UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2016
OR
o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______ to ________
Commission file number: 001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
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| | |
Delaware | | 20-0467835 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | |
5320 Legacy Drive, Plano, TX | | 75024 |
(Address of principal executive offices) | | (Zip Code) |
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| | |
Registrant’s telephone number, including area code: | | (972) 673-2000 |
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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| | | |
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
| | (Do not check if a smaller reporting company) | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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| | |
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Class | | Outstanding at April 30, 2016 |
Common Stock, $.001 par value | | 350,593,956 |
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Denbury Resources Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
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| | | | | | | | |
| | March 31, | | December 31, |
| | 2016 | | 2015 |
Assets |
Current assets | | | | |
Cash and cash equivalents | | $ | 8,252 |
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| $ | 2,812 |
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Accrued production receivable | | 95,934 |
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| 100,413 |
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Trade and other receivables, net | | 87,228 |
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| 87,924 |
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Derivative assets | | 72,798 |
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| 142,846 |
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Other current assets | | 8,763 |
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| 10,005 |
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Total current assets | | 272,975 |
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| 344,000 |
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Property and equipment | | |
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| |
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Oil and natural gas properties (using full cost accounting) | | |
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| |
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Proved properties | | 10,296,792 |
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| 10,245,195 |
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Unevaluated properties | | 902,990 |
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| 894,948 |
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CO2 properties | | 1,186,607 |
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| 1,187,458 |
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Pipelines and plants | | 2,293,102 |
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| 2,293,219 |
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Other property and equipment | | 405,039 |
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| 408,194 |
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Less accumulated depletion, depreciation, amortization and impairment | | (9,982,733 | ) |
| (9,653,205 | ) |
Net property and equipment | | 5,101,797 |
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| 5,375,809 |
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Other assets | | 163,775 |
| | 166,555 |
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Total assets | | $ | 5,538,547 |
| | $ | 5,886,364 |
|
Liabilities and Stockholders’ Equity |
Current liabilities | | |
| | |
|
Accounts payable and accrued liabilities | | $ | 186,715 |
| | $ | 253,197 |
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Oil and gas production payable | | 79,765 |
| | 87,337 |
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Derivative liabilities | | 25,005 |
| | — |
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Current maturities of long-term debt | | 32,917 |
| | 32,481 |
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Total current liabilities | | 324,402 |
| | 373,015 |
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Long-term liabilities | | |
| | |
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Long-term debt, net of current portion | | 3,222,497 |
| | 3,245,114 |
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Asset retirement obligations | | 142,101 |
| | 138,919 |
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Deferred tax liabilities, net | | 742,148 |
| | 837,263 |
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Other liabilities | | 26,121 |
| | 27,484 |
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Total long-term liabilities | | 4,132,867 |
| | 4,248,780 |
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Commitments and contingencies (Note 7) | |
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| |
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Stockholders’ equity | | | | |
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding | | — |
| | — |
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Common stock, $.001 par value, 600,000,000 shares authorized; 354,340,533 and 354,541,626 shares issued, respectively | | 354 |
| | 355 |
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Paid-in capital in excess of par | | 2,356,069 |
| | 2,353,134 |
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Accumulated deficit | | (1,228,039 | ) | | (1,042,882 | ) |
Treasury stock, at cost, 3,734,768 and 3,124,311 shares, respectively | | (47,106 | ) | | (46,038 | ) |
Total stockholders’ equity | | 1,081,278 |
| | 1,264,569 |
|
Total liabilities and stockholders’ equity | | $ | 5,538,547 |
| | $ | 5,886,364 |
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
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| | | | | | | | |
| | Three Months Ended March 31, |
| | 2016 | | 2015 |
Revenues and other income | | | | |
Oil, natural gas, and related product sales | | $ | 187,803 |
| | $ | 297,470 |
|
CO2 sales and transportation fees | | 6,272 |
| | 6,972 |
|
Interest income and other income | | 769 |
| | 3,207 |
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Total revenues and other income | | 194,844 |
| | 307,649 |
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Expenses | | |
| | |
|
Lease operating expenses | | 102,447 |
| | 141,084 |
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Marketing and plant operating expenses | | 13,194 |
| | 11,685 |
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CO2 discovery and operating expenses | | 607 |
| | 947 |
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Taxes other than income | | 20,092 |
| | 26,679 |
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General and administrative expenses | | 33,901 |
| | 46,280 |
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Interest, net of amounts capitalized of $5,780 and $8,409, respectively | | 42,171 |
| | 40,099 |
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Depletion, depreciation, and amortization | | 77,366 |
| | 149,958 |
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Commodity derivatives expense (income) | | 22,826 |
| | (83,076 | ) |
Gain on debt extinguishment | | (94,991 | ) | | — |
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Write-down of oil and natural gas properties | | 256,000 |
| | 146,200 |
|
Other expenses | | 1,544 |
| | — |
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Total expenses | | 475,157 |
| | 479,856 |
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Loss before income taxes | | (280,313 | ) | | (172,207 | ) |
Income tax benefit | | (95,120 | ) | | (64,461 | ) |
Net loss | | $ | (185,193 | ) | | $ | (107,746 | ) |
| | | | |
Net loss per common share | | | | |
Basic | | $ | (0.53 | ) | | $ | (0.31 | ) |
Diluted | | $ | (0.53 | ) | | $ | (0.31 | ) |
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| |
|
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Dividends declared per common share | | $ | — |
| | $ | 0.0625 |
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| |
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| |
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Weighted average common shares outstanding | | |
| | |
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Basic | | 347,235 |
| | 350,688 |
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Diluted | | 347,235 |
| | 350,688 |
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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Comprehensive Operations
(In thousands)
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| | | | | | | | |
| | Three Months Ended March 31, |
| | 2016 | | 2015 |
Net loss | | $ | (185,193 | ) | | $ | (107,746 | ) |
Other comprehensive income, net of income tax: | | |
| | |
|
Interest rate lock derivative contracts reclassified to income, net of tax of $0 and $11, respectively | | — |
| | 17 |
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Total other comprehensive income | | — |
| | 17 |
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Comprehensive loss | | $ | (185,193 | ) | | $ | (107,729 | ) |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
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| | | | | | | | |
| | Three Months Ended March 31, |
| | 2016 | | 2015 |
Cash flows from operating activities | | | | |
Net loss | | $ | (185,193 | ) | | $ | (107,746 | ) |
Adjustments to reconcile net loss to cash flows from operating activities | | | | |
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Depletion, depreciation, and amortization | | 77,366 |
| | 149,958 |
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Write-down of oil and natural gas properties | | 256,000 |
| | 146,200 |
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Deferred income taxes | | (95,115 | ) | | (66,036 | ) |
Stock-based compensation | | 859 |
| | 7,849 |
|
Commodity derivatives expense (income) | | 22,826 |
| | (83,076 | ) |
Receipt on settlements of commodity derivatives | | 72,227 |
| | 148,465 |
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Gain on debt extinguishment | | (94,991 | ) | | — |
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Amortization of debt issuance costs and discounts | | 3,306 |
| | 2,221 |
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Other, net | | (416 | ) | | (2,359 | ) |
Changes in assets and liabilities, net of effects from acquisitions | | |
| | |
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Accrued production receivable | | 4,479 |
| | 33,636 |
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Trade and other receivables | | 812 |
| | 16,828 |
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Other current and long-term assets | | 1,437 |
| | (6,136 | ) |
Accounts payable and accrued liabilities | | (53,548 | ) | | (83,248 | ) |
Oil and natural gas production payable | | (7,572 | ) | | (17,716 | ) |
Other liabilities | | (448 | ) | | (1,076 | ) |
Net cash provided by operating activities | | 2,029 |
| | 137,764 |
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| | | | |
Cash flows from investing activities | | |
| | |
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Oil and natural gas capital expenditures | | (65,692 | ) | | (162,192 | ) |
CO2 capital expenditures | | (315 | ) | | (14,855 | ) |
Pipelines and plants capital expenditures | | (635 | ) | | (12,455 | ) |
Other | | (312 | ) | | (3,076 | ) |
Net cash used in investing activities | | (66,954 | ) | | (192,578 | ) |
| | | | |
Cash flows from financing activities | | |
| | |
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Bank repayments | | (696,000 | ) | | (595,000 | ) |
Bank borrowings | | 831,000 |
| | 665,000 |
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Repurchases of senior subordinated notes | | (55,521 | ) | | — |
|
Cash dividends paid | | (387 | ) | | (22,068 | ) |
Other | | (8,727 | ) | | (10,250 | ) |
Net cash provided by financing activities | | 70,365 |
| | 37,682 |
|
Net increase (decrease) in cash and cash equivalents | | 5,440 |
| | (17,132 | ) |
Cash and cash equivalents at beginning of period | | 2,812 |
| | 23,153 |
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Cash and cash equivalents at end of period | | $ | 8,252 |
| | $ | 6,021 |
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2016, our consolidated results of operations for the three months ended March 31, 2016 and 2015, and our consolidated cash flows for the three months ended March 31, 2016 and 2015.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, beginning “Other current assets,” “Deferred tax liabilities, net,” “Paid-in capital in excess of par” and “Accumulated deficit” have been adjusted for changes related to (1) the accounting for excess tax benefits and forfeitures associated with share-based payment transactions, (2) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (3) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.
Net Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards. For the three months ended March 31, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:
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| | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands | | 2016 | | 2015 |
Basic weighted average common shares outstanding | | 347,235 |
| | 350,688 |
|
Potentially dilutive securities | | |
| | |
|
Restricted stock, stock options, SARs and performance-based equity awards | | — |
| | — |
|
Diluted weighted average common shares outstanding | | 347,235 |
| | 350,688 |
|
Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share (although time-vesting restricted stock is issued and outstanding upon grant).
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:
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| | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands | | 2016 | | 2015 |
Stock options and SARs | | 7,412 |
| | 10,507 |
|
Restricted stock and performance-based equity awards | | 5,097 |
| | 2,948 |
|
Write-Down of Oil and Natural Gas Properties
The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015 and the first quarter of 2016, from $79.55 per Bbl for the first quarter of 2015 to $44.03 per Bbl for the first quarter of 2016. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $2.22 per Mcf for the first quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $256.0 million and $146.2 million during the three months ended March 31, 2016 and March 31, 2015, respectively.
Recent Accounting Pronouncements
Recently Adopted
Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to beginning “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.
Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows.
Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs associated with our senior subordinated notes of $32.8 million have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows.
Not Yet Adopted
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (“ASU 2016-08”) which clarifies the implementation guidance on principal versus agent considerations. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09, ASU 2015-14 and ASU 2016-08 will have on our consolidated financial statements.
Note 2. Long-Term Debt
The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
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| | | | | | | | |
| | March 31, | | December 31, |
In thousands | | 2016 | | 2015 |
Senior Secured Bank Credit Agreement | | $ | 310,000 |
| | $ | 175,000 |
|
6⅜% Senior Subordinated Notes due 2021 | | 396,000 |
| | 400,000 |
|
5½% Senior Subordinated Notes due 2022 | | 1,207,745 |
| | 1,250,000 |
|
4⅝% Senior Subordinated Notes due 2023 | | 1,094,000 |
| | 1,200,000 |
|
Other Subordinated Notes, including premium of $6 and $7, respectively | | 2,256 |
| | 2,257 |
|
Pipeline financings | | 209,399 |
| | 211,766 |
|
Capital lease obligations | | 65,817 |
| | 71,324 |
|
Total | | 3,285,217 |
| | 3,310,347 |
|
Issuance costs on senior subordinated notes | | (29,803 | ) | | (32,752 | ) |
Total, net of debt issuance costs on senior subordinated notes | | 3,255,414 |
| | 3,277,595 |
|
Less: current obligations | | (32,917 | ) | | (32,481 | ) |
Long-term debt and capital lease obligations | | $ | 3,222,497 |
| | $ | 3,245,114 |
|
The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 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. As of April 18, 2016, in connection with our May 2016 borrowing base redetermination requirement, we have reduced our borrowing base and lender commitments to $1.05 billion, with the next such redetermination scheduled for November 2016.
In order to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with maintenance financial covenants in this low oil price environment, we have entered into three amendments to the Bank Credit Agreement between May 2015 and April 2016 that have modified the Bank Credit Agreement as follows:
| |
• | for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio); |
| |
• | for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; |
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• | beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters |
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019;
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• | allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements); |
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• | limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and |
| |
• | limits the amount spent on repurchases of our senior subordinated notes to $225 million. |
Additionally, such amendments provide for the following changes to the Bank Credit Agreement: (1) increases the applicable margin for ABR Loans and LIBOR Loans by 75 basis points such that the margin for ABR Loans now ranges from 1% to 2% per annum and the margin for LIBOR Loans now ranges from 2% to 3% per annum, (2) increases the commitment fee rate to 0.50%, and (3) provides for semi-annual scheduled redeterminations of the borrowing base in May and November of each year. As of March 31, 2016, we were in compliance with all debt covenants under the Bank Credit Agreement. The weighted average interest rate on borrowings outstanding as of March 31, 2016, under the Bank Credit Agreement was 2.4%.
The above description of our Bank Credit Agreement financial covenants and the changes provided for within the three amendments are qualified by the express language and defined terms contained in the Bank Credit Agreement, the First Amendment to the Bank Credit Agreement dated May 4, 2015, the Second Amendment to the Bank Credit Agreement dated February 17, 2016, and the Third Amendment to the Bank Credit Agreement dated April 18, 2016, each of which are filed as exhibits to our periodic reports filed with the SEC.
2016 Repurchases of Senior Subordinated Notes
During February and March 2016, we repurchased a total of $4.0 million in aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021 (the “2021 Notes”), $42.3 million in aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 (the “2022 Notes”), and $106.0 million in aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023 (the “2023 Notes”) 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. As of May 4, 2016, an additional $169.5 million may be spent on senior subordinated notes repurchases under the Bank Credit Agreement.
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, 2016, we had $34.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $33.6 million during 2015 and an additional $0.9 million during the first quarter of 2016 to reduce the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.
As of March 31, 2016, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during the fourth quarter of 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of March 31, 2016.
Note 4. Stockholders’ Equity
Dividends
During the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share, with dividends totaling $22.1 million paid to stockholders during the three months ended March 31, 2015. In
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
September 2015, in light of the continuing low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.
Note 5. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2016, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes our commodity derivative contracts as of March 31, 2016, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification (“FASC”) Derivatives and Hedging topic:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) |
Range (1) | | Weighted Average Price |
Swap | | Sold Put | | Floor | | Ceiling |
Oil Contracts: | | | | | | | | | | | | | | | |
2016 Enhanced Swaps (2) | | | | | | | | | | | | | | | |
Apr – June | | NYMEX | | 2,000 | | $ | 90.35 | – | 90.35 |
| | $ | 90.35 |
| | $ | 68.00 |
| | $ | — |
| | $ | — |
|
Apr – June | | LLS | | 6,000 | | | 93.30 | – | 93.50 |
| | 93.38 |
| | 70.00 |
| | — |
| | — |
|
2016 Fixed-Price Swaps | | | | | | | | | | | | | | | |
Apr – June | | NYMEX | | 11,500 | | $ | 60.30 | – | 63.75 |
| | $ | 61.84 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Apr – June | | LLS | | 3,500 | | | 64.20 | – | 66.15 |
| | 64.99 |
| | — |
| | — |
| | — |
|
July – Sept | | NYMEX | | 16,500 | | | 36.25 | – | 40.65 |
| | 38.24 |
| | — |
| | — |
| | — |
|
July – Sept | | LLS | | 7,000 | | | 37.24 | – | 42.15 |
| | 39.61 |
| | — |
| | — |
| | — |
|
Oct – Dec | | NYMEX | | 23,000 | | | 36.25 | – | 40.00 |
| | 37.97 |
| | — |
| | — |
| | — |
|
Oct – Dec | | LLS | | 7,000 | | | 37.24 | – | 41.00 |
| | 39.16 |
| | — |
| | — |
| | — |
|
2016 Three-Way Collars (3) | | | | | | | | | | | | | | | |
Apr – June | | NYMEX | | 2,000 | | $ | 85.00 | – | 95.50 |
| | $ | — |
| | $ | 68.00 |
| | $ | 85.00 |
| | $ | 95.50 |
|
Apr – June | | LLS | | 2,000 | | | 88.00 | – | 98.25 |
| | — |
| | 70.00 |
| | 88.00 |
| | 98.25 |
|
2016 Collars | | | | | | | | | | | | | | | | | |
Apr – June | | NYMEX | | 5,000 | | $ | 55.00 | – | 72.25 |
| | $ | — |
| | $ | — |
| | $ | 55.00 |
| | $ | 71.01 |
|
Apr – June | | LLS | | 2,000 | | | 58.00 | – | 73.00 |
| | — |
| | — |
| | 58.00 |
| | 73.00 |
|
July – Sept | | NYMEX | | 4,500 | | | 55.00 | – | 72.65 |
| | — |
| | — |
| | 55.00 |
| | 71.22 |
|
July – Sept | | LLS | | 3,000 | | | 58.00 | – | 74.30 |
| | — |
| | — |
| | 58.00 |
| | 73.85 |
|
2017 Fixed-Price Swaps | | | | | | | | | | | | | | | |
Jan – Mar | | NYMEX | | 20,000 | | $ | 41.15 | – | 44.35 |
| | $ | 42.39 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Jan – Mar | | LLS | | 9,000 | | | 42.35 | – | 45.60 |
| | 43.51 |
| | — |
| | — |
| | — |
|
| |
(1) | Ranges presented for fixed-price swaps and enhanced 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) | An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes. |
| |
(3) | 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. |
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 6. Fair Value Measurements
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
| |
• | Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. |
| |
• | Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and 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, 2016, instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, 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 $14 thousand in the fair value of these instruments as of March 31, 2016. |
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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, 2016 | | | | | | | | |
Assets | | | | | | | | |
Oil derivative contracts – current | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
|
Total Assets | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
|
| | | | | | | | |
Liabilities | | | | | | | | |
Oil derivative contracts – current | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
|
Total Liabilities | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
|
| | | | | | | | |
December 31, 2015 | | |
| | |
| | |
| | |
|
Assets | | |
| | |
| | |
| | |
|
Oil derivative contracts – current | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
|
Total Assets | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
|
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
Level 3 Fair Value Measurements
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2016 and 2015:
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands | | 2016 | | 2015 |
Fair value of Level 3 instruments, beginning of period | | $ | 52,834 |
| | $ | 188,446 |
|
Fair value adjustments on commodity derivatives | | 281 |
| | 25,085 |
|
Payment (receipts) on settlements of commodity derivatives | | (30,075 | ) | | (48,516 | ) |
Fair value of Level 3 instruments, end of period | | $ | 23,040 |
| | $ | 165,015 |
|
| | | | |
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 | | $ | 133 |
| | $ | 23,099 |
|
We utilize an income approach to value our Level 3 enhanced swaps, 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:
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
|
| | | | | | | | | | |
| | Fair Value at 3/31/2016 (in thousands) | | Valuation Technique | | Unobservable Input | | Volatility Range |
Oil derivative contracts | | $ | 23,040 |
| | Discounted cash flow / Black-Scholes | | Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2016 | | 26.9% – 38.0% |
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 fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our debt as of March 31, 2016 and December 31, 2015, excluding pipeline financing and capital lease obligations, was $1,487.4 million and $1,119.0 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.
Note 7. Commitments and Contingencies
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.
NGS Sub Corp., Evolution, et al v. Denbury Onshore, LLC
In March 2015, Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”), the parent of the entity which sold Denbury Onshore, LLC (“Denbury Onshore”), a subsidiary of Denbury Resources Inc. (“DRI” and together with Denbury Onshore, “Denbury”), its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the 133rd Judicial District Court in Houston, Harris County, Texas since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining “payout” as defined in the agreements, and the extent and terms of assignment of reversionary interests in the unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury in connection with the June 2013 Delhi Field release of well fluids, and for the first time Evolution estimated its damages attributable to its allegations in the case as exceeding $200 million. The amended petition also added a claim for unspecified punitive damages. In Denbury’s answer and counterclaim, we have denied Evolution’s claims, alleged breach of contract by Evolution for failing to convey the full interest for which we paid and for violating our preferential purchase rights, and asked for a declaratory judgment as to various purchase document terms, including those pertaining to the determination of payout, the assignment of provisions of the documents, and cost sharing. Denbury has also filed a Motion for Summary Judgment seeking dismissal of Evolution’s tort claims for negligence and gross negligence.
Discovery is ongoing in the case, and the case is currently set for trial in July 2016. We believe that Evolution’s claims and requests for damages in this matter are without merit and we intend to vigorously pursue our requested relief under the purchase documents.
Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 8. Additional Balance Sheet Details
Accounts Payable and Accrued Liabilities
|
| | | | | | | | |
| | March 31, | | December 31, |
In thousands | | 2016 | | 2015 |
Accrued interest | | $ | 44,201 |
| | $ | 48,908 |
|
Accounts payable | | 32,688 |
| | 30,477 |
|
Accrued lease operating expenses | | 30,169 |
| | 37,549 |
|
Taxes payable | | 17,717 |
| | 32,438 |
|
Accrued compensation | | 14,403 |
| | 46,780 |
|
Accrued exploration and development costs | | 13,500 |
| | 20,892 |
|
Other | | 34,037 |
| | 36,153 |
|
Total | | $ | 186,715 |
| | $ | 253,197 |
|
Note 9. Subsequent Event
During the first week of May 2016, we entered into privately negotiated exchange agreements to exchange $922.5 million in aggregate principal amount of our outstanding 2021 Notes, 2022 Notes and 2023 Notes for $531.2 million in aggregate principal amount of new 9% Senior Secured Second Lien Notes due 2021 and 36.9 million shares of Denbury common stock. The transactions are currently expected to close May 10, 2016, subject to customary closing conditions.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
OVERVIEW
Denbury 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.
Oil Price Decline and Impact on Our Business. Oil prices generally constitute the single largest variable in our operating results. Oil prices have historically been volatile, with NYMEX prices ranging from $35 to $111 per Bbl over the last three calendar years, and prices have declined dramatically since the fourth quarter of 2014 to less than $27 per Bbl in January 2016, the lowest level in over 13 years. The following charts illustrate the fluctuations in our realized oil and natural gas prices, excluding the impact of commodity derivative settlements, during 2014, 2015 and the first quarter of 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended |
Average realized prices | | 3/31/14 | | 6/30/14 | | 9/30/14 | | 12/31/14 | | | 3/31/15 | | 6/30/15 | | 9/30/15 | | 12/31/15 | | | 3/31/16 |
Oil price per Bbl | | $ | 97.69 |
| | $ | 100.04 |
| | $ | 94.78 |
| | $ | 70.80 |
| | | $ | 46.02 |
| | $ | 56.92 |
| | $ | 45.74 |
| | $ | 40.41 |
| | | $ | 30.71 |
|
Natural gas price per Mcf | | 4.71 |
| | 4.39 |
| | 3.55 |
| | 3.54 |
| | | 2.54 |
| | 2.44 |
| | 2.40 |
| | 2.00 |
| | | 1.70 |
|
As oil prices continued to decline in the first quarter of 2016 from already depressed levels, our focus remained on cost reductions and preserving liquidity. We continue to take steps to reduce our costs in all categories of our business, and we have made significant progress in that regard as demonstrated in our first quarter results discussed below. We have set our capital development budget (excluding capitalized interest) at $200 million for 2016, which we currently anticipate will primarily be funded with cash flow from operations, thus preserving our liquidity. One advantage we have in this environment is that our oil assets have relatively low decline rates, and therefore we anticipate that our production will decline by less than 10% in 2016, assuming the mid-point of our production guidance, even with our significantly reduced planned capital spending level. This decline rate is even lower if we exclude wells that we anticipate will be shut in for economic reasons. Lastly, we have hedged
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
approximately half of our estimated production through the second quarter of 2017 in order to cover our current level of cash costs and to help mitigate any future price declines or sustained low oil prices.
During this period of reduced capital spending, we have continued to evaluate our assets with a goal of increasing the value of both existing assets and future projects by optimizing field operational and development plans, reducing CO2 injection volumes due to increased efficiency, and reducing costs such as power and workovers. Over the past year, we have reduced our CO2 injection volumes by 35% and our lease operating expenses by 27% when comparing the first quarters of 2015 and 2016. These initiatives aim to increase the profitability of our assets, making them more resilient to lower oil prices. Together, we believe these initiatives will help us manage through this low oil price environment and provide us with liquidity for the foreseeable future.
As more fully discussed under Capital Resources and Liquidity below, our banks recently completed their borrowing base redetermination under our senior secured bank credit facility, which resulted in a reduction in the banks’ commitment level under our facility from $1.5 billion to $1.05 billion. In addition, we entered into an amendment to our senior secured bank credit facility terms in February 2016 to relax certain of our financial covenants in 2016 and 2017, and we entered into another amendment in April 2016, which allows for up to $1.0 billion in junior lien debt capacity. As of March 31, 2016, we had $310.0 million drawn on our senior secured bank credit facility, leaving us with $680.7 million in availability under our bank line after adjusting for the recently revised commitment level. Borrowings under our senior secured bank credit facility increased from $175.0 million at December 31, 2015, due in part to $55.5 million utilized to purchase $152.3 million in aggregate principal amount of senior subordinated notes in open-market transactions, resulting in a net reduction of $96.7 million in our long-term debt (see Capital Resources and Liquidity – 2016 Repurchases of Senior Subordinated Notes below). The remaining portion of the increase in our senior secured bank credit facility balance from December 31, 2015 is primarily due to seasonal working capital outflows in the first quarter of 2016 associated with accrued compensation, ad valorem taxes and semi-annual interest payments on our senior subordinated notes.
Recent Debt Reduction Transactions. During February and March 2016, we reduced our outstanding long-term indebtedness through open-market purchases, and in May 2016 we entered into exchange agreements with a limited number of holders of our outstanding senior subordinated notes to exchange these notes for the Company’s 9% Senior Secured Second Lien Notes due 2021. The transactions are currently expected to close May 10, 2016, subject to customary closing conditions. See Capital Resources and Liquidity – 2016 Repurchases of Senior Subordinated Notes and 2016 Senior Subordinated Notes Exchange Agreements for further discussion.
Operating Highlights. Our financial results continue to be impacted by the decrease in realized oil prices as highlighted above, which decreased from an average of $46.02 per Bbl in the first quarter of 2015 to $30.71 in the first quarter of 2016. During the first quarter of 2016, we recognized a net loss of $185.2 million, or $0.53 per diluted common share, compared to a net loss of $107.7 million, or $0.31 per diluted common share, during the first quarter of 2015. The change in net loss between the first quarter of 2015 and 2016 was primarily due to the increase in the size of our full cost pool ceiling test write-down of our oil and natural gas properties, which totaled $256.0 million ($160.5 million net of tax) in the 2016 quarter (see Write-Down of Oil and Natural Gas Properties below), partially offset by a $95.0 million gain on debt extinguishment in the first quarter of 2016. Other significant changes between the first quarter of 2015 and 2016 were a $109.7 million (37%) decline in our oil and natural gas revenues between the periods, which was primarily oil-price related, and a $105.9 million decrease in commodity derivatives income, offset in part by a $72.6 million (48%) decrease in depletion, depreciation, and amortization, a $38.6 million (27%) reduction in lease operating expense, a $12.4 million (27%) decrease in general and administrative expenses, and a $6.6 million (25%) decrease in taxes other than income. The $105.9 million decrease in commodity derivatives income between the two periods was due to a $29.7 million increased loss associated with noncash fair value commodity adjustments and $76.2 million less in receipts from settlements of derivative contracts during the 2016 period.
We generated $2.0 million of cash flows from operating activities in the first quarter of 2016, compared to $164.9 million in the fourth quarter of 2015 and $137.8 million in the prior-year first quarter. These results include cash outflows for seasonal working capital changes of $54.8 million and $57.7 million during the three months ending March 31, 2016 and 2015, respectively, compared to cash inflows for working capital changes of $35.6 million during the three months ending December 31, 2015. The decrease in cash flows from operations between the first quarter of 2015 and 2016 was due primarily to lower oil prices, which caused a decrease in oil revenues, and approximately 51% lower receipts on derivative settlements, partially offset by reductions in lease operating expenses, general and administrative expenses, and taxes other than income.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
During the first quarter of 2016, our oil and natural gas production, which was 95% oil, averaged 69,351 BOE/d, compared to an average of 74,356 BOE/d produced during the first quarter of 2015 and 72,002 BOE/d during the fourth quarter of 2015. The year-over-year and sequential quarterly declines were primarily due to natural production declines based on our lower capital spending level, coupled with production shut in due to economics, as oil prices declined further during the quarter. We estimate that approximately 2,800 BOE/d of production was shut in as of March 31, 2016 attributable to uneconomic wells, resulting in a decrease to sequential quarterly production of approximately 1,100 BOE/d. We estimate that approximately one-half of the production currently shut in is profitable at $50 per Bbl, approximately two-thirds at $60 per Bbl, with the remainder requiring an oil price in excess of $60 per Bbl in order to be economic. See Results of Operations – Production for further discussion.
Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $30.71 per Bbl during the first quarter of 2016, a decrease of 33% compared to $46.02 per Bbl realized during the first quarter of 2015 and a decrease of 24% compared to $40.41 per Bbl realized during the fourth quarter of 2015. The oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) was $3.02 per Bbl below NYMEX prices in the first quarter of 2016, compared to a negative $2.81 per-Bbl NYMEX differential in the first quarter of 2015 and a negative $1.74 per-Bbl NYMEX differential in the fourth quarter of 2015. The weakening in our oil price differential in comparison to its level in the first quarter of 2015 was principally due to weakening of our Light Louisiana Sweet (“LLS”) premium relative to NYMEX oil prices.
One of our primary focuses in the past few years has been to reduce costs throughout the organization, through a number of internal initiatives. As a result of these efforts, we have been able to make continued reductions in our lease operating expenses, and in the first quarter of 2016 these expenses were $16.23 per BOE, a 16% decrease on a sequential-quarter basis and a 23% decrease when compared to per-BOE levels in the first quarter of 2015. In addition, our recurring lease operating expenses per BOE decreased in each sequential quarter in 2014 and 2015 and decreased a total of 38% between fourth-quarter 2013 levels and those in the first quarter of 2016, with decreases realized in most categories of lease operating expenses, the most significant of which were workover costs, CO2 costs, power costs, and certain third-party contractor and vendor costs.
Write-Down of Oil and Natural Gas Properties. Due to a continued decline in the rolling first-day-of-the-month average oil and natural gas price for the preceding 12-month periods in 2015 and 2016, we recognized full cost pool ceiling test write-downs of $256.0 million and $146.2 million during the three months ended March 31, 2016 and March 31, 2015, respectively. See Note 1, Basis of Presentation – Write-Down of Oil and Natural Gas Properties, to the Unaudited Condensed Consolidated Financial Statements, and Results of Operations – Write-Down of Oil and Natural Gas Properties for additional information regarding the ceiling test.
Impact of Commodity Price Decline on Proved Oil and Natural Gas Reserves Quantities. Declines in commodity prices may materially impact estimated quantities of proved reserves, as certain reserves may reach the point at which they become uneconomic to produce earlier than they would otherwise. The SEC requires proved reserves to be determined based on average first-day-of-the-month oil and natural gas prices for the trailing 12-month period. Using these prices, our total proved reserves at December 31, 2015, were 288.6 MMBOE, of which 98% was oil and 2% was natural gas. During 2015 and the first quarter of 2016, the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves declined from $50.28 per Bbl at December 31, 2015, to $46.26 per Bbl at March 31, 2016, and for natural gas declined from $2.63 per MMBtu at December 31, 2015, to $2.45 per MMBtu at March 31, 2016. Although we had no significant change in our reserve quantities during the first quarter of 2016, based on current NYMEX futures prices, during 2016, we currently expect negative price revisions of less than 10% of our 2015 year-end proved reserves. The actual reserve revisions could occur for various reasons, including differences in actual commodity prices from commodity futures prices and changes in oil and natural gas price differentials, forecasted production rates, forecasted operating and capital costs, and changes in development plans, all of which are key assumptions in estimating proved oil and natural gas reserves.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our senior secured bank credit facility. Outstanding borrowings under our senior secured bank credit facility were $310.0 million as of March 31, 2016, compared to $175.0 million as of December 31, 2015. The $135.0 million increase in borrowings includes $55.5 million utilized to repurchase $152.3 million in aggregate principal amount of senior subordinated notes in open-market transactions, with the remainder primarily due to seasonal working capital outflows in the first quarter of 2016 associated with accrued compensation, ad valorem taxes and semi-annual interest payments on our senior subordinated notes. As a result of the significant reduction in oil prices discussed above and less advantageous hedge positions, our cash flow from
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
operations has significantly decreased, from $137.8 million during the three months ended March 31, 2015 and $164.9 million during the three months ended December 31, 2015, to $2.0 million during the three months ended March 31, 2016.
The culmination of these factors places a significant priority on the preservation of cash and liquidity until oil prices improve. We have taken and will continue to take steps to lower our costs in all categories of our business, and we have made significant progress in that regard. We also amended our Bank Credit Agreement in the first quarter of 2016 to relax certain bank covenants through 2017 to address potential covenant compliance issues if oil prices remain at levels comparable to the first quarter of 2016. As of March 31, 2016, we had $310.0 million drawn on our senior secured bank credit facility, leaving us $680.7 million of current liquidity after consideration of $59.3 million of outstanding letters of credit and adjusting for the recently revised lender commitment level of $1.05 billion. This liquidity, coupled with our other cost saving and liquidity measures, should be sufficient to supplement our capital or operating cash outflows as needed until oil prices improve, which we believe will be in the next twelve to eighteen months. Based upon our current forecasted levels of production and costs, hedges in place as of May 2, 2016, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our bank covenants during 2016 and 2017.
To protect our liquidity, we have entered into additional oil swaps for the second half of 2016 and the first half of 2017, such that we now have approximately half of our estimated oil production hedged through the first half of 2017. While these prices are not sufficient to provide enough cash flow to grow our production, they do at least cover our most recent total cash costs which were in a per-barrel range in the low $30’s in the first quarter of 2016, including corporate overhead and interest, thereby minimizing the amount that would be required for day-to-day operations from our bank line.
Senior Secured Bank Credit Facility. As of March 31, 2016, we had $310.0 million of debt outstanding (based on a $1.05 billion commitment level from our banks) and $59.3 million in letters of credit on the senior secured bank credit facility. In order to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with maintenance financial covenants in this low oil price environment, we have entered into three amendments to the Bank Credit Agreement between May 2015 and April 2016 that have modified the Bank Credit Agreement as follows:
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• | for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio); |
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• | for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; |
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• | beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019; |
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• | allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements); |
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• | limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and |
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• | limits the amount spent on repurchases of our senior subordinated notes to $225 million. |
For these financial performance covenant calculations as of March 31, 2016, our ratio of consolidated senior secured debt to consolidated EBITDAX was 0.36 to 1.0, our ratio of consolidated EBITDAX to consolidated interest charges was 4.71 to 1.0, and our current ratio was 4.99. Based upon our current forecasted levels of production and costs, hedges in place as of May 2, 2016, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our bank covenants during 2016 and 2017.
The above description of our Bank Credit Agreement financial covenants and the changes provided for within the three amendments are qualified by the express language and defined terms contained in the Bank Credit Agreement, the First Amendment to the Bank Credit Agreement dated May 4, 2015, the Second Amendment to the Bank Credit Agreement dated February 17, 2016 (the “Second Amendment”), and the Third Amendment to the Bank Credit Agreement dated April 18, 2016 (the “Third Amendment”), each of which are filed as exhibits to our periodic reports filed with the SEC.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2016 Repurchases of Senior Subordinated Notes. During the first quarter of 2016, we repurchased a total of $152.3 million in aggregate principal amount of our existing senior subordinated notes in open-market transactions, consisting of $4.0 million in aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021 (the “2021 Notes”), $42.3 million in aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 (the “2022 Notes”), and $106.0 million in aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023 (the “2023 Notes”) for a total purchase price of $55.5 million, excluding accrued interest. The repurchases were made at prices ranging from approximately 25% to 45% of the principal amount of the individual senior subordinated notes. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off. We currently estimate saving approximately $6 million in annual cash interest related to these repurchases, which takes into account the reduction in debt and the lower interest rate on our bank credit facility as compared to the senior subordinated notes. The Second Amendment limits the amount of these open-market repurchases of our senior subordinated notes to $225 million, so as of May 4, 2016, after taking these repurchases into account, we have an additional $169.5 million remaining to spend on senior subordinated notes repurchases.
2016 Senior Subordinated Notes Exchange Agreements. During the first week of May 2016, we entered into privately negotiated exchange agreements to exchange $126.6 million in aggregate principal amount of our 2021 Notes, $351.6 million in aggregate principal amount of our 2022 Notes, and $444.2 million in aggregate principal amount of our 2023 Notes for $531.2 million in aggregate principal amount of new 9% Senior Secured Second Lien Notes due 2021 plus 36.9 million shares of Denbury common stock. The transactions are currently expected to close May 10, 2016, subject to customary closing conditions. We expect to realize a minimal reduction in cash interest related to these transactions. Our Bank Credit Agreement allows for the incurrence of up to $1.0 billion of junior lien debt, so after taking these exchanges into account, we have an additional $468.8 million of junior lien debt capacity that remains available to us. Combined with the repurchases of senior subordinated notes in open-market transactions during February and March 2016, these transactions will result in a net reduction of the Company’s debt of approximately $488 million.
Capital Spending. We anticipate that our full-year 2016 capital budget, excluding capitalized interest and acquisitions, will be approximately $200 million, which includes approximately $55 million in capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. This combined 2016 capital budget amount, excluding capitalized interest and acquisitions, is comprised of the following:
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• | $100 million allocated for tertiary oil field expenditures; |
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• | $35 million allocated for other areas, primarily non-tertiary oil field expenditures; |
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• | $10 million to be spent on CO2 sources and pipeline construction; and |
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• | $55 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. |
Based upon our currently forecasted levels of production and costs, commodity hedges in place, and current oil commodity futures prices, we intend to fund our development capital spending primarily with cash flow from operations, with any potential shortfall funded with incremental borrowings under our senior secured bank credit facility, and as of March 31, 2016, we had ample availability on our senior secured bank credit facility to cover any foreseeable cash flow shortfall. If prices were to decrease further or changes in operating results were to cause us to have a reduction in anticipated 2016 cash flows below our currently forecasted operating cash flows, we could potentially make minor additional reductions in our capital expenditures, as further reductions in our capital spending are limited to some degree by existing prior commitments and capitalized items. If we further reduce our capital spending due to lower cash flows, any sizeable reduction could further lower our anticipated production levels in future years.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the three months ended March 31, 2016 and 2015:
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands | | 2016 | | 2015 |
Capital expenditures by project | | | | |
Tertiary oil fields | | $ | 31,964 |
| | $ | 42,900 |
|
Non-tertiary fields | | 5,873 |
| | 30,984 |
|
Capitalized internal costs (1) | | 14,473 |
| | 18,412 |
|
Oil and natural gas capital expenditures | | 52,310 |
| | 92,296 |
|
CO2 pipelines | | — |
| | 779 |
|
CO2 sources (2) | | — |
| | 9,852 |
|
Other | | 8 |
| | (238 | ) |
Capital expenditures, before acquisitions and capitalized interest | | 52,318 |
| | 102,689 |
|
Acquisitions of oil and natural gas properties | | 224 |
| | 261 |
|
Capital expenditures, before capitalized interest | | 52,542 |
| | 102,950 |
|
Capitalized interest | | 5,780 |
| | 8,409 |
|
Capital expenditures, total | | $ | 58,322 |
| | $ | 111,359 |
|
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(1) | Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. |
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(2) | Includes capital expenditures related to the Riley Ridge gas processing facility. |
For the three months ended March 31, 2016, our capital expenditures and property acquisitions were funded primarily with borrowings on our senior secured bank credit facility as our cash flow was used primarily to cover other working capital changes. For the three months ended March 31, 2015, our capital expenditures and property acquisitions were fully funded with cash flows from operations.
Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include operating leases for office space and various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.
Our commitments and obligations consist of those detailed as of December 31, 2015, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations.
RESULTS OF OPERATIONS
Our tertiary operations represent a significant portion of our overall operations and are our primary long-term strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play, and we have outlined certain of these differences in our Form 10-K and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operating Results Table
Certain of our operating results and statistics for the comparative three months ended March 31, 2016 and 2015 are included in the following table:
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-share and unit data | | 2016 | | 2015 |
Operating results | | | | |
Net income (loss) (1) | | $ | (185,193 | ) | | $ | (107,746 | ) |
Net income (loss) per common share – basic (1) | | (0.53 | ) | | (0.31 | ) |
Net income (loss) per common share – diluted (1) | | (0.53 | ) | | (0.31 | ) |
Dividends declared per common share | | — |
| | 0.0625 |
|
Net cash provided by operating activities | | 2,029 |
| | 137,764 |
|
Average daily production volumes | | |
| | |
|
Bbls/d | | 66,139 |
| | 70,564 |
|
Mcf/d | | 19,270 |
| | 22,752 |
|
BOE/d (2) | | 69,351 |
| | 74,356 |
|
Operating revenues | | |
| | |
|
Oil sales | | $ | 184,816 |
| | $ | 292,270 |
|
Natural gas sales | | 2,987 |
| | 5,200 |
|
Total oil and natural gas sales | | $ | 187,803 |
| | $ | 297,470 |
|
Commodity derivative contracts (3) | | |
| | |
|
Receipt on settlements of commodity derivatives | | $ | 72,227 |
| | $ | 148,465 |
|
Noncash fair value adjustments on commodity derivatives (4) | | (95,053 | ) | | (65,389 | ) |
Commodity derivatives income (expense) | | $ | (22,826 | ) | | $ | 83,076 |
|
Unit prices – excluding impact of derivative settlements | | |
| | |
|
Oil price per Bbl | | $ | 30.71 |
| | $ | 46.02 |
|
Natural gas price per Mcf | | 1.70 |
| | 2.54 |
|
Unit prices – including impact of derivative settlements (3) | | | | |
|
Oil price per Bbl | | $ | 42.71 |
| | $ | 69.28 |
|
Natural gas price per Mcf | | 1.70 |
| | 2.91 |
|
Oil and natural gas operating expenses | | | | |
|
Lease operating expenses | | $ | 102,447 |
| | $ | 141,084 |
|
Marketing expenses, net of third-party purchases, and plant operating expenses | | 11,592 |
| | 9,843 |
|
Production and ad valorem taxes | | 17,178 |
| | 22,899 |
|
Oil and natural gas operating revenues and expenses per BOE | | | | |
|
Oil and natural gas revenues | | $ | 29.76 |
| | $ | 44.45 |
|
Lease operating expenses | | 16.23 |
| | 21.08 |
|
Marketing expenses, net of third-party purchases, and plant operating expenses | | 1.84 |
| | 1.47 |
|
Production and ad valorem taxes | | 2.72 |
| | 3.42 |
|
CO2 sources – revenues and expenses | | |
| | |
|
CO2 sales and transportation fees | | $ | 6,272 |
| | $ | 6,972 |
|
CO2 discovery and operating expenses | | (607 | ) | | (947 | ) |
CO2 revenue and expenses, net | | $ | 5,665 |
| | $ | 6,025 |
|
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(1) | Includes full cost pool ceiling test write-downs of $256.0 million and $146.2 million for the three months ended March 31, 2016 and March 31, 2015, respectively. |
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(2) | Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”). |
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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(3) | See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. |
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(4) | Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represent only the net change between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $72.2 million for the three months ended March 31, 2016, compared to receipts on settlements of $148.5 million for the three months ended March 31, 2015. We believe that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Production
Average daily production by area for each of the four quarters of 2015 and for the first quarter of 2016 is shown below:
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| | | | | | | | | | | | | | | | |
| | Average Daily Production (BOE/d) |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | | First Quarter |
Operating Area | | 2015 | | 2015 | | 2015 | | 2015 | | | 2016 |
Tertiary oil production | | | | | | | | | | | |
Gulf Coast region | | | | | | | | | | | |
Mature properties (1) | | 10,801 |
| | 11,170 |
|
| 10,946 |
| | 10,403 |
| | | 9,666 |
|
Delhi | | 3,551 |
| | 3,623 |
| | 3,676 |
| | 3,898 |
| | | 3,971 |
|
Hastings | | 4,694 |
| | 5,350 |
| | 5,114 |
| | 5,082 |
| | | 5,068 |
|
Heidelberg | | 6,027 |
| | 5,885 |
| | 5,600 |
| | 5,635 |
| | | 5,346 |
|
Oyster Bayou | | 5,861 |
| | 5,936 |
| | 5,962 |
| | 5,831 |
| | | 5,494 |
|
Tinsley | | 8,928 |
| | 8,740 |
| | 7,311 |
| | 7,522 |
| | | 7,899 |
|
Total Gulf Coast region | | 39,862 |
|
| 40,704 |
| | 38,609 |
| | 38,371 |
| |
| 37,444 |
|
Rocky Mountain region | | | | | | | | | | | |
Bell Creek | | 1,965 |
| | 1,880 |
| | 2,225 |
| | 2,806 |
| | | 3,020 |
|
Total Rocky Mountain region | | 1,965 |
| | 1,880 |
| | 2,225 |
| | 2,806 |
| | | 3,020 |
|
Total tertiary oil production | | 41,827 |
| | 42,584 |
| | 40,834 |
| | 41,177 |
| | | 40,464 |
|
Non-tertiary oil and gas production | | | | | | | | | | | |
Gulf Coast region | | | | | | | | | | | |
Mississippi | | 1,761 |
| | 1,400 |
| | 1,592 |
| | 1,800 |
| | | 978 |
|
Texas | | 6,490 |
| | 6,304 |
| | 6,508 |
| | 6,470 |
| | | 6,148 |
|
Other | | 1,006 |
| | 906 |
| | 846 |
| | 800 |
| | | 549 |
|
Total Gulf Coast region | | 9,257 |
| | 8,610 |
| | 8,946 |
| | 9,070 |
| | | 7,675 |
|
Rocky Mountain region | | | | | | | | | | | |
Cedar Creek Anticline | | 18,522 |
| | 18,089 |
| | 17,515 |
| | 17,875 |
| | | 17,778 |
|
Other | | 4,750 |
| | 4,433 |
| | 4,115 |
| | 3,880 |
| | | 3,434 |
|
Total Rocky Mountain region | | 23,272 |
| | 22,522 |
| | 21,630 |
| | 21,755 |
| | | 21,212 |
|
Total non-tertiary production | | 32,529 |
| | 31,132 |
| | 30,576 |
| | 30,825 |
| |
| 28,887 |
|
Total production | | 74,356 |
| | 73,716 |
| | 71,410 |
| | 72,002 |
| | | 69,351 |
|
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(1) | Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields. |
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Total Production
Total production during the first quarter of 2016 averaged 69,351 BOE/d, a decrease of 5,005 BOE/d (7%) compared to first quarter of 2015 production levels and a decrease of 2,651 BOE/d (4%) compared to fourth quarter of 2015 production levels. The year-over-year and sequential quarterly declines were primarily due to natural production declines based on our lower capital spending level, coupled with production shut in due to economics, as oil prices declined further during the quarter. We estimate that approximately 2,800 BOE/d of production was shut in as of March 31, 2016 attributable to uneconomic wells, resulting in a decrease to sequential quarterly production of approximately 1,100 BOE/d. These decreases were partially offset by increases in production due to continued development at Bell Creek Field in the Rocky Mountain region. Our production during the three months ended March 31, 2016 was 95% oil, consistent with oil production during the three months ended March 31, 2015 and December 31, 2015. In mid-April 2016, a series of strong thunderstorms in the Houston area affected two Denbury fields, causing damage to a primary tank battery in Conroe Field and flooding at Thompson Field. As a result of these storms, we currently have approximately 2,000 Bbls/d shut in and are working to restore full production in both fields. We expect to have most of this shut-in production back online by the end of May, and we estimate the combined production impact to be approximately 300 Bbls/d for the full year.
Tertiary Production
Oil production from our tertiary operations during the first quarter of 2016 decreased 713 Bbls/d (2%) when comparing the fourth quarter of 2015 and the first quarter of 2016 and decreased 1,363 Bbls/d (3%) compared to the same period in 2015. These decreases were primarily the result of natural production declines at Heidelberg Field, where future development has slowed due to commodity prices, Oyster Bayou Field, where production is believed to have peaked, and our mature properties in the Gulf Coast region, partially offset by increased production due to continued development at Bell Creek Field in the Rocky Mountain region. The year-over-year and sequential quarter changes were further impacted by first quarter of 2016 production at Tinsley Field, which decreased 1,029 Bbls/d from the prior year quarter, although production increased 377 Bbls/d from the fourth quarter of 2015. Although we experienced certain facility processing constraints at Tinsley Field during the third quarter of 2015, production has largely returned to normal levels; however, production from Tinsley Field is believed to have peaked in 2015, with a modest production decline currently expected in 2016.
Non-Tertiary Production
Production from our non-tertiary operations averaged 28,887 BOE/d during the first quarter of 2016, a decrease of 1,938 BOE/d (6%) compared to the fourth quarter of 2015 levels and a decrease of 3,642 BOE/d (11%) compared to the first quarter of 2015 levels. The production declines were impacted by production that we estimated to be attributable to wells shut in as uneconomic to either produce or repair due to commodity prices at this time. In addition, the sequential and year-over-year decreases also included natural production declines at Cedar Creek Anticline and our other non-tertiary Rocky Mountain properties and our non-tertiary properties in the Gulf Coast.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three months ended March 31, 2016 decreased 27% sequentially when compared to oil and natural gas revenues during the three months ended December 31, 2015 and decreased 37% compared to these revenues for the same period in 2015. The changes in our oil and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| | 2016 vs. 2015 |
In thousands | | Decrease in Revenues | | Percentage Decrease in Revenues |
Change in oil and natural gas revenues due to: | | | | |
Decrease in production | | $ | (16,942 | ) | | (7 | )% |
Decrease in commodity prices | | (92,725 | ) | | (30 | )% |
Total decrease in oil and natural gas revenues | | $ | (109,667 | ) | | (37 | )% |
Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 2016 and 2015:
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
| | 2016 | | 2015 |
Average net realized prices: | | | | |
Oil price per Bbl | | $ | 30.71 |
| | $ | 46.02 |
|
Natural gas price per Mcf | | 1.70 |
| | 2.54 |
|
Price per BOE | | 29.76 |
| | 44.45 |
|
Average NYMEX differentials: | | |
| | |
|
Oil per Bbl | | $ | (3.02 | ) | | $ | (2.81 | ) |
Natural gas per Mcf | | (0.29 | ) | | (0.28 | ) |
As reflected in the table above, our average net realized oil price, excluding the impact of commodity derivative contracts, decreased 33% during the first quarter of 2016 from the average price received during the first quarter of 2015 and 24% when compared to the fourth quarter of 2015. Company-wide average oil price differentials in the first quarter of 2016 were $3.02 per Bbl below NYMEX, compared to an average differential of $2.81 per Bbl below NYMEX in the first quarter of 2015 and $1.74 per Bbl below NYMEX in the fourth quarter of 2015, principally due to weakening of our Gulf Coast region LLS price differentials described below. Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials. The oil differentials we received in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.
Our average NYMEX oil differential in the Gulf Coast region was a negative $1.95 per Bbl and $0.29 per Bbl during the three months ended March 31, 2016 and 2015, respectively, and a negative $0.87 per Bbl during the three months ended December 31, 2015. These differentials are impacted significantly by the changes in prices received for our crude oil sold under LLS index prices relative to the change in NYMEX prices, as well as various other price adjustments such as those noted above. The quarterly average LLS-to-NYMEX differential (on a trade-month basis) was a positive $1.60 per Bbl in the first quarter of 2016, down from a positive $2.60 per Bbl in the first quarter of 2015 and a positive $2.08 per Bbl in the fourth quarter of 2015. During the first quarter of 2016, we sold approximately 58% of our crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
NYMEX oil differentials in the Rocky Mountain region averaged $5.04 per Bbl and $7.75 per Bbl below NYMEX during the three months ended March 31, 2016 and 2015, respectively, and $3.41 per Bbl below NYMEX during the three months ended December 31, 2015. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.
Commodity Derivative Contracts
The following table summarizes the impact our oil and natural gas derivative contracts had on our operating results for the three months ended March 31, 2016 and 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2016 | | 2015 |
In thousands | | Crude Oil Derivative Contracts | | Natural Gas Derivative Contracts | | Total Commodity Derivative Contracts |
Receipt on settlements of commodity derivatives | | $ | 72,227 |
| | $ | 147,716 |
| | $ | — |
| | $ | 749 |
| | $ | 72,227 |
| | $ | 148,465 |
|
Noncash fair value adjustments on commodity derivatives (1) | | (95,053 | ) | | (65,122 | ) | | — |
| | (267 | ) | | (95,053 | ) | | (65,389 | ) |
Total income (expense) | | $ | (22,826 | ) | | $ | 82,594 |
| | $ | — |
| | $ | 482 |
| | $ | (22,826 | ) | | $ | 83,076 |
|
| |
(1) | Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value adjustments on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
In order to protect our liquidity and provide price certainty to a portion of our oil production, we have hedged approximately half of our estimated production out through the second quarter of 2017. The following table summarizes our commodity derivative contracts as of May 2, 2016:
|
| | | | | | |
| | 2Q16 | 3Q16 | 4Q16 | 1Q17 | 2Q17 |
WTI NYMEX | Volumes Hedged (Bbls/d) | 11,500 | 18,500 | 26,000 | 22,000 | 22,000 |
Fixed-Price Swaps | Swap Price (1) | $61.84 | $38.96 | $38.70 | $42.67 | $43.99 |
WTI NYMEX | Volumes Hedged (Bbls/d) | 2,000 | — | — | — | — |
Enhanced Swaps | Swap / Sold Put Price (1)(2) | $90.35 / $68 | — | — | — | — |
Argus LLS | Volumes Hedged (Bbls/d) | 3,500 | 7,000 | 7,000 | 10,000 | 7,000 |
Fixed-Price Swaps | Swap Price (1) | $64.99 | $39.61 | $39.16 | $43.77 | $45.35 |
Argus LLS | Volumes Hedged (Bbls/d) | 6,000 | — | — | — | — |
Enhanced Swaps | Swap / Sold Put Price (1)(2) | $93.38 / $70 | — | — | — | — |
WTI NYMEX | Volumes Hedged (Bbls/d) | 5,000 | 4,500 | — | — | — |
Collars | Ceiling Price / Floor (1) | $71.01 / $55 | $71.22 / $55 | — | — | — |
WTI NYMEX | Volumes Hedged (Bbls/d) | 2,000 | — | — | — | — |
3-Way Collars | Ceiling Price / Floor / Sold Put Price (1)(2) | $95.50 / $85 / $68 | — | — | — | — |
Argus LLS | Volumes Hedged (Bbls/d) | 2,000 | 3,000 | — | — | — |
Collars | Ceiling Price / Floor (1) | $73 / $58 | $73.85 / $58 | — | — | — |
Argus LLS | Volumes Hedged (Bbls/d) | 2,000 | — | — | — | — |
3-Way Collars | Ceiling Price / Floor / Sold Put Price (1)(2) | $98.25 / $88 / $70 | — | — | — | — |
| Total Volumes Hedged (Bbls/d) | 34,000 | 33,000 | 33,000 | 32,000 | 29,000 |
| |
(1) | Averages are volume weighted. |
| |
(2) | If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the swap or floor price and the sold put price. |
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil and natural gas derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations. The details of our outstanding commodity derivative contracts at March 31, 2016, are included in Note 5, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements. Also, see Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion on our commodity derivative contracts.
Production Expenses
Lease Operating Expense
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-BOE data | | 2016 | | 2015 |
Lease operating expense | | | | |
Tertiary | | $ | 62,188 |
| | $ | 85,459 |
|
Non-tertiary | | 40,259 |
| | 55,625 |
|
Total lease operating expense | | $ | 102,447 |
| | $ | 141,084 |
|
| | | | |
Lease operating expense per BOE | | |
| | |
|
Tertiary | | $ | 16.89 |
| | $ | 22.70 |
|
Non-tertiary | | 15.32 |
| | 19.00 |
|
Total lease operating expense per BOE | | 16.23 |
| | 21.08 |
|
Our lease operating costs have declined as a result of our cost reduction efforts, as well as general market decreases in the prices of many of the components of these costs, culminating in a six-year low in our total lease operating expenses in the first quarter of 2016, decreases in each of our last nine sequential quarters and a total decrease of 38% over approximately the last two years. Our recurring lease operating expenses was $16.23 per BOE in the first quarter of 2016, compared to $19.31 in the fourth quarter of 2015. Total lease operating expenses decreased $38.6 million (27%) on an absolute-dollar basis or $4.85 (23%) on a per-BOE basis during the three months ended March 31, 2016, compared to levels in the prior year period. This reduction was due to cost decreases in most lease operating expense categories, the most significant of which included (1) a decrease in workover costs and repairs as a result of reduced failures through root-cause analysis and fewer well repairs as more wells are uneconomic to repair based on low commodity prices, (2) lower power costs due to lower usage, (3) lower CO2 expense resulting from a 35% decrease in CO2 injection volumes, (4) lower company labor costs resulting from a reduction in force, and (5) lower third-party contractor and vendor expenses such as contract labor and chemical costs. Sequentially, lease operating expenses declined 20% on an absolute-dollar basis and 16% on a per-BOE basis between the fourth quarter of 2015 and the first quarter of 2016, as we have seen many of our costs decline, with the decrease in power, labor, CO2 and workover expense the primary components of lease operating expense cost reductions. As mentioned above, we have deferred certain well workovers and repairs in this current commodity price environment, resulting in us shutting in certain wells that are uneconomic to either produce or repair at this time. As a result, it is unlikely that we will be able to sustain these current low lease operating expense levels in future periods as we expect production levels to gradually decline throughout the year and if prices improve, we may decide to increase our spending for workover and repair work. We estimate that approximately one-half of the production currently shut in is profitable at $50 per Bbl, approximately two-thirds at $60 per Bbl, with the remainder requiring an oil price in excess of $60 per Bbl in order to be economic.
Tertiary lease operating expenses decreased $23.3 million (27%) on an absolute-dollar basis or $5.81 (26%) on a per-barrel basis during the first quarter of 2016 compared to the first quarter of 2015. When comparing the first quarter of 2016 to the fourth quarter of 2015, tertiary lease operating expenses decreased $14.5 million (19%) or $3.36 (17%) on a per-barrel basis. The year-over-year and sequential quarter declines were primarily due to (1) lower workover costs and repairs, (2) lower power costs due to lower rates and usage, (3) lower CO2 expense resulting from a decrease in CO2 injection volumes during both comparative periods, and (4) lower third-party contractor and vendor expenses such as contract labor and chemical costs.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Currently, our CO2 expense comprises approximately 20% of our typical tertiary lease operating expenses, and for the CO2 reserves we already own, consists of CO2 production expenses, and for the CO2 reserves we do not own, consists of our purchase of CO2 from royalty and working interest owners and industrial sources. During the first quarter of 2016 and 2015, approximately 56% and 63%, respectively, of the CO2 utilized in our CO2 floods consisted of CO2 owned and produced by us (our net revenue interest). The price we pay others for CO2 varies by source and is generally indexed to oil prices. When combining the production cost of the CO2 we own with what we pay third parties for CO2, our average cost of CO2 during the first quarter of 2016 was approximately $0.30 per Mcf, including taxes paid on CO2 production but excluding depletion and depreciation of capital. This rate during the first quarter of 2016 was slightly higher than the $0.29 per Mcf during the first quarter of 2015 and lower than the $0.35 per Mcf comparable measure during the fourth quarter of 2015. The rate increase between the first quarter of 2015 and 2016 was primarily due to higher utilization of industrial-sourced CO2, which has a higher average cost than our naturally occurring CO2 sources, partially offset by reductions in the price of CO2 due to the significant decline in oil prices (though the decline is somewhat limited by certain contracts in place with price floors). The decrease in the CO2 cost per Mcf between the fourth quarter of 2015 and first quarter of 2016 was primarily due to fewer workovers and a 10% decrease in CO2 injection volumes due to further increased efficiencies, largely in the Gulf Coast region. Including the cost of depreciation and amortization of capital expended at our CO2 source fields and industrial sources, but excluding depreciation of our CO2 pipelines, our cost of CO2 was $0.41 per Mcf and $0.39 per Mcf during the first quarter of 2016 and 2015, respectively.
Non-tertiary lease operating expenses decreased $15.4 million (28%) on an absolute-dollar basis and $3.68 (19%) on a per-BOE basis between the three months ended March 31, 2015 and 2016, and decreased $10.9 million (21%) on an absolute-dollar basis and $2.72 (15%) on a per-BOE basis between the fourth quarter of 2015 and first quarter of 2016. The year-over-year and sequential quarter decreases were primarily due to lower workover costs, repairs and maintenance costs, and lower third-party contractor and vendor expenses such as contract labor and chemical costs during the 2016 period.
Marketing and Plant Operating Expenses
Marketing and plant operating expenses primarily consist of amounts incurred relating to the marketing, processing, and transportation of oil and natural gas production, as well as expenses related to our Riley Ridge gas processing facility. Marketing and plant operating expenses increased $1.5 million (13%) during the three months ended March 31, 2016, compared to the same period in 2015, primarily due to an increase in marketing and compression expenses, partially offset by a reduction in expenses related to the Riley Ridge gas processing facility, which is currently shut in.
Taxes Other Than Income
Taxes other than income includes ad valorem, production and franchise taxes. Taxes other than income decreased $6.6 million during the three months ended March 31, 2016 compared to the same period in 2015. The levels of taxes other than income during most periods are generally aligned with fluctuations in oil and natural gas revenues.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-BOE data and employees | | 2016 | | 2015 |
Gross cash compensation and administrative costs | | $ | 79,738 |
| | $ | 95,280 |
|
Gross stock-based compensation | | 2,884 |
| | 11,059 |
|
Operator labor and overhead recovery charges | | (35,133 | ) | | (42,128 | ) |
Capitalized exploration and development costs | | (13,588 | ) | | (17,931 | ) |
Net G&A expense | | $ | 33,901 |
| | $ | 46,280 |
|
| | | | |
G&A per BOE: | | |
| | |
|
Net administrative costs | | $ | 5.29 |
| | $ | 5.89 |
|
Net stock-based compensation | | 0.08 |
| | 1.03 |
|
Net G&A expense | | $ | 5.37 |
| | $ | 6.92 |
|
| | | | |
Employees as of March 31 | | 1,096 |
| | 1,496 |
|
Gross cash compensation and administrative costs on an absolute-dollar basis decreased $15.5 million (16%) during the three months ended March 31, 2016, compared to those costs in the same period in 2015, primarily due to lower employee-related costs such as salaries, bonus accruals and long-term incentives, offset in part by severance costs. As part of our efforts to reduce overhead and operating costs in response to the significant decline in oil prices, we reduced our employee headcount in mid-2015 and further reduced our employee headcount in February 2016 through an involuntary workforce reduction, which contributed to an overall headcount reduction of approximately 27% since March 31, 2015. The severance-related payments associated with the 2016 workforce reduction were approximately $9.3 million.
Net G&A expense on a per-BOE basis decreased 22% during the three months ended March 31, 2016, compared to levels in the same period in 2015, primarily based upon the changes noted in gross cash compensation and administrative costs, partially offset by lower operating and overhead recovery charges, lower capitalized exploration and development costs, and lower production volumes.
Gross stock-based compensation on an absolute-dollar basis decreased $8.2 million (74%) during the three months ended March 31, 2016, compared to levels in the same period in 2015. The change between the comparative three-month periods was primarily due to the reductions in headcount mentioned above, the reduction in previously recognized stock compensation expense associated with our performance share awards for our executive officers which vested in the first quarter of 2016 or are projected to vest in future periods below target levels, and the postponement of our annual long-term incentive award grant from January in prior year to mid-year 2016.
Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition, salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities.
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-BOE data and interest rates | | 2016 | | 2015 |
Cash interest expense | | $ | 44,645 |
| | $ | 46,287 |
|
Noncash interest expense | | 3,306 |
| | 2,221 |
|
Less: capitalized interest | | (5,780 | ) | | (8,409 | ) |
Interest expense, net | | $ | 42,171 |
| | $ | 40,099 |
|
Interest expense, net per BOE | | $ | 6.68 |
| | $ | 5.99 |
|
Average debt outstanding | | $ | 3,326,140 |
| | $ | 3,615,918 |
|
Average interest rate (1) | | 5.4 | % | | 5.1 | % |
| |
(1) | Includes commitment fees but excludes debt issue costs and amortization of discount or premium. |
Our average interest rate increased slightly between the first quarter of 2015 and 2016 due to an increase in the applicable margin for loans under the senior secured bank credit facility and an increase in our commitment fee rate, as well as lower average borrowings on our senior secured bank credit facility which is at a lower rate than our senior subordinated notes. Capitalized interest during the first quarter of 2016 decreased $2.6 million (31%), compared to the same period in 2015, primarily due to a reduction in the number of projects that qualify for interest capitalization.
Depletion, Depreciation, and Amortization (“DD&A”)
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-BOE data | | 2016 | | 2015 |
Depletion and depreciation of oil and natural gas properties | | $ | 47,417 |
| | $ | 116,347 |
|
Depletion and depreciation of CO2 properties | | 5,573 |
| | 8,212 |
|
Amortization of asset retirement obligations | | 2,902 |
| | 2,327 |
|
Depreciation of pipelines, plants and other property and equipment | | 21,474 |
| | 23,072 |
|
Total DD&A | | $ | 77,366 |
| | $ | 149,958 |
|
| | | | |
DD&A per BOE: | | |
| | |
|
Oil and natural gas properties | | $ | 7.98 |
| | $ | 17.73 |
|
CO2 properties, pipelines, plants and other property and equipment | | 4.28 |
| | 4.68 |
|
Total DD&A cost per BOE | | $ | 12.26 |
| | $ | 22.41 |
|
| | | | |
Write-down of oil and natural gas properties | | $ | 256,000 |
| | $ | 146,200 |
|
We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and costs. In addition, under full cost accounting rules, the divestiture of oil and gas properties generally does not result in gain or loss recognition; instead, the proceeds of the disposition reduce the full cost pool. As such, our DD&A rate has changed significantly over time, and it may continue to change in the future. DD&A of oil and natural gas properties and asset retirement obligations decreased 58% on an absolute-dollar basis and decreased 55% on a per-BOE basis between the first quarter of 2015 and 2016 and decreased 40% on an absolute-dollar basis and decreased 37% on a per-BOE basis between the fourth quarter of 2015 and first quarter of 2016, primarily due to a reduction in depletable costs associated with our reserves base resulting from the significant full cost pool ceiling test write-downs recognized during 2015 and an overall reduction in future development costs, partially offset by reductions in proved oil and natural gas reserve quantities. The per-BOE decrease was also partially offset by a decrease in production volumes during the first quarter of 2016 when compared to 2015. Given the additional full cost pool ceiling test write-down recognized
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
during the three months ended March 31, 2016, we currently expect our DD&A rate in the second quarter of 2016 to decrease slightly from the first quarter of 2016 rate and will likely decrease further as we are anticipating additional write-downs in the second quarter based on current oil prices. However, the overall decrease in our second quarter DD&A rate will also be impacted by potential changes in reserve volumes, production, and future capital expenditure estimates, among other factors, and therefore, the actual decrease may differ from this estimate.
Depletion and depreciation of our CO2 properties, pipelines, plants and other property and equipment decreased 14% on an absolute-dollar basis and 9% on a per-BOE basis during the three months ended March 31, 2016, compared to the same period in 2015, primarily due to lower depletion associated with our CO2 properties resulting from a decrease in CO2 production during the period.
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. As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015 and the first quarter of 2016, from $79.55 per Bbl for the first quarter of 2015 to $44.03 per Bbl for the first quarter of 2016. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $2.22 per Mcf for the first quarter of 2016. These prices represent a decrease of 8% for crude oil and 9% for natural gas prices compared to adjusted prices used to calculate the December 31, 2015, full cost ceiling value. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $256.0 million and $146.2 million during the three months ended March 31, 2016 and 2015, respectively. We currently expect that we will record an additional write-down in the second quarter of 2016 of $400 million or higher if oil and natural gas prices remain at or near late-April 2016 levels for the remainder of the second quarter, as the 12-month average prices used in determining the full cost ceiling value would reflect lower prices in the second quarter of 2016 than in the second quarter of 2015. Any such write-down would also be affected, in part, by changes in proved oil and natural gas reserve volumes, future capital expenditures and operating costs.
Income Taxes
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per-BOE amounts and tax rates | | 2016 | | 2015 |
Current income tax expense (benefit) | | $ | (5 | ) | | $ | 1,575 |
|
Deferred income tax benefit | | (95,115 | ) | | (66,036 | ) |
Total income tax benefit | | $ | (95,120 | ) | | $ | (64,461 | ) |
Average income tax benefit per BOE | | $ | (15.07 | ) | | $ | (9.63 | ) |
Effective tax rate | | 33.9 | % | | 37.4 | % |
Total net deferred tax liability | | $ | 742,148 |
| | $ | 837,263 |
|
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, 2016, we had $34.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized a tax valuation allowance during 2015 of $33.6 million and an additional $0.9 million during the first quarter of 2016 to reduce the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.
As of March 31, 2016, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during the fourth quarter of 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, 2016.
Our income taxes are based on estimated statutory rates of approximately 38% in 2016 and 2015. Our effective tax rate for the three months ended March 31, 2016 was lower than our estimated statutory rate, primarily due to the impact of a tax shortfall on the stock-based compensation deduction (e.g., the compensation expense recognized in the financial statements was greater than the actual compensation realized resulting in a shortfall in the income tax deduction for stock awards that vested during the quarter) which, prior to the adoption of ASU 2016-09, was recorded as an adjustment to equity. The amounts recorded as current income tax expense during the first quarter of 2015 represent our federal taxes, reduced by enhanced oil recovery credits during the prior year period, plus our state income taxes. The deferred income tax benefits during the three months ended March 31, 2016 and March 31, 2015, were primarily due to the impact of the write-down of our oil and natural gas properties during the year.
As of March 31, 2016, we had an estimated $51.1 million of enhanced oil recovery credits to carry forward related to our tertiary operations, $21.6 million of research and development credits, and $41.1 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2016 or future years. The enhanced oil recovery credits and research and development credits do not begin to expire until 2023 and 2031, respectively. We currently do not expect to earn additional enhanced oil recovery credits during 2016.
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
Per-BOE data | | 2016 | | 2015 |
Oil and natural gas revenues | | $ | 29.76 |
| | $ | 44.45 |
|
Receipt on settlements of commodity derivatives | | 11.44 |
| | 22.19 |
|
Lease operating expenses | | (16.23 | ) | | (21.08 | ) |
Production and ad valorem taxes | | (2.72 | ) | | (3.42 | ) |
Marketing expenses, net of third party purchases, and plant operating expenses | | (1.84 | ) | | (1.47 | ) |
Production netback | | 20.41 |
| | 40.67 |
|
CO2 sales, net of operating and exploration expenses | | 0.89 |
| | 0.90 |
|
General and administrative expenses | | (5.37 | ) | | (6.92 | ) |
Interest expense, net | | (6.68 | ) | | (5.99 | ) |
Other | | (0.24 | ) | | 0.55 |
|
Changes in assets and liabilities relating to operations | | (8.69 | ) | | (8.62 | ) |
Cash flows from operations | | 0.32 |
| | 20.59 |
|
DD&A | | (12.26 | ) | | (22.41 | ) |
Write-down of oil and natural gas properties | | (40.56 | ) | | (21.85 | ) |
Deferred income taxes | | 15.07 |
| | 9.87 |
|
Gain on debt extinguishment | | 15.05 |
| | — |
|
Noncash fair value adjustments on commodity derivatives (1) | | (15.06 | ) | | (9.78 | ) |
Other noncash items | | 8.10 |
| | 7.48 |
|
Net loss | | $ | (29.34 | ) | | $ | (16.10 | ) |
| |
(1) | Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value adjustments on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
CRITICAL ACCOUNTING POLICIES
For additional discussion of our critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K.
FORWARD-LOOKING INFORMATION
The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, future hydrocarbon prices, the length or severity of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to reduce our debt levels, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected oil and gas costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, or the timing of pipeline construction or completion or the cost thereof, dates of completion of to-be-constructed industrial plants and the initial date of capture of CO2 from such plants, timing of CO2 injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, anticipated future cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and their availability, helium reserves, potential reserves, percentages of recoverable original oil in place, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the range of potential insurance recoveries, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial and credit markets; general economic conditions; competition; government regulations, including tax and environmental; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Debt and Interest Rate Sensitivity
We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. As of March 31, 2016, we had $310.0 million of debt outstanding on our senior secured bank credit facility. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in light of recent credit downgrades in February 2016, we were required to provide a $41.3 million letter of credit to the lessor, which we provided on March 4, 2016. The letter of credit may be drawn upon in the event Denbury Onshore or Denbury fail to make a payment due under the pipeline financing lease agreement or upon other specified defaults set out in the pipeline financing lease agreement (filed as Exhibit 99.1 to the Form 8-K filed with the SEC on June 5, 2008). The fair value of our senior subordinated debt is based on quoted market prices. The following table presents the principal cash flows and fair values of our outstanding debt at March 31, 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
In thousands | | 2017 | | 2019 | | 2021 | | 2022 | | 2023 | | Total |
Variable rate debt: | | | | | | | | | | | | |
Senior Secured Bank Credit Facility (weighted average interest rate of 2.4% at March 31, 2016) | | $ | — |
| | $ | 310,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 310,000 |
|
Fixed rate debt: | | |
| | |
| | |
| | |
| | | | |
6⅜% Senior Subordinated Notes due 2021 | | — |
| | — |
| | 396,000 |
| | — |
| | — |
| | 396,000 |
|
5½% Senior Subordinated Notes due 2022 | | — |
| | — |
| | — |
| | 1,207,745 |
| | — |
| | 1,207,745 |
|
4⅝% Senior Subordinated Notes due 2023 | | — |
| | — |
| | — |
| | — |
| | 1,094,000 |
| | 1,094,000 |
|
Other Subordinated Notes | | 2,250 |
| | — |
| | — |
| | — |
| | — |
| | 2,250 |
|
See Note 2, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.
Oil and Natural Gas Derivative Contracts
Historically, we have entered into 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. In order to protect our liquidity and provide price certainty to a portion of our oil production, we have hedged approximately half of our estimated production out through the second quarter of 2017. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Commodity Derivative Contracts for a detail of our commodity derivative contracts as of May 2, 2016. We anticipate that we may use more fixed-price swaps in the future or a combination of fixed-price swaps and collars as we look to provide more certainty around our future cash flows. See also Note 5, Commodity Derivative Contracts, and Note 6, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. 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. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting treatment to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At March 31, 2016, our commodity derivative contracts were recorded at their fair value, which was a net asset of $47.8 million, a $95.0 million decrease from the $142.8 million net asset recorded at December 31, 2015. Changes in this value are comprised of the expiration of commodity derivative contracts during the three months ended March 31, 2016, new commodity derivative contracts entered into during 2016 for future periods, and to the changes in oil futures prices between December 31, 2015 and March 31, 2016.
Commodity Derivative Sensitivity Analysis
Based on NYMEX and LLS crude oil futures prices as of March 31, 2016, and assuming both a 10% increase and decrease thereon, we would expect to receive payments on our crude oil derivative contracts as shown in the following table:
|
| | | | |
| | Receipt / (Payment) |
In thousands | | Crude Oil Derivative Contracts |
Based on: | | |
Futures prices as of March 31, 2016 | | $ | 47,419 |
|
10% increase in prices | | 3,790 |
|
10% decrease in prices | | 91,035 |
|
Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments of our commodity derivative contracts due to changes in commodity prices as reflected in the above table would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil and natural gas production to which those commodity derivative contracts relate.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the first quarter of fiscal 2016, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. 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 business or finances, litigation is subject to inherent uncertainties. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our business or 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.
In mid-2006, Denbury Onshore, LLC (“Denbury Onshore”), a subsidiary of Denbury Resources Inc. (“DRI” and together with Denbury Onshore, “Denbury”), purchased its original interest in the Delhi Field in northeastern Louisiana from NGS Sub Corp. (“NGS”), a subsidiary of Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”). Under the purchase documents, Denbury Onshore committed to develop the enhanced production of the Holt Bryant Unit (the “Unit”), which is a specific portion of the Delhi Field, and after Denbury Onshore’s receipt of a defined level of net cash flow from the Unit (as defined in the purchase documents, “payout”), agreed to assign a reversionary interest in the Unit back to NGS. After several years of dispute regarding payout calculations and related contractual terms, in December 2013, Evolution filed suit against Denbury Onshore and DRI in the 133rd Judicial District Court in Houston, Harris County, Texas for unspecified damages. Evolution’s amended petition alleges breach of contract, and requests a declaratory judgment as to various provisions of the purchase documents and accompanying oil and gas conveyancing instruments, including as to the method of calculation and timing of payout, the sharing of various costs, and the timing and extent of post-payout assignments from Denbury Onshore to NGS. Evolution also brings claims for negligence and gross negligence in connection with the June-2013 Delhi Field release of well fluids. Evolution states in its amended petition that it is seeking over $200 million in damages in addition to unspecified punitive damages and attorneys’ fees. In Denbury’s answer and counterclaim, we have denied Evolution’s claims, alleged breach of contract by Evolution for failing to convey the full interest for which we paid and for violating our preferential purchase rights, and asked for a declaratory judgment as to various purchase document terms, including those pertaining to the determination of payout, the assignment of provisions of the documents, and cost sharing. Denbury has also filed a Motion for Summary Judgment seeking dismissal of Evolution’s tort claims for negligence and gross negligence.
Discovery in the case is ongoing. The case is currently set for trial in July 2016. We believe that Evolution’s claims and requests for damages in this matter are without merit and we intend to vigorously pursue our requested relief under the purchase documents.
Potential Mississippi Environmental Administrative Proceeding
The Company is currently attempting to conclude negotiations with the Mississippi Department of Environmental Quality (“MDEQ”) that began following receipt of a February 2015 notice from the MDEQ related to a discharge of materials at the West Heidelberg Field in Jasper County, Mississippi in the third quarter of 2013. Based upon discussions with the MDEQ during the first quarter of 2016, it is currently anticipated that an agreement related to the discharge providing for a monetary fine as a civil penalty will be reached with the MDEQ in 2016, thus eliminating the need for an administrative proceeding. The Company expects any such fine will not be material to the Company’s business or financial condition.
Item 1A. Risk Factors
Information with respect to the Company’s risk factors has been incorporated by reference to Item 1A of the Form 10-K. There have been no material changes to the risk factors contained in the Form 10-K since its filing.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes purchases of our common stock during the first quarter of 2016:
|
| | | | | | | | | | | | | | |
Month | | Total Number of Shares Purchased (1) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (2) |
January 2016 | | 557,800 |
| | $ | 1.71 |
| | — |
| | $ | 210.1 |
|
February 2016 | | 3,058 |
| | 1.11 |
| | — |
| | 210.1 |
|
March 2016 | | 49,599 |
| | 2.23 |
| | — |
| | 210.1 |
|
Total | | 610,457 |
| | |
| — |
| |
|
|
| |
(1) | Stock repurchases during the first quarter of 2016 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights. |
| |
(2) | In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program. |
Between early October 2011, when we announced the commencement of a common share repurchase program, and March 31, 2016, we repurchased 64.4 million shares of Denbury common stock (approximately 16.0% of our outstanding shares of common stock at September 30, 2011) for $951.8 million, with no repurchases made since October 2015. An additional $210.1 million remains authorized for purchases of common stock under this repurchase program.
Item 3. Defaults upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.
Item 6. Exhibits
|
| | |
Exhibit No. | | Exhibit |
10(a)* | | 2016 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(b)* | | 2016 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(c)* | | 2016 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(d)* | | 2016 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(e)* | | 2016 Form of Oil Price Change vs. TSR Performance Award.
|
10(f)* | | Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of March 31, 2016.
|
10(g) | | Third Amendment to Amended and Restated Credit Agreement, dated as of April 18, 2016, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 20, 2016, File No. 001-12935).
|
31(a)* | | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31(b)* | | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32* | | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
101* | | Interactive Data Files.
|
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | |
| | DENBURY RESOURCES INC. |
| | |
May 6, 2016 | | /s/ Mark C. Allen |
| | Mark C. Allen Sr. Vice President and Chief Financial Officer |
| | |
May 6, 2016 | | /s/ Alan Rhoades |
| | Alan Rhoades Vice President and Chief Accounting Officer |
INDEX TO EXHIBITS
|
| | |
Exhibit No. | | Exhibit |
10(a) | | 2016 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(b) | | 2016 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(c) | | 2016 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(d) | | 2016 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
|
10(e) | | 2016 Form of Oil Price Change vs. TSR Performance Award.
|
10(f) | | Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of March 31, 2016.
|
31(a) | | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31(b) | | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32 | | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
101 | | Interactive Data Files.
|
Exhibit 10(a)
Maximum Performance Shares Date of Grant: January 4, 2016
2016 TSR PERFORMANCE AWARD
(EQUITY PORTION)
2004 OMNIBUS STOCK AND INCENTIVE PLAN
DENBURY RESOURCES INC.
This TSR PERFORMANCE AWARD (this “Award”) is made effective on the Date of Grant by Denbury Resources Inc. (the “Company”) in favor of _____________________ (“Holder”).
WHEREAS, in accordance with the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc., as amended and/or restated (the “Plan”), the Committee may grant performance-based Awards;
WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn Performance Shares (as defined below) based on the Performance Criteria set forth in the Plan and this Award, and subject to all of the provisions, including without limitation the vesting provisions, of the Plan and of this Award;
WHEREAS, no Performance Shares will be issued or outstanding until the Vesting Date; and
WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.
NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:
1. Performance Share Grant. The Company hereby grants Holder the right to earn and vest in up to a maximum of [___________] Restricted Stock Units (the “Performance Shares”). On the Delivery Date, the Performance Shares entitle the Holder to receive shares of the Company’s Common Stock equal to the number of Earned Performance Shares up to and including the number of Maximum Performance Shares.
2. Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:
| |
(a) | “Annual TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of the calculation of TSR for each of them set out in Section 4(a) hereof as to a Calendar Year within the Performance Period. |
| |
(b) | “Beginning Common Stock Price” means the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured. |
| |
(c) | “Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company and each Peer Company. |
| |
(d) | “Change of Control” or “CIC” means, without limitation, the same as it does in the Plan. |
| |
(e) | “Closing Price” means the last reported sales price of the primary common equity security of the Company and each Peer Company, as reported by the national exchange upon which such security is traded; provided, however, in the event the primary common equity security of the Company or a Peer Company is not traded on a national exchange at the time of such determination, “Closing Price” will be the price determined by the Committee in good faith based upon a review of the facts and circumstances available to the Committee. |
| |
(f) | “Delivery Date” means (i) if Sections 6(b), 7(c)(i), (ii), or (iii) apply, the date on which Performance Shares are delivered to Holder which shall be no later than the dates set forth in Section 6(b) or 7(c)(i), (ii) or (iii), as applicable or (ii) if |
Sections 6(b) or 7(c)(i), (ii) or (iii) do not apply, the date on which Earned Performance Shares are delivered to Holder, which shall be no later than 30 days following March 31, 2019 (i.e., the Vesting Date).
| |
(g) | “Disability” means, without limitation, the same as it does in the Plan. |
| |
(h) | “Earned Performance Shares” means the number of Performance Shares which are earned during the Performance Period as described and calculated in Section 6. |
| |
(i) | “Ending Common Stock Price” equals the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days ending on and including the last day of each Calendar Year, taken separately, within the Performance Period. |
| |
(j) | “Maximum Performance Shares” means the maximum number of Performance Shares, as set forth in Section 1, which may be earned under this Award if there are no reductions in the number of Performance Shares under Section 5. |
| |
(k) | “Peer Company” means each of the companies listed on Appendix A hereto, as adjusted pursuant to Appendix A. |
| |
(l) | “Performance Criteria” means the Total Shareholder Return measure defined in Section 4 for the Performance Period. |
| |
(m) | “Performance Period” means the three-year period beginning on the first day of the Calendar Year of the Date of Grant and ending on December 31 of the Calendar Year three years thereafter, provided that in the event of a Change of Control, the Performance Period will end on the date that such Change of Control takes effect. |
| |
(n) | “Performance Percentage” means that percentage determined based upon the relative ranking of the Company’s Three-Year Average TSR for the Performance Period compared to the Three-Year Average TSR of each Peer Company for the Performance Period as determined under the provisions of Section 4(e), subject to reduction under Sections 5 and 12, if any. |
| |
(o) | “Post Separation Change of Control” means a Change of Control that closes following Holder’s Separation, but where such Separation resulted from the Commencement of the Change of Control prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change of Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change of Control involving such person, group, or their affiliates. |
| |
(p) | “Three-Year Average TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of averaging their respective Annual TSR for each of the Calendar Years in the Performance Period. |
| |
(q) | “Total Shareholder Return” or “TSR” shall mean that percentage which reflects the increase or decrease in the average closing trading price of the Company’s or a Peer Company’s primary common equity security (assuming reinvestment of any dividends) between the last 10 trading days of one Calendar Year and the last 10 trading days of the next Calendar Year, or as applicable, the average of such yearly increases or decreases. |
| |
(r) | “Value of Reinvested Dividends” means a dollar amount derived by (i) calculating an aggregate number of shares (or fractions thereof) of the Company or any Peer Company represented by the sum of each dividend paid on their respective primary common equity security during a Calendar Year (or portion thereof under Section 4(a)(ii) below) within the Performance Period, determined by dividing the per share amount or value paid through each such dividend by the Closing Price of that company’s primary common equity security on each such dividend payment date, and (ii) then multiplying that aggregate number of shares by the Ending Common Stock Price, respectively, of that company for that Calendar Year (or portion thereof in the event of a Change of Control). |
| |
(s) | “Vesting Date” means March 31, 2019 or the effective date of any earlier (i) Change of Control pursuant to Section 6(b) or (ii) death, Disability or Post Separation Change of Control pursuant to Sections 7(c)(i), (ii) or (iii), as appropriate. |
3. Performance Shares as Contractual Right. Each Performance Share represents a contractual right to receive one share of Common Stock of the Company, subject to the terms and conditions of this Award; provided that, based on relative Total Shareholder Return as detailed below, the number of Performance Shares that become Earned Performance Shares may range
from 0% to 100% of the number of Maximum Performance Shares, and Holder’s right to receive Common Stock of the Company in respect of Performance Shares is generally contingent.
4. Performance Percentage Earned With Respect to Total Shareholder Return Measure.
| |
(a) | Total Shareholder Return shall be calculated for the periods specified below as follows: |
(i) Annual TSR for the Company and each Peer Company for each Calendar Year within the Performance Period shall equal the result of the following calculation for each such company:
|
| |
Ending Common Stock Price + Value of Reinvested Dividends | - 1 |
Beginning Common Stock Price |
(ii) For any Calendar Year in which a Change of Control of the Company occurs, Annual TSR for the Company and each Peer Company for that Calendar Year shall equal the result of the following calculation for each such company:
| |
(b) | The Three-Year Average TSR of the Company and each Peer Company is to be calculated as soon as practical after the end of the Performance Period. Once calculated for the Company and for each Peer Company, the exact percentage of the Company and each Peer Company’s respective Three-Year Average TSR shall be listed in Column 3 of the table below in descending order of their respective Three-Year Average TSR from the highest percentage to the lowest percentage. |
| |
(c) | Column 2 of the table below shall reflect each such company’s name. |
| |
(d) | The percentages in Column 4 of the table below are based upon increments derived by dividing 100% by 17 (the number of Peer Companies), which percentage increments will be adjusted, if necessary, on a pro rata basis to reflect a reduction in the number of Peer Companies (for example, if at the end of the Performance Period there were 16 Peer Companies, then the 5.9% increment currently shown in Column 4 would become 6.3%). |
| |
(e) | The Company’s earned Performance Percentage will be that percentage shown in Column 5 (subject to adjustment, if any, provided in Sections 5 or 12) opposite the ranking of the Company in Column 1 (for example, in the following table for 18 Companies, being ranked as tenth would equal a Performance Percentage of 94%). The earned Performance Percentage will be adjusted to reflect adjustments made to the percentages in Column 4, if any, pursuant to Section 4(d) above; provided however, that the earned Performance Percentage may not be greater than 100%. |
|
| | | | |
Column 1 | Column 2 | Column 3 | Column 4 | Column 5 |
Ranking | Company Name | Actual Three-Year Average TSR (expressed as a %) | Scale of Three-Year Average TSR for 18 Companies (expressed as a %) | Performance Percentage Scale (subject to interpolation) |
1 | | | 100.0% | 100% |
2 | | | 94.1% | 100% |
3 | | | 88.2% | 100% |
4 | | | 82.4% | 100% |
5 | | | 76.5% | 100% |
6 | | | 70.6% | 100% |
7 | | | 64.7% | 100% |
8 | | | 58.8% | 100% |
9 | | | 52.9% | 100% |
10 | | | 47.1% | 94% |
11 | | | 41.2% | 82% |
12 | | | 35.3% | 71% |
13 | | | 29.4% | 59% |
14 | | | 23.5% | 47% |
15 | | | 17.6% | 35% |
16 | | | 11.8% | 24% |
17 | | | 5.9% | 12% |
18 | | | 0.0% | 0% |
5. Committee’s Reduction of Performance Percentage. Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by Committee resolution prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation. Any reduction of Holder’s Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period. The Committee does not have discretion to increase a Holder’s Performance Percentage.
6. Earned Performance Shares.
(a) Earned Performance Shares. The number of Earned Performance Shares shall be equal to the product of (i) the Maximum Performance Shares multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. No fractional shares will be issued to the Holder. The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period), and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change of Control provisions of Section 6(b) below.
(b) Change of Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change of Control of the Company occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change of Control of the Company, the Performance Period will end on the date of the Change of Control and the performance for the partial year will be annualized as set out in Section 4(a)(ii) above and averaged with the Annual TSR calculated for any prior completed Calendar Year to determine Earned Performance Shares, which Holder will be entitled to receive on the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Shares under this Award.
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7. | Vesting (and Forfeiture) of Earned Performance Shares. |
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(a) | No Separation Prior to the Vesting Date. If Holder does not experience a Separation prior to the Vesting Date, Holder will be 100% vested in the Earned Performance Shares. |
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(b) | Retirement Vesting Date. In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, then irrespective of whether or not Holder experiences a Separation prior to the Vesting Date, Holder will be entitled to receive Performance Shares in an amount equal to the number of Earned Performance Shares on the Vesting Date (which Performance Shares will be delivered to Holder on the Delivery Date), without any right to receive any additional Performance Shares pursuant to this Award, and without any proration of the number of Performance Shares earned in such circumstances. Notwithstanding the foregoing, in the event Holder experiences a Separation after Holder’s Retirement Vesting Date, but within 12 months of the Date of Grant, all rights to receive Performance Shares under this Award will be forfeited. |
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(c) | Forfeiture. Except to the extent expressly provided in Sections 7(b) and 7(c) (i), (ii) or (iii), Holder permanently will forfeit all rights with respect to all Performance Shares upon the date of his Separation, if such Separation occurs prior to the Vesting Date. |
(i) Death. If Holder experiences a Separation by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death. If Holder experiences a Separation by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the number of Earned Performance Shares based on the calculation in Section 6 herein (and does not have any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death.
(ii) Disability. If Holder experiences a Separation by reason of Disability prior to the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, are entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the Calendar Year in which the Holder experiences a Separation by reason of Disability. If Holder experiences a Separation by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive the number of Earned Performance Shares based on the calculation in Section 6 herein (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event later than 60 days following the Vesting Date.
(iii) Post Separation Change of Control. If there is a Post Separation Change of Control, Holder will be entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any additional Performance Shares pursuant to this Award) as soon as reasonably possible after the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs.
8. Withholding. On or before the Delivery Date, the Company may require Holder (or Holder’s Beneficiary) to pay to the Company an amount the Company deems necessary to satisfy its (or an Affiliate’s) obligation to withhold federal, state, local, and foreign income or other taxes that Holder incurs as a result of the settlement of the Award. Such tax obligations may be paid by Holder (or Holder’s Beneficiary) to the Company (a) in cash, (b) by delivery of previously owned shares of Common Stock, (c) through net settlement of the Award, or (d) through any other method permitted under the Plan and approved by the Committee. If the tax obligations are satisfied through the withholding of shares of Common Stock through net settlement, the number of shares of Common Stock that may be withheld shall be limited to the number of shares of Common Stock that have an aggregate Fair Market Value on the Delivery Date equal to the aggregate amount of the tax liabilities determined based on the applicable minimum statutory withholding rates for federal, state, local, and foreign tax purposes, including payroll taxes, or such other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company or Holder.
9. Issuance of Common Stock. Without limitation, Holder shall not have any of the rights and privileges of an owner of the Company’s Common Stock (including voting rights and dividend rights), until the Vesting Date. The Company shall deliver the Earned Performance Shares in the form described in Section 1 above (reduced by the number of shares of Common Stock delivered to the Company to pay required withholding under Section 8 above) to Holder as soon as reasonably possible following vesting. The Holder agrees that the delivery of Common Stock is subject to the Company’s stock ownership guidelines, as potentially modified from time to time.
10. Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to
which the Performance Criteria has been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s or a Peer Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award, and, to the extent the Award is intended to qualify as “performance based” under Section 162(m) of the Internal Revenue Code, does not affect such qualification. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties. The Committee, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to an administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.
11. Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Committee a written designation of beneficiary (such person(s) being the Holder’s “Beneficiary”), on such form as may be prescribed by the Committee. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.
12. Adjustments in this Award. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company, appropriate adjustments may be made to this Award in a manner deemed equitable by the Committee.
13. Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee shall make all relevant annually determined calculations and determinations hereunder, and will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.
14. No Transfers Permitted. The rights under this Award are not transferable by the Holder other than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Earned Performance Shares.
15. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder’s right to terminate employment, or the Company’s right to terminate Holder’s employment, at any time.
16. Governing Law. Without limitation, this Award shall be construed and enforced in accordance with, and be governed by, the laws of Delaware.
17. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, permitted successors and assigns of the parties hereto.
18. Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.
19. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.
20. Clawback. The Performance Shares are subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject the Performance Shares and amounts paid or realized with respect to the Performance Shares to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Performance Shares.
21. Compliance with Securities Laws. Notwithstanding any provision of this Award to the contrary, the issuance of Stock will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Stock may then be listed. No Stock will be issued
hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other laws or regulations or the requirements of any stock exchange or market system upon which the Stock may then be listed. In addition, Stock will not be issued hereunder unless (a) a registration statement under the Securities Act is at the time of issuance in effect with respect to the shares issued or (b) in the opinion of legal counsel of the Company, the shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. THE HOLDER IS CAUTIONED THAT ISSUANCE OF COMPANY COMMON STOCK UPON THE VESTING OF PERFORMANCE SHARES GRANTED PURSUANT TO THIS AWARD MAY NOT OCCUR UNLESS THE FOREGOING CONDITIONS ARE SATISFIED. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any shares of Stock subject to the Award will relieve the Company of any liability in respect of the failure to issue such shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate persons to make shares of Stock available for issuance.
22. Section 409A of the Code. It is the intention of the Committee that this Award is exempt from the Nonqualified Deferred Compensation Rules as a short-term deferral (within the meaning of such rules), and, as such, that this Award will be operated and construed accordingly. Neither this Section 22 nor any other provision of this Award or the Plan is or contains a representation to the Holder regarding the tax consequences of the grant, vesting, settlement, or sale of this Award (or the Stock underlying this Award), and should not be interpreted as such.
[Signature page to follow]
IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representatives on the Date of Grant.
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| DENBURY RESOURCES INC. | | |
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By: | | | |
| Phil Rykhoek Chief Executive Officer | | Mark C. Allen Senior Vice President and Chief Financial Officer |
ACKNOWLEDGMENT
The undersigned hereby acknowledges (i) receipt of this Award, (ii) the opportunity to review the Plan, (iii) the opportunity to discuss this Award with a representative of the Company, and the undersigned’s personal advisors, to the extent the undersigned deems necessary or appropriate, (iv) the understanding of the terms and provisions of the Award and the Plan, and (v) the understanding that, by the undersigned’s signature below, the undersigned is agreeing to be bound by all of the terms and provisions of this Award and the Plan.
Without limitation, the undersigned agrees to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee regarding any questions arising under the Plan, or this Award, or both.
Effective as of the Date of Grant.
Appendix A
Peer Companies
California Resources Corporation (CRC)
Canadian Oil Sands Limited (COS.TO)
Concho Resources, Inc. (CXO)
ConocoPhillips (COP)
Continental Resources, Inc. (CLR)
Crescent Point Energy Corp. (CPG)
Devon Energy Corporation (DVN)
Marathon Oil Corporation (MRO)
MEG Energy Corporation (MEG.TO)
Murphy Oil Corporation (MUR)
Oasis Petroleum, Inc. (OAS)
Occidental Petroleum Corporation (OXY)
Pioneer Natural Resources Company (PXD)
Sandridge Energy, Inc. (SD)
SM Energy Company (SM)
Vermilion Energy (VET)
Whiting Petroleum Corporation (WLL)
In the event that a Peer Company is acquired and ceases to have its primary common equity security listed or publicly traded, such company will be removed as a Peer Company for the purposes of calculating achievement of the Performance Percentage; provided, however, that if a Peer Company is forced to delist from the securities exchange upon which it was traded due to low stock price or other reasons or files for bankruptcy, then that company will remain a Peer Company and shall occupy the last position (or positions, if there are more than one such companies) in the TSR ranking.
Exhibit 10(b)
$____________ Maximum Performance Cash Date of Grant: January 4, 2016
2016 TSR PERFORMANCE AWARD
(CASH PORTION)
2004 OMNIBUS STOCK AND INCENTIVE PLAN
DENBURY RESOURCES INC.
This TSR PERFORMANCE AWARD (this “Award”) is made effective on the Date of Grant by Denbury Resources Inc. (the “Company”) in favor of _____________________ (“Holder”).
WHEREAS, in accordance with the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc., as amended and/or restated (the “Plan”), the Committee may grant performance-based Awards;
WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn Performance Cash (as defined below) based on the Performance Criteria set forth in the Plan and this Award, and subject to all of the provisions, including without limitation the vesting provisions, of the Plan and of this Award;
WHEREAS, no Performance Cash will be paid until the Vesting Date; and
WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.
NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:
1. Performance Cash Grant. The Company hereby grants Holder the right to earn and vest in up to a maximum of $___________ (the “Performance Cash”). On the Delivery Date, the Performance Cash entitles the Holder to receive a lump sum payment of cash equal to the amount of Earned Performance Cash up to and including the amount of Maximum Performance Cash.
2. Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:
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(a) | “Annual TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of the calculation of TSR for each of them set out in Section 4(a) hereof as to a Calendar Year within the Performance Period. |
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(b) | “Beginning Common Stock Price” means the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured. |
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(c) | “Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company and each Peer Company. |
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(d) | “Change of Control” or “CIC” means, without limitation, the same as it does in the Plan. |
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(e) | “Closing Price” means the last reported sales price of the primary common equity security of the Company and each Peer Company, as reported by the national exchange upon which such security is traded; provided, however, in the event the primary common equity security of the Company or a Peer Company is not traded on a national exchange at the time of such determination, “Closing Price” will be the price determined by the Committee in good faith based upon a review of the facts and circumstances available to the Committee. |
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(f) | “Delivery Date” means (i) if Sections 6(b), 7(c)(i) or (ii) apply, the date on which Performance Cash is paid to Holder which shall be no later than the dates set forth in Section 6(b) or 7(c)(i) or (ii), as applicable or (ii) if Sections 6(b) or 7(c)(i) or (ii) do not apply, the date on which Earned Performance Cash is paid to Holder, which shall be no later than 30 days following March 31, 2019 (i.e., the Vesting Date). |
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(g) | “Disability” means, without limitation, the same as it does in the Plan. |
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(h) | “Earned Performance Cash” means the amount of Performance Cash which is earned during the Performance Period as described and calculated in Section 6. |
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(i) | “Ending Common Stock Price” equals the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days ending on and including the last day of each Calendar Year, taken separately, within the Performance Period. |
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(j) | “Maximum Performance Cash” means the maximum amount of Performance Cash, as set forth in Section 1, which may be earned under this Award if there are no reductions in the amount of Performance Cash under Section 5. |
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(k) | “Peer Company” means each of the companies listed on Appendix A hereto, as adjusted pursuant to Appendix A. |
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(l) | “Performance Criteria” means the Total Shareholder Return measure defined in Section 4 for the Performance Period. |
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(m) | “Performance Period” means the three-year period beginning on the first day of the Calendar Year of the Date of Grant and ending on December 31 of the Calendar Year three years thereafter, provided that in the event of a Change of Control, the Performance Period will end on the date that such Change of Control takes effect. |
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(n) | “Performance Percentage” means that percentage determined based upon the relative ranking of the Company’s Three-Year Average TSR for the Performance Period compared to the Three-Year Average TSR of each Peer Company for the Performance Period as determined under the provisions of Section 4(e), subject to reduction under Sections 5 and 12, if any. |
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(o) | “Post Separation Change of Control” means a Change of Control that closes following Holder’s Separation, but where such Separation resulted from the Commencement of the Change of Control prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change of Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change of Control involving such person, group, or their affiliates. |
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(p) | “Three-Year Average TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of averaging their respective Annual TSR for each of the Calendar Years in the Performance Period. |
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(q) | “Total Shareholder Return” or “TSR” shall mean that percentage which reflects the increase or decrease in the average closing trading price of the Company’s or a Peer Company’s primary common equity security (assuming reinvestment of any dividends) between the last 10 trading days of one Calendar Year and the last 10 trading days of the next Calendar Year, or as applicable, the average of such yearly increases or decreases. |
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(r) | “Value of Reinvested Dividends” means a dollar amount derived by (i) calculating an aggregate number of shares (or fractions thereof) of the Company or any Peer Company represented by the sum of each dividend paid on their respective primary common equity security during a Calendar Year (or portion thereof under Section 4(a)(ii) below) within the Performance Period, determined by dividing the per share amount or value paid through each such dividend by the Closing Price of that company’s primary common equity security on each such dividend payment date, and (ii) then multiplying that aggregate number of shares by the Ending Common Stock Price, respectively, of that company for that Calendar Year (or portion thereof in the event of a Change of Control). |
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(s) | “Vesting Date” means March 31, 2019 or the effective date of any earlier (i) Change of Control pursuant to Section 6(b) or (ii) death or Disability pursuant to Sections 7(c)(i) or (ii), as appropriate. |
3. Performance Cash as Contractual Right. Performance Cash represents a contractual right to receive a specified amount of cash, subject to the terms and conditions of this Award; provided that, based on relative Total Shareholder Return as detailed below, the amount of Performance Cash that become Earned Performance Cash may range from 0% to 100% of the amount of Maximum Performance Cash, and Holder’s right to receive an amount of Performance Cash is generally contingent.
4. Performance Percentage Earned With Respect to Total Shareholder Return Measure.
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(a) | Total Shareholder Return shall be calculated for the periods specified below as follows: |
(i) Annual TSR for the Company and each Peer Company for each Calendar Year within the Performance Period shall equal the result of the following calculation for each such company:
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Ending Common Stock Price + Value of Reinvested Dividends | - 1 |
Beginning Common Stock Price |
(ii) For any Calendar Year in which a Change of Control of the Company occurs, Annual TSR for the Company and each Peer Company for that Calendar Year shall equal the result of the following calculation for each such company:
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(b) | The Three-Year Average TSR of the Company and each Peer Company is to be calculated as soon as practical after the end of the Performance Period. Once calculated for the Company and for each Peer Company, the exact percentage of the Company and each Peer Company’s respective Three-Year Average TSR shall be listed in Column 3 of the table below in descending order of their respective Three-Year Average TSR from the highest percentage to the lowest percentage. |
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(c) | Column 2 of the table below shall reflect each such company’s name. |
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(d) | The percentages in Column 4 of the table below are based upon increments derived by dividing 100% by 17 (the number of Peer Companies), which percentage increments will be adjusted, if necessary, on a pro rata basis to reflect a reduction in the number of Peer Companies (for example, if at the end of the Performance Period there were 16 Peer Companies, then the 5.9% increment currently shown in Column 4 would become 6.3%). |
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(e) | The Company’s earned Performance Percentage will be that percentage shown in Column 5 (subject to adjustment, if any, provided in Sections 5 or 12) opposite the ranking of the Company in Column 1 (for example, in the following table for 18 Companies, being ranked as eighth would equal a Performance Percentage of 18%). The earned Performance Percentage will be adjusted to reflect adjustments made to the percentages in Column 4, if any, pursuant to Section 4(d) above; provided however, that the earned Performance Percentage may not be greater than 100%. |
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Column 1 | Column 2 | Column 3 | Column 4 | Column 5 |
Ranking | Company Name | Actual Three-Year Average TSR (expressed as a %) | Scale of Three-Year Average TSR for 18 Companies (expressed as a %) | Performance Percentage Scale (subject to interpolation) |
1 | | | 100.0% | 100% |
2 | | | 94.1% | 88% |
3 | | | 88.2% | 76% |
4 | | | 82.4% | 65% |
5 | | | 76.5% | 53% |
6 | | | 70.6% | 41% |
7 | | | 64.7% | 29% |
8 | | | 58.8% | 18% |
9 | | | 52.9% | 6% |
10 | | | 47.1% | 0% |
11 | | | 41.2% | 0% |
12 | | | 35.3% | 0% |
13 | | | 29.4% | 0% |
14 | | | 23.5% | 0% |
15 | | | 17.6% | 0% |
16 | | | 11.8% | 0% |
17 | | | 5.9% | 0% |
18 | | | 0.0% | 0% |
5. Committee’s Reduction of Performance Percentage. Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by Committee resolution prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation. Any reduction of Holder’s Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period. The Committee does not have discretion to increase a Holder’s Performance Percentage.
6. Earned Performance Cash.
(a) Earned Performance Cash. The amount of Earned Performance Cash shall be equal to the product of (i) the Maximum Performance Cash multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period), and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change of Control provisions of Section 6(b) below.
(b) Change of Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change of Control of the Company occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change of Control of the Company, the Performance Period will end on the date of the Change of Control and the performance for the partial year will be annualized as set out in Section 4(a)(ii) above and averaged with the Annual TSR calculated for any prior completed Calendar Year to determine Earned Performance Cash, which Holder will be entitled to receive on the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Cash under this Award.
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7. | Vesting (and Forfeiture) of Earned Performance Cash. |
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(a) | No Separation Prior to the Vesting Date. If Holder does not experience a Separation prior to the Vesting Date, Holder will be 100% vested in the Earned Performance Cash. |
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(b) | Retirement Vesting Date. In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, then irrespective of whether or not Holder experiences a Separation prior to the Vesting Date, Holder will be entitled to receive Performance Cash in an amount equal to the amount of Earned Performance Cash on the Vesting Date (which Performance Cash will be delivered to Holder on the Delivery Date), without any right to receive any additional Performance Cash pursuant to this Award, and without any proration of the amount of Performance Cash earned in such circumstances. Notwithstanding the foregoing, in the event Holder experiences a Separation after Holder’s Retirement Vesting Date but within 12 months of the Date of Grant, all rights to receive Performance Cash under this Award will be forfeited. |
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(c) | Forfeiture. Except to the extent expressly provided in Sections 7(b) and 7(c) (i) or (ii), Holder permanently will forfeit all rights with respect to all Performance Cash upon the date of his Separation, if such Separation occurs prior to the Vesting Date. |
(i) Death. If Holder experiences a Separation by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will not be entitled to receive any amount of Performance Cash pursuant to this Award. If Holder experiences a Separation by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the amount of Earned Performance Cash based on the calcul--ation in Section 6 herein (and does not have any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death.
(ii) Disability. If Holder experiences a Separation by reason of Disability prior to the last day of the Performance Period, neither Holder nor Holder’s Beneficiary, as applicable, are entitled to receive any amount of Performance Cash pursuant to this Award. If Holder experiences a Separation by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive the amount of Earned Performance Cash based on the calculation in Section 6 herein (without any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event later than 60 days following the Vesting Date.
(iii) Post Separation Change of Control. If there is a Post Separation Change of Control, Holder will not be entitled to receive any amount of Performance Cash pursuant to this Award.
8. Withholding. The Company will reduce the amount payable, if any, pursuant to this Award by all applicable withholding, including federal, state, local and foreign tax withholding as well as any other deductions applicable to payments pursuant to this Award.
9. [Intentionally Left Blank]
10. Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which the Performance Criteria has been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s or a Peer Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award, and, to the extent the Award is intended to qualify as “performance based” under Section 162(m) of the Internal Revenue Code, does not affect such qualification. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties. The Committee, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to an administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.
11. Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Committee a written designation of beneficiary (such person(s) being the Holder’s “Beneficiary”), on such form as may be prescribed by the Committee. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.
12. Adjustments in this Award. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company, appropriate adjustments may be made to this Award in a manner deemed equitable by the Committee.
13. Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee shall make all relevant annually determined calculations and determinations hereunder and will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.
14. No Transfers Permitted. The rights under this Award are not transferable by the Holder other than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Earned Performance Cash.
15. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder’s right to terminate employment, or the Company’s right to terminate Holder’s employment, at any time.
16. Governing Law. Without limitation, this Award shall be construed and enforced in accordance with, and be governed by, the laws of Delaware.
17. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, permitted successors and assigns of the parties hereto.
18. Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.
19. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.
20. Clawback. The Performance Cash are subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject the Performance Cash and amounts paid or realized with respect to the Performance Cash to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Performance Cash.
21. Section 409A of the Code. It is the intention of the Committee that this Award is exempt from the Nonqualified Deferred Compensation Rules as a short-term deferral (within the meaning of such rules), and, as such, that this Award will be operated and construed accordingly. Neither this Section 21 nor any other provision of this Award or the Plan is or contains a representation to the Holder regarding the tax consequences of the grant, vesting, or settlement of this Award and should not be interpreted as such.
[Signature page to follow]
IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representatives on the Date of Grant.
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| | | |
| DENBURY RESOURCES INC. | | |
| | | |
| | | |
By: | | | |
| Phil Rykhoek Chief Executive Officer | | Mark C. Allen Senior Vice President and Chief Financial Officer |
ACKNOWLEDGMENT
The undersigned hereby acknowledges (i) receipt of this Award, (ii) the opportunity to review the Plan, (iii) the opportunity to discuss this Award with a representative of the Company, and the undersigned’s personal advisors, to the extent the undersigned deems necessary or appropriate, (iv) the understanding of the terms and provisions of the Award and the Plan, and (v) the understanding that, by the undersigned’s signature below, the undersigned is agreeing to be bound by all of the terms and provisions of this Award and the Plan.
Without limitation, the undersigned agrees to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee regarding any questions arising under the Plan, or this Award, or both.
Effective as of the Date of Grant.
Appendix A
Peer Companies
California Resources Corporation (CRC)
Canadian Oil Sands Limited (COS.TO)
Concho Resources, Inc. (CXO)
ConocoPhillips (COP)
Continental Resources, Inc. (CLR)
Crescent Point Energy Corp. (CPG)
Devon Energy Corporation (DVN)
Marathon Oil Corporation (MRO)
MEG Energy Corporation (MEG.TO)
Murphy Oil Corporation (MUR)
Oasis Petroleum, Inc. (OAS)
Occidental Petroleum Corporation (OXY)
Pioneer Natural Resources Company (PXD)
Sandridge Energy, Inc. (SD)
SM Energy Company (SM)
Vermilion Energy (VET)
Whiting Petroleum Corporation (WLL)
In the event that a Peer Company is acquired and ceases to have its primary common equity security listed or publicly traded, such company will be removed as a Peer Company for the purposes of calculating achievement of the Performance Percentage; provided, however, that if a Peer Company is forced to delist from the securities exchange upon which it was traded due to low stock price or other reasons or files for bankruptcy, then that company will remain a Peer Company and shall occupy the last position (or positions, if there are more than one such companies) in the TSR ranking.
Exhibit 10(c)
____________ Maximum Performance Shares Date of Grant: March 30, 2016
2016 EBITDAX PERFORMANCE AWARD
(EQUITY PORTION)
2004 OMNIBUS STOCK AND INCENTIVE PLAN
DENBURY RESOURCES INC.
This EBITDAX PERFORMANCE AWARD (this “Award”) is made effective on the Date of Grant by Denbury Resources Inc. (the “Company”) in favor of __________ (“Holder”).
WHEREAS, in accordance with the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc., as amended and/or restated (the “Plan”), the Committee may grant performance-based Awards;
WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn Performance Shares (as defined below) based on the Performance Criteria set forth in the Plan and this Award, and subject to all of the provisions, including without limitation the vesting provisions, of the Plan and of this Award;
WHEREAS, no Performance Shares will be issued or outstanding until the Vesting Date; and
WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.
NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:
1.Performance Share Grant. The Company hereby grants Holder the right to earn and vest in up to a maximum of [___________] Restricted Stock Units (the “Performance Shares”). On the Delivery Date, the Performance Shares entitle the Holder to receive shares of the Company’s Common Stock equal to the number of Earned Performance Shares up to and including the number of Maximum Performance Shares.
2.Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:
(a)“Actual Reported Production” means production of oil, condensate, natural gas liquids (“NGLs”), natural gas, synthetic oil, and synthetic gas expressed on a BOE basis, as reported in each Peer Company’s and the Company’s Form 10-K for the Performance Period, excluding production generated from each such company’s equity-method investee(s), if any.
(b)“BOE” means Barrels of Oil Equivalent, and for all purposes hereof, will be calculated using the ratio of one barrel of crude oil, condensate or NGLs to six thousand cubic feet of natural gas.
(c)“Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company and each Peer Company.
(d)“Calculated Estimate of General and Administrative Expense” means for each Non-Upstream-Focused Company, individually, (i) the quotient (rounded to four decimals and expressed as a percentage) of (x) its oil and natural gas revenues from continuing operations derived from exploration and production activities (as disclosed in its Form 10-K for the Performance Period in accordance with Financial Accounting Standards Board Codification (“FASC”) 932-235-50 (“FAS 69”) in its Form 10-K for the Performance Period), divided by (y) its total revenues from continuing operations reported on its consolidated income statement in its Form 10-K for the Performance Period; multiplied by (ii) its total general and administrative expenses from continuing operations for the Performance Period as reported on its consolidated income statement in its Form 10-K.
(e)“Change of Control” means, without limitation, the same as it does in the Plan.
(f)“Delivery Date” means (i) if Sections 6(b), 7(c)(i), (ii), or (iii) apply, the date on which Performance Shares are delivered to Holder which shall be no later than the dates set forth in Section 6(b) or 7(c)(i), (ii) or (iii), as applicable or (ii) if Sections 6(b) or 7(c)(i), (ii) or (iii) do not apply, the date on which Earned Performance Shares are delivered to Holder, which shall be no later than 30 days following March 31, 2017 (i.e., the Vesting Date).
(g)“Disability” means, without limitation, the same as it does in the Plan.
(h)“Earned Performance Shares” means the number of Performance Shares which are earned during the Performance Period as described and calculated in Section 6.
(i) “Maximum Performance Shares” means the maximum number of Performance Shares, as set forth in Section 1, which may be earned under this Award if there are no reductions in the number of Performance Shares under Section 5.
(j)“Non-Upstream-Focused Companies” means the Peer Companies so designated in Appendix A.
(k)“Peer Company” means each of the companies listed on Appendix A hereto, as adjusted pursuant to Appendix A.
(l)“Performance Criteria” means the EBITDAX Measure defined in Section 4 for the Performance Period.
(m)“Performance Percentage” means, that percentage determined based upon the relative ranking of the Company’s EBITDAX Measure for the Performance Period compared to the EBITDAX Measure of each Peer Company for the Performance Period as determined under the provisions of Section 4(e), subject to reduction under Sections 5 and 12, if any.
(n)“Performance Period” means the period beginning on January 1, 2016, and ending on December 31, 2016.
(o) “Performance Period Pretax Operating Income” means, (a) for Upstream-Focused Companies, pre-tax income, as reported on the consolidated Income Statement in each Peer Company’s and the Company’s Form 10-K for the Performance Period, adjusted to exclude the following items, as applicable: (i) interest income and expense; (ii) exploration expense; (iii) depletion, depreciation, amortization and accretion expense; (iv) commodity derivative gains and losses; (v) impairment charges; (vi) gains and losses incurred on the extinguishment of debt; and (vii) gains and losses incurred on the purchase or sale of assets, and (b) for Non-Upstream-Focused Companies, pre-tax income, as reported by the Peer Company or the Company in accordance with FASC 932-235-50 (previously FAS 69), adjusted to exclude the following items, as applicable: (i) interest income and expense; (ii) exploration expense; (iii) depletion, depreciation, amortization and accretion expense; (iv) commodity derivative gains and losses; (v) impairment charges; (vi) gains and losses incurred on the extinguishment of debt; (vii) gains and losses incurred on the purchase or sale of assets, and (viii) general and administrative expenses related to continuing operations. Performance Period Pretax Operating Income for Non-Upstream-Focused Companies will also be reduced by such company’s Calculated Estimate of General and Administrative Expense. Performance Period Pretax Operating Income will include all operations of each such company, other than those related to an equity-method investment, including operations that qualify as discontinued operations under generally accepted accounting principles in the United States of America.
(p)“Performance Period Pretax Operating Income per BOE” means for each Peer Company and for the Company, its Performance Period Pretax Operating Income divided by its Actual Reported Production.
(q)“Post Separation Change of Control” means a Change of Control that closes following Holder’s Separation, but where such Separation resulted from the Commencement of the Change of Control prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change of Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change of Control involving such person, group, or their affiliates.
(r) “Upstream-Focused Companies” means the Company and those companies so designated in Appendix A.
(s) “Vesting Date” means March 31, 2017 or the effective date of any earlier (i) Change of Control pursuant to Section 6(b) or (ii) death, Disability or Post Separation Change of Control pursuant to Sections 7(c)(i), (ii) or (iii), as appropriate.
3.Performance Shares as Contractual Right. Each Performance Share represents a contractual right to receive one share of Common Stock of the Company, subject to the terms and conditions of this Award; provided that, based on the EBITDAX Measure as detailed below, the number of Performance Shares that become Earned Performance Shares may range from 0% to 100% of the number of Maximum Performance Shares, and Holder’s right to receive Common Stock of the Company in respect of Performance Shares is generally contingent.
4.Performance Percentage Earned With Respect to EBITDAX Measure.
(a)The “EBITDAX Measure” means, for the Company and each Peer Company: Performance Period Pretax Operating Income per BOE.
(b)The EBITDAX Measure of the Company and each Peer Company is to be calculated as soon as practical after the end of the Performance Period. Once calculated for the Company and for each Peer Company, the exact EBITDAX Measure for each such company shall be listed in Column 3 of the table below in descending order of their respective EBITDAX Measure from the highest percentage to the lowest percentage.
(c)Column 2 of the table below shall reflect each such company’s name.
(d)The percentages in Column 4 of the table below are based upon increments derived by dividing 100% by 13 (the number of Peer Companies), which percentage increments will be adjusted, if necessary, on a pro rata basis to reflect a reduction in the number of Peer Companies (for example, if at the end of the Performance Period there were 12 Peer Companies, then the 7.7% increment currently shown in Column 4 would become 8.3%).
(e)The Company’s earned Performance Percentage will be that percentage shown in Column 5 (subject to adjustment, if any, provided in Sections 5 or 12) opposite the ranking of the Company in Column 1 (for example, in the following table for 14 Companies, being ranked as eighth would equal a Performance Percentage of 92%). The earned Performance Percentage will be adjusted to reflect adjustments made to the percentages in Column 4, if any, pursuant to Section 4(d) above; provided however, that the earned Performance Percentage may not be greater than 100%.
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| | | | |
Column 1 | Column 2 | Column 3 | Column 4 | Column 5 |
Ranking | Company Name | Actual EBITDAX Measure | Scale of EBITDAX Measure for 14 Companies (expressed as a %) | Performance Percentage Scale (subject to interpolation) |
1 | | | 100% | 100% |
2 | | | 92.3% | 100% |
3 | | | 84.6% | 100% |
4 | | | 76.9% | 100% |
5 | | | 69.2% | 100% |
6 | | | 61.5% | 100% |
7 | | | 53.8% | 100% |
8 | | | 46.2% | 92% |
9 | | | 38.5% | 77% |
10 | | | 30.8% | 62% |
11 | | | 23.1% | 46% |
12 | | | 15.4% | 31% |
13 | | | 7.7% | 15% |
14 | | | 0% | 0% |
5.Committee’s Reduction of Performance Percentage. Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by Committee resolution prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation. Any reduction of Holder’s Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period. The Committee does not have discretion to increase a Holder’s Performance Percentage.
6.Earned Performance Shares.
(a)Earned Performance Shares. The number of Earned Performance Shares shall be equal to the product of (i) the Maximum Performance Shares multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. No fractional shares will be issued to the Holder. The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period), and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change of Control provisions of Section 6(b) below.
(b)Change of Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change of Control of the Company occurs during the Performance Period then, regardless of the EBITDAX Percentage at the date of the Change of Control of the Company, Holder will be entitled to receive delivery of a number of Performance Shares equal to the Maximum Performance Shares (notwithstanding any provision hereof to the contrary, none of which Maximum Performance Shares will be retained by the Company other than as payment for withholding) as soon as reasonably possible following such Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Shares under this Award.
7.Vesting (and Forfeiture) of Earned Performance Shares.
(a)No Separation Prior to the Vesting Date. If Holder does not experience a Separation prior to the Vesting Date, Holder will be 100% vested in the Earned Performance Shares.
(b)Retirement Vesting Date. In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, then irrespective of whether or not Holder experiences a Separation prior to the Vesting Date, Holder will be entitled to receive Performance Shares in an amount equal to the number of Earned Performance Shares on the Vesting Date (which Performance Shares will be delivered to Holder on the Delivery Date), without any right to receive any additional Performance Shares pursuant to this Award, and without any proration of the number of Performance Shares earned in such circumstances. Notwithstanding the foregoing, in the event Holder experiences a Separation after Holder’s Retirement Vesting Date, but within 12 months of the Date of Grant, all rights to receive Performance Shares under this Award will be forfeited.
(c)Forfeiture. Except to the extent expressly provided in Sections 7(b) and 7(c) (i), (ii) or (iii), Holder permanently will forfeit all rights with respect to all Performance Shares upon the date of his Separation, if such Separation occurs prior to the Vesting Date.
(i) Death. If Holder experiences a Separation by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death. If Holder experiences a Separation by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the number of Earned Performance Shares based on the calculation in Section 6 herein (and does not have any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death.
(ii) Disability. If Holder experiences a Separation by reason of Disability prior to the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, are entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the Calendar Year in which the Holder experiences a Separation by reason of Disability. If Holder experiences a Separation by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period,
Holder or Holder’s Beneficiary, as applicable, will be entitled to receive the number of Earned Performance Shares based on the calculation in Section 6 herein (without any right to receive any other Performance Shares pursuant to this Award) as soon as reasonably possible, but in no event later than 60 days following the Vesting Date.
(iii) Post Separation Change of Control. If there is a Post Separation Change of Control, Holder will be entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without any right to receive any additional Performance Shares pursuant to this Award) as soon as reasonably possible after the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs.
8.Withholding. On or before the Delivery Date, the Company may require Holder (or Holder’s Beneficiary) to pay to the Company an amount the Company deems necessary to satisfy its (or an Affiliate’s) obligation to withhold federal, state, local, and foreign income or other taxes that Holder incurs as a result of the settlement of the Award. Such tax obligations may be paid by Holder (or Holder’s Beneficiary) to the Company (a) in cash, (b) by delivery of previously owned shares of Common Stock, (c) through net settlement of the Award, or (d) through any other method permitted under the Plan and approved by the Committee. If the tax obligations are satisfied through the withholding of shares of Common Stock through net settlement, the number of shares of Common Stock that may be withheld shall be limited to the number of shares of Common Stock that have an aggregate Fair Market Value on the Delivery Date equal to the aggregate amount of the tax liabilities determined based on the applicable minimum statutory withholding rates for federal, state, local, and foreign tax purposes, including payroll taxes, or such other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company or Holder.
9.Issuance of Common Stock. Without limitation, Holder shall not have any of the rights and privileges of an owner of the Company’s Common Stock (including voting rights and dividend rights), until the Vesting Date. The Company shall deliver the Earned Performance Shares in the form described in Section 1 above (reduced by the number of shares of Common Stock delivered to the Company to pay required withholding under Section 8 above) to Holder as soon as reasonably possible following vesting. The Holder agrees that the delivery of Common Stock is subject to the Company’s stock ownership guidelines, as potentially modified from time to time.
10.Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which the Performance Criteria has been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s or a Peer Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award, and, to the extent the Award is intended to qualify as “performance based” under Section 162(m) of the Internal Revenue Code, does not affect such qualification. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties. The Committee, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to an administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.
11.Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Committee a written designation of beneficiary (such person(s) being the Holder’s “Beneficiary”), on such form as may be prescribed by the Committee. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.
12.Adjustments in this Award. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company, appropriate adjustments may be made to this Award in a manner deemed equitable by the Committee.
13.Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee shall make all relevant annually determined calculations and determinations hereunder, and will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information
is available.
14.No Transfers Permitted. The rights under this Award are not transferable by the Holder other than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Earned Performance Shares.
15.No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder’s right to terminate employment, or the Company’s right to terminate Holder’s employment, at any time.
16.Governing Law. Without limitation, this Award shall be construed and enforced in accordance with, and be governed by, the laws of Delaware.
17.Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, permitted successors and assigns of the parties hereto.
18.Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.
19.Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.
20.Clawback. The Performance Shares are subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject the Performance Shares and amounts paid or realized with respect to the Performance Shares to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Performance Shares.
21.Compliance with Securities Laws. Notwithstanding any provision of this Award to the contrary, the issuance of Stock will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Stock may then be listed. No Stock will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other laws or regulations or the requirements of any stock exchange or market system upon which the Stock may then be listed. In addition, Stock will not be issued hereunder unless (a) a registration statement under the Securities Act is at the time of issuance in effect with respect to the shares issued or (b) in the opinion of legal counsel of the Company, the shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. THE HOLDER IS CAUTIONED THAT ISSUANCE OF COMPANY COMMON STOCK UPON THE VESTING OF PERFORMANCE SHARES GRANTED PURSUANT TO THIS AWARD MAY NOT OCCUR UNLESS THE FOREGOING CONDITIONS ARE SATISFIED. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any shares of Stock subject to the Award will relieve the Company of any liability in respect of the failure to issue such shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate persons to make shares of Stock available for issuance.
22.Section 409A of the Code. It is the intention of the Committee that this Award is exempt from the Nonqualified Deferred Compensation Rules as a short-term deferral (within the meaning of such rules), and, as such, that this Award will be operated and construed accordingly. Neither this Section 22 nor any other provision of this Award or the Plan is or contains a representation to the Holder regarding the tax consequences of the grant, vesting, settlement, or sale of this Award (or the Stock underlying this Award), and should not be interpreted as such.
[Signature page to follow]
IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representatives on the Date of Grant.
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| | | |
| DENBURY RESOURCES INC. | | |
| | | |
| | | |
By: | | | |
| Phil Rykhoek Chief Executive Officer | | Mark C. Allen Senior Vice President and Chief Financial Officer |
ACKNOWLEDGMENT
The undersigned hereby acknowledges (i) receipt of this Award, (ii) the opportunity to review the Plan, (iii) the opportunity to discuss this Award with a representative of the Company, and the undersigned’s personal advisors, to the extent the undersigned deems necessary or appropriate, (iv) the understanding of the terms and provisions of the Award and the Plan, and (v) the understanding that, by the undersigned’s signature below, the undersigned is agreeing to be bound by all of the terms and provisions of this Award and the Plan.
Without limitation, the undersigned agrees to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee regarding any questions arising under the Plan, or this Award, or both.
Effective as of the Date of Grant.
Exhibit 10(d)
_________ Maximum Performance Cash Date of Grant: March 30, 2016
2016 EBITDAX PERFORMANCE AWARD
(CASH PORTION)
2004 OMNIBUS STOCK AND INCENTIVE PLAN
DENBURY RESOURCES INC.
This EBITDAX PERFORMANCE AWARD (this “Award”) is made effective on the Date of Grant by Denbury Resources Inc. (the “Company”) in favor of __________ (“Holder”).
WHEREAS, in accordance with the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc., as amended and/or restated (the “Plan”), the Committee may grant performance-based Awards;
WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn Performance Cash (as defined below) based on the Performance Criteria set forth in the Plan and this Award, and subject to all of the provisions, including without limitation the vesting provisions, of the Plan and of this Award;
WHEREAS, no Performance Cash will be paid until the Vesting Date; and
WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.
NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:
1.Performance Cash Grant. The Company hereby grants Holder the right to earn and vest in up to a maximum of $_____________ (the “Performance Cash”). On the Delivery Date, the Performance Cash entitles the Holder to receive a lump sum payment of cash equal to the amount of Earned Performance Cash up to and including the amount of Maximum Performance Cash.
2.Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:
(a)“Actual Reported Production” means production of oil, condensate, natural gas liquids (“NGLs”), natural gas, synthetic oil, and synthetic gas expressed on a BOE basis, as reported in each Peer Company’s and the Company’s Form 10-K for the Performance Period, excluding production generated from each such company’s equity-method investee(s), if any.
(b)“BOE” means Barrels of Oil Equivalent, and for all purposes hereof, will be calculated using the ratio of one barrel of crude oil, condensate or NGLs to six thousand cubic feet of natural gas.
(c)“Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company and each Peer Company.
(d)“Calculated Estimate of General and Administrative Expense” means for each Non-Upstream-Focused Company, individually, (i) the quotient (rounded to four decimals and expressed as a percentage) of (x) its oil and natural gas revenues from continuing operations derived from exploration and production activities (as disclosed in its Form 10-K for the Performance Period in accordance with Financial Accounting Standards Board Codification (“FASC”) 932-235-50 (“FAS 69”) in its Form 10-K for the Performance Period), divided by (y) its total revenues from continuing operations reported on its consolidated income statement in its Form 10-K for the Performance Period; multiplied by (ii) its total general and administrative expenses from continuing operations for the Performance Period as reported on its consolidated income statement in its Form 10-K.
(e)“Change of Control” means, without limitation, the same as it does in the Plan.
(f)“Delivery Date” means (i) if Sections 6(b), 7(c)(i) or (ii) apply, the date on which Performance Cash is paid to Holder which shall be no later than the dates set forth in Section 6(b) or 7(c)(i) or (ii), as applicable or (ii) if Sections 6(b) or 7(c)(i) or (ii) do not apply, the date on which Earned Performance Cash is paid to Holder, which shall be no later than 30 days following March 31, 2017 (i.e., the Vesting Date).
(g)“Disability” means, without limitation, the same as it does in the Plan.
(h)“Earned Performance Cash” means the amount of Performance Cash which is earned during the Performance Period as described and calculated in Section 6.
(i) “Maximum Performance Cash” means the maximum amount of Performance Cash, as set forth in Section 1, which may be earned under this Award if there are no reductions in the amount of Performance Cash under Section 5.
(j)“Non-Upstream-Focused Companies” means the Peer Companies so designated in Appendix A.
(k)“Peer Company” means each of the companies listed on Appendix A hereto, as adjusted pursuant to Appendix A.
(l)“Performance Criteria” means the EBITDAX Measure defined in Section 4 for the Performance Period.
(m)“Performance Percentage” means, that percentage determined based upon the relative ranking of the Company’s EBITDAX Measure for the Performance Period compared to the EBITDAX Measure of each Peer Company for the Performance Period as determined under the provisions of Section 4(e), subject to reduction under Sections 5 and 12, if any.
(n) “Performance Period” means the period beginning on January 1, 2016, and ending on December 31, 2016.
(o) “Performance Period Pretax Operating Income” means, (a) for Upstream-Focused Companies, pre-tax income, as reported on the consolidated Income Statement in each Peer Company’s and the Company’s Form 10-K for the Performance Period, adjusted to exclude the following items, as applicable: (i) interest income and expense; (ii) exploration expense; (iii) depletion, depreciation, amortization and accretion expense; (iv) commodity derivative gains and losses; (v) impairment charges; (vi) gains and losses incurred on the extinguishment of debt; and (vii) gains and losses incurred on the purchase or sale of assets, and (b) for Non-Upstream-Focused Companies, pre-tax income, as reported by the Peer Company or the Company in accordance with FASC 932-235-50 (previously FAS 69), adjusted to exclude the following items, as applicable: (i) interest income and expense; (ii) exploration expense; (iii) depletion, depreciation, amortization and accretion expense; (iv) commodity derivative gains and losses; (v) impairment charges; (vi) gains and losses incurred on the extinguishment of debt; (vii) gains and losses incurred on the purchase or sale of assets, and (viii) general and administrative expenses related to continuing operations. Performance Period Pretax Operating Income for Non-Upstream-Focused Companies will also be reduced by such company’s Calculated Estimate of General and Administrative Expense. Performance Period Pretax Operating Income will include all operations of each such company, other than those related to an equity-method investment, including operations that qualify as discontinued operations under generally accepted accounting principles in the United States of America.
(p)“Performance Period Pretax Operating Income per BOE” means for each Peer Company and for the Company, its Performance Period Pretax Operating Income divided by its Actual Reported Production.
(q)“Post Separation Change of Control” means a Change of Control that closes following Holder’s Separation, but where such Separation resulted from the Commencement of the Change of Control prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change of Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change of Control involving such person, group, or their affiliates.
(r)“Upstream-Focused Companies” means the Company and those companies so designated in Appendix A.
(s)“Vesting Date” means March 31, 2017 or the effective date of any earlier (i) Change of Control pursuant to Section 6(b) or (ii) death or Disability pursuant to Sections 7(c)(i) or (ii), as appropriate.
3.Performance Cash as Contractual Right. Performance Cash represents a contractual right to receive a specified amount of cash, subject to the terms and conditions of this Award; provided that, based on the EBITDAX Measure as detailed below, the amount of Performance Cash that become Earned Performance Cash may range from 0% to 100% of the amount of Maximum Performance Cash, and Holder’s right to receive an amount of Performance Cash is generally contingent.
4.Performance Percentage Earned With Respect to EBITDAX Measure.
(a)The “EBITDAX Measure” means, for the Company and each Peer Company: Performance Period Pretax Operating Income per BOE.
(b)The EBITDAX Measure of the Company and each Peer Company is to be calculated as soon as practical after the end of the Performance Period. Once calculated for the Company and for each Peer Company, the exact EBITDAX Measure for each such company shall be listed in Column 3 of the table below in descending order of their respective EBITDAX Measure from the highest percentage to the lowest percentage.
(c)Column 2 of the table below shall reflect each such company’s name.
(d)The percentages in Column 4 of the table below are based upon increments derived by dividing 100% by 13 (the number of Peer Companies), which percentage increments will be adjusted, if necessary, on a pro rata basis to reflect a reduction in the number of Peer Companies (for example, if at the end of the Performance Period there were 12 Peer Companies, then the 7.7% increment currently shown in Column 4 would become 8.3%).
(e)The Company’s earned Performance Percentage will be that percentage shown in Column 5 (subject to adjustment, if any, provided in Sections 5 or 12) opposite the ranking of the Company in Column 1 (for example, in the following table for 14 Companies, being ranked as seventh would equal a Performance Percentage of 8%). The earned Performance Percentage will be adjusted to reflect adjustments made to the percentages in Column 4, if any, pursuant to Section 4(d) above; provided however, that the earned Performance Percentage may not be greater than 100%.
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Column 1 | Column 2 | Column 3 | Column 4 | Column 5 |
Ranking | Company Name | Actual EBITDAX Measure | Scale of EBITDAX Measure for 14 Companies (expressed as a %) | Performance Percentage Scale (subject to interpolation) |
1 | | | 100.0% | 100% |
2 | | | 92.3% | 85% |
3 | | | 84.6% | 69% |
4 | | | 76.9% | 54% |
5 | | | 69.2% | 38% |
6 | | | 61.5% | 23% |
7 | | | 53.8% | 8% |
8 | | | 46.2% | 0% |
9 | | | 38.5% | 0% |
10 | | | 30.8% | 0% |
11 | | | 23.1% | 0% |
12 | | | 15.4% | 0% |
13 | | | 7.7% | 0% |
14 | | | 0% | 0% |
5.Committee’s Reduction of Performance Percentage. Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by Committee resolution prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation. Any reduction of Holder’s
Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period. The Committee does not have discretion to increase a Holder’s Performance Percentage.
6.Earned Performance Cash.
(a)Earned Performance Cash. The amount of Earned Performance Cash shall be equal to the product of (i) the Maximum Performance Cash multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period), and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change of Control provisions of Section 6(b) below.
(b)Change of Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change of Control of the Company occurs during the Performance Period then, regardless of the EBITDAX Percentage at the date of the Change of Control of the Company, Holder will be entitled to receive delivery of an amount of Performance Cash equal to the Maximum Performance Cash (notwithstanding any provision hereof to the contrary, none of which Maximum Performance Cash will be retained by the Company other than as payment for withholding) as soon as reasonably possible following such Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Cash under this Award.
7.Vesting (and Forfeiture) of Earned Performance Cash.
(a)No Separation Prior to the Vesting Date. If Holder does not experience a Separation prior to the Vesting Date, Holder will be 100% vested in the Earned Performance Cash.
(b)Retirement Vesting Date. In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, then irrespective of whether or not Holder experiences a Separation prior to the Vesting Date, Holder will be entitled to receive Performance Cash in an amount equal to the amount of Earned Performance Cash on the Vesting Date (which Performance Cash will be delivered to Holder on the Delivery Date), without any right to receive any additional Performance Cash pursuant to this Award, and without any proration of the amount of Performance Cash earned in such circumstances. Notwithstanding the foregoing, in the event Holder experiences a Separation after Holder’s Retirement Vesting Date but within 12 months of the Date of Grant, all rights to receive Performance Cash under this Award will be forfeited.
(c)Forfeiture. Except to the extent expressly provided in Sections 7(b) and 7(c) (i) or (ii), Holder permanently will forfeit all rights with respect to all Performance Cash upon the date of his Separation, if such Separation occurs prior to the Vesting Date.
(i) Death. If Holder experiences a Separation by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will not be entitled to receive any amount of Performance Cash pursuant to this Award. If Holder experiences a Separation by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the amount of Earned Performance Cash based on the calculation in Section 6 herein (and does not have any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death.
(ii) Disability. If Holder experiences a Separation by reason of Disability prior to the last day of the Performance Period, neither Holder nor Holder’s Beneficiary, as applicable, are entitled to receive any amount of Performance Cash pursuant to this Award. If Holder experiences a Separation by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive the amount of Earned Performance Cash based on the calculation in Section 6 herein (without any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event later than 60 days following the Vesting Date.
(iii) Post Separation Change of Control. If there is a Post Separation Change of Control, Holder will not be entitled to receive any amount of Performance Cash pursuant to this Award.
8.Withholding. The Company will reduce the amount payable, if any, pursuant to this Award by all applicable withholding, including federal, state, local and foreign tax withholding as well as any other deductions applicable to payments pursuant to this Award.
9.[Intentionally Left Blank]
10.Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which the Performance Criteria has been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s or a Peer Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award, and, to the extent the Award is intended to qualify as “performance based” under Section 162(m) of the Internal Revenue Code, does not affect such qualification. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties. The Committee, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to an administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.
11.Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Committee a written designation of beneficiary (such person(s) being the Holder’s “Beneficiary”), on such form as may be prescribed by the Committee. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.
12.Adjustments in this Award. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company, appropriate adjustments may be made to this Award in a manner deemed equitable by the Committee.
13.Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee shall make all relevant annually determined calculations and determinations hereunder, and will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.
14.No Transfers Permitted. The rights under this Award are not transferable by the Holder other than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Earned Performance Cash.
15.No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder’s right to terminate employment, or the Company’s right to terminate Holder’s employment, at any time.
16.Governing Law. Without limitation, this Award shall be construed and enforced in accordance with, and be governed by, the laws of Delaware.
17.Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, permitted successors and assigns of the parties hereto.
18.Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.
19.Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.
20.Clawback. The Performance Cash are subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject the Performance Cash and amounts paid or realized with respect to the Performance Cash to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Performance Cash.
21.Section 409A of the Code. It is the intention of the Committee that this Award is exempt from the Nonqualified Deferred Compensation Rules as a short-term deferral (within the meaning of such rules), and, as such, that this Award will be operated and construed accordingly. Neither this Section 21 nor any other provision of this Award or the Plan is or contains a representation to the Holder regarding the tax consequences of the grant, vesting, or settlement of this Award and should not be interpreted as such.
[Signature page to follow]
IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representatives on the Date of Grant.
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| DENBURY RESOURCES INC. | | |
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By: | | | |
| Phil Rykhoek Chief Executive Officer | | Mark C. Allen Senior Vice President and Chief Financial Officer |
ACKNOWLEDGMENT
The undersigned hereby acknowledges (i) receipt of this Award, (ii) the opportunity to review the Plan, (iii) the opportunity to discuss this Award with a representative of the Company, and the undersigned’s personal advisors, to the extent the undersigned deems necessary or appropriate, (iv) the understanding of the terms and provisions of the Award and the Plan, and (v) the understanding that, by the undersigned’s signature below, the undersigned is agreeing to be bound by all of the terms and provisions of this Award and the Plan.
Without limitation, the undersigned agrees to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee regarding any questions arising under the Plan, or this Award, or both.
Effective as of the Date of Grant.
Exhibit 10(e)
$__________Maximum Performance Cash Date of Grant: January 4, 2016
2016 OIL PRICE CHANGE
VS.
TSR PERFORMANCE AWARD
DENBURY RESOURCES INC.
This OIL PRICE CHANGE vs. TSR PERFORMANCE AWARD (this “Award”) is made effective on the Date of Grant by Denbury Resources Inc. (the “Company”) in favor of ______________ (“Holder”). Defined terms used herein which are capitalized but not defined in this Award shall have the meaning assigned to them under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc., as amended and/or restated (the “Plan”).
WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn Performance Cash (as defined below) based on the Performance Criteria set forth in this Award and subject to all of the provisions of this Award;
WHEREAS, no Performance Cash will be paid until the Vesting Date;
WHEREAS, the Performance Cash is to be issued under this Award as a standalone award agreement and not pursuant to any of the Company’s equity compensation plans; and
WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms and provisions set forth herein.
NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:
1. Performance Cash Grant. The Company hereby grants Holder the right to earn and vest in up to a maximum of $________ (the “Performance Cash”). On the Delivery Date, the Performance Cash entitles the Holder to receive a lump sum payment of cash equal to the amount of Earned Performance Cash up to and including the amount of Maximum Performance Cash.
2. Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:
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(a) | “Annual TSR” means for the Company, the result, expressed as a percentage, of the calculation of TSR set out in Section 4(a) hereof as to a Calendar Year within the Performance Period. |
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(b) | “Annual Oil Price” means, the result, expressed as a percentage, of the calculation set out in Section 4(b) hereof as to a Calendar Year within the Performance Period. |
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(c) | “Beginning Common Stock Price” means the average of the Closing Price of the primary common equity security for the Company for each of the 10 trading days immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured. |
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(d) | “Beginning Crude Oil WTI (NYMEX)” equals the forward looking average closing trading price of the next 12 months of Crude Oil WTI (NYMEX) strip prices immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured. |
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(e) | “Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company. |
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(f) | “Change of Control” or “CIC” means, without limitation, the same as it does in the Plan. |
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(g) | “Closing Price” means the last reported sales price of the primary common equity security of the Company, as reported by the national exchange upon which such security is traded; provided, however, in the event the primary common equity |
security of the Company is not traded on a national exchange at the time of such determination, “Closing Price” will be the price determined by the Committee in good faith based upon a review of the facts and circumstances available to the Committee.
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(h) | “Delivery Date” means (i) if Sections 6(b), 7(c)(i), (ii), or (iii) apply, the date on which Performance Cash is paid to Holder which shall be no later than the dates set forth in Section 6(b) or 7(c)(i), (ii) or (iii), as applicable or (ii) if Sections 6(b) or 7(c)(i), (ii) or (iii) do not apply, the date on which Earned Performance Cash is paid to Holder, which shall be no later than 30 days following March 31, 2019 (i.e., the Vesting Date). |
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(i) | “Disability” means, without limitation, the same as it does in the Plan. |
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(j) | “Earned Performance Cash” means the amount of Performance Cash which is earned during the Performance Period as described and calculated in Section 6. |
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(k) | “Ending Common Stock Price” equals the average of the Closing Price of the primary common equity security for the Company for each of the 10 trading days ending on and including the last day of each Calendar Year, taken separately, within the Performance Period. |
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(l) | “Ending Crude Oil WTI (NYMEX)” equals the forward looking average closing trading price of the next 12 months of Crude Oil WTI (NYMEX) strip prices for each of the last 10 trading days ending on and including the last day of each Calendar Year, taken separately, within the Performance Period. |
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(m) | “Maximum Performance Cash” means the maximum amount of Performance Cash, as set forth in Section 1, which may be earned under this Award if there are no reductions in the amount of Performance Cash under Section 5. |
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(n) | “Performance Period” means the three-year period beginning on the first day of the Calendar Year of the Date of Grant and ending on December 31 of the Calendar Year three years thereafter, provided that in the event of a Change of Control, the Performance Period will end on the date that such Change of Control takes effect. |
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(o) | “Performance Percentage” means that percentage determined based upon the TSR Relative to Oil Price Change as determined under the provisions of Section 4(d), subject to reduction under Sections 5 and 12, if any. |
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(p) | “Post Separation Change of Control” means a Change of Control that closes following Holder’s Separation, but where such Separation resulted from the Commencement of the Change of Control prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change of Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change of Control involving such person, group, or their affiliates. |
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(q) | “Target Performance Cash” means one-half of the Maximum Performance Cash which may be earned under this Award if there are no reductions in the amount of Performance Cash under Section 5. |
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(r) | “Three-Year Average Oil Price” means, the result, expressed as a percentage, of averaging the Annual Oil Price for each of the Calendar Years in the Performance Period. |
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(s) | “Three-Year Average TSR” means for the Company, the result, expressed as a percentage, of averaging the Annual TSR for each of the Calendar Years in the Performance Period. |
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(t) | “Total Shareholder Return” or “TSR” shall mean that percentage which reflects the increase or decrease in the average closing trading price of the Company’s primary common equity security (assuming reinvestment of any dividends) between the last 10 trading days of one Calendar Year and the last 10 trading days of the next Calendar Year, or as applicable, the average of such yearly increases or decreases. |
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(u) | “TSR Relative to Oil Price Change” means, the result, expressed as a percentage, of the calculation set out in Section 4(c) hereof. |
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(v) | “Value of Reinvested Dividends” means a dollar amount derived by (i) calculating an aggregate number of shares (or fractions thereof) of the Company represented by the sum of each dividend paid on the primary common equity security during a Calendar Year (or portion thereof under Section 4(a)(ii) below) within the Performance Period, determined by dividing the per share amount or value paid through each such dividend by the Closing Price of the primary common equity security on each such dividend payment date, and (ii) then multiplying that aggregate number of shares by the Ending Common Stock Price, respectively, for that Calendar Year (or portion thereof in the event of a Change of Control). |
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(w) | “Vesting Date” means March 31, 2019 or the effective date of any earlier (i) Change of Control pursuant to Section 6(b) or (ii) death, Disability or Post Separation Change of Control pursuant to Sections 7(c)(i), (ii) or (iii), as appropriate. |
3. Performance Cash as Contractual Right. Performance Cash represents a contractual right to receive a specified amount of cash, subject to the terms and conditions of this Award; provided that, based on TSR Relative to Oil Price Change as detailed below, the amount of Performance Cash that become Earned Performance Cash may range from 0% to 200% of the amount of Target Performance Cash, and Holder’s right to receive an amount of Performance Cash is generally contingent.
4. Performance Percentage Earned With Respect to Oil Price vs. TSR Change. TSR Relative to Oil Price Change shall be calculated for the periods specified below as follows:
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(a) | Annual TSR shall be calculated for the periods specified below as follows: |
(i) Annual TSR for the Company for each Calendar Year within the Performance Period shall equal the result of the following calculation:
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Ending Common Stock Price + Value of Reinvested Dividends | - 1 |
Beginning Common Stock Price |
(ii) For any Calendar Year in which a Change of Control of the Company occurs, Annual TSR for the Company for that Calendar Year shall equal the result of the following calculation:
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(b) | Annual Oil Price shall be calculated for the periods specified below as follows: |
(i) Annual Oil Price for each Calendar Year within the Performance Period shall equal the result of the following calculation:
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Ending Crude Oil WTI (NYMEX) | - 1 |
Beginning Crude Oil WTI (NYMEX) |
(ii) For any Calendar Year in which a Change of Control of the Company occurs, Annual Oil Price for that Calendar Year shall equal the result of the following calculation:
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(c) | TSR Relative to Oil Price Change shall mean the difference (expressed as a percent) between Three-Year Average TSR and the Three-Year Average Oil Price. |
(Three-Year Average TSR - Three-Year Average Oil Price) = TSR Relative to Oil Price Change
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(d) | TSR Relative to Oil Price Change is to be calculated as soon as practical after the end of the Performance Period. The Company’s Performance Percentage will be that percentage shown in Column 2 opposite the TSR Relative to Oil Price Change percentage shown in Column 1. |
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Column 1 | Column 2 |
TSR Relative to Oil Price Change | Performance Percentage Scale |
> 50% | 200% |
≤ 50% and > 45% | 190% |
≤ 45% and > 40% | 180% |
≤ 40% and > 35% | 170% |
≤ 35% and > 30% | 160% |
≤ 30% and > 25% | 150% |
≤ 25% and > 20% | 140% |
≤ 20% and > 15% | 130% |
≤ 15% and > 10% | 120% |
≤ 10% and > 5% | 110% |
≤ 5% and > -5% | 100% |
≤ -5% and > -10% | 90% |
≤ -10% and > -15% | 80% |
≤ -15% and > -20% | 70% |
≤ -20% and > -25% | 60% |
≤ -25% and > -30% | 50% |
≤ -30% and > -35% | 40% |
≤ -35% and > -40% | 30% |
≤ -40% and > -45% | 20% |
≤ -45% and > -50% | 10% |
≤ -50 | 0% |
5. Committee’s Reduction of Performance Percentage. Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by Committee resolution prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation. Any reduction of Holder’s Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period. The Committee does not have discretion to increase a Holder’s Performance Percentage.
6. Earned Performance Cash.
(a) Earned Performance Cash. The amount of Earned Performance Cash shall be equal to the product of (i) the Target Performance Cash multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period),
and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change of Control provisions of Section 6(b) below.
(b) Change of Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change of Control of the Company occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change of Control of the Company, the Performance Period will end on the date of the Change of Control and the TSR and Oil Price Change performance for the partial year will be annualized as set out in Section 4(a)(ii) and Section 4(b)(ii) above and averaged with the Annual TSR and Annual Oil Price, as appropriate, calculated for any prior completed Calendar Year to determine Earned Performance Cash, which Holder will be entitled to receive on the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Cash under this Award.
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7. | Vesting (and Forfeiture) of Earned Performance Cash. |
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(a) | No Separation Prior to the Vesting Date. If Holder does not experience a Separation prior to the Vesting Date, Holder will be 100% vested in the Earned Performance Cash. |
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(b) | Retirement Vesting Date. In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, then irrespective of whether or not Holder experiences a Separation prior to the Vesting Date, Holder will be entitled to receive Performance Cash in an amount equal to the amount of Earned Performance Cash on the Vesting Date (which Performance Cash will be delivered to Holder on the Delivery Date), without any right to receive any additional Performance Cash pursuant to this Award, and without any proration of the amount of Performance Cash earned in such circumstances. Notwithstanding the foregoing, in the event Holder experiences a Separation after Holder’s Retirement Vesting Date but within 12 months of the Date of Grant, all rights to receive Performance Cash under this Award will be forfeited. |
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(c) | Forfeiture. Except to the extent expressly provided in Sections 7(b) and 7(c) (i), (ii) or (iii), Holder permanently will forfeit all rights with respect to all Performance Cash upon the date of his Separation, if such Separation occurs prior to the Vesting Date. |
(i) Death. If Holder experiences a Separation by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive Performance Cash in an amount equal to the amount of Target Performance Cash (without any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death. If Holder experiences a Separation by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the amount of Earned Performance Cash based on the calculation in Section 6 herein (and does not have any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event more than 60 days after Holder’s death.
(ii) Disability. If Holder experiences a Separation by reason of Disability prior to the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive Performance Cash in an amount equal to the amount of Target Performance Cash (without any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the Calendar Year in which the Holder experiences a Separation by reason of Disability. If Holder experiences a Separation by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive the amount of Earned Performance Cash based on the calculation in Section 6 herein (without any right to receive any other Performance Cash pursuant to this Award) as soon as reasonably possible, but in no event later than 60 days following the Vesting Date.
(iii) Post Separation Change of Control. If there is a Post Separation Change of Control, Holder will be entitled to receive Performance Cash in an amount equal to the amount of Target Performance Cash (without any right to receive any additional Performance Cash) as soon as reasonably possible after the date of the Change of Control, but in no event later than the 15th day of the third month after the end of the Calendar Year in which such Change of Control occurs.
8. Withholding. The Company will reduce the amount payable, if any, pursuant to this Award by all applicable withholding, including federal, state, local and foreign tax withholding as well as any other deductions applicable to payments pursuant to this Award.
9. [Intentionally Left Blank]
10. Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which the Performance Criteria has been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award, and, to the extent the Award is intended to qualify as “performance based” under Section 162(m) of the Internal Revenue Code, does not affect such qualification. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties. The Committee, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to an administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.
11. Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Committee a written designation of beneficiary (such person(s) being the Holder’s “Beneficiary”), on such form as may be prescribed by the Committee. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.
12. Adjustments in this Award. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company, appropriate adjustments may be made to this Award in a manner deemed equitable by the Committee.
13. Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee shall make all relevant annually determined calculations and determinations hereunder and will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.
14. No Transfers Permitted. The rights under this Award are not transferable by the Holder other than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Earned Performance Cash.
15. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder’s right to terminate employment, or the Company’s right to terminate Holder’s employment, at any time.
16. Governing Law. Without limitation, this Award shall be construed and enforced in accordance with, and be governed by, the laws of Delaware.
17. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, permitted successors and assigns of the parties hereto.
18. Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.
19. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.
20. Clawback. The Performance Cash are subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject the Performance Cash and amounts paid or realized with respect to the Performance Cash to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur,
including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Performance Cash.
21. Section 409A of the Code. It is the intention of the Committee that this Award is exempt from the Nonqualified Deferred Compensation Rules as a short-term deferral (within the meaning of such rules), and, as such, that this Award will be operated and construed accordingly. Neither this Section 21 nor any other provision of this Award or the Plan is or contains a representation to the Holder regarding the tax consequences of the grant, vesting, or settlement of this Award and should not be interpreted as such.
[Signature page to follow]
IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representatives on the Date of Grant.
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| DENBURY RESOURCES INC. | | |
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By: | | | |
| Phil Rykhoek Chief Executive Officer | | Mark C. Allen Senior Vice President and Chief Financial Officer |
ACKNOWLEDGMENT
The undersigned hereby acknowledges (i) receipt of this Award, (ii) the opportunity to review the Plan, (iii) the opportunity to discuss this Award with a representative of the Company, and the undersigned’s personal advisors, to the extent the undersigned deems necessary or appropriate, (iv) the understanding of the terms and provisions of the Award and the Plan, and (v) the understanding that, by the undersigned’s signature below, the undersigned is agreeing to be bound by all of the terms and provisions of this Award and the Plan.
Without limitation, the undersigned agrees to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee regarding any questions arising under the Plan, or this Award, or both.
Effective as of the Date of Grant.
Exhibit 10(f)
DENBURY RESOURCES
SEVERANCE PROTECTION PLAN
(As amended and restated effective as of March 31, 2016)
ARTICLE I
ESTABLISHMENT OF PLAN
As of the Effective Date, Denbury Resources Inc. (the “Company”) hereby amends and restates the severance plan known as the Denbury Resources Severance Protection Plan, which plan was originally adopted effective December 6, 2000, subsequently amended effective December 5, 2007, December 30, 2008, and December 31, 2010, amended and restated effective December 15, 2011, December 13, 2012 and May 6, 2015, and hereby further amended and restated effective March 31, 2016, and which as set forth in this document is hereinafter referred to as the “Plan.” For purposes of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), the Company intends the Plan to continue to be a “Severance Plan” within the meaning of the applicable ERISA regulations.
ARTICLE II
DEFINITIONS
As used herein, the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.
Section 2.1Administrator. The Board or any committee thereof as may be appointed from time to time by the Board to supervise the administration of the Plan.
Section 2.2Affiliate. With respect to a specified person, a person that directly or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with the specified person.
Section 2.3Base Salary. The amount a Participant is entitled to receive as wages or salary on an annualized basis, calculated on the basis of their salary rate on either the date immediately prior to a Change of Control or their Termination Date, whichever amount is higher.
Section 2.4Board. The Board of Directors of the Company.
Section 2.5Bonus Amount. An amount equal to fifty percent (50%) of the total amount of all Bonuses paid to a Participant during the twenty four (24) month period immediately preceding the date of the Change of Control; provided, however, if a Participant was not an Employee on January 1st of the calendar year which is two years prior to the year in which the Change of Control occurs, then the Bonus Amount for such Participant shall equal the greater of (i) fifty percent (50%) of the total amount of all Bonuses paid to such Participant during the twenty four (24) month period immediately preceding the date of the Change of Control, and (ii) the total amount of all Bonuses paid to such Participant during the twelve (12) month period immediately preceding the date of the Change of Control. For the purposes of this Section 2.5, “Bonuses” shall mean any and all cash bonuses paid to a Participant including, without limitation, discretionary cash bonuses (whether based on company performance or individual performance) and Christmas cash bonuses, but “Bonuses” shall specifically exclude any new-hire or sign-on cash bonuses paid to a Participant and any “spot” bonuses paid to a Participant such as Drops of Excellence or similar awards.
Section 2.6Cause. An Employer shall have “Cause” to terminate a Participant if the Participant (i) willfully and continually fails to substantially perform his duties with the Employer (other than a failure resulting from the Participant's incapacity due to physical or mental illness), or (ii) willfully engages in conduct which is demonstrably and materially injurious to the Employer, monetarily or otherwise. No act, nor failure to act, on the Participant's part, shall be considered “willful” unless he has acted or failed to act with an absence of good faith and without a reasonable belief that his action or failure to act was in the best interest of the Employer. Notwithstanding anything contained in this Plan to the contrary, no failure to perform by the Participant after Notice of Termination is given by or to the Participant shall constitute Cause.
Section 2.7Change of Control. A “Change of Control” shall mean the occurrence of any one of the following with respect to the Company:
(a)“Continuing Directors” no longer constitute a majority of the Board; the term (i) “Director” shall mean a member of the Board, and (ii) “Continuing Director” shall mean any individual who has served as a Director
for one year or more, together with any new Directors whose election by the Board or whose nomination for election by the shareholders of the Company was approved by a vote of a majority of the Directors then still in office who were either Directors at the beginning of such one-year period or whose election or nomination for election was previously so approved;
(b)any person or combination of persons acting as a group (as defined in Rule 13d-3 under the Securities Exchange Act of 1934 (as amended from time to time, including rules thereunder and successor provisions and rules thereto, the “Exchange Act”)) become the beneficial owners (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of Common Shares representing thirty percent (30%) or more of the voting power of the Company’s then outstanding securities entitled generally to vote for the election of Directors;
(c)a merger or consolidation to which the Company is a party, regardless of the surviving entity in such transaction, if (i) the shareholders of the Company immediately prior to the effective date of such merger or consolidation have beneficial ownership (as defined in Rule 13d-3 under the Exchange Act) of less than fifty percent (50%) of the combined voting power to vote for the election of directors of the surviving corporation, or other entity following the effective date of such merger or consolidation, or (ii) following such merger or consolidation, fifty percent (50%) or more of the individuals who (on the date immediately prior to the date of execution of the agreement providing for such merger or consolidation) constitute the members of Senior Management do not, as of a date six months after such merger or consolidation, hold an officer’s position which would make them a member of senior management of the surviving corporation; or
(d)the sale of all, or substantially all, of the assets of the Company or the liquidation or dissolution of the Company.
Notwithstanding anything herein to the contrary, under no circumstances will a change in the constitution of the board of directors or managers of any Subsidiary, a change in the beneficial ownership of any Subsidiary, the merger or consolidation of a Subsidiary with any other entity, the sale of all or substantially all of the assets of any Subsidiary or the liquidation or dissolution of any Subsidiary (in each case which does not constitute and is not part of a sale of all or substantially all of the assets of the Company) constitute a “Change of Control” under this Plan.
Section 2.8Common Shares. “Common Shares” means shares of common stock, $.001 par value of Denbury Resources Inc.
Section 2.9Company. Denbury Resources Inc., a Delaware corporation.
Section 2.10Disability. “Disability” shall mean a Participant’s inability to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which, in the reasonable opinion of the Administrator based on such medical evidence as it deems necessary, can be expected to result in death or can be expected to last for a continuous period of not less than 12 months; provided, however, that such Disability did not result, in whole or in part from: (i) a felonious undertaking or (ii) an intentional self-inflicted wound.
Section 2.11Effective Date. March 31, 2016.
Section 2.12Employee. An individual shall be an “Employee” only if the individual is shown as an employee of an Employer on the payroll records of such Employer. In addition, any person eligible for benefits under a severance plan not originally sponsored by the Company or Subsidiaries of the Company as of the date of adoption of this amended and restated Plan, including the EAP Properties Inc. Employee Severance Protection Plan (any such plan being an “Acquired Plan”), shall not be entitled to receive benefits under this Plan except to the extent and in the amount that benefits payable under this Plan are in excess of amounts payable to that person under such an Acquired Plan.
Section 2.13Employer. The Company and any Participating Employer. With respect to a Participant who is not an Employee of the Company, any reference under this Plan to such Participant's “Employer” shall refer only to the employer of the Participant, and in no event shall be construed to refer to the Company as well.
Section 2.14Good Reason. “Good Reason” shall mean the occurrence of any of the following events or conditions:
(a)a material diminution in the Participant's authority, duties or responsibilities;
(b)a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Participant is required to report, including a requirement that a Participant report to an Officer or Employee instead of reporting directly to the Board of the Company;
(c)a material diminution in the Participant's base compensation;
(d)a material change in the geographic location at which the Participant must perform the services; or
(e)any material breach by the Employer of any provision of this Plan.
The Participant is required to provide written notice to the Employer of the existence of the condition that would result in termination of employment for Good Reason within 90 days of the initial existence of the condition. Upon receipt of such written notice, the Employer has 30 days to remedy the condition (the “cure period”). If the Employer does not remedy the condition within the cure period, the Participant will meet the requirements for termination of employment for Good Reason, provided, however, that the Participant actually does terminate his employment not more than thirty (30) days after the expiration of the Employer’s cure period.
Section 2.15Notice of Termination. A notice which indicates the specific basis for any termination of employment; no purported termination of employment shall be effective without such Notice of Termination.
Section 2.16Officer. Each individual who at the time in question is a corporate officer of the Company and is so designated pursuant to the Company’s Bylaws.
Section 2.17Participant. An Employee who meets the eligibility requirements of Article III.
Section 2.18Participating Employer. Each Subsidiary of the Company shall be a Participating Employer in this Plan unless determined otherwise by the Company.
Section 2.19Payment Date. For a Participant entitled to payment under Section 4.1 as a result of a termination of employment other than for Cause during the period beginning six months prior to a Change of Control and ending on the date of the Change of Control, the Payment Date is the first business day that is at least fifteen (15) days after the Change of Control. For a Participant entitled to payment under Section 4.1 as a result of a termination of employment other than for Cause during the period beginning on the Change of Control and ending two years after the Change of Control, the Payment Date is the first business day that is at least fifteen (15) days after the Participant’s termination of employment.
Section 2.20Senior Management. Shall mean that group of Participants composed of the Company’s Chief Executive Officer, President, Chief Operating Officer, Chief Financial Officer, Executive Vice Presidents, Senior Vice Presidents and General Counsel, as such specific positions exist and individuals are then serving in such positions at the time in question.
Section 2.21Severance Benefit. The benefits payable in accordance with Article IV of the Plan.
Section 2.22Severance Units. A Participant who is neither (x) a member of Senior Management nor (y) an Officer not a member of Senior Management, shall receive one (1) Severance Unit, to be used in calculating his Severance Benefit, for (i) each ten thousand dollars ($10,000) of the aggregate of his Base Salary plus Bonus Amount, and (ii) each twelve months of employment by the Company or an Employer; the sum of any partial Severance Units under (i) and (ii) shall be rounded to the nearest higher whole number of Severance Units. However, the maximum number of Severance Units that may be granted to a Participant is eighteen (18), and each Participant shall be granted at least four (4) Severance Units.
Section 2.23Subsidiary. Any corporation or other entity that is a member of a controlled group, as defined in Section 414(b) or (c) of the Internal Revenue Code of 1986, as amended (the “Code”), with the Company.
Section 2.24Termination Date. In the case of the Participant's death, the Participant’s Termination Date shall be his date of death. In all other cases, the Participant's Termination Date shall be the date specified in the written Notice of Termination and as of which date the Participant does in fact terminate employment with his Employer.
ARTICLE III
ELIGIBILITY AND PARTICIPATION
Section 3.1Participation. Each Employee of the Company or of a Participating Employer during the time such Employer is participating in this Plan shall be eligible to participate in the Plan, as amended from time to time hereafter. An Employee of an Employer shall automatically cease being a Participant if his employment terminates more than six months prior to a Change of Control or more than two years after a Change of Control, or at any time for a reason that does not entitle the Participant to benefits under the Plan. Without limitation, an Employee of an Employer shall be ineligible for benefits under the Plan if his employment terminates at any time due to death or Disability, or due to termination by the Employer for Cause or due to his terminating his employment for any reason other than Good Reason.
Section 3.2Duration of Participation. Once an Employee of an Employer becomes a Participant, a Participant shall cease to be a Participant in the Plan upon the first to occur of: (i) the date that is six (6) months after the Termination Date (the “Six Month Date”), if as of the Six Month Date he is not then entitled to a Severance Benefit under the terms of this Plan, or (ii) the date on which he has received all of the benefits to which he is entitled under this Plan. This Plan shall not confer upon any Employee any right with respect to continuation of employment by any Employer, or any right to provide services to an Employer, nor shall this Plan interfere in any way with such Employee’s right to terminate employment, or such Employer’s right to terminate such Employee’s employment, at any time.
ARTICLE IV
SEVERANCE BENEFITS
Section 4.1Right to Severance Benefit.
After a Change of Control has occurred, a Participant shall be entitled to receive from the Employer a Severance Benefit in the amount provided in Sections 4.2 and 4.3 if (i) his employment is terminated by the Company or a Participating Employer for any reason other than for Cause, during the period beginning six months prior to such Change of Control and ending two years after such Change of Control, or (ii) Participant terminates his employment for Good Reason; provided that a Participant shall not be entitled to receive such a Severance Benefit if the Participant’s employment is terminated due to Participant’s Disability or death.
Section 4.2Amount of Severance Benefit. If a Participant is entitled to a Severance Benefit under Section 4.1, the Employer shall pay to the Participant, on the Payment Date, an amount in cash equal to one of the following amounts:
(a)for members of Senior Management, three (3) times the sum of the Participant’s Base Salary and the Bonus Amount;
(b)for all other Officers that are not members of Senior Management, two and one-half (2-1/2) times the sum of the Participant's Base Salary and the Bonus Amount; and
(c)for all other Participants, one-twelfth (1/12) of the sum of the Participant’s Base Salary and Bonus Amount multiplied by the Participant’s Severance Units.
Section 4.3Further Benefits. If a Participant is entitled to a Severance Benefit under Section 4.1, such Participant shall also be entitled to:
(a)Continuation at Employer’s expense, on behalf of the Participant and his dependents and beneficiaries, of all medical, dental, vision, and health benefits and insurance coverage which were being provided to the Participant at the time of termination of employment for a period of time subsequent to the Participant's termination of employment. Subject to termination of the Employer’s obligation under Section 4.3(b), this period of time shall be 18 months for members of Senior Management; 15 months for all other Officers that are not members of Senior Management; and for all other Participants, a period of time (in months) equal to fifty percent (50%) of such Participant's Severance Units. The benefits provided in this Section 4.3(a) shall be no less favorable to the Participant, in terms of amounts and deductibles and costs to him, than the coverage provided the Participant under the plans providing such benefits at the time of termination of the Participant’s employment. The payment by the Employer of the cost of such benefits shall be treated as additional taxable income to such Participants to the extent necessary to avoid a violation of the nondiscrimination provisions of Section 105(h) of the Code. Should the continuation of any medical or similar coverages be through fully insured plans, and should such continuation violate the nondiscrimination requirements for such plans
under the Patient Protection and Affordable Care Act (“Health Care Reform”), then such Participants shall receive additional cash severance benefits rather than continued coverage under such plans of Employer in an amount based on the premium cost of such coverage that the Employer would otherwise pay under this sentence.
(b)The Employer's obligation hereunder to provide a benefit shall terminate if the Participant obtains comparable coverage under a subsequent employer's benefit plan. For purposes of the preceding sentence, benefits will not be comparable during any waiting period for eligibility for such benefits or during any period during which there is a preexisting condition limitation on such benefits. The Employer also shall pay a lump sum equal to the amount of any additional income tax payable by the Participant and attributable to the taxability of the cost of the benefits provided under subparagraph (a) of this Section within the time limitations for reimbursing such tax under Section 12.11 hereof. At the end of the period of coverage set forth above, the Participant shall be entitled to all health and similar benefits that are or would have been made available to the Participant pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1986 (“COBRA”) or other applicable law, as if the Participant then terminated employment or had a reduction in hours triggering a right to benefits under COBRA or other applicable law at the end of such period.
Section 4.4Mitigation or Set-off of Amounts Payable Hereunder. The Participant shall not be required to mitigate the amount of any payment provided for in this Article IV by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Article IV be reduced by any compensation earned by the Participant as the result of employment by the Company or any successor after the Payment Date or by another employer after the Termination Date, or otherwise. The Employer's obligations hereunder also shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Employer may have against the Participant.
Section 4.5Company Guarantee of Severance Benefit. In the event a Participant becomes entitled to receive from the Employer a Severance Benefit under this Article IV above and such Employer fails to pay such Severance Benefit, the Company shall assume the obligation of such Employer to pay such Severance Benefit. In consideration of the Company's assumption of the obligation to pay such Severance Benefit provided under this Plan, the Company (as the source of payment of benefits under the Plan) shall be subrogated to any recovery (irrespective of whether there is recovery from the third party of the full amount of all claims against the third party) or right to recovery of either a Participant or his legal representative against the Employer or any person or entity. The Participant or his legal representative shall cooperate in doing what is reasonably necessary to assist the Company in exercising such rights, including but not limited to notifying the Company of the institution of any claim against a third party and notifying the third party and the third party's insurer, if any, of the Company's subrogation rights. Neither the Participant nor his legal representative shall do anything after a loss to prejudice such rights. In its sole discretion, the Company reserves the right to prosecute an action in the name of the Participant or his legal representative against any third parties potentially liable to the Participant. The Company shall have the absolute discretion to settle subrogation claims on any basis it deems warranted and appropriate under the circumstances. If a Participant or his legal representative initiates a lawsuit against any third parties potentially liable to the Participant, the Company shall not be responsible for any attorney's fees or court costs that may be incurred in such liability claim. The Company shall be entitled, to the extent of any payments made to or on behalf of a Participant or a dependent of the Participant, to be paid first from the proceeds of any settlement or judgment that may result from the exercise of any rights of recovery asserted by or on behalf of a Participant or his legal representative against any person or entity legally responsible for the injury for which such payment was made. The right is also hereby given the Company to receive directly from the Employer or any third party(ies), attorney(s) or insurance company(ies) an amount equal to the amount paid to or on behalf of the Participant.
Section 4.6Forfeiture of Severance Benefits. A Participant shall forfeit any and all entitlement to any Severance Benefit if the Administrator determines that the Participant has failed to fulfill any requirement of the Plan.
Section 4.7Payment after Death. If a Participant dies before his or her Severance Benefits have been paid in full, the remaining Severance Benefits will be paid to the beneficiaries named in such Participant’s last will and testament, or if no will or beneficiary exist then to such Participant’s heirs at law, and shall be paid within no more than 90 days following the Participant’s death. The Plan shall be discharged fully and completely to the extent of any payment made to any such beneficiaries or heirs at law.
ARTICLE V
TERMINATION OF EMPLOYMENT
Section 5.1Written Notice Required. Subject to Section 12.10, any purported termination of employment, either by the Employer or by the Participant, shall be communicated by written Notice of Termination to the other.
ARTICLE VI
ADDITIONAL PAYMENTS BY THE COMPANY; NET BEST TREATMENT DETERMINATION
Section 6.1Gross-Up Payment. In the event it shall be determined that any payment or distribution of any type by the Employer to or for the benefit of an Officer (as defined below for this Section 6.1), whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise (the “Total Payments”), would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are collectively referred to as the “Excise Tax”), then the Officer shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that at the time of payment by the Officer of all income and “FICA” taxes (including any interest and penalties imposed with respect to such taxes) imposed upon the Gross-Up Payment, the Officer shall receive a net Gross-Up Payment equal to the Excise Tax imposed upon the Total Payments. The Gross-Up Payment shall be made in the manner specified in Section 12.11. Solely for purposes of this Section 6.1, “Officer” shall be confined to individuals who (i) are Participants, (ii) are either (a) a member of Senior Management (as defined below), or (b) a Vice President of the Company, and (iii) were elected as a corporate officer before January 1, 2011.
Section 6.2Determination By Accountant. All determinations required to be made under this Article VI, including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by the independent accounting firm retained by the Company on the date of Change of Control, or such other independent qualified third party firm retained for such purpose (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Officer within fifteen (15) business days of the Payment Date or Termination Date, whichever is applicable, or such earlier time as is requested by the Company. If the Accounting Firm determines that no Excise Tax is payable by the Officer, it shall furnish the Officer with an opinion that he has substantial authority not to report any Excise Tax on his federal income tax return. Any determination by the Accounting Firm shall be binding upon the Company and the Officer. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that a Gross-Up Payment which will not have been made by the Company should have been made (“Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 6.3 and the Officer thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Officer in the manner specified in Section 12.11.
Section 6.3Notification Required. The Officer shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Officer knows of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Officer shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Officer in writing prior to the expiration of such period that it desires to contest such claim, the Officer shall:
(a)give the Company any information reasonably requested by the Company relating to such claim,
(b)take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,
(c)cooperate with the Company in good faith in order to effectively contest such claim,
(d)permit the Company to participate in any proceedings relating to such claim, provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Officer harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of such representation and payment of costs and expenses. Any such payments hereunder shall be made in the manner specified in Section 12.11. Without limitation on the foregoing provisions of this Section 6.3, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Officer to pay the tax claimed and sue for a refund, or contest the claim in any permissible manner, and the Officer agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Officer to pay such claim and sue for a refund, the Company shall advance the amount of such payment to
the Officer, on an interest-free basis and shall indemnify and hold the Officer harmless, on an after-tax basis, from any Excise Tax or income tax, including interest or penalties with respect thereto, imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Officer with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Officer shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.
Section 6.4Repayment. If, after the receipt by the Officer of an amount advanced by the Company pursuant to Section 6.3, the Officer becomes entitled to receive any refund with respect to such claim, the Officer shall (subject to the Company's complying with the requirements of Section 6.3) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Officer of an amount advanced by the Company pursuant to Section 6.3, a determination is made that the Officer shall not be entitled to any refund with respect to such claim and the Company does not notify the Officer in writing of its intent to contest such denial of refund prior to the expiration of thirty days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.
Section 6.5“Net Best” Treatment Determination. Notwithstanding anything in this Agreement to the contrary, any Officer, who is not eligible for any payment under Section 6.1, is a “disqualified individual” (as defined in Section 280G of the Code), and if any compensation, payment or distribution by the Company to or for the benefit of such Officer, whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise, calculated in a manner consistent with Section 280G of the Code and the applicable regulations thereunder (collectively, the “Severance Payments”), would be subject to Excise Taxes, the following provisions shall apply:
(a) If the Severance Payments, reduced by the sum of the Excise Tax and the total of the Federal, state, and local income and employment taxes payable by such Officer on the amount of the Severance Payments which are in excess of the Threshold Amount, are greater than or equal to the Threshold Amount, such Officer shall be entitled to the full Severance Benefits payable under this Plan.
(b) If the Threshold Amount is less than (x) the Severance Payments, but greater than (y) the Severance Payments reduced by the sum of the Excise Tax and the total of the Federal, state, and local income and employment taxes on the amount of the Severance Payments which are in excess of the Threshold Amount, then the Severance Payments shall be reduced (but not below zero) to the extent necessary so that the sum of all Severance Payments shall not exceed the Threshold Amount. In such event, the Severance Payments shall be reduced in the following order to the extent applicable: (1) cash Severance Benefits not subject to Section 409A of the Code; (2) cash Severance Benefits subject to Section 409A of the Code; (3) equity-based Severance Benefits and any accelerated equity-based Severance Benefits; and (4) non-cash forms of Severance Benefits. To the extent any Severance Benefits are to be made over time (e.g., in installments, etc.), then any such Severance Benefits shall be reduced in reverse chronological order. If any reduced payment is made and through error or otherwise that payment exceeds the Threshold Amount, such Officer shall immediately repay such excess to the Company upon notification that any such overpayment has been made to the Officer.
For the purposes of this Section 6.5, “Threshold Amount” shall mean three times the Officer’s “base amount” within the meaning of Section 280G(b)(3) of the Code and the regulations promulgated thereunder less one dollar ($1.00). The determination as to which of the alternative provisions of this Section 6.5 shall apply to such Officer shall be made substantially in accordance with the procedure set forth in Section 6.2 as if the determination by the Accounting Firm were with respect to a Gross-Up Payment. Any determination related to application of the foregoing provisions by the Accounting Firm shall be conclusive and binding upon the Company and any such Officer.
ARTICLE VII
SUCCESSORS TO COMPANY
Section 7.1Successors. This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. As used herein, “the Company” shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid which otherwise becomes bound by all the terms and provisions hereof by operation of law.
ARTICLE VIII
DURATION, AMENDMENT, PLAN TERMINATION
AND ADOPTION BY SUBSIDIARIES
Section 8.1Duration. This Plan shall continue in effect until terminated in accordance with Section 8.2. If a Change of Control occurs, this Plan shall continue in full force and effect, and shall not terminate or expire, until after all Participants who have become entitled to a Severance Benefit hereunder shall have received all of such benefits in full.
Section 8.2Amendment and Termination. The Plan and its attached Schedules may be terminated or amended in any respect by resolution adopted by two-thirds of the Board; provided, however, that no such amendment or termination of the Plan may be made if such amendment or termination would adversely affect any right of a Participant who became a Participant prior to the later of (i) the date of adoption of any such amendment or termination, or (ii) the effective date of any such amendment or termination; and, provided further, that the Plan no longer shall be subject to amendment, change, substitution, deletion, revocation or termination which adversely affects any Participant in any respect whatsoever within two (2) years following a Change of Control.
Section 8.3Form of Amendment. The form of any amendment or termination of the Plan shall be a written instrument signed by a duly authorized officer or officers of the Company, certifying that the amendment or termination has been approved by the Board.
ARTICLE IX
CLAIMS AND APPEAL PROCEDURES
Section 9.1Claims Procedure. With respect to any claim for Severance Benefits under the Plan, the Administrator will issue a decision on whether the claim is denied or granted within ninety (90) days after receipt of the claim by the Administrator, unless special circumstances require an extension of time for processing the claim, in which case a decision will be rendered not later than ninety (90) days after receipt of the claim. Written notice of the extension will be furnished to the Participant prior to the expiration of the initial ninety (90) day period and will indicate the special circumstances requiring an extension of time for processing the claim and will indicate the date the Administrator expects to render its decision. If the claim is denied in whole or in part, the decision in writing by the Administrator shall include the specific reasons for the denial and reference to the Plan provisions on which the denial is based. The decision also shall include: (i) a description of any additional material or information necessary for the Participant to perfect the claim, and an explanation of why the material or information is necessary and (ii) an explanation of the claims review procedure and the time limits applicable to such procedures, including a statement of the Participant’s right to bring a civil action under Section 502(a) of ERISA following a denial upon review of the claim.
Section 9.2Appeals Procedure. If his claim is denied in whole or in part, a Participant may appeal in writing a denial of the claim, in part or in whole, and request a review by the Administrator. The appeal must be submitted within sixty (60) days after notice of the denial of the claim. The Administrator shall afford the Participant a full and fair review of the decision denying the claim and shall: (i) provide, upon request and free of charge, reasonable access to and copies of all documents, records and other information relevant to the claim; (ii) permit the Participant to submit to the Administrator written comments, documents, records and other information relating to the claim; and (iii) provide a review that takes into account all comments, documents, records and other information submitted by the Participant relating to the claim, without regard to whether such information was submitted or considered in the initial determination. The Administrator will review the appeal and notify the Participant of the final decision within sixty (60) days after receiving the request for review unless the Administrator requires an extension due to special circumstances, in which case the final decision will be made within sixty (60) days after the Administrator receives the request for review. If special circumstances require an extension of time, the Participant shall be furnished written notice prior to the termination of the initial 60-day period which explains the special circumstances requiring an extension of time and the date by which the Administrator expects to render its decision on review. The decision on review shall include: (i) specific reasons for the decision, (ii) references to the specific Plan provisions on which the decision of the Administrator is based, (iii) a statement that the Participant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records and other information relevant to the Participant’s claim, and (iv) a statement describing any voluntary appeal procedures offered by the Plan and a statement of the Participant’s right to bring an action under Section 502(a) of ERISA.
Section 9.3Exclusive Initial Remedy. No action may be brought for benefits provided by this Plan or to enforce any right hereunder until after a claim has been submitted to and determined by the Administrator and all appeal rights under the Plan have been exhausted. Thereafter, the Participant may bring an action for benefits provided by this Plan or to enforce any right hereunder. The Participant's beneficiary should follow the same claims procedure in the event of the Participant's death.
ARTICLE X
PLAN ADMINISTRATION
Section 10.1In General. The general administration of the Plan and the duty to carry out its provisions shall be vested in the Administrator, which shall be the “Plan Administrator” as that term is defined in Section 3(16)(A) of ERISA. The Plan and Severance Benefits under the Plan shall be administered by the Administrator appointed from time to time by the Company. The Administrator may, in its discretion, secure the services of other parties, including agents and/or Employees to carry out the day-to-day functions necessary to an efficient operation of the Plan. The Administrator's interpretations, decisions, requests and exercises of power and responsibilities shall not be subject to review by anyone and shall be final, binding, and conclusive upon all persons. The Administrator shall, in its sole and absolute discretion, have the exclusive right to interpret all of the terms of the Plan, to determine eligibility for coverage and benefits, to resolve disputes as to eligibility, type, or amount of benefits, to correct any errors or omissions in the form or operation of the Plan, to make such other determinations with respect to the Plan, and to exercise such other powers and responsibilities as shall be provided for in the Plan or as shall be necessary or helpful with respect thereto. The Administrator under and pursuant to this Plan shall be the named fiduciary for purposes of Section 402(a) of ERISA with respect to all powers and duties expressly or implicitly assigned to it hereunder. Any determination or decision by the Company made under or with respect to any provision of the Plan shall be in the Company's sole and absolute discretion, shall not be subject to review by anyone and shall be final, binding and conclusive upon all persons. Benefits under this Plan will be paid only if the Administrator decides in its discretion that the applicant is entitled to them.
Section 10.2Reimbursement and Compensation. The Administrator shall receive no compensation for its services as Administrator, but it shall be entitled to reimbursement for all sums reasonably and necessarily expended by it in the performance of such duties.
Section 10.3Rulemaking Powers. The Administrator shall have the power to make reasonable and uniform rules and regulations required in the administration of the Plan, to make all determinations necessary for the Plan's administration, except those determinations which the Plan requires others to make, and to construe and interpret the Plan wherever necessary to carry out its intent and purpose and to facilitate its administration.
ARTICLE XI
SOURCE OF SEVERANCE PAYMENT
Section 11.1No Separate Fund Established All Severance Benefits shall be paid in cash from the general funds of the Company or an Employer, and no special or separate fund shall be established. Nothing contained in the Plan shall create or be construed to create a trust of any kind, and nothing contained in the Plan nor any action taken pursuant to the provisions of the Plan shall create or be construed to create a fiduciary relationship between the Company or an Employer and a Participant, beneficiary, Employee or other person. To the extent that any person acquires a right to receive Severance Benefits from the Company or an Employer under the Plan, such right shall be no greater than the right of any unsecured general creditor of the Company or Employer. For purposes of the Code, the Company intends this Plan to be an unfunded, unsecured promise to pay on the part of the Company. For purposes of ERISA, the Company intends the Plan to be a “severance plan” within the meaning of the applicable ERISA regulations.
ARTICLE XII
MISCELLANEOUS
Section 12.1Participant's Legal Expenses. The Company agrees to pay, upon written demand therefor by the Participant, fifty percent (50%) of all legal fees and expenses which the Participant may reasonably incur in order to collect amounts to be paid or obtain benefits to be provided to such Participant under the Plan, plus in each case interest at the “applicable Federal rate” (as defined in Section 1274(d) of the Code). In any such action brought by a Participant for damages or to enforce any provisions hereof, he shall be entitled to seek both legal and equitable relief and remedies, including, without limitation, specific performance of the Company's obligations hereunder, in his sole discretion. However, in any instance where a Participant receives, as the result of a final, nonappealable judgment of a court of competent jurisdiction or a mutually agreed upon settlement with the Company, Severance Benefits greater than those first offered by the Company or its successor to the Participant, then the Company shall pay one hundred percent (100%) of all such legal fees and expenses incurred by the Participant. Any such payments hereunder shall be made in the manner specified in Section 12.11.
Section 12.2Employment Status. This Plan does not constitute a contract of employment or impose on the Employer any obligation to retain a Participant as an Employee, to change the status of a Participant's employment, or to change any employment policies of the Employer.
Section 12.3Validity and Severability. The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
Section 12.4The Participant's Heirs, etc. This Agreement shall inure to the benefit of and be enforceable by the Participant's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Participant should die while any amounts would still be payable to him hereunder as if he had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms hereof to his designee or, if there be no such designee, to his estate.
Section 12.5Governing Law. The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of the State of Texas.
Section 12.6Choice of Forum. A Participant shall be entitled to enforce the provisions of this Plan in any state or federal court located in the Collin County, Texas, in addition to any other appropriate forum.
Section 12.7Notice. For the purposes hereof, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed to the Company at its principal place of business and to the Participant at his address as shown on the records of the Employer, provided that all notices to the Company shall be directed to the attention of the Chief Executive Officer of the Company with a copy to the Secretary of the Company, or to such other in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt.
Section 12.8Alienation. No benefit, right or interest of any person under the Plan will be subject to alienation, anticipation, sale, transfer, assignment, pledge, encumbrance or charge, seizure, attachment or legal, equitable or other process or be liable for or subject to, the debts, liabilities or other obligations of such persons, except as otherwise required by law. No Participant, dependent or their beneficiary shall have any right or claim to benefits from the Plan, except as specified in the Plan.
Section 12.9Pronouns. A pronoun or adjective in the masculine gender includes the feminine gender, and the singular includes the plural, unless the context clearly indicates otherwise.
Section 12.10Section 409A. It is the intent of the parties that this Plan be interpreted and administered in compliance with the requirements of Section 409A of the Code (“Section 409A”) to the extent applicable. In this connection, the Administrator or Company shall have authority to take any action, or refrain from taking any action, with respect to this Plan that is reasonably necessary to ensure compliance with Section 409A (provided that the Administrator or Company shall choose the action that best preserves the value of the payments and benefits provided to any Participant under this Plan). In the event a Participant is a “specified employee” within the meaning of Section 409A, payments which constitute a “deferral of compensation” under Section 409A and which would otherwise become due during the first six (6) months following such Participant’s termination of employment shall: (i) be delayed; (ii) all such delayed payments shall be paid in full in the seventh (7th) month after the Participant’s termination of employment (the date of payment within such seventh month being within the sole discretion of the Company); and (iii) all subsequent payments shall be paid in accordance with their original payment schedule; provided, however, that the above delay shall not apply to any payments that are excepted from coverage by Section 409A, including, but not limited to, those payments covered by the short-term deferral exception described in Treasury Regulations Section 1.409A-1(b)(4). A termination of a Participant’s employment hereunder (and similar phrases used under the Plan), shall be interpreted as a “separation from service” within the meaning of Section 409A. Notwithstanding the preceding, the Administrator, the Company and its Affiliates shall not be liable to any Participant or any other person if the Internal Revenue Service or any court or other authority having jurisdiction over such matter determines for any reason that any amount hereunder is subject to taxes, penalties or interest as a result of failing to comply with Section 409A.
Section 12.11Reimbursements. With respect to the reimbursement of fees, taxes and expenses provided for herein, including payments made pursuant to indemnification provisions, and Gross Up Payments, the following shall apply: (i) unless a specific time period during which such expense reimbursements and tax gross-up payments may be incurred is provided for herein, such time period shall be deemed to be Participant’s lifetime; (ii) the amount of expenses eligible for reimbursement hereunder in any particular year shall not affect the expenses eligible for reimbursement in any other year; (iii) the right to reimbursement of expenses shall not be subject to liquidation or exchange for any other benefit; and (iv) a Participant shall be entitled to a reimbursement of an eligible expense or a Gross-Up Payment hereunder only if such claim or reimbursement request is made to the Employer on or before 15 days prior to the last day of the calendar year following the calendar year in which the expense was incurred or the tax was remitted, as the case may be, and the reimbursement is made on or before the last day of such calendar year.
Exhibit 31(a)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Phil Rykhoek, certify that:
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1. | I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant); |
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2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
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3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
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4. | The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
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(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
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(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
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(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
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5. | The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
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(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
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(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
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May 6, 2016 | | /s/ Phil Rykhoek |
| | Phil Rykhoek |
| | President and Chief Executive Officer |
Exhibit 31(b)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Mark C. Allen, certify that:
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1. | I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant); |
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2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
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3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
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4. | The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
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(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
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(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
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(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
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5. | The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
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(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
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(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
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May 6, 2016 | | /s/ Mark Allen |
| | Mark C. Allen |
| | Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary |
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Annual Report on Form 10-Q for the quarter ended March 31, 2016 (the Report) of Denbury Resources Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
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1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
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2. | The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury. |
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Dated: | May 6, 2016 | | /s/ Phil Rykhoek |
| | | Phil Rykhoek |
| | | President and Chief Executive Officer |
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Dated: | May 6, 2016 | | /s/ Mark C. Allen |
| | | Mark C. Allen |
| | | Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary |
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v3.4.0.3
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands |
Mar. 31, 2016 |
Dec. 31, 2015 |
Current assets |
|
|
Cash and cash equivalents |
$ 8,252
|
$ 2,812
|
Accrued production receivable |
95,934
|
100,413
|
Trade and other receivables, net |
87,228
|
87,924
|
Derivative assets |
72,798
|
142,846
|
Other current assets |
8,763
|
10,005
|
Total current assets |
272,975
|
344,000
|
Oil and natural gas properties (using full cost accounting) |
|
|
Proved properties |
10,296,792
|
10,245,195
|
Unevaluated properties |
902,990
|
894,948
|
CO2 properties |
1,186,607
|
1,187,458
|
Pipelines and plants |
2,293,102
|
2,293,219
|
Other property and equipment |
405,039
|
408,194
|
Less accumulated depletion, depreciation, amortization and impairment |
(9,982,733)
|
(9,653,205)
|
Net property and equipment |
5,101,797
|
5,375,809
|
Other assets |
163,775
|
166,555
|
Total assets |
5,538,547
|
5,886,364
|
Current liabilities |
|
|
Accounts payable and accrued liabilities |
186,715
|
253,197
|
Oil and gas production payable |
79,765
|
87,337
|
Derivative liabilities |
25,005
|
0
|
Current maturities of long-term debt |
32,917
|
32,481
|
Total current liabilities |
324,402
|
373,015
|
Long-term liabilities |
|
|
Long-term debt, net of current portion |
3,222,497
|
3,245,114
|
Asset retirement obligations |
142,101
|
138,919
|
Deferred tax liabilities, net |
742,148
|
837,263
|
Other liabilities |
26,121
|
27,484
|
Total long-term liabilities |
$ 4,132,867
|
$ 4,248,780
|
Commitments and contingencies (Note 7) |
|
|
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; 354,340,533 and 354,541,626 shares issued, respectively |
354
|
355
|
Paid-in capital in excess of par |
2,356,069
|
2,353,134
|
Accumulated deficit |
(1,228,039)
|
(1,042,882)
|
Treasury stock, at cost, 3,734,768 and 3,124,311 shares, respectively |
(47,106)
|
(46,038)
|
Total stockholders' equity |
1,081,278
|
1,264,569
|
Total liabilities and stockholders' equity |
$ 5,538,547
|
$ 5,886,364
|
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v3.4.0.3
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares
|
Mar. 31, 2016 |
Dec. 31, 2015 |
Stockholders' equity |
|
|
Preferred stock, par value |
$ 0.001
|
$ 0.001
|
Preferred stock, shares authorized |
25,000,000
|
25,000,000
|
Preferred stock, shares issued |
0
|
0
|
Preferred stock, shares outstanding |
0
|
0
|
Common stock, par value |
$ 0.001
|
$ 0.001
|
Common stock, shares authorized |
600,000,000
|
600,000,000
|
Common stock, shares issued |
354,340,533
|
354,541,626
|
Treasury stock, shares |
3,734,768
|
3,124,311
|
X |
- DefinitionFace amount or stated value per share of common stock.
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v3.4.0.3
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended |
Mar. 31, 2016 |
Mar. 31, 2015 |
Revenues and other income |
|
|
Oil, natural gas, and related product sales |
$ 187,803
|
$ 297,470
|
CO2 sales and transportation fees |
6,272
|
6,972
|
Interest income and other income |
769
|
3,207
|
Total revenues and other income |
194,844
|
307,649
|
Expenses |
|
|
Lease operating expenses |
102,447
|
141,084
|
Marketing and plant operating expenses |
13,194
|
11,685
|
CO2 discovery and operating expenses |
607
|
947
|
Taxes other than income |
20,092
|
26,679
|
General and administrative expenses |
33,901
|
46,280
|
Interest, net of amounts capitalized of $5,780 and $8,409, respectively |
42,171
|
40,099
|
Depletion, depreciation, and amortization |
77,366
|
149,958
|
Commodity derivatives expense (income) |
22,826
|
(83,076)
|
Gain on debt extinguishment |
(94,991)
|
0
|
Write-down of oil and natural gas properties |
256,000
|
146,200
|
Other expenses |
1,544
|
0
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|
479,856
|
Loss before income taxes |
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|
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|
Income tax benefit |
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|
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|
$ (107,746)
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|
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$ (0.31)
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|
$ 0.0625
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Weighted average common shares outstanding |
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|
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347,235
|
350,688
|
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350,688
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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands |
3 Months Ended |
Mar. 31, 2016 |
Mar. 31, 2015 |
Cash flows from operating activities |
|
|
Net loss |
$ (185,193)
|
$ (107,746)
|
Adjustments to reconcile net loss to cash flows from operating activities |
|
|
Depletion, depreciation, and amortization |
77,366
|
149,958
|
Write-down of oil and natural gas properties |
256,000
|
146,200
|
Deferred income taxes |
(95,115)
|
(66,036)
|
Stock-based compensation |
859
|
7,849
|
Commodity derivatives expense (income) |
22,826
|
(83,076)
|
Receipt on settlements of commodity derivatives |
72,227
|
148,465
|
Gain on debt extinguishment |
(94,991)
|
0
|
Amortization of debt issuance costs and discounts |
3,306
|
2,221
|
Other, net |
(416)
|
(2,359)
|
Changes in assets and liabilities, net of effects from acquisitions |
|
|
Accrued production receivable |
4,479
|
33,636
|
Trade and other receivables |
812
|
16,828
|
Other current and long-term assets |
1,437
|
(6,136)
|
Accounts payable and accrued liabilities |
(53,548)
|
(83,248)
|
Oil and natural gas production payable |
(7,572)
|
(17,716)
|
Other liabilities |
(448)
|
(1,076)
|
Net cash provided by operating activities |
2,029
|
137,764
|
Cash flows from investing activities |
|
|
Oil and natural gas capital expenditures |
(65,692)
|
(162,192)
|
CO2 capital expenditures |
(315)
|
(14,855)
|
Pipelines and plants capital expenditures |
(635)
|
(12,455)
|
Other |
(312)
|
(3,076)
|
Net cash used in investing activities |
(66,954)
|
(192,578)
|
Cash flows from financing activities |
|
|
Bank repayments |
(696,000)
|
(595,000)
|
Bank borrowings |
831,000
|
665,000
|
Repurchases of senior subordinated notes |
(55,521)
|
0
|
Cash dividends paid |
(387)
|
(22,068)
|
Other |
(8,727)
|
(10,250)
|
Net cash provided by financing activities |
70,365
|
37,682
|
Net increase (decrease) in cash and cash equivalents |
5,440
|
(17,132)
|
Cash and cash equivalents at beginning of period |
2,812
|
23,153
|
Cash and cash equivalents at end of period |
$ 8,252
|
$ 6,021
|
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v3.4.0.3
Basis of Presentation
|
3 Months Ended |
Mar. 31, 2016 |
Accounting Policies [Abstract] |
|
Basis of Presentation and Significant Accounting Policies |
Note 1. Basis of Presentation
Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2016, our consolidated results of operations for the three months ended March 31, 2016 and 2015, and our consolidated cash flows for the three months ended March 31, 2016 and 2015.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, beginning “Other current assets,” “Deferred tax liabilities, net,” “Paid-in capital in excess of par” and “Accumulated deficit” have been adjusted for changes related to (1) the accounting for excess tax benefits and forfeitures associated with share-based payment transactions, (2) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (3) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.
Net Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards. For the three months ended March 31, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Basic weighted average common shares outstanding | | 347,235 |
| | 350,688 |
| Potentially dilutive securities | | |
| | |
| Restricted stock, stock options, SARs and performance-based equity awards | | — |
| | — |
| Diluted weighted average common shares outstanding | | 347,235 |
| | 350,688 |
|
Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share (although time-vesting restricted stock is issued and outstanding upon grant).
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Stock options and SARs | | 7,412 |
| | 10,507 |
| Restricted stock and performance-based equity awards | | 5,097 |
| | 2,948 |
|
Write-Down of Oil and Natural Gas Properties
The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015 and the first quarter of 2016, from $79.55 per Bbl for the first quarter of 2015 to $44.03 per Bbl for the first quarter of 2016. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $2.22 per Mcf for the first quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $256.0 million and $146.2 million during the three months ended March 31, 2016 and March 31, 2015, respectively.
Recent Accounting Pronouncements
Recently Adopted
Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to beginning “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.
Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows.
Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs associated with our senior subordinated notes of $32.8 million have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows.
Not Yet Adopted
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (“ASU 2016-08”) which clarifies the implementation guidance on principal versus agent considerations. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09, ASU 2015-14 and ASU 2016-08 will have on our consolidated financial statements.
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v3.4.0.3
Long-Term Debt
|
3 Months Ended |
Mar. 31, 2016 |
Debt Disclosure [Abstract] |
|
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 | | 2016 | | 2015 | Senior Secured Bank Credit Agreement | | $ | 310,000 |
| | $ | 175,000 |
| 6⅜% Senior Subordinated Notes due 2021 | | 396,000 |
| | 400,000 |
| 5½% Senior Subordinated Notes due 2022 | | 1,207,745 |
| | 1,250,000 |
| 4⅝% Senior Subordinated Notes due 2023 | | 1,094,000 |
| | 1,200,000 |
| Other Subordinated Notes, including premium of $6 and $7, respectively | | 2,256 |
| | 2,257 |
| Pipeline financings | | 209,399 |
| | 211,766 |
| Capital lease obligations | | 65,817 |
| | 71,324 |
| Total | | 3,285,217 |
| | 3,310,347 |
| Issuance costs on senior subordinated notes | | (29,803 | ) | | (32,752 | ) | Total, net of debt issuance costs on senior subordinated notes | | 3,255,414 |
| | 3,277,595 |
| Less: current obligations | | (32,917 | ) | | (32,481 | ) | Long-term debt and capital lease obligations | | $ | 3,222,497 |
| | $ | 3,245,114 |
|
The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 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. As of April 18, 2016, in connection with our May 2016 borrowing base redetermination requirement, we have reduced our borrowing base and lender commitments to $1.05 billion, with the next such redetermination scheduled for November 2016.
In order to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with maintenance financial covenants in this low oil price environment, we have entered into three amendments to the Bank Credit Agreement between May 2015 and April 2016 that have modified the Bank Credit Agreement as follows:
| | • | for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio); |
| | • | for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; |
| | • | beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019; |
| | • | allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements); |
| | • | limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and |
| | • | limits the amount spent on repurchases of our senior subordinated notes to $225 million. |
Additionally, such amendments provide for the following changes to the Bank Credit Agreement: (1) increases the applicable margin for ABR Loans and LIBOR Loans by 75 basis points such that the margin for ABR Loans now ranges from 1% to 2% per annum and the margin for LIBOR Loans now ranges from 2% to 3% per annum, (2) increases the commitment fee rate to 0.50%, and (3) provides for semi-annual scheduled redeterminations of the borrowing base in May and November of each year. As of March 31, 2016, we were in compliance with all debt covenants under the Bank Credit Agreement. The weighted average interest rate on borrowings outstanding as of March 31, 2016, under the Bank Credit Agreement was 2.4%.
The above description of our Bank Credit Agreement financial covenants and the changes provided for within the three amendments are qualified by the express language and defined terms contained in the Bank Credit Agreement, the First Amendment to the Bank Credit Agreement dated May 4, 2015, the Second Amendment to the Bank Credit Agreement dated February 17, 2016, and the Third Amendment to the Bank Credit Agreement dated April 18, 2016, each of which are filed as exhibits to our periodic reports filed with the SEC.
2016 Repurchases of Senior Subordinated Notes
During February and March 2016, we repurchased a total of $4.0 million in aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021 (the “2021 Notes”), $42.3 million in aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 (the “2022 Notes”), and $106.0 million in aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023 (the “2023 Notes”) 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. As of May 4, 2016, an additional $169.5 million may be spent on senior subordinated notes repurchases under the Bank Credit Agreement.
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- DefinitionThe entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.
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v3.4.0.3
Income Taxes
|
3 Months Ended |
Mar. 31, 2016 |
Income Tax Disclosure [Abstract] |
|
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, 2016, we had $34.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $33.6 million during 2015 and an additional $0.9 million during the first quarter of 2016 to reduce the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.
As of March 31, 2016, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during the fourth quarter of 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of March 31, 2016.
|
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- DefinitionThe entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.
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v3.4.0.3
Stockholders' Equity
|
3 Months Ended |
Mar. 31, 2016 |
Stockholders' Equity Note [Abstract] |
|
Stockholders' Equity |
Note 4. Stockholders’ Equity
Dividends
During the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share, with dividends totaling $22.1 million paid to stockholders during the three months ended March 31, 2015. In September 2015, in light of the continuing low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.
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- DefinitionThe entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.
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v3.4.0.3
Commodity Derivative Contracts
|
3 Months Ended |
Mar. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Commodity Derivative Contracts |
Note 5. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2016, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of March 31, 2016, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification (“FASC”) Derivatives and Hedging topic: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) | Range (1) | | Weighted Average Price | Swap | | Sold Put | | Floor | | Ceiling | Oil Contracts: | | | | | | | | | | | | | | | | 2016 Enhanced Swaps (2) | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 2,000 | | $ | 90.35 | – | 90.35 |
| | $ | 90.35 |
| | $ | 68.00 |
| | $ | — |
| | $ | — |
| Apr – June | | LLS | | 6,000 | | | 93.30 | – | 93.50 |
| | 93.38 |
| | 70.00 |
| | — |
| | — |
| 2016 Fixed-Price Swaps | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 11,500 | | $ | 60.30 | – | 63.75 |
| | $ | 61.84 |
| | $ | — |
| | $ | — |
| | $ | — |
| Apr – June | | LLS | | 3,500 | | | 64.20 | – | 66.15 |
| | 64.99 |
| | — |
| | — |
| | — |
| July – Sept | | NYMEX | | 16,500 | | | 36.25 | – | 40.65 |
| | 38.24 |
| | — |
| | — |
| | — |
| July – Sept | | LLS | | 7,000 | | | 37.24 | – | 42.15 |
| | 39.61 |
| | — |
| | — |
| | — |
| Oct – Dec | | NYMEX | | 23,000 | | | 36.25 | – | 40.00 |
| | 37.97 |
| | — |
| | — |
| | — |
| Oct – Dec | | LLS | | 7,000 | | | 37.24 | – | 41.00 |
| | 39.16 |
| | — |
| | — |
| | — |
| 2016 Three-Way Collars (3) | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 2,000 | | $ | 85.00 | – | 95.50 |
| | $ | — |
| | $ | 68.00 |
| | $ | 85.00 |
| | $ | 95.50 |
| Apr – June | | LLS | | 2,000 | | | 88.00 | – | 98.25 |
| | — |
| | 70.00 |
| | 88.00 |
| | 98.25 |
| 2016 Collars | | | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 5,000 | | $ | 55.00 | – | 72.25 |
| | $ | — |
| | $ | — |
| | $ | 55.00 |
| | $ | 71.01 |
| Apr – June | | LLS | | 2,000 | | | 58.00 | – | 73.00 |
| | — |
| | — |
| | 58.00 |
| | 73.00 |
| July – Sept | | NYMEX | | 4,500 | | | 55.00 | – | 72.65 |
| | — |
| | — |
| | 55.00 |
| | 71.22 |
| July – Sept | | LLS | | 3,000 | | | 58.00 | – | 74.30 |
| | — |
| | — |
| | 58.00 |
| | 73.85 |
| 2017 Fixed-Price Swaps | | | | | | | | | | | | | | | | Jan – Mar | | NYMEX | | 20,000 | | $ | 41.15 | – | 44.35 |
| | $ | 42.39 |
| | $ | — |
| | $ | — |
| | $ | — |
| Jan – Mar | | LLS | | 9,000 | | | 42.35 | – | 45.60 |
| | 43.51 |
| | — |
| | — |
| | — |
|
| | (1) | Ranges presented for fixed-price swaps and enhanced 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) | An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes. |
| | (3) | 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. |
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- DefinitionThe entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.
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v3.4.0.3
Fair Value Measurements
|
3 Months Ended |
Mar. 31, 2016 |
Fair Value Disclosures [Abstract] |
|
Fair Value Measurements |
Note 6. Fair Value Measurements
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
| | • | Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. |
| | • | Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and 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, 2016, instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, 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 $14 thousand in the fair value of these instruments as of March 31, 2016. |
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated: | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | March 31, 2016 | | | | | | | | | Assets | | | | | | | | | Oil derivative contracts – current | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
| Total Assets | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
| | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
| Total Liabilities | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
| | | | | | | | | | December 31, 2015 | | |
| | |
| | |
| | |
| Assets | | |
| | |
| | |
| | |
| Oil derivative contracts – current | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
| Total Assets | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
|
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
Level 3 Fair Value Measurements
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2016 and 2015: | | | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Fair value of Level 3 instruments, beginning of period | | $ | 52,834 |
| | $ | 188,446 |
| Fair value adjustments on commodity derivatives | | 281 |
| | 25,085 |
| Payment (receipts) on settlements of commodity derivatives | | (30,075 | ) | | (48,516 | ) | Fair value of Level 3 instruments, end of period | | $ | 23,040 |
| | $ | 165,015 |
| | | | | | 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 | | $ | 133 |
| | $ | 23,099 |
|
We utilize an income approach to value our Level 3 enhanced swaps, 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 3/31/2016 (in thousands) | | Valuation Technique | | Unobservable Input | | Volatility Range | Oil derivative contracts | | $ | 23,040 |
| | Discounted cash flow / Black-Scholes | | Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2016 | | 26.9% – 38.0% |
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 fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our debt as of March 31, 2016 and December 31, 2015, excluding pipeline financing and capital lease obligations, was $1,487.4 million and $1,119.0 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.
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- DefinitionThe entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.
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v3.4.0.3
Commitments and Contingencies
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3 Months Ended |
Mar. 31, 2016 |
Commitments and Contingencies Disclosure [Abstract] |
|
Commitments and Contingencies |
Note 7. Commitments and Contingencies
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.
NGS Sub Corp., Evolution, et al v. Denbury Onshore, LLC
In March 2015, Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”), the parent of the entity which sold Denbury Onshore, LLC (“Denbury Onshore”), a subsidiary of Denbury Resources Inc. (“DRI” and together with Denbury Onshore, “Denbury”), its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the 133rd Judicial District Court in Houston, Harris County, Texas since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining “payout” as defined in the agreements, and the extent and terms of assignment of reversionary interests in the unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury in connection with the June 2013 Delhi Field release of well fluids, and for the first time Evolution estimated its damages attributable to its allegations in the case as exceeding $200 million. The amended petition also added a claim for unspecified punitive damages. In Denbury’s answer and counterclaim, we have denied Evolution’s claims, alleged breach of contract by Evolution for failing to convey the full interest for which we paid and for violating our preferential purchase rights, and asked for a declaratory judgment as to various purchase document terms, including those pertaining to the determination of payout, the assignment of provisions of the documents, and cost sharing. Denbury has also filed a Motion for Summary Judgment seeking dismissal of Evolution’s tort claims for negligence and gross negligence.
Discovery is ongoing in the case, and the case is currently set for trial in July 2016. We believe that Evolution’s claims and requests for damages in this matter are without merit and we intend to vigorously pursue our requested relief under the purchase documents.
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v3.4.0.3
Additional Balance Sheet Details
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3 Months Ended |
Mar. 31, 2016 |
Disclosure Text Block [Abstract] |
|
Additional Balance Sheet Details |
Note 8. Additional Balance Sheet Details
Accounts Payable and Accrued Liabilities | | | | | | | | | | | | March 31, | | December 31, | In thousands | | 2016 | | 2015 | Accrued interest | | $ | 44,201 |
| | $ | 48,908 |
| Accounts payable | | 32,688 |
| | 30,477 |
| Accrued lease operating expenses | | 30,169 |
| | 37,549 |
| Taxes payable | | 17,717 |
| | 32,438 |
| Accrued compensation | | 14,403 |
| | 46,780 |
| Accrued exploration and development costs | | 13,500 |
| | 20,892 |
| Other | | 34,037 |
| | 36,153 |
| Total | | $ | 186,715 |
| | $ | 253,197 |
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v3.4.0.3
Subsequent Event
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3 Months Ended |
Mar. 31, 2016 |
Subsequent Events [Abstract] |
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Subsequent Event |
Note 9. Subsequent Event
During the first week of May 2016, we entered into privately negotiated exchange agreements to exchange $922.5 million in aggregate principal amount of our outstanding 2021 Notes, 2022 Notes and 2023 Notes for $531.2 million in aggregate principal amount of new 9% Senior Secured Second Lien Notes due 2021 and 36.9 million shares of Denbury common stock. The transactions are currently expected to close May 10, 2016, subject to customary closing conditions.
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- DefinitionThe entire disclosure for significant events or transactions that occurred after the balance sheet date through the date the financial statements were issued or the date the financial statements were available to be issued. Examples include: the sale of a capital stock issue, purchase of a business, settlement of litigation, catastrophic loss, significant foreign exchange rate changes, loans to insiders or affiliates, and transactions not in the ordinary course of business.
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v3.4.0.3
Basis of Presentation (Policies)
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3 Months Ended |
Mar. 31, 2016 |
Accounting Policies [Abstract] |
|
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.
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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, 2015 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
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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, 2016, our consolidated results of operations for the three months ended March 31, 2016 and 2015, and our consolidated cash flows for the three months ended March 31, 2016 and 2015.
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Reclassifications |
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, beginning “Other current assets,” “Deferred tax liabilities, net,” “Paid-in capital in excess of par” and “Accumulated deficit” have been adjusted for changes related to (1) the accounting for excess tax benefits and forfeitures associated with share-based payment transactions, (2) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (3) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.
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Net Loss per Common Share |
Net Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards. For the three months ended March 31, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Basic weighted average common shares outstanding | | 347,235 |
| | 350,688 |
| Potentially dilutive securities | | |
| | |
| Restricted stock, stock options, SARs and performance-based equity awards | | — |
| | — |
| Diluted weighted average common shares outstanding | | 347,235 |
| | 350,688 |
|
Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share (although time-vesting restricted stock is issued and outstanding upon grant).
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Stock options and SARs | | 7,412 |
| | 10,507 |
| Restricted stock and performance-based equity awards | | 5,097 |
| | 2,948 |
|
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Oil and Natural Gas Properties Policy |
Write-Down of Oil and Natural Gas Properties
The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015 and the first quarter of 2016, from $79.55 per Bbl for the first quarter of 2015 to $44.03 per Bbl for the first quarter of 2016. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $2.22 per Mcf for the first quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $256.0 million and $146.2 million during the three months ended March 31, 2016 and March 31, 2015, respectively.
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Recent Accounting Pronouncements |
Recent Accounting Pronouncements
Recently Adopted
Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to beginning “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.
Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows.
Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs associated with our senior subordinated notes of $32.8 million have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows.
Not Yet Adopted
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (“ASU 2016-08”) which clarifies the implementation guidance on principal versus agent considerations. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09, ASU 2015-14 and ASU 2016-08 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, 2016, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
|
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). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and 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, 2016, instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, 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 $14 thousand in the fair value of these instruments as of March 31, 2016. |
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
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v3.4.0.3
Basis of Presentation (Tables)
|
3 Months Ended |
Mar. 31, 2016 |
Accounting Policies [Abstract] |
|
Weighted average shares used in the 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 loss per common share calculations for the periods indicated: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Basic weighted average common shares outstanding | | 347,235 |
| | 350,688 |
| Potentially dilutive securities | | |
| | |
| Restricted stock, stock options, SARs and performance-based equity awards | | — |
| | — |
| Diluted weighted average common shares outstanding | | 347,235 |
| | 350,688 |
|
|
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 loss per share, as their effect would have been antidilutive: | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Stock options and SARs | | 7,412 |
| | 10,507 |
| Restricted stock and performance-based equity awards | | 5,097 |
| | 2,948 |
|
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v3.4.0.3
Long-Term Debt (Tables)
|
3 Months Ended |
Mar. 31, 2016 |
Debt Disclosure [Abstract] |
|
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 | | 2016 | | 2015 | Senior Secured Bank Credit Agreement | | $ | 310,000 |
| | $ | 175,000 |
| 6⅜% Senior Subordinated Notes due 2021 | | 396,000 |
| | 400,000 |
| 5½% Senior Subordinated Notes due 2022 | | 1,207,745 |
| | 1,250,000 |
| 4⅝% Senior Subordinated Notes due 2023 | | 1,094,000 |
| | 1,200,000 |
| Other Subordinated Notes, including premium of $6 and $7, respectively | | 2,256 |
| | 2,257 |
| Pipeline financings | | 209,399 |
| | 211,766 |
| Capital lease obligations | | 65,817 |
| | 71,324 |
| Total | | 3,285,217 |
| | 3,310,347 |
| Issuance costs on senior subordinated notes | | (29,803 | ) | | (32,752 | ) | Total, net of debt issuance costs on senior subordinated notes | | 3,255,414 |
| | 3,277,595 |
| Less: current obligations | | (32,917 | ) | | (32,481 | ) | Long-term debt and capital lease obligations | | $ | 3,222,497 |
| | $ | 3,245,114 |
|
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v3.4.0.3
Commodity Derivative Contracts (Tables)
|
3 Months Ended |
Mar. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Commodity derivative contracts not classified as hedging instruments |
The following table summarizes our commodity derivative contracts as of March 31, 2016, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification (“FASC”) Derivatives and Hedging topic: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) | Range (1) | | Weighted Average Price | Swap | | Sold Put | | Floor | | Ceiling | Oil Contracts: | | | | | | | | | | | | | | | | 2016 Enhanced Swaps (2) | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 2,000 | | $ | 90.35 | – | 90.35 |
| | $ | 90.35 |
| | $ | 68.00 |
| | $ | — |
| | $ | — |
| Apr – June | | LLS | | 6,000 | | | 93.30 | – | 93.50 |
| | 93.38 |
| | 70.00 |
| | — |
| | — |
| 2016 Fixed-Price Swaps | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 11,500 | | $ | 60.30 | – | 63.75 |
| | $ | 61.84 |
| | $ | — |
| | $ | — |
| | $ | — |
| Apr – June | | LLS | | 3,500 | | | 64.20 | – | 66.15 |
| | 64.99 |
| | — |
| | — |
| | — |
| July – Sept | | NYMEX | | 16,500 | | | 36.25 | – | 40.65 |
| | 38.24 |
| | — |
| | — |
| | — |
| July – Sept | | LLS | | 7,000 | | | 37.24 | – | 42.15 |
| | 39.61 |
| | — |
| | — |
| | — |
| Oct – Dec | | NYMEX | | 23,000 | | | 36.25 | – | 40.00 |
| | 37.97 |
| | — |
| | — |
| | — |
| Oct – Dec | | LLS | | 7,000 | | | 37.24 | – | 41.00 |
| | 39.16 |
| | — |
| | — |
| | — |
| 2016 Three-Way Collars (3) | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 2,000 | | $ | 85.00 | – | 95.50 |
| | $ | — |
| | $ | 68.00 |
| | $ | 85.00 |
| | $ | 95.50 |
| Apr – June | | LLS | | 2,000 | | | 88.00 | – | 98.25 |
| | — |
| | 70.00 |
| | 88.00 |
| | 98.25 |
| 2016 Collars | | | | | | | | | | | | | | | | | | Apr – June | | NYMEX | | 5,000 | | $ | 55.00 | – | 72.25 |
| | $ | — |
| | $ | — |
| | $ | 55.00 |
| | $ | 71.01 |
| Apr – June | | LLS | | 2,000 | | | 58.00 | – | 73.00 |
| | — |
| | — |
| | 58.00 |
| | 73.00 |
| July – Sept | | NYMEX | | 4,500 | | | 55.00 | – | 72.65 |
| | — |
| | — |
| | 55.00 |
| | 71.22 |
| July – Sept | | LLS | | 3,000 | | | 58.00 | – | 74.30 |
| | — |
| | — |
| | 58.00 |
| | 73.85 |
| 2017 Fixed-Price Swaps | | | | | | | | | | | | | | | | Jan – Mar | | NYMEX | | 20,000 | | $ | 41.15 | – | 44.35 |
| | $ | 42.39 |
| | $ | — |
| | $ | — |
| | $ | — |
| Jan – Mar | | LLS | | 9,000 | | | 42.35 | – | 45.60 |
| | 43.51 |
| | — |
| | — |
| | — |
|
| | (1) | Ranges presented for fixed-price swaps and enhanced 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) | An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes. |
| | (3) | 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. |
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- DefinitionTabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.
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v3.4.0.3
Fair Value Measurements (Tables)
|
3 Months Ended |
Mar. 31, 2016 |
Fair Value Disclosures [Abstract] |
|
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, 2016 | | | | | | | | | Assets | | | | | | | | | Oil derivative contracts – current | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
| Total Assets | | $ | — |
| | $ | 49,758 |
| | $ | 23,040 |
| | $ | 72,798 |
| | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
| Total Liabilities | | $ | — |
| | $ | 25,005 |
| | $ | — |
| | $ | 25,005 |
| | | | | | | | | | December 31, 2015 | | |
| | |
| | |
| | |
| Assets | | |
| | |
| | |
| | |
| Oil derivative contracts – current | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
| Total Assets | | $ | — |
| | $ | 90,012 |
| | $ | 52,834 |
| | $ | 142,846 |
|
|
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, 2016 and 2015: | | | | | | | | | | | | Three Months Ended | | | March 31, | In thousands | | 2016 | | 2015 | Fair value of Level 3 instruments, beginning of period | | $ | 52,834 |
| | $ | 188,446 |
| Fair value adjustments on commodity derivatives | | 281 |
| | 25,085 |
| Payment (receipts) on settlements of commodity derivatives | | (30,075 | ) | | (48,516 | ) | Fair value of Level 3 instruments, end of period | | $ | 23,040 |
| | $ | 165,015 |
| | | | | | 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 | | $ | 133 |
| | $ | 23,099 |
|
|
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 3/31/2016 (in thousands) | | Valuation Technique | | Unobservable Input | | Volatility Range | Oil derivative contracts | | $ | 23,040 |
| | Discounted cash flow / Black-Scholes | | Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2016 | | 26.9% – 38.0% |
|
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- DefinitionTabular disclosure of the inputs and valuation techniques used to measure fair value, and a discussion of changes in valuation techniques and related inputs, if any, applied during the period to each separate class of assets, liabilities, and financial instruments classified in shareholders' equity that are measured on a recurring and/or nonrecurring basis.
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v3.4.0.3
Additional Balance Sheet Details (Tables)
|
3 Months Ended |
Mar. 31, 2016 |
Table Text Block [Abstract] |
|
Accounts Payable and Accrued Liabilities |
Accounts Payable and Accrued Liabilities | | | | | | | | | | | | March 31, | | December 31, | In thousands | | 2016 | | 2015 | Accrued interest | | $ | 44,201 |
| | $ | 48,908 |
| Accounts payable | | 32,688 |
| | 30,477 |
| Accrued lease operating expenses | | 30,169 |
| | 37,549 |
| Taxes payable | | 17,717 |
| | 32,438 |
| Accrued compensation | | 14,403 |
| | 46,780 |
| Accrued exploration and development costs | | 13,500 |
| | 20,892 |
| Other | | 34,037 |
| | 36,153 |
| Total | | $ | 186,715 |
| | $ | 253,197 |
|
|
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- DefinitionAdditional shares included in the calculation of diluted EPS as a result of the potentially dilutive effect of share based payment arrangements using the treasury stock method.
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v3.4.0.3
Basis of Presentation Basis of Presentation (Details Textuals 2) - USD ($) $ in Thousands |
Mar. 31, 2016 |
Dec. 31, 2015 |
Accounting Changes and Error Corrections [Abstract] |
|
|
Current deferred tax assets, Net |
|
$ 1,500
|
Issuance costs on senior subordinated notes |
$ 29,803
|
32,752
|
New Accounting Pronouncement, Early Adoption [Line Items] |
|
|
Accumulated deficit |
(1,228,039)
|
(1,042,882)
|
Other Assets, Current |
8,763
|
10,005
|
Additional Paid in Capital |
$ 2,356,069
|
2,353,134
|
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits [Member] |
|
|
New Accounting Pronouncement, Early Adoption [Line Items] |
|
|
Accumulated deficit |
|
15,700
|
Deferred Tax Liabilities, Net |
|
14,800
|
Other Assets, Current |
|
800
|
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member] |
|
|
New Accounting Pronouncement, Early Adoption [Line Items] |
|
|
Additional Paid in Capital |
|
$ 400
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v3.4.0.3
Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands |
Mar. 31, 2016 |
Dec. 31, 2015 |
Debt Instrument [Line Items] |
|
|
Senior Secured Bank Credit Agreement |
$ 310,000
|
$ 175,000
|
Pipeline financings |
209,399
|
211,766
|
Capital lease obligations |
65,817
|
71,324
|
Total |
3,285,217
|
3,310,347
|
Issuance costs on senior subordinated notes |
(29,803)
|
(32,752)
|
Total, net of debt issuance costs on senior subordinated notes |
3,255,414
|
3,277,595
|
Less current obligations |
(32,917)
|
(32,481)
|
Long-term debt and capital lease obligations |
3,222,497
|
3,245,114
|
6 3/8% Senior Subordinated Notes due 2021 |
|
|
Debt Instrument [Line Items] |
|
|
Senior Subordinated Notes |
$ 396,000
|
400,000
|
Debt Instrument, Interest Rate, Stated Percentage |
6.375%
|
|
5 1/2% Senior Subordinated Notes due 2022 |
|
|
Debt Instrument [Line Items] |
|
|
Senior Subordinated Notes |
$ 1,207,745
|
1,250,000
|
Debt Instrument, Interest Rate, Stated Percentage |
5.50%
|
|
4 5/8% Senior Subordinated Notes due 2023 |
|
|
Debt Instrument [Line Items] |
|
|
Senior Subordinated Notes |
$ 1,094,000
|
1,200,000
|
Debt Instrument, Interest Rate, Stated Percentage |
4.625%
|
|
Other Subordinated Notes |
|
|
Debt Instrument [Line Items] |
|
|
Senior Subordinated Notes |
$ 2,256
|
2,257
|
Including premium of |
$ 6
|
$ 7
|
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v3.4.0.3
Long-Term Debt (Details Textuals)
|
|
3 Months Ended |
|
|
Feb. 17, 2016
USD ($)
|
Mar. 31, 2016
USD ($)
|
Mar. 31, 2015
USD ($)
|
May. 04, 2016
USD ($)
|
Apr. 18, 2016
USD ($)
|
Long Term Debt (Textuals) [Abstract] |
|
|
|
|
|
Interest in guarantor subsidiaries |
|
100.00%
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Weighted average interest rate on Bank Credit Facility |
|
2.40%
|
|
|
|
Senior Notes [Abstract] |
|
|
|
|
|
Gains (Losses) on Extinguishment of Debt |
|
$ 94,991,000
|
$ 0
|
|
|
Debt Instrument, Repurchase Amount |
|
$ 55,500,000
|
|
|
|
Year 2016 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Senior Secured Debt to EBITDAX |
3.0
|
|
|
|
|
EBITDAX to Consolidated Interest |
1.25
|
|
|
|
|
Year 2017 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Senior Secured Debt to EBITDAX |
3.0
|
|
|
|
|
EBITDAX to Consolidated Interest |
1.25
|
|
|
|
|
Q1 | Year 2018 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Total Net Debt to EBITDAX Requirement |
|
6.0
|
|
|
|
Q1 | Year 2019 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Total Net Debt to EBITDAX Requirement |
|
4.25
|
|
|
|
Q2 | Year 2018 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Total Net Debt to EBITDAX Requirement |
|
5.5
|
|
|
|
Q3 | Year 2018 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Total Net Debt to EBITDAX Requirement |
|
5.0
|
|
|
|
Q4 | Year 2018 |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Total Net Debt to EBITDAX Requirement |
|
5.0
|
|
|
|
Line of Credit |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage |
0.50%
|
|
|
|
|
5 1/2% Senior Subordinated Notes due 2022 |
|
|
|
|
|
Senior Notes [Abstract] |
|
|
|
|
|
Debt Instrument, Repurchased Face Amount |
|
$ 42,300,000
|
|
|
|
6 3/8% Senior Subordinated Notes due 2021 |
|
|
|
|
|
Senior Notes [Abstract] |
|
|
|
|
|
Debt Instrument, Repurchased Face Amount |
|
4,000,000
|
|
|
|
4 5/8% Senior Subordinated Notes due 2023 |
|
|
|
|
|
Senior Notes [Abstract] |
|
|
|
|
|
Debt Instrument, Repurchased Face Amount |
|
$ 106,000,000
|
|
|
|
Subsequent Event |
|
|
|
|
|
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
|
Maximum amount of junior lien debt permitted |
|
|
|
|
$ 1,000,000,000.0
|
Senior Notes [Abstract] |
|
|
|
|
|
Stock Repurchase Program, Remaining Authorized Repurchase Amount |
|
|
|
$ 169,500,000
|
|
Cash and Cash Equivalents [Member] | Line of Credit |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Credit Facility Covenants |
$ 225,000,000
|
|
|
|
|
Maximum Outstanding Credit Facility Balance [Member] | Line of Credit |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Credit Facility Covenants |
250,000,000
|
|
|
|
|
Senior Subordinated Notes [Member] | Line of Credit |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Credit Facility Covenants |
$ 225,000,000
|
|
|
|
|
Base Rate [Member] | Line of Credit | Minimum |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Interest Rate Margins on Bank Credit Facility |
1.00%
|
|
|
|
|
Base Rate [Member] | Line of Credit | Maximum |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Interest Rate Margins on Bank Credit Facility |
2.00%
|
|
|
|
|
London Interbank Offered Rate (LIBOR) [Member] | Line of Credit | Minimum |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Interest Rate Margins on Bank Credit Facility |
2.00%
|
|
|
|
|
London Interbank Offered Rate (LIBOR) [Member] | Line of Credit | Maximum |
|
|
|
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
|
|
|
Interest Rate Margins on Bank Credit Facility |
3.00%
|
|
|
|
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v3.4.0.3
Commodity Derivative Contracts (Details)
|
Mar. 31, 2016
bbl / d
$ / Barrel
|
Enhanced Swaps | Year 2016 | Q2 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
2,000
|
Weighted average swap price |
90.35
|
Weighted average sold put price |
68.00
|
Enhanced Swaps | Year 2016 | Q2 | NYMEX | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
90.35
|
Enhanced Swaps | Year 2016 | Q2 | NYMEX | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
90.35
|
Enhanced Swaps | Year 2016 | Q2 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
6,000
|
Weighted average swap price |
93.38
|
Weighted average sold put price |
70.00
|
Enhanced Swaps | Year 2016 | Q2 | LLS | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
93.30
|
Enhanced Swaps | Year 2016 | Q2 | LLS | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
93.50
|
Swap | Year 2016 | Q2 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
11,500
|
Weighted average swap price |
61.84
|
Swap | Year 2016 | Q2 | NYMEX | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
60.30
|
Swap | Year 2016 | Q2 | NYMEX | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
63.75
|
Swap | Year 2016 | Q2 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
3,500
|
Weighted average swap price |
64.99
|
Swap | Year 2016 | Q2 | LLS | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
64.20
|
Swap | Year 2016 | Q2 | LLS | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
66.15
|
Swap | Year 2016 | Q3 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
16,500
|
Weighted average swap price |
38.24
|
Swap | Year 2016 | Q3 | NYMEX | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
36.25
|
Swap | Year 2016 | Q3 | NYMEX | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
40.65
|
Swap | Year 2016 | Q3 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
7,000
|
Weighted average swap price |
39.61
|
Swap | Year 2016 | Q3 | LLS | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
37.24
|
Swap | Year 2016 | Q3 | LLS | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
42.15
|
Swap | Year 2016 | Q4 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
23,000
|
Weighted average swap price |
37.97
|
Swap | Year 2016 | Q4 | NYMEX | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
36.25
|
Swap | Year 2016 | Q4 | NYMEX | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
40.00
|
Swap | Year 2016 | Q4 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
7,000
|
Weighted average swap price |
39.16
|
Swap | Year 2016 | Q4 | LLS | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
37.24
|
Swap | Year 2016 | Q4 | LLS | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
41.00
|
Swap | Year 2017 | Q1 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
20,000
|
Weighted average swap price |
42.39
|
Swap | Year 2017 | Q1 | NYMEX | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
41.15
|
Swap | Year 2017 | Q1 | NYMEX | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
44.35
|
Swap | Year 2017 | Q1 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
9,000
|
Weighted average swap price |
43.51
|
Swap | Year 2017 | Q1 | LLS | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
42.35
|
Swap | Year 2017 | Q1 | LLS | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
45.60
|
Three-way Collar | Year 2016 | Q2 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
2,000
|
Derivative, Floor Price |
85.00
|
Derivative, Cap Price |
95.50
|
Weighted average sold put price |
68.00
|
Weighted average floor price |
85.00
|
Weighted average ceiling price |
95.50
|
Three-way Collar | Year 2016 | Q2 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
2,000
|
Derivative, Floor Price |
88.00
|
Derivative, Cap Price |
98.25
|
Weighted average sold put price |
70.00
|
Weighted average floor price |
88.00
|
Weighted average ceiling price |
98.25
|
Collar | Year 2016 | Q2 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
5,000
|
Derivative, Floor Price |
55.00
|
Derivative, Cap Price |
72.25
|
Weighted average floor price |
55.00
|
Weighted average ceiling price |
71.01
|
Collar | Year 2016 | Q2 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
2,000
|
Derivative, Floor Price |
58.00
|
Derivative, Cap Price |
73.00
|
Weighted average floor price |
58.00
|
Weighted average ceiling price |
73.00
|
Collar | Year 2016 | Q3 | NYMEX |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
4,500
|
Derivative, Floor Price |
55.00
|
Derivative, Cap Price |
72.65
|
Weighted average floor price |
55.00
|
Weighted average ceiling price |
71.22
|
Collar | Year 2016 | Q3 | LLS |
|
Derivative [Line Items] |
|
Volume per Day | bbl / d |
3,000
|
Derivative, Floor Price |
58.00
|
Derivative, Cap Price |
74.30
|
Weighted average floor price |
58.00
|
Weighted average ceiling price |
73.85
|
X |
- DefinitionAggregate notional amount of derivative expressed in nonmonetary units. For example, the number of barrels specified in a fuel oil forward purchase contract.
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v3.4.0.3
Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands |
Mar. 31, 2016 |
Dec. 31, 2015 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current asset |
$ 72,798
|
$ 142,846
|
Total Assets |
72,798
|
142,846
|
Oil derivative contracts - current liability |
25,005
|
0
|
Total Liabilities |
25,005
|
|
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
|
0
|
Total Assets |
0
|
0
|
Oil derivative contracts - current liability |
0
|
|
Total Liabilities |
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 |
49,758
|
90,012
|
Total Assets |
49,758
|
90,012
|
Oil derivative contracts - current liability |
25,005
|
|
Total Liabilities |
25,005
|
|
Significant Unobservable Inputs (Level 3) |
|
|
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current asset |
23,040
|
52,834
|
Total Assets |
23,040
|
$ 52,834
|
Oil derivative contracts - current liability |
0
|
|
Total Liabilities |
$ 0
|
|
X |
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Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands |
3 Months Ended |
Mar. 31, 2016 |
Mar. 31, 2015 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] |
|
|
Fair value of Level 3 instruments, beginning of period |
$ 52,834
|
$ 188,446
|
Fair value adjustments on commodity derivatives |
281
|
25,085
|
Payment (receipts) on settlements of commodity derivatives |
(30,075)
|
(48,516)
|
Fair value of Level 3 instruments, end of period |
23,040
|
165,015
|
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 |
$ 133
|
$ 23,099
|
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3 Months Ended |
|
|
|
Mar. 31, 2016 |
Dec. 31, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] |
|
|
|
|
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs |
$ 23,040
|
$ 52,834
|
$ 165,015
|
$ 188,446
|
Income Approach Valuation Technique |
|
|
|
|
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] |
|
|
|
|
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs |
$ 23,040
|
|
|
|
Income Approach Valuation Technique | Minimum |
|
|
|
|
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] |
|
|
|
|
Expected Volatility Range |
26.90%
|
|
|
|
Income Approach Valuation Technique | Maximum |
|
|
|
|
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] |
|
|
|
|
Expected Volatility Range |
38.00%
|
|
|
|
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v3.4.0.3
Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands |
Mar. 31, 2016 |
Dec. 31, 2015 |
Accounts Payable and Accrued Liabilities, Current [Abstract] |
|
|
Accrued interest |
$ 44,201
|
$ 48,908
|
Accounts payable |
32,688
|
30,477
|
Accrued lease operating expenses |
30,169
|
37,549
|
Taxes payable |
17,717
|
32,438
|
Accrued compensation |
14,403
|
46,780
|
Accrued exploration and development costs |
13,500
|
20,892
|
Other |
34,037
|
36,153
|
Total |
$ 186,715
|
$ 253,197
|
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v3.4.0.3
Subsequent Event (Details Textuals) - Subsequent Event shares in Millions, $ in Millions |
May. 06, 2016
USD ($)
Rate
shares
|
Subsequent Event [Line Items] |
|
Debt Conversion, Original Debt, Amount |
$ 922.5
|
Debt Conversion, Converted Instrument, Amount |
$ 531.2
|
Debt Conversion, Converted Instrument, Rate | Rate |
9.00%
|
Debt Conversion, Converted Instrument, Shares Issued | shares |
36.9
|
X |
- DefinitionThe value of the financial instrument(s) that the original debt is being converted into in a noncash (or part noncash) transaction. "Part noncash" refers to that portion of the transaction not resulting in cash receipts or cash payments in the period.
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