DENBURY RESOURCES INC, 10-Q filed on 5/5/2017
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2017
Apr. 30, 2017
Document And Company Information [Abstract]
 
 
Entity Registrant Name
Denbury Resources Inc. 
 
Trading Symbol
DNR 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q1 
 
Current Fiscal Year End Date
--12-31 
 
Entity Central Index Key
0000945764 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
398,337,400 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Current assets
 
 
Cash and cash equivalents
$ 1,747 
$ 1,606 
Accrued production receivable
118,483 
124,936 
Trade and other receivables, net
55,653 
43,900 
Derivative assets
1,062 
0 
Other current assets
11,324 
10,684 
Total current assets
188,269 
181,126 
Oil and natural gas properties (using full cost accounting)
 
 
Proved properties
10,475,877 
10,419,827 
Unevaluated properties
951,220 
927,819 
CO2 properties
1,187,711 
1,188,467 
Pipelines and plants
2,285,435 
2,285,812 
Other property and equipment
373,537 
378,776 
Less accumulated depletion, depreciation, amortization and impairment
(11,255,392)
(11,212,327)
Net property and equipment
4,018,388 
3,988,374 
Other assets
102,002 
105,078 
Total assets
4,308,659 
4,274,578 
Current liabilities
 
 
Accounts payable and accrued liabilities
180,529 
200,266 
Oil and gas production payable
73,250 
80,585 
Derivative liabilities
18,799 
69,279 
Current maturities of long-term debt (including future interest payable of $50,349 and $50,349, respectively - see Note 2)
83,701 1
83,366 1
Total current liabilities
356,279 
433,496 
Long-term liabilities
 
 
Long-term debt, net of current portion (including future interest payable on $178,476 and $178,476, respectively - see Note 2)
2,956,385 
2,909,732 
Asset retirement obligations
151,390 
146,807 
Deferred tax liabilities, net
328,786 
293,878 
Other liabilities
22,060 
22,217 
Total long-term liabilities
3,458,621 
3,372,634 
Commitments and contingencies (Note 6)
   
   
Stockholders' equity
 
 
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
0 
0 
Common stock, $.001 par value, 600,000,000 shares authorized; 402,706,108 and 402,334,655 shares issued, respectively
403 
402 
Paid-in capital in excess of par
2,540,057 
2,534,670 
Accumulated deficit
(1,997,455)
(2,018,989)
Treasury stock, at cost, 4,403,152 and 3,906,877 shares, respectively
(49,246)
(47,635)
Total stockholders' equity
493,759 
468,448 
Total liabilities and stockholders' equity
$ 4,308,659 
$ 4,274,578 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Debt Instrument [Line Items]
 
 
Current maturities of long-term debt
$ 83,701 1
$ 83,366 1
Long-term Debt and Capital Lease Obligations
2,956,385 
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
0 
0 
Preferred stock, shares outstanding
0 
0 
Common stock, par value (actual)
$ 0.001 
$ 0.001 
Common stock, shares authorized
600,000,000 
600,000,000 
Common stock, shares issued
402,706,108 
402,334,655 
Treasury stock, shares
4,403,152 
3,906,877 
Future interest payable on 9% Senior Secured Second Lien Notes
 
 
Debt Instrument [Line Items]
 
 
Current maturities of long-term debt
50,349 
50,349 
Long-term Debt and Capital Lease Obligations
$ 178,476 
$ 178,476 
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Revenues and other income
 
 
Oil, natural gas, and related product sales
$ 266,178 
$ 187,803 
CO2 sales and transportation fees
5,388 
6,272 
Interest income and other income
3,888 
769 
Total revenues and other income
275,454 
194,844 
Expenses
 
 
Lease operating expenses
113,840 
102,447 
Marketing and plant operating expenses
14,065 
13,194 
CO2 discovery and operating expenses
593 
607 
Taxes other than income
22,440 
20,092 
General and administrative expenses
28,241 
33,901 
Interest, net of amounts capitalized of $4,654 and $5,780, respectively
27,178 
42,171 
Depletion, depreciation, and amortization
51,195 
77,366 
Commodity derivatives expense (income)
(24,602)
22,826 
Gain on debt extinguishment
0 
(94,991)
Write-down of oil and natural gas properties
0 
256,000 
Other expenses
0 
1,544 
Total expenses
232,950 
475,157 
Income (loss) before income taxes
42,504 
(280,313)
Income tax provision (benefit)
20,974 
(95,120)
Net income (loss)
$ 21,530 
$ (185,193)
Net income (loss) per common share
 
 
Basic
$ 0.06 
$ (0.53)
Diluted
$ 0.05 
$ (0.53)
Weighted average common shares outstanding
 
 
Basic
389,397 
347,235 
Diluted
392,997 
347,235 
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Expenses
 
 
Capitalized interest
$ 4,654 
$ 5,780 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Cash flows from operating activities
 
 
Net income (loss)
$ 21,530 
$ (185,193)
Adjustments to reconcile net income (loss) to cash flows from operating activities
 
 
Depletion, depreciation, and amortization
51,195 
77,366 
Write-down of oil and natural gas properties
0 
256,000 
Deferred income taxes
34,909 
(95,115)
Stock-based compensation
4,106 
859 
Commodity derivatives expense (income)
24,602 
(22,826)
Receipt (payment) on settlements of commodity derivatives
(26,940)
72,227 
Gain on debt extinguishment
0 
(94,991)
Debt issuance costs and discounts
1,901 
3,306 
Other, net
(344)
(416)
Changes in assets and liabilities, net of effects from acquisitions
 
 
Accrued production receivable
6,453 
4,479 
Trade and other receivables
(12,185)
812 
Other current and long-term assets
643 
1,437 
Accounts payable and accrued liabilities
(23,890)
(53,548)
Oil and natural gas production payable
(7,335)
(7,572)
Other liabilities
(1,179)
(448)
Net cash provided by operating activities
24,262 
2,029 
Cash flows from investing activities
 
 
Oil and natural gas capital expenditures
(52,152)
(65,692)
Acquisitions of oil and natural gas properties
(16,222)
(224)
Pipelines and plants capital expenditures
(246)
(635)
Net proceeds from sales of oil and natural gas properties and equipment
415 
0 
Other
608 
(403)
Net cash used in investing activities
(67,597)
(66,954)
Cash flows from financing activities
 
 
Bank repayments
(343,000)
(696,000)
Bank borrowings
397,000 
831,000 
Repurchases of senior subordinated notes
0 
(55,521)
Pipeline financing and capital lease debt repayments
(7,055)
(7,387)
Other
(3,469)
(1,727)
Net cash provided by financing activities
43,476 
70,365 
Net increase in cash and cash equivalents
141 
5,440 
Cash and cash equivalents at beginning of period
1,606 
2,812 
Cash and cash equivalents at end of period
$ 1,747 
$ 8,252 
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 March 31, 2017, our consolidated results of operations for the three months ended March 31, 2017 and 2016, and our consolidated cash flows for the three months ended March 31, 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 months ended March 31, 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
 
 
March 31,
In thousands
 
2017
 
2016
Basic weighted average common shares outstanding
 
389,397

 
347,235

Potentially dilutive securities
 
 

 
 

Restricted stock and performance-based equity awards
 
3,600

 
—

Diluted weighted average common shares outstanding
 
392,997

 
347,235



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).

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
 
 
March 31,
In thousands
 
2017
 
2016
Stock appreciation rights
 
5,044

 
7,412

Restricted stock and performance-based equity awards
 
1,229

 
5,097



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 a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a ceiling test write-down during the three months ended March 31, 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. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and early adoption is permitted. Effective January 1, 2017, we adopted ASU 2017-01. The adoption of ASU 2017-01 did not have a material impact on our current period consolidated financial statements.

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 still evaluating this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.
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:
 
 
March 31,
 
December 31,
In thousands
 
2017
 
2016
Senior Secured Bank Credit Agreement
 
$
355,000

 
$
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 $2 and $3, respectively
 
2,252

 
2,253

Pipeline financings
 
200,038

 
202,671

Capital lease obligations
 
43,649

 
48,718

Total debt principal balance
 
2,826,211

 
2,779,914

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
228,825

 
228,825

Issuance costs on senior secured second lien and senior subordinated notes
 
(14,950
)
 
(15,641
)
Total debt, net of debt issuance costs
 
3,040,086

 
2,993,098

Less: current maturities of long-term debt (1)
 
(83,701
)
 
(83,366
)
Long-term debt and capital lease obligations
 
$
2,956,385

 
$
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 March 31, 2017 include $50.3 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 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 May 2017, 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 November 2017. 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 3.2% as of March 31, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

In conjunction with the May 2017 borrowing base redetermination, we amended 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. The amendments to the Bank Credit Agreement included the following:

•
Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;
•
Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, 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;
•
Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and
•
Increasing 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.

The requirement to maintain a current ratio of 1.0 to 1.0 was not amended, and so remains in place. Also, incurrence of additional debt (separate from debt under the credit facility) in connection with certain events remains subject to a Total Leverage Test unless the consolidated total net debt to EBITDAX ratio is reduced on a pro forma basis by the event. All of the above descriptions of our Bank Credit Agreement and the amendments thereto are qualified by the express language and defined terms contained in the Bank Credit Agreement and the Fourth Amendment to the Bank Credit Agreement dated May 3, 2017, each of which are filed as exhibits to our periodic reports filed with the SEC.

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 6⅜% Senior Subordinated Notes due 2021, $42.3 million principal amount of our 5½% Senior Subordinated Notes due 2022, and $106.0 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off, during the three months ended March 31, 2016. As of May 3, 2017, 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 March 31, 2017, we had $36.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of falling commodity prices, combined with 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 $36.5 million during 2015 and 2016, which reduced the carrying value of these deferred tax assets to zero as of December 31, 2016. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.

As of March 31, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 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 March 31, 2017.
Commodity Derivative Contracts
Commodity Derivative Contracts
Note 4. 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 March 31, 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 March 31, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
22,000
 
$
41.20
–
46.50

 
$
43.99

 
$
—

 
$
—

 
$
—

Apr – June
 
LLS
 
7,000
 
 
42.65
–
46.65

 
45.35

 
—

 
—

 
—

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

 
$
—

 
$
—

 
$
40.00

 
$
70.00

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July – Sept
 
NYMEX
 
14,500
 
$
40.00
–
70.25

 
$
—

 
$
30.00

 
$
40.00

 
$
69.09

July – Sept
 
LLS
 
2,000
 
 
41.00
–
69.25

 
—

 
31.00

 
41.00

 
69.25

Oct – Dec
 
NYMEX
 
11,000
 
 
40.00
–
70.20

 
—

 
30.00

 
40.00

 
69.67

Oct – Dec
 
LLS
 
1,000
 
 
41.00
–
70.25

 
—

 
31.00

 
41.00

 
70.25



(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 5. 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 March 31, 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 $2 thousand in the fair value of these instruments as of March 31, 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
March 31, 2017
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$
—

 
$
971

 
$
91

 
$
1,062

Total Assets
 
$
—

 
$
971

 
$
91

 
$
1,062

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$
—

 
$
18,799

 
$
—

 
$
18,799

Total Liabilities
 
$
—

 
$
18,799

 
$
—

 
$
18,799

 
 
 
 
 
 
 
 
 
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 months ended March 31, 2017 and 2016:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2017
 
2016
Fair value of Level 3 instruments, beginning of period
 
$
(526
)
 
$
52,834

Fair value gains on commodity derivatives
 
617

 
281

Receipts on settlements of commodity derivatives
 
—

 
(30,075
)
Fair value of Level 3 instruments, end of period
 
$
91

 
$
23,040

 
 
 
 
 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date
 
$
236

 
$
133



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
3/31/2017
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
91

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2017
 
22.8% – 34.2%


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. The estimated fair value of the principal amount of our debt as of March 31, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $2,231.3 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 6. Commitments and Contingencies

Commitments

Our CO2 offtake agreement with Mississippi Power Company, which includes the purchase and transportation of CO2 from their Kemper County energy facility to our Mississippi tertiary floods, is currently expected to begin during the second quarter of 2017, depending on the date of commencement of commercial operation of their Kemper County facility. The purchase and transportation costs are variable costs based on the actual quantities delivered. We currently plan to account for the transportation portion of the agreement as an operating lease 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.

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 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 7. Additional Balance Sheet Details

Trade and Other Receivables, Net
 
 
March 31,
 
December 31,
In thousands
 
2017
 
2016
Trade accounts receivable, net
 
$
17,346

 
$
20,084

Federal income tax receivable
 
14,054

 
—

Other receivables
 
24,253

 
23,816

Total
 
$
55,653

 
$
43,900

Basis of Presentation (Policies)
Organization and Nature of Operations 
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 - Basis of Accounting, Policy 
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.
Interim Financial Statements - Use of Estimates 
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 March 31, 2017, our consolidated results of operations for the three months ended March 31, 2017 and 2016, and our consolidated cash flows for the three months ended March 31, 2017 and 2016
Reclassifications 
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 
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 months ended March 31, 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
 
 
March 31,
In thousands
 
2017
 
2016
Basic weighted average common shares outstanding
 
389,397

 
347,235

Potentially dilutive securities
 
 

 
 

Restricted stock and performance-based equity awards
 
3,600

 
—

Diluted weighted average common shares outstanding
 
392,997

 
347,235



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).

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
 
 
March 31,
In thousands
 
2017
 
2016
Stock appreciation rights
 
5,044

 
7,412

Restricted stock and performance-based equity awards
 
1,229

 
5,097

Oil and Natural Gas Properties Policy 
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 a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a ceiling test write-down during the three months ended March 31, 2017.
Recent Accounting Pronouncements 
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. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and early adoption is permitted. Effective January 1, 2017, we adopted ASU 2017-01. The adoption of ASU 2017-01 did not have a material impact on our current period consolidated financial statements.

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 still evaluating this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.
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 March 31, 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.
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 March 31, 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 $2 thousand in the fair value of these instruments as of March 31, 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)
Weighted average shares used in the 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 income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2017
 
2016
Basic weighted average common shares outstanding
 
389,397

 
347,235

Potentially dilutive securities
 
 

 
 

Restricted stock and performance-based equity awards
 
3,600

 
—

Diluted weighted average common shares outstanding
 
392,997

 
347,235

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share 
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
 
 
March 31,
In thousands
 
2017
 
2016
Stock appreciation rights
 
5,044

 
7,412

Restricted stock and performance-based equity awards
 
1,229

 
5,097

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:
 
 
March 31,
 
December 31,
In thousands
 
2017
 
2016
Senior Secured Bank Credit Agreement
 
$
355,000

 
$
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 $2 and $3, respectively
 
2,252

 
2,253

Pipeline financings
 
200,038

 
202,671

Capital lease obligations
 
43,649

 
48,718

Total debt principal balance
 
2,826,211

 
2,779,914

Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 
228,825

 
228,825

Issuance costs on senior secured second lien and senior subordinated notes
 
(14,950
)
 
(15,641
)
Total debt, net of debt issuance costs
 
3,040,086

 
2,993,098

Less: current maturities of long-term debt (1)
 
(83,701
)
 
(83,366
)
Long-term debt and capital lease obligations
 
$
2,956,385

 
$
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 March 31, 2017 include $50.3 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 March 31, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
22,000
 
$
41.20
–
46.50

 
$
43.99

 
$
—

 
$
—

 
$
—

Apr – June
 
LLS
 
7,000
 
 
42.65
–
46.65

 
45.35

 
—

 
—

 
—

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

 
$
—

 
$
—

 
$
40.00

 
$
70.00

2017 Three-Way Collars (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July – Sept
 
NYMEX
 
14,500
 
$
40.00
–
70.25

 
$
—

 
$
30.00

 
$
40.00

 
$
69.09

July – Sept
 
LLS
 
2,000
 
 
41.00
–
69.25

 
—

 
31.00

 
41.00

 
69.25

Oct – Dec
 
NYMEX
 
11,000
 
 
40.00
–
70.20

 
—

 
30.00

 
40.00

 
69.67

Oct – Dec
 
LLS
 
1,000
 
 
41.00
–
70.25

 
—

 
31.00

 
41.00

 
70.25



(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)
Fair value hierarchy of financial assets and liabilities 
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
March 31, 2017
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$
—

 
$
971

 
$
91

 
$
1,062

Total Assets
 
$
—

 
$
971

 
$
91

 
$
1,062

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Oil derivative contracts – current
 
$
—

 
$
18,799

 
$
—

 
$
18,799

Total Liabilities
 
$
—

 
$
18,799

 
$
—

 
$
18,799

 
 
 
 
 
 
 
 
 
December 31, 2016
 
 

 
 

 
 

 
 

Liabilities
 
 

 
 

 
 

 
 

Oil derivative contracts – current
 
$
—

 
$
68,753

 
$
526

 
$
69,279

Total Liabilities
 
$
—

 
$
68,753

 
$
526

 
$
69,279

Changes in fair value of Level 3 assets and liabilities 
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2017 and 2016:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2017
 
2016
Fair value of Level 3 instruments, beginning of period
 
$
(526
)
 
$
52,834

Fair value gains on commodity derivatives
 
617

 
281

Receipts on settlements of commodity derivatives
 
—

 
(30,075
)
Fair value of Level 3 instruments, end of period
 
$
91

 
$
23,040

 
 
 
 
 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date
 
$
236

 
$
133

Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3) 
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
3/31/2017
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
91

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2017
 
22.8% – 34.2%
Additional Balance Sheet Details (Tables)
Trade and Other Receivables, Net
Trade and Other Receivables, Net
 
 
March 31,
 
December 31,
In thousands
 
2017
 
2016
Trade accounts receivable, net
 
$
17,346

 
$
20,084

Federal income tax receivable
 
14,054

 
—

Other receivables
 
24,253

 
23,816

Total
 
$
55,653

 
$
43,900

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Weighted average shares used in the basic and diluted net income per common share
 
 
Basic weighted average common shares outstanding
389,397 
347,235 
Potentially dilutive securities
 
 
Restricted stock and performance-based equity awards
3,600 
0 
Diluted weighted average common shares outstanding
392,997 
347,235 
Basis of Presentation (Antidilutive Securities) (Details)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
SARs
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
5,044 
7,412 
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
1,229 
5,097 
Basis of Presentation (Details Textuals) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Accounting Policies [Abstract]
 
 
Write-down of oil and natural gas properties
$ 0 
$ 256,000 
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Debt Instrument [Line Items]
 
 
Senior Secured Bank Credit Agreement
$ 355,000 
$ 301,000 
Pipeline financings
200,038 
202,671 
Capital lease obligations
43,649 
48,718 
Total debt principal balance
2,826,211 
2,779,914 
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021
228,825 1
228,825 1
Total debt, net of debt issuance costs
3,040,086 
2,993,098 
Less: current maturities of long-term debt
(83,701)1
(83,366)1
Long-term debt and capital lease obligations
2,956,385 
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 
Less: current maturities of long-term debt
(50,300)
 
Debt Instrument, Interest Rate, Stated Percentage
9.00% 
 
Second Lien and Senior Subordinated Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Issuance costs on senior secured second lien and senior subordinated notes
(14,950)
(15,641)
Senior Subordinated Notes [Member] |
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 [Member] |
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 [Member] |
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 [Member] |
Other Subordinated Notes
 
 
Debt Instrument [Line Items]
 
 
Senior Subordinated Notes
2,252 
2,253 
Including premium of
$ 2 
$ 3 
Long-Term Debt (Details Textuals) (USD $)
3 Months Ended 0 Months Ended
Mar. 31, 2017
Mar. 31, 2016
May 5, 2017
Subsequent Event [Member]
May 3, 2017
Subsequent Event [Member]
Mar. 31, 2016
Senior Subordinated Notes [Member]
6 3/8% Senior Subordinated Notes due 2021
Mar. 31, 2016
Senior Subordinated Notes [Member]
5 1/2% Senior Subordinated Notes due 2022
Mar. 31, 2016
Senior Subordinated Notes [Member]
4 5/8% Senior Subordinated Notes due 2023
May 5, 2017
Year 2017
Q2
Subsequent Event [Member]
May 5, 2017
Year 2017
Q3
Subsequent Event [Member]
May 5, 2017
Year 2017
Q4
Subsequent Event [Member]
May 5, 2017
Year 2018
Q1
Subsequent Event [Member]
May 5, 2017
Year 2018
Q2
Subsequent Event [Member]
May 5, 2017
Year 2018
Q3
Subsequent Event [Member]
May 5, 2017
Year 2018
Q4
Subsequent Event [Member]
May 5, 2017
Year 2019
Q1
Subsequent Event [Member]
May 5, 2017
Year 2019
Q2
Subsequent Event [Member]
May 5, 2017
Year 2019
Q3
Subsequent Event [Member]
May 5, 2017
Base Rate [Member]
Minimum
Senior Secured Bank Credit Facility
Subsequent Event [Member]
May 5, 2017
Base Rate [Member]
Maximum
Senior Secured Bank Credit Facility
Subsequent Event [Member]
May 5, 2017
London Interbank Offered Rate (LIBOR) [Member]
Minimum
Senior Secured Bank Credit Facility
Subsequent Event [Member]
May 5, 2017
London Interbank Offered Rate (LIBOR) [Member]
Maximum
Senior Secured Bank Credit Facility
Subsequent Event [Member]
Long Term Debt (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest in guarantor subsidiaries
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
$ 152,300,000 
 
 
$ 4,000,000 
$ 42,300,000 
$ 106,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Amount
 
55,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on debt extinguishment
0 
94,991,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
3.20% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Debt to Consolidated EBITDAX
 
 
 
 
 
 
 
3.0 
3.0 
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 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior subordinated notes available for repurchase
 
 
 
$ 148,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Details) (USD $)
24 Months Ended
Dec. 31, 2016
Mar. 31, 2017
Income Tax Disclosure [Abstract]
 
 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
 
$ 36,500,000 
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount
36,500,000 
 
Unrecognized Tax Benefits
 
5,400,000 
Deferred Tax Assets, Net of Valuation Allowance
$ 0 
 
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) (Year 2017)
Mar. 31, 2017
Swap |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
22,000 
Weighted average swap price
43.99 
Swap |
Q2 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
41.20 
Swap |
Q2 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
46.50 
Swap |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per day
7,000 
Weighted average swap price
45.35 
Swap |
Q2 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
42.65 
Swap |
Q2 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
46.65 
Collar |
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 
Three-way Collar |
Q3 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
14,500 
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
69.09 
Three-way Collar |
Q3 |
LLS
 
Derivative [Line Items]
 
Volume per day
2,000 
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 
Three-way Collar |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per day
11,000 
Derivative, Floor Price
40.00 
Derivative, Cap Price
70.20 
Weighted average sold put price
30.00 
Weighted average floor price
40.00 
Weighted average ceiling price
69.67 
Three-way Collar |
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 
Fair Value Measurements (Fair Value Hierarchy Table) (Details) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
$ 1,062 
$ 0 
Total Assets
1,062 
 
Oil derivative contracts - current liability
18,799 
69,279 
Total Liabilities
18,799 
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
0 
 
Total Assets
0 
 
Oil derivative contracts - current liability
0 
0 
Total Liabilities
0 
0 
Significant Other Observable Inputs (Level 2)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil derivative contracts - current asset
971 
 
Total Assets
971 
 
Oil derivative contracts - current liability
18,799 
68,753 
Total Liabilities
18,799 
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
91 
 
Total Assets
91 
 
Oil derivative contracts - current liability
0 
526 
Total Liabilities
$ 0 
$ 526 
Fair Value Measurements (Level 3 Fair Value Measurements) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 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
$ (526)
$ 52,834 
Fair value gains on commodity derivatives
617 
281 
Receipts on settlements of commodity derivatives
0 
(30,075)
Fair value of Level 3 instruments, end of period
91 
23,040 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date
$ 236 
$ 133 
Fair Value Measurements (Level 3 Valuation Techniques) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2016
Dec. 31, 2015
Mar. 31, 2017
Income Approach Valuation Technique
Mar. 31, 2017
Income Approach Valuation Technique
Minimum
Mar. 31, 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
$ 91 
$ (526)
$ 23,040 
$ 52,834 
$ 91 
 
 
Expected Volatility Range
 
 
 
 
 
22.80% 
34.20% 
Fair Value Measurements (Details Textuals) (USD $)
Mar. 31, 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
$ 2,000 
 
Debt, Fair Value
$ 2,231,300,000 
$ 2,327,800,000 
Commitments and Contingencies (Details) (Helium Supply Arrangement [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 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 Additional Balance Sheet Details (Trade and Other Receivables, Net Table) (Details) (USD $)
In Thousands, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Receivables [Abstract]
 
 
Trade accounts receivable, net
$ 17,346 
$ 20,084 
Federal income tax receivable
14,054 
0 
Other receivables
24,253 
23,816 
Total
$ 55,653 
$ 43,900