
Commodity Derivative Contracts (Tables)
Commodity derivative contracts not classified as hedging instruments
The following table summarizes our commodity derivative contracts as of September 30, 2017, 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:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
12,000
 
$
48.40
50.13

 
$
49.76

 
$

 
$

 
$

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
14,000
 
$
40.00
70.20

 
$

 
$
31.07

 
$
41.07

 
$
65.79

Oct – Dec
 
LLS
 
1,000
 
 
41.00
70.25

 

 
31.00

 
41.00

 
70.25

2017 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
1,000
 
$
40.00
70.00

 
$

 
$

 
$
40.00

 
$
70.00

2018 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Dec
 
NYMEX
 
15,500
 
$
50.00
50.40

 
$
50.13

 
$

 
$

 
$

2018 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Dec
 
NYMEX
 
15,000
 
$
45.00
56.60

 
$

 
$
36.50

 
$
46.50

 
$
53.88

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017 Basis Swaps (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dec
 
Argus LLS
 
5,000
 
$
4.15

4.15

 
$
4.15

 
$

 
$

 
$

2018 Basis Swaps (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – June
 
Argus LLS
 
2,500
 
$
3.13

3.15

 
$
3.13

 
$

 
$

 
$



(1)
Ranges presented for fixed-price swaps and basis 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.
(3)
The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.
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, 2017
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
58

 
$
2

 
$
60

Total Assets
 
$

 
$
58

 
$
2

 
$
60

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$

 
$
(16,746
)
 
$

 
$
(16,746
)
Oil derivative contracts – long-term
 

 
(4,263
)
 

 
(4,263
)
Total Liabilities
 
$

 
$
(21,009
)
 
$

 
$
(21,009
)
 
 
 
 
 
 
 
 
 
December 31, 2016
 
 

 
 

 
 

 
 

Liabilities
 
 

 
 

 
 

 
 

Oil derivative contracts – current
 
$

 
$
(68,753
)
 
$
(526
)
 
$
(69,279
)
Total Liabilities
 
$

 
$
(68,753
)
 
$
(526
)
 
$
(69,279
)
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, 2017 and 2016:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2017
 
2016
 
2017
 
2016
Fair value of Level 3 instruments, beginning of period
 
$
99

 
$
240

 
$
(526
)
 
$
52,834

Fair value gains (losses) on commodity derivatives
 
(97
)
 
2,402

 
528

 
(2,134
)
Receipts on settlements of commodity derivatives
 

 
(3,167
)
 

 
(51,225
)
Fair value of Level 3 instruments, end of period
 
$
2

 
$
(525
)
 
$
2

 
$
(525
)
 
 
 
 
 
 
 
 
 
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
 
$
(71
)
 
$
891

 
$
54

 
$
(525
)
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
9/30/2017
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
2

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017
 
15.4% – 33.4%
Additional Balance Sheet Details (Tables)
Trade and Other Receivables, Net
Trade and Other Receivables, Net
 
 
September 30,
 
December 31,
In thousands
 
2017
 
2016
Trade accounts receivable, net
 
$
15,319

 
$
20,084

Federal income tax receivable
 
11,687

 

Other receivables
 
28,312

 
23,816

Total
 
$
55,318

 
$
43,900

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Weighted average shares used in the basic and diluted net income (loss) per common share
 
 
 
 
Basic weighted average common shares outstanding
392,013 
388,572 
390,448 
368,863 
Potentially dilutive securities
 
 
 
 
Restricted stock and performance-based equity awards
1,010 
2,177 
Diluted weighted average common shares outstanding
393,023 
388,572 
392,625 
368,863 
Basis of Presentation (Antidilutive Securities) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Stock appreciation rights
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
4,551 
6,091 
4,793 
6,590 
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
9,891 
9,178 
6,259 
6,053 
Basis of Presentation (Details Textuals) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Sep. 30, 2017
Sep. 30, 2016
Accounting Policies [Abstract]
 
 
 
 
 
 
Write-down of oil and natural gas properties
$ 0 
$ 75,521 
$ 479,400 
$ 256,000 
$ 0 
$ 810,921 
Asset Acquisition and Assets Held for Sale (Details Textuals) (USD $)
In Millions, unless otherwise specified
0 Months Ended
Jun. 30, 2017
Sep. 30, 2017
Business Combinations [Abstract]
 
 
Non-operated working interest acquired in asset acquisition
23.00% 
 
Costs Incurred, Acquisition of Oil and Gas Properties
$ 71.5 
 
Land Available-for-sale
 
$ 33.1 
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
May 31, 2016
Debt Instrument [Line Items]
 
 
 
Senior Secured Bank Credit Agreement
$ 495,000 
$ 301,000 
 
Pipeline financings
195,258 
202,671 
 
Capital lease obligations
34,542 
48,718 
 
Total debt principal balance
2,952,323 
2,779,914 
 
Future interest payable on 9% Senior Secured Second Lien Notes due 2021
203,686 1
228,825 1
 
Total debt, net of debt issuance costs
3,142,441 
2,993,098 
 
Less: current maturities of long-term debt
(85,002)1
(83,366)1
 
Long-term debt and capital lease obligations
3,057,439 
2,909,732 
 
9% Senior Secured Second Lien Notes Due 2021
 
 
 
Debt Instrument [Line Items]
 
 
 
9% Senior Secured Second Lien Notes due 2021
614,919 
614,919 
614,919 
Less: current maturities of long-term debt
(50,490)
 
 
Debt Instrument, Interest Rate, Stated Percentage
9.00% 
 
 
Second Lien and Senior Subordinated Notes
 
 
 
Debt Instrument [Line Items]
 
 
 
Issuance costs on senior secured second lien and senior subordinated notes
(13,568)
(15,641)
 
Senior Subordinated Notes |
6 3/8% Senior Subordinated Notes due 2021
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
215,144 
215,144 
 
Debt Instrument, Interest Rate, Stated Percentage
6.375% 
 
 
Senior Subordinated Notes |
5 1/2% Senior Subordinated Notes due 2022
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
772,912 
772,912 
 
Debt Instrument, Interest Rate, Stated Percentage
5.50% 
 
 
Senior Subordinated Notes |
4 5/8% Senior Subordinated Notes due 2023
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
622,297 
622,297 
 
Debt Instrument, Interest Rate, Stated Percentage
4.625% 
 
 
Senior Subordinated Notes |
Other Subordinated Notes
 
 
 
Debt Instrument [Line Items]
 
 
 
Senior Subordinated Notes
2,251 
2,253 
 
Including premium of
$ 1 
$ 3 
 
Long-Term Debt (Details Textuals) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended
May 31, 2016
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Dec. 31, 2016
Nov. 6, 2017
Subsequent Event [Member]
Nov. 1, 2017
Subsequent Event [Member]
Sep. 30, 2016
Notes Exchange [Member]
Sep. 30, 2016
Senior Subordinated Notes
Sep. 30, 2017
Year 2017
Q4
Sep. 30, 2017
Year 2018
Q1
Sep. 30, 2017
Year 2018
Q2
Sep. 30, 2017
Year 2018
Q3
Sep. 30, 2017
Year 2018
Q4
Sep. 30, 2017
Year 2019
Q1
Sep. 30, 2017
Year 2019
Q2
Sep. 30, 2017
Year 2019
Q3
Sep. 30, 2017
Base Rate [Member]
Minimum
Senior Secured Bank Credit Facility
Sep. 30, 2017
Base Rate [Member]
Maximum
Senior Secured Bank Credit Facility
Sep. 30, 2017
London Interbank Offered Rate (LIBOR) [Member]
Minimum
Senior Secured Bank Credit Facility
Sep. 30, 2017
London Interbank Offered Rate (LIBOR) [Member]
Maximum
Senior Secured Bank Credit Facility
Long Term Debt (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest in guarantor subsidiaries
 
100.00% 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
$ 181,900,000 
 
$ 181,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Amount
 
 
76,700,000 
 
76,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on debt extinguishment
 
7,826,000 
115,095,000 
 
 
 
12,000,000 
103,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Conversion, Original Debt, Amount
1,057,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock, Shares, Issued
40,700,000 
407,622,526 
 
407,622,526 
 
402,334,655 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Extinguishment of Debt, Amount
442,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Bank Credit Facility [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit, Borrowing Base
 
 
 
 
 
 
 
1,050,000,000.00 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Current Borrowing Capacity
 
 
 
 
 
 
 
1,050,000,000.00 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average interest rate on Bank Credit Facility
 
4.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Debt to Consolidated EBITDAX
 
 
 
 
 
 
 
 
 
 
3.0 
3.0 
2.5 
2.5 
2.5 
2.5 
2.5 
2.5 
 
 
 
 
Consolidated EBITDAX to Consolidated Interest Charges
 
 
 
 
 
 
 
 
 
 
1.25 
1.25 
1.25 
1.25 
1.25 
1.25 
1.25 
1.25 
 
 
 
 
Interest rate margins on Senior Secured Bank Credit Facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.50% 
2.50% 
2.50% 
3.50% 
Current Ratio Requirement
 
 
 
1.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum Incurrence of Junior Lien Debt Permitted
 
1,000,000,000 
 
1,000,000,000 
 
 
1,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior subordinated notes available for repurchase or other redemptions
 
 
 
 
 
 
$ 148,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2017
Rate
Sep. 30, 2016
Rate
Income Tax Disclosure [Abstract]
 
 
 
Statutory rate
 
38.00% 
38.00% 
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount
$ 8.6 
 
 
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount
$ 2.1 
 
 
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details)
Sep. 30, 2017
Swap |
Year 2017 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
12,000 
Weighted average swap price
49.76 
Swap |
Year 2017 |
Q4 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
48.40 
Swap |
Year 2017 |
Q4 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
50.13 
Swap |
Year 2018 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
15,500 
Weighted average swap price
50.13 
Swap |
Year 2018 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
50.00 
Swap |
Year 2018 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
50.40 
Three-way Collar |
Year 2017 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
14,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
70.20 
Weighted average sold put price
31.07 
Weighted average floor price
41.07 
Weighted average ceiling price
65.79 
Three-way Collar |
Year 2017 |
Q4 |
LLS
 
Derivative [Line Items]
 
Volume per day
1,000 
Derivative, Floor Price
41.00 
Derivative, Cap Price
70.25 
Weighted average sold put price
31.00 
Weighted average floor price
41.00 
Weighted average ceiling price
70.25 
Three-way Collar |
Year 2018 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
15,000 
Derivative, Floor Price
45.00 
Derivative, Cap Price
56.60 
Weighted average sold put price
36.50 
Weighted average floor price
46.50 
Weighted average ceiling price
53.88 
Collar |
Year 2017 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
1,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
70.00 
Weighted average floor price
40.00 
Weighted average ceiling price
70.00 
Basis Swap |
Year 2017 |
December |
LLS
 
Derivative [Line Items]
 
Volume per day
5,000 
Weighted average swap price
4.15 
Basis Swap |
Year 2017 |
December |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
4.15 
Basis Swap |
Year 2017 |
December |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
4.15 
Basis Swap |
Year 2018 |
Q1-Q2 |
LLS
 
Derivative [Line Items]
 
Volume per day
2,500 
Weighted average swap price
3.13 
Basis Swap |
Year 2018 |
Q1-Q2 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
3.13 
Basis Swap |
Year 2018 |
Q1-Q2 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
3.15 
Fair Value Measurements (Fair Value Hierarchy Table) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
$ 60 
$ 0 
Total Assets
60 
 
Oil derivative contracts - current liability
(16,746)
(69,279)
Oil derivative contracts - long-term liabilities
(4,263)
Total Liabilities
(21,009)
(69,279)
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
Oil derivative contracts - long-term liabilities
 
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
58 
 
Total Assets
58 
 
Oil derivative contracts - current liability
(16,746)
(68,753)
Oil derivative contracts - long-term liabilities
(4,263)
 
Total Liabilities
(21,009)
(68,753)
Significant Unobservable Inputs (Level 3)
 
 
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
(526)
Oil derivative contracts - long-term liabilities
 
Total Liabilities
$ 0 
$ (526)
Fair Value Measurements (Level 3 Fair Value Measurements) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Fair value of Level 3 instruments, beginning of period
$ 99 
$ 240 
$ (526)
$ 52,834 
Fair value gains (losses) on commodity derivatives
(97)
2,402 
528 
(2,134)
Receipts on settlements of commodity derivatives
(3,167)
(51,225)
Fair value of Level 3 instruments, end of period
(525)
(525)
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
$ (71)
$ 891 
$ 54 
$ (525)
Fair Value Measurements (Level 3 Valuation Techniques) (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Jun. 30, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Dec. 31, 2015
Sep. 30, 2017
Income Approach Valuation Technique
Sep. 30, 2017
Income Approach Valuation Technique
Minimum
Sep. 30, 2017
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
$ 2 
$ 99 
$ (526)
$ (525)
$ 240 
$ 52,834 
$ 2 
 
 
Expected Volatility Range
 
 
 
 
 
 
 
15.40% 
33.40% 
Fair Value Measurements (Details Textuals) (USD $)
Sep. 30, 2017
Dec. 31, 2016
Fair Value Disclosures [Abstract]
 
 
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs
$ 100,000 
 
Debt, Fair Value
$ 1,996,600,000 
$ 2,327,800,000 
Commitments and Contingencies (Details) (Helium Supply Arrangement [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Sep. 30, 2017
Helium Supply Arrangement [Member]
 
Long-term Purchase Commitment [Line Items]
 
Term of Long Term Supply Arrangement
20 years 
Maximum Annual Payment In Event Of Shortfall
$ 8.0 
Maximum Payment In Event Of Shortfall
$ 46.0 
Additional Balance Sheet Details (Trade and Other Receivables, Net Table) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Receivables [Abstract]
 
 
Trade accounts receivable, net
$ 15,319 
$ 20,084 
Federal income tax receivable
11,687 
Other receivables
28,312 
23,816 
Total
$ 55,318 
$ 43,900