10-Q

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, 2017

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)

Delaware	20-0467835
(State or other jurisdictionof incorporation or organization)	(I.R.S. EmployerIdentification No.)
5320 Legacy Drive, Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
		(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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.

Class	Outstanding at April 30, 2017
Common Stock, $.001 par value	398,337,400

Denbury Resources Inc.

Table of Contents

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	3
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29
Item 4.	Controls and Procedures	31
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	34
	Signatures	35

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

	March 31,			December 31,
	2017			2016
Assets
Current assets
Cash and cash equivalents	$	1,747		$	1,606
Accrued production receivable	118,483			124,936
Trade and other receivables, net	55,653			43,900
Derivative assets	1,062			—
Other current assets	11,324			10,684
Total current assets	188,269			181,126
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	10,475,877			10,419,827
Unevaluated properties	951,220			927,819
CO2 properties	1,187,711			1,188,467
Pipelines and plants	2,285,435			2,285,812
Other property and equipment	373,537			378,776
Less accumulated depletion, depreciation, amortization and impairment	(11,255,392		)	(11,212,327		)
Net property and equipment	4,018,388			3,988,374
Other assets	102,002			105,078
Total assets	$	4,308,659		$	4,274,578
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	180,529		$	200,266
Oil and gas production payable	73,250			80,585
Derivative liabilities	18,799			69,279
Current maturities of long-term debt (including future interest payable of $50,349 and $50,349, respectively – see Note 2)	83,701			83,366
Total current liabilities	356,279			433,496
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $178,476 and $178,476, respectively – see Note 2)	2,956,385			2,909,732
Asset retirement obligations	151,390			146,807
Deferred tax liabilities, net	328,786			293,878
Other liabilities	22,060			22,217
Total long-term liabilities	3,458,621			3,372,634
Commitments and contingencies (Note 6)
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $.001 par value, 600,000,000 shares authorized; 402,706,108 and 402,334,655 shares issued, respectively	403			402
Paid-in capital in excess of par	2,540,057			2,534,670
Accumulated deficit	(1,997,455		)	(2,018,989		)
Treasury stock, at cost, 4,403,152 and 3,906,877 shares, respectively	(49,246		)	(47,635		)
Total stockholders’ equity	493,759			468,448
Total liabilities and stockholders’ equity	$	4,308,659		$	4,274,578

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)

	Three Months Ended March 31,
	2017			2016
Revenues and other income
Oil, natural gas, and related product sales	$	266,178		$	187,803
CO2 sales and transportation fees	5,388			6,272
Interest income and other income	3,888			769
Total revenues and other income	275,454			194,844
Expenses
Lease operating expenses	113,840			102,447
Marketing and plant operating expenses	14,065			13,194
CO2 discovery and operating expenses	593			607
Taxes other than income	22,440			20,092
General and administrative expenses	28,241			33,901
Interest, net of amounts capitalized of $4,654 and $5,780, respectively	27,178			42,171
Depletion, depreciation, and amortization	51,195			77,366
Commodity derivatives expense (income)	(24,602		)	22,826
Gain on debt extinguishment	—			(94,991		)
Write-down of oil and natural gas properties	—			256,000
Other expenses	—			1,544
Total expenses	232,950			475,157
Income (loss) before income taxes	42,504			(280,313		)
Income tax provision (benefit)	20,974			(95,120		)
Net income (loss)	$	21,530		$	(185,193	)
Net income (loss) per common share
Basic	$	0.06		$	(0.53	)
Diluted	$	0.05		$	(0.53	)
Weighted average common shares outstanding
Basic	389,397			347,235
Diluted	392,997			347,235

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	21,530		$	(185,193	)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	51,195			77,366
Write-down of oil and natural gas properties	—			256,000
Deferred income taxes	34,909			(95,115		)
Stock-based compensation	4,106			859
Commodity derivatives expense (income)	(24,602		)	22,826
Receipt (payment) on settlements of commodity derivatives	(26,940		)	72,227
Gain on debt extinguishment	—			(94,991		)
Debt issuance costs and discounts	1,901			3,306
Other, net	(344		)	(416		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	6,453			4,479
Trade and other receivables	(12,185		)	812
Other current and long-term assets	643			1,437
Accounts payable and accrued liabilities	(23,890		)	(53,548		)
Oil and natural gas production payable	(7,335		)	(7,572		)
Other liabilities	(1,179		)	(448		)
Net cash provided by operating activities	24,262			2,029
Cash flows from investing activities
Oil and natural gas capital expenditures	(52,152		)	(65,692		)
Acquisitions of oil and natural gas properties	(16,222		)	(224		)
Pipelines and plants capital expenditures	(246		)	(635		)
Net proceeds from sales of oil and natural gas properties and equipment	415			—
Other	608			(403		)
Net cash used in investing activities	(67,597		)	(66,954		)
Cash flows from financing activities
Bank repayments	(343,000		)	(696,000		)
Bank borrowings	397,000			831,000
Repurchases of senior subordinated notes	—			(55,521		)
Pipeline financing and capital lease debt repayments	(7,055		)	(7,387		)
Other	(3,469		)	(1,727		)
Net cash provided by financing activities	43,476			70,365
Net increase in cash and cash equivalents	141			5,440
Cash and cash equivalents at beginning of period	1,606			2,812
Cash and cash equivalents at end of period	$	1,747		$	8,252

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5

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, 2016 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2017, our consolidated results of operations for the three months endedMarch 31, 2017 and 2016, and our consolidated cash flows for the three months ended March 31, 2017 and 2016.

Reclassifications

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

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock and nonvested performance-based equity awards.  For the three months endedMarch 31, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

	Three Months Ended
	March 31,
In thousands	2017	2016
Basic weighted average common shares outstanding	389,397	347,235
Potentially dilutive securities
Restricted stock and performance-based equity awards	3,600	—
Diluted weighted average common shares outstanding	392,997	347,235

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

6

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

	Three Months Ended
	March 31,
In thousands	2017	2016
Stock appreciation rights	5,044	7,412
Restricted stock and performance-based equity awards	1,229	5,097

2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a ceiling test write-down during the three months endedMarch 31, 2017.

Recent Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and early adoption is permitted. Effective January 1, 2017, we adopted ASU 2017-01. The adoption of ASU 2017-01 did not have a material impact on our current period consolidated financial statements.

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

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is still evaluating this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.

7

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:

	March 31,			December 31,
In thousands	2017			2016
Senior Secured Bank Credit Agreement	$	355,000		$	301,000
9% Senior Secured Second Lien Notes due 2021	614,919			614,919
6⅜% Senior Subordinated Notes due 2021	215,144			215,144
5½% Senior Subordinated Notes due 2022	772,912			772,912
4⅝% Senior Subordinated Notes due 2023	622,297			622,297
Other Subordinated Notes, including premium of $2 and $3, respectively	2,252			2,253
Pipeline financings	200,038			202,671
Capital lease obligations	43,649			48,718
Total debt principal balance	2,826,211			2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)	228,825			228,825
Issuance costs on senior secured second lien and senior subordinated notes	(14,950		)	(15,641		)
Total debt, net of debt issuance costs	3,040,086			2,993,098
Less: current maturities of long-term debt (1)	(83,701		)	(83,366		)
Long-term debt and capital lease obligations	$	2,956,385		$	2,909,732

(1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. In May 2017, as part of our semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with the next such redetermination scheduled for November 2017. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 3.2% as of March 31, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

In conjunction with the May 2017 borrowing base redetermination, we amended certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders. The amendments to the Bank Credit Agreement included the following:

• Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;

• Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

8

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

• Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and

• Increasing the applicable margin for ABR Loans and LIBOR Loans by 50 basis points such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum.

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

2016 Repurchases of Senior Subordinated Notes

During the first quarter of 2016, we repurchased a total of $152.3 million of our outstanding long-term indebtedness, consisting of $4.0 million principal amount of our 6⅜% Senior Subordinated Notes due 2021, $42.3 million principal amount of our 5½% Senior Subordinated Notes due 2022, and $106.0 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off, during the three months ended March 31, 2016. As of May 3, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on repurchases or other redemptions of our senior subordinated notes.

Note 3. Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. As of March 31, 2017, we had $36.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of falling commodity prices, combined with a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $36.5 million during 2015 and 2016, which reduced the carrying value of these deferred tax assets to zero as of December 31, 2016. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.

As of March 31, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of March 31, 2017.

Note 4. Commodity Derivative Contracts

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

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

9

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2017, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of March 31, 2017, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range (1)				Weighted Average Price
							Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2017 Fixed-Price Swaps
Apr – June	NYMEX	22,000	$	41.20	–	46.50	$	43.99	$	—	$	—	$	—
Apr – June	LLS	7,000		42.65	–	46.65	45.35		—		—		—
2017 Collars
Oct – Dec	NYMEX	1,000	$	40.00	–	70.00	$	—	$	—	$	40.00	$	70.00
2017 Three-Way Collars(2)
July – Sept	NYMEX	14,500	$	40.00	–	70.25	$	—	$	30.00	$	40.00	$	69.09
July – Sept	LLS	2,000		41.00	–	69.25	—		31.00		41.00		69.25
Oct – Dec	NYMEX	11,000		40.00	–	70.20	—		30.00		40.00		69.67
Oct – Dec	LLS	1,000		41.00	–	70.25	—		31.00		41.00		70.25

(1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Note 5. Fair Value Measurements

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

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

10

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

• Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At March 31, 2017, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $2 thousand in the fair value of these instruments as of March 31, 2017.

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

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2017
Assets
Oil derivative contracts – current	$	—	$	971	$	91	$	1,062
Total Assets	$	—	$	971	$	91	$	1,062
Liabilities
Oil derivative contracts – current	$	—	$	18,799	$	—	$	18,799
Total Liabilities	$	—	$	18,799	$	—	$	18,799
December 31, 2016
Liabilities
Oil derivative contracts – current	$	—	$	68,753	$	526	$	69,279
Total Liabilities	$	—	$	68,753	$	526	$	69,279

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 endedMarch 31, 2017 and 2016:

	Three Months Ended
	March 31,
In thousands	2017			2016
Fair value of Level 3 instruments, beginning of period	$	(526	)	$	52,834
Fair value gains on commodity derivatives	617			281
Receipts on settlements of commodity derivatives	—			(30,075		)
Fair value of Level 3 instruments, end of period	$	91		$	23,040
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	236		$	133

We utilize an income approach to value our Level 3 costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:

	Fair Value at 3/31/2017 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	91	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2017	22.8% – 34.2%

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices. The estimated fair value of the principal amount of our debt as of March 31, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $2,231.3 million and $2,327.8 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 6. Commitments and Contingencies

Commitments

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

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Riley Ridge Helium Supply Contract Claim

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

Note 7. Additional Balance Sheet Details

Trade and Other Receivables, Net

	March 31,		December 31,
In thousands	2017		2016
Trade accounts receivable, net	$	17,346	$	20,084
Federal income tax receivable	14,054		—
Other receivables	24,253		23,816
Total	$	55,653	$	43,900

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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, 2016 (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 the Form 10-K, 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 Impact on Our Business.  Our financial results are significantly impacted by changes in oil prices, as 97% of our production is oil. Our realized oil price averaged $50.31 per Bbl in the first quarter of 2017, and although that was significantly lower than oil prices a few years ago, averaging over $90 per Bbl in 2014, first quarter prices were 64% higher than our average realized oil price in the first quarter of 2016 of $30.71 per Bbl. We utilize commodity derivative contracts to hedge a portion of our production and thereby limit to some degree our exposure to significant changes in oil prices. As such, our realized oil price, including the impact from hedge settlements, was only 6% higher when comparing the first quarters of 2016 and 2017.

Operating Highlights. We recognized net income of $21.5 million, or $0.05 per diluted common share, during the first quarter of 2017, compared to a net loss of $185.2 million, or $0.53 per diluted common share, during the first quarter of 2016. This change to a net income position from a net loss during the first quarter of 2016 was primarily due to prior year’s first quarter results including a $256.0 million full cost pool ceiling test write-down of our oil and natural gas properties, offset in part by a $95.0 million gain on extinguishment of debt. Additional factors leading to the 2017 period’s improved results included (1) a $78.4 million (42%) increase in oil and natural gas revenues, which was primarily driven by an increase in oil prices, (2) a $47.4 million increase in commodity derivatives income, consisting of an increase in income from noncash fair value adjustments of $146.6 million, partially offset by additional expense from reduced cash receipts from settlements of commodity derivative contracts between the two periods, (3) a $26.2 million (34%) decrease in depletion, depreciation, and amortization, and (4) a $15.0 million (36%) decrease in interest expense, net.

We generated $24.3 million of cash flows from operating activities in the first quarter of 2017, an increase of $22.2 million from the first quarter of 2016. The increase in cash flows from operations was due primarily to a $78.4 million increase in oil and natural gas revenues driven by higher oil commodity prices, which was offset by a $99.2 million decline in derivative receipts ($26.9 million of net payments during the first quarter of 2017 compared to $72.2 million of net receipts during the first quarter of 2016), a $15.0 million decrease in interest expense, and lower comparative working capital outflows ($37.5 million during the first quarter of 2017 compared to $54.8 million during the first quarter of 2016).

During the first quarter of 2017, our continuing oil and natural gas production averaged 59,933 BOE/d, compared to an average of 60,685 BOE/d produced during the fourth quarter of 2016 and 67,682 BOE/d produced during the first quarter of 2016. Although a majority of the 11% decline in continuing production from the first quarter of 2016 was due to natural declines as our capital spending levels were not sufficient to maintain production levels, production was also impacted by weather-related downtime and downtime as we expanded our tertiary development and performed conformance work. See Results of Operations – Production for further discussion. Our 2017 capital spending has been budgeted at approximately $300 million, excluding capitalized interest and acquisitions, a 44% increase over our 2016 capital spending level. Based on NYMEX futures prices in mid-February 2017, when we announced our capital budget, it was expected that our projected cash flow from operations would fund all but a minor amount of this capital spending. With this increased capital spending level, we currently anticipate our 2017 average annual production rate remaining relatively flat with our exit rate in 2016 of roughly 60,000 BOE/d.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $50.31 per Bbl during the first quarter of 2017, an increase of 64% compared to $30.71 per Bbl realized during the first quarter of 2016 and an increase

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

of 5% when compared to $48.03 per Bbl realized during the fourth quarter of 2016. The oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) was $1.64 per Bbl below NYMEX prices in the first quarter of 2017, compared to a negative$3.02 per-Bbl NYMEX differential in the first quarter of 2016 and a negative $1.22 per-Bbl NYMEX differential in the fourth quarter of 2016. The improvement in our oil price differential in comparison to its level in the first quarter of 2016 was principally due to improvements of our Light Louisiana Sweet (“LLS”) premium relative to NYMEX oil prices and Rocky Mountain region price differentials.

2017 West Yellow Creek Field Acquisition. In March 2017, we completed the acquisition of an approximate 48% non-operating working interest in West Yellow Creek Field in Mississippi for approximately $16 million (before closing adjustments). West Yellow Creek Field currently has minimal production and proved reserves, as the operator is in the process of converting the field to a CO₂ EOR flood and has invested significant capital in that development. Having available CO₂ was a primary factor in being able to enter into this joint venture, and as part of the transaction, we will sell CO₂ to the operator. Based on current plans, we expect capital expenditures on this development to be less than $10 million in 2017, with first tertiary production expected from the field in late 2017 or early 2018.

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. Our cash flow from operations increased from $2.0 million during the three months ended March 31, 2016, to $24.3 million during the three months ended March 31, 2017. In the first half of 2017, we have oil price swaps in place on approximately half of our anticipated oil production at per-barrel prices in the low-to-mid $40’s. As oil prices have been above these levels for the first part of the year, our cash flow for the first quarter of 2017 was negatively impacted by $26.9 million due to these hedges, and we anticipate that our second quarter cash flows could be similarly impacted if oil prices remain in the low to mid-$50’s. As such, we anticipate our cash flow from operations will be higher in the second half of 2017 assuming oil prices remain somewhat consistent throughout the year.

Our development capital budget for 2017 is currently estimated at $300 million, before acquisitions and capitalized interest, and we expect that our cash flow operations should cover most of our capital budget, using an average oil price for 2017 in the mid-$50’s (see Capital Spending below for further discussion). To the extent our cash flows from operations is less than our capital spending, we currently plan to fund those expenditures in the near term with incremental borrowings under our bank credit facility. If oil prices were to decrease or changes in operating results were to cause a reduction in anticipated 2017 cash flows significantly below our currently forecasted operating cash flows, we could reduce our capital expenditures, as only a small portion of our planned capital spending is subject to contracts that cannot be terminated. If we reduce our capital spending due to lower cash flows, any sizeable reduction could negatively impact our production levels in future periods.

The preservation of cash and liquidity remains a significant priority for us in the current oil price environment. We have taken steps to lower our costs in all categories of our business, and we have made significant progress in that regard. As of March 31, 2017, we had $355.0 million drawn on our $1.05 billion senior secured bank credit facility, leaving us $622.9 million of current liquidity after consideration of $72.1 million of outstanding letters of credit. This liquidity, coupled with our other cost saving and liquidity preservation measures and the improvement in oil prices, should be sufficient to cover any foreseeable cash flow shortfall between our cash flow from operations and capital spending.

Since we do not expect oil prices to return in the foreseeable future to recent historical highs of 2014, we have adjusted, and must continue to adjust, our business to compete in an oil price environment that is likely not as robust as it was a few years ago, requiring reductions in overall debt levels over time. Our subordinated debt is currently trading significantly higher than it was a year ago, making it more difficult to make accretive exchanges or repurchases of this debt. We would like to reduce our debt further if possible, and we plan to monitor the market and be opportunistic in any debt transactions based on market conditions. These potential transactions could include purchases of our subordinated debt in the open market, cash tenders for our debt or public or privately negotiated debt exchanges, and future potential debt reduction with proceeds of issuances of equity, asset sales and other cash-generating activities. We are entitled to utilize up to an additional $148.3 million of the availability under our senior secured bank credit facility for such repurchases and may also consider using other forms of capital such as second lien notes or other senior notes.

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”). In May

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

2017, as part of our semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with the next such redetermination scheduled for November 2017. As of March 31, 2017, we had $355.0 million of debt outstanding and $72.1 million in letters of credit on the senior secured bank credit facility, leaving us with significant liquidity. The Bank Credit Agreement contains certain restrictive covenants and financial performance covenants through the maturity of the facility. In conjunction with the May 2017 borrowing base redetermination, we amended certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders. The amendments to the Bank Credit Agreement included the following:

• Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;

• Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

• Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and

• Increasing the applicable margin for ABR Loans and LIBOR Loans by 50 basis points such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum.

The requirement to maintain a current ratio of 1.0 to 1.0 was not amended, and so remains in place. Also, incurrence of additional debt (separate from debt under the credit facility) in connection with certain events remains subject to a Total Leverage Test unless the consolidated total net debt to EBITDAX ratio is reduced on a pro forma basis by the event. For our financial performance covenant calculations as of March 31, 2017, our ratio of consolidated senior secured debt to consolidated EBITDAX was 0.91 to 1.0 (based upon a maximum permitted ratio of 3.0 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 2.30 to 1.0 (based upon a required ratio of not less than 1.25 to 1.0), and our current ratio was 3.19 to 1.0 (based upon a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of May 3, 2017, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our bank covenants during the remainder of 2017 and 2018.

All of the above descriptions of our Bank Credit Agreement and the amendments thereto are qualified by the express language and defined terms contained in the Bank Credit Agreement and the Fourth Amendment to the Bank Credit Agreement dated May 3, 2017, each of which are filed as exhibits to our periodic reports filed with the SEC.

Capital Spending. We currently anticipate that our full-year 2017 capital budget, excluding capitalized interest and acquisitions, will be approximately $300 million, which includes approximately $55 million in capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.  This combined 2017 capital budget amount, excluding capitalized interest and acquisitions, is comprised of the following:

• $175 million allocated for tertiary oil field expenditures;

• $60 million allocated for other areas, primarily non-tertiary oil field expenditures;

• $10 million to be spent on CO₂ sources and pipelines; and

• $55 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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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 31,2017 and 2016:

	Three Months Ended
	March 31,
In thousands	2017		2016
Capital expenditures by project
Tertiary oil fields	$	21,207	$	31,964
Non-tertiary fields	18,440		5,873
Capitalized internal costs (1)	13,646		14,473
Oil and natural gas capital expenditures	53,293		52,310
Other	10		8
Capital expenditures, before acquisitions and capitalized interest	53,303		52,318
Acquisitions of oil and natural gas properties	16,098		224
Capital expenditures, before capitalized interest	69,401		52,542
Capitalized interest	4,654		5,780
Capital expenditures, total	$	74,055	$	58,322

(1) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

For the three months ended March 31, 2017, our capital expenditures and property acquisitions were funded with $24.3 million of cash flows from operations, with additional funds provided by borrowings on our Bank Credit Agreement. For the three months ended March 31, 2016, our capital expenditures and property acquisitions were funded primarily with borrowings on our Bank Credit Agreement, as our cash flow was used primarily to cover other working capital changes.

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

Our commitments and obligations consist of those detailed as of December 31, 2016, 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.

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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 endedMarch 31, 2017 and 2016 are included in the following table:

	Three Months Ended
	March 31,
In thousands, except per-share and unit data	2017			2016
Operating results
Net income (loss) (1)	$	21,530		$	(185,193	)
Net income (loss) per common share – basic (1)	0.06			(0.53		)
Net income (loss) per common share – diluted (1)	0.05			(0.53		)
Net cash provided by operating activities	24,262			2,029
Average daily production volumes
Bbls/d	58,303			66,139
Mcf/d	9,778			19,270
BOE/d (2)	59,933			69,351
Operating revenues
Oil sales	$	263,974		$	184,816
Natural gas sales	2,204			2,987
Total oil and natural gas sales	$	266,178		$	187,803
Commodity derivative contracts (3)
Receipt (payment) on settlements of commodity derivatives	$	(26,940	)	$	72,227
Noncash fair value gains (losses) on commodity derivatives (4)	51,542			(95,053		)
Commodity derivatives income (expense)	$	24,602		$	(22,826	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	50.31		$	30.71
Natural gas price per Mcf	2.50			1.70
Unit prices – including impact of derivative settlements (3)
Oil price per Bbl	$	45.17		$	42.71
Natural gas price per Mcf	2.50			1.70
Oil and natural gas operating expenses
Lease operating expenses	$	113,840		$	102,447
Marketing expenses, net of third-party purchases, and plant operating expenses	10,088			11,592
Production and ad valorem taxes	20,841			17,178
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	49.35		$	29.76
Lease operating expenses	21.11			16.23
Marketing expenses, net of third-party purchases, and plant operating expenses	1.87			1.84
Production and ad valorem taxes	3.86			2.72
CO2 sources – revenues and expenses
CO2 sales and transportation fees	$	5,388		$	6,272
CO2 discovery and operating expenses	(593		)	(607		)
CO2 revenue and expenses, net	$	4,795		$	5,665

(1) Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $256.0 million for the three months endedMarch 31, 2016.

(2) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

(3) See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.

(4) Noncash fair value gains (losses) 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 gains (losses) on commodity derivatives represent only the net changes 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 payments on settlements of $26.9 million for the three months endedMarch 31, 2017 compared to receipts on settlements of $72.2 million for the three months ended March 31, 2016. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon 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 gains (losses) 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.

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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 2016 and for the first quarter of 2017 is shown below:

	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter
Operating Area	2016	2016	2016	2016	2017
Tertiary oil production
Gulf Coast region
Mature properties (1)	9,666	9,415	8,653	8,440	8,111
Delhi	3,971	3,996	4,262	4,387	4,991
Hastings	5,068	4,972	4,729	4,552	4,288
Heidelberg	5,346	5,246	5,000	4,924	4,730
Oyster Bayou	5,494	5,088	4,767	4,988	5,075
Tinsley	7,899	7,335	6,756	6,786	6,666
Total Gulf Coast region	37,444	36,052	34,167	34,077	33,861
Rocky Mountain region
Bell Creek	3,020	3,160	3,032	3,269	3,209
Total Rocky Mountain region	3,020	3,160	3,032	3,269	3,209
Total tertiary oil production	40,464	39,212	37,199	37,346	37,070
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	673	1,017	963	745	1,342
Texas	6,148	4,104	4,234	5,143	4,333
Other	549	456	538	569	495
Total Gulf Coast region	7,370	5,577	5,735	6,457	6,170
Rocky Mountain region
Cedar Creek Anticline	17,778	16,325	16,017	15,186	15,067
Other	2,070	1,862	1,763	1,696	1,626
Total Rocky Mountain region	19,848	18,187	17,780	16,882	16,693
Total non-tertiary production	27,218	23,764	23,515	23,339	22,863
Total continuing production	67,682	62,976	60,714	60,685	59,933
Property sales
Williston Assets (2)	1,364	1,267	819	—	—
Other property divestitures	305	263	—	—	—
Total production	69,351	64,506	61,533	60,685	59,933

(1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields.

(2) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Total Production

Total continuing production during the first quarter of 2017 averaged 59,933 BOE/d, including 37,070 Bbls/d from tertiary properties and 22,863 BOE/d from non-tertiary properties. Total continuing production excludes production from the Williston Assets that were sold during the third quarter of 2016 and other minor property divestitures, which production totaled 1,669 BOE/d during the first quarter of 2016. This total continuing production level represents a decrease of 752 BOE/d (1%) compared to fourth quarter of 2016 production levels and a decrease of 7,749 BOE/d (11%) compared to first quarter of 2016 production levels.

Our production during the three months endedMarch 31, 2017 was 97% oil, slightly higher than our 95% oil production during the three months endedMarch 31, 2016.

Tertiary Production

Oil production from our tertiary operations during the first quarter of 2017decreased276 Bbls/d (1%) when comparing the fourth quarter of 2016 and the first quarter of 2017 and decreased3,394 Bbls/d (8%) compared to the same period in 2016. These decreases were primarily due to natural production declines at most of our fields in the Gulf Coast region due to the lower capital expenditure level throughout 2016 and downtime at Hastings Field as we expand our tertiary development and perform conformance work, partially offset by both increased production due to continued CO₂ enhanced oil recovery response and natural gas liquids volumes from the plant at Delhi Field in the Gulf Coast region, which began operation in late 2016. The year-to-year first quarter decline in production was further offset by increased quarterly production at Bell Creek Field in the Rocky Mountain region.

Non-Tertiary Production

Continuing production from our non-tertiary operations averaged 22,863 BOE/d during the first quarter of 2017, a decrease of 476 BOE/d (2%) compared to the fourth quarter of 2016 and a decrease of 4,355 BOE/d (16%) compared to the first quarter of 2016 levels. The year-over-year and sequential quarter production declines include unplanned downtime caused by power disruptions at Thompson Field in the Gulf Coast region and winter storms impacting production at Cedar Creek Anticline (“CCA”) in the Rocky Mountain region. During the first quarter of 2017, we did not have any gas production at Conroe Field, which previously averaged over 3,000 Mcf/d during the fourth quarter of 2016, due to a third-party’s gas processing facility being shut-in. A new gas processing plant was completed in late-April 2017, with gas sales expected to resume near previous levels. In addition, the year-over-year change includes natural production declines.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months endedMarch 31, 2017increased42% compared to these revenues for the same period in 2016.  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,
	2017 vs. 2016
In thousands	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(27,288	)	(14	)%
Increase in commodity prices	105,663			56	%
Total increase in oil and natural gas revenues	$	78,375		42	%

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, 2017 and 2016:

	Three Months Ended
	March 31,
	2017			2016
Average net realized prices:
Oil price per Bbl	$	50.31		$	30.71
Natural gas price per Mcf	2.50			1.70
Price per BOE	49.35			29.76
Average NYMEX differentials:
Oil per Bbl	$	(1.64	)	$	(3.02	)
Natural gas per Mcf	(0.57		)	(0.29		)

Our average net realized oil price, excluding the impact of commodity derivative contracts, increased64% during the first quarter of 2017 from the average price received during the first quarter of 2016 and increased5% when compared to the fourth quarter of 2016.  Company-wide average oil price differentials in the first quarter of 2017 were $1.64 per Bbl below NYMEX, compared to an average differential of $3.02 per Bbl below NYMEX in the first quarter of 2016 and $1.22 per Bbl below NYMEX in the fourth quarter of 2016. 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. Additional information about our oil differentials 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$1.42 per Bbl and a negative $1.95 per Bbl during the first quarter of 2017 and 2016, respectively, and a negative$0.81 per Bbl during the fourth quarter of 2016. 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 $1.58 per Bbl in the first quarter of 2017, consistent with a positive $1.60 per Bbl in the first quarter of 2016 and a slight increase from the positive $1.42 per Bbl in the fourth quarter of 2016. During the first quarter of 2017, we sold approximately 60% 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.

NYMEX oil differentials in the Rocky Mountain region averaged $2.09 per Bbl and $5.04 per Bbl below NYMEX during the first quarter of 2017 and 2016, respectively, and $2.06 per Bbl below NYMEX during the fourth quarter of 2016. 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 crude oil derivative contracts had on our operating results for the three months endedMarch 31, 2017 and 2016:

	Three Months Ended
	March 31,
In thousands	2017			2016
Receipt (payment) on settlements of commodity derivatives	$	(26,940	)	$	72,227
Noncash fair value gains (losses) on commodity derivatives (1)	51,542			(95,053		)
Total income (expense)	$	24,602		$	(22,826	)

(1) Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Based on current futures prices as of May 3, 2017, which average approximately $48 per Bbl for the second quarter of 2017, and the fixed-price swaps that we have in place, we currently expect that we will make cash payments of approximately $13 million during the second quarter of 2017 upon settlement of these contracts, the amount of which is dependent upon fluctuations in future NYMEX prices in relation to the fixed prices of these swaps, which have a weighted average price of $44.32 per Bbl. Commodity derivative contracts in place for the second half of 2017 solely include collars and three-way collars. Based on current contracts in place and NYMEX oil futures prices as of May 3, 2017, minimal or no settlements are currently expected during the second half of 2017. 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, 2017, are included in Note 4, 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 Expenses

	Three Months Ended
	March 31,
In thousands, except per-BOE data	2017		2016
Total lease operating expenses	$	113,840	$	102,447
Total lease operating expenses per BOE	$	21.11	$	16.23

Total lease operating expensesincreased$11.4 million(11%) on an absolute-dollar basis and$4.88(30%) on a per-BOE basis during thethree months endedMarch 31, 2017compared to levels in the same period in 2016. Sequentially, lease operating expenses increased$7.9 million (7%) on an absolute-dollar basis and $2.13 (11%) on a per-BOE basis between the fourth quarter of 2016 and the first quarter of 2017. These increases include higher CO₂ expense during the period primarily due to an increase in the cost of CO₂, which is discussed in further detail below. In addition, our lease operating expenses during the current period were impacted by increased workover and other repair activity at certain fields, as workover activity was significantly curtailed during 2016 due to the lower oil price environment. Although the average cost of these projects was higher than in recent periods, the increases were primarily due to project scale, and are not directly attributable to an increase in service cost rates. Lease operating expenses were impacted to a smaller degree by incremental operating costs, including power and fuel costs, related to the newly operating Delhi NGL plant. Total lease operating expenses on a per-BOE basis were further impacted by the 14% decline in total production between the three months endedMarch 31, 2016 and 2017.

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 quarters of 2017 and 2016, approximately 57% and 56%, 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, including taxes paid on CO₂ production but excluding depletion, depreciation and amortization of capital expended at our CO₂ source fields and industrial sources, our average cost of CO₂ was approximately $0.41 per Mcf during the first quarter of 2017, compared to $0.33 per Mcf during the first quarter of 2016 and $0.39 per Mcf during the fourth quarter of 2016. The increase when compared to the first quarter of 2016 was partially attributable to increases in the cost of CO₂ due to increases in oil prices, and further impacted by a lower utilization of CO₂ in the 2017 period, while certain pipeline and processing costs are relatively fixed. The 2017 period increase when compared to the fourth quarter of 2016 was primarily impacted by higher utilization of industrial-sourced CO₂, which has a higher average cost than our naturally-occurring CO₂ sources. As we anticipate additional industrial-sourced CO₂ volumes from MSPC coming into our CO₂ supply during the second quarter of 2017, we expect that our per-Mcf cost of CO₂ could trend higher; however, utilizing industrial-sourced CO₂ significantly reduces the future capital we would otherwise have to spend at Jackson Dome and provides a long-term consistent source of CO₂.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, and to a lesser extent expenses related to our Riley Ridge gas processing facility. Marketing and plant operating expenses were $14.1 million and $13.2 million for the three months endedMarch 31, 2017 and 2016, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased$2.3 million (12%) during the three months endedMarch 31, 2017 compared to the same period in 2016, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.

General and Administrative Expenses (“G&A”)

	Three Months Ended
	March 31,
In thousands, except per-BOE data and employees	2017			2016
Gross cash compensation and administrative costs	$	66,447		$	79,738
Gross stock-based compensation	5,388			2,884
Operator labor and overhead recovery charges	(31,531		)	(35,133		)
Capitalized exploration and development costs	(12,063		)	(13,588		)
Net G&A expense	$	28,241		$	33,901
G&A per BOE:
Net administrative costs	$	4.48		$	5.29
Net stock-based compensation	0.76			0.08
Net G&A expenses	$	5.24		$	5.37
Employees as of March 31	1,061			1,096

Gross cash compensation and administrative costs on an absolute-dollar basis decreased$13.3 million (17%) during the three months endedMarch 31, 2017 compared to those costs in the same period in 2016, primarily due to lower employee-related costs such as salaries during the 2017 period and the inclusion of severance-related payments of approximately $9.3 million in the prior-year period associated with the 2016 involuntary workforce reduction.

Net G&A expense on a per-BOE basis decreased2% during the three months ended March 31, 2017 compared to levels in the same period in 2016. The change was 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 increased$2.5 million (87%) during the three months endedMarch 31, 2017 compared to levels in the same period in 2016. The increase between the comparative three-month periods was primarily due to lower stock compensation expense in the prior-year period associated with our performance share awards for our executive officers due to downward adjustments in the first quarter of 2016 for expected payouts of performance-based awards.

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.

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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	2017			2016
Cash interest (1)	$	42,500		$	44,645
Less: interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes (1)	(12,569		)	—
Noncash interest expense	1,901			3,306
Less: capitalized interest	(4,654		)	(5,780		)
Interest expense, net	$	27,178		$	42,171
Interest expense, net per BOE	$	5.04		$	6.68
Average debt principal outstanding	$	2,818,832		$	3,326,140
Average interest rate (2)	6.0		%	5.4		%

(1) Cash interest is presented on an accrual basis, and includes the portion of interest on our 2021 Senior Secured Notes (interest on which is to be paid semiannually May 15 and November 15 of each year) versus the GAAP financial statement presentation in which interest on these notes is accounted for as debt and not reflected as interest for financial reporting purposes. See below for further discussion.

(2) Includes commitment fees but excludes debt issue costs and amortization of discount or premium.

As reflected in the table above, cash interest during the three months endedMarch 31, 2017, decreased when compared to the same period in 2016 due primarily to repurchasing a total of $181.9 million principal amount of our existing senior subordinated notes at a discount to par value in open-market transactions during 2016. For the three months ended March 31, 2017, $12.6 million of interest on our 2021 Senior Secured Notes was accounted for as debt, and is therefore not reflected as interest expense in the Unaudited Condensed Consolidated Statements of Operations in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors. Noncash interest expense during the three months endedMarch 31, 2017 decreased when compared to the same prior year period primarily due to the prior-year period including a $1.0 million write-off of debt issuance costs associated with our senior secured bank credit facility following the February 2016 amendment which reduced our lender commitments. Capitalized interest during the three months endedMarch 31, 2017decreased$1.1 million (19%) compared to the same period in 2016, 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	2017		2016
Oil and natural gas properties	$	27,818	$	50,016
CO2 properties, pipelines, plants and other property and equipment	23,377		27,350
Total DD&A	$	51,195	$	77,366
DD&A per BOE:
Oil and natural gas properties	$	5.16	$	7.98
CO2 properties, pipelines, plants and other property and equipment	4.33		4.28
Total DD&A cost per BOE	$	9.49	$	12.26
Write-down of oil and natural gas properties	$	—	$	256,000

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 decreased44% on an absolute-dollar basis during the three months ended March 31, 2017 compared to the same period in 2016. On a per-BOE basis, DD&A of oil and natural gas properties decreased 35% during the three months ended March 31, 2017, compared to the same period in 2016. These decreases were primarily due to a reduction in depletable costs associated with our reserves base resulting from the full cost pool ceiling test write-downs recognized during 2016 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 2017 when compared to production in the 2016 period.

Depletion and depreciation of our CO₂ properties, pipelines, plants and other property and equipment decreased15% on an absolute-dollar basis and increased 1% on a per-BOE basis during the three months ended March 31, 2017, compared to the same period in 2016. The decrease on an absolute-dollar basis between periods was primarily due to a decrease in plant depreciation due to the accelerated depreciation charge at the Riley Ridge gas processing facility during the fourth quarter of 2016, while the slight increase on a per-BOE basis was primarily driven by the decrease in oil and natural gas production volumes between the first quarters of 2016 and 2017.

2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a full cost pool ceiling test write-down in the first quarter of 2017.

Income Taxes

	Three Months Ended
	March 31,
In thousands, except per-BOE amounts and tax rates	2017			2016
Current income tax benefit	$	(13,935	)	$	(5	)
Deferred income tax expense (benefit)	34,909			(95,115		)
Total income tax expense (benefit)	$	20,974		$	(95,120	)
Average income tax expense (benefit) per BOE	$	3.89		$	(15.07	)
Effective tax rate	49.3		%	33.9		%
Total net deferred tax liability	$	328,786		$	742,148

Our income taxes are based on an estimated statutory rate of approximately 38% in 2017 and 2016. Effective January 1, 2016, we adopted Accounting Standards Update 2016-09 (“ASU 2016-09”), Improvements to Employee Share-Based Payment Accounting, which impacted the timing of when excess tax benefits or tax shortfalls are recognized. Our effective tax rates for the three months ended March 31, 2017 and 2016 differed from 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 first quarter) which, prior to the adoption of ASU 2016-09, was recorded as an adjustment to equity. The current income tax benefit during the three months ended March 31, 2017, represents the estimated current year receivable resulting from alternative minimum tax credits. The deferred income tax benefits during the three months ended March 31, 2016, were primarily due to the impact of the write-down of our oil and natural gas properties during the year.

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. As of March 31, 2017, we had $36.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of falling commodity prices, combined with a new tax law enacted in the State of Louisiana effective June 30, 2015, which

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $36.5 million during 2015 and 2016, which reduced the carrying value of these deferred tax assets to zero as of December 31, 2016. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.

As of March 31, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of March 31, 2017.

As of March 31, 2017, 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 $29.0 million of alternative minimum tax credits (net of $12.1 million related to the estimated credits to be applied to our 2016 tax return) that can be utilized to reduce our current income taxes during 2017 or future years.  The enhanced oil recovery credits and research and development credits do not begin to expire until 2023 and 2031, respectively.

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	2017			2016
Oil and natural gas revenues	$	49.35		$	29.76
Receipt (payment) on settlements of commodity derivatives	(5.00		)	11.44
Lease operating expenses	(21.11		)	(16.23		)
Production and ad valorem taxes	(3.86		)	(2.72		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.87		)	(1.84		)
Production netback	17.51			20.41
CO2 sales, net of operating and exploration expenses	0.89			0.89
General and administrative expenses	(5.24		)	(5.37		)
Interest expense, net	(5.04		)	(6.68		)
Other	3.33			(0.24		)
Changes in assets and liabilities relating to operations	(6.95		)	(8.69		)
Cash flows from operations	4.50			0.32
DD&A	(9.49		)	(12.26		)
Write-down of oil and natural gas properties	—			(40.56		)
Deferred income taxes	(6.47		)	15.07
Gain on debt extinguishment	—			15.05
Noncash fair value gains (losses) on commodity derivatives (1)	9.56			(15.06		)
Other noncash items	5.89			8.10
Net income (loss)	$	3.99		$	(29.34	)

(1) Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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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 data and/or 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, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus 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 further 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 prices and oilfield costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, future interest rates, 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, 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, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, potential increases in regional or worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, long-term forecasts of production, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our estimated original oil in place, operations and future plans.  Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “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, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; 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.

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Denbury Resources Inc.

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, 2017, we had $355.0 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 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 values of our 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices.  The following table presents the principal cash flows and fair values of our outstanding debt as of March 31, 2017:

In thousands	2017		2019		2021		2022		2023		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 3.2% at March 31, 2017)	$	—	$	355,000	$	—	$	—	$	—	$	355,000	$	355,000
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	—		—		614,919		—		—		614,919		646,464
6⅜% Senior Subordinated Notes due 2021	—		—		215,144		—		—		215,144		175,880
5½% Senior Subordinated Notes due 2022	—		—		—		772,912		—		772,912		599,007
4⅝% Senior Subordinated Notes due 2023	—		—		—		—		622,297		622,297		452,721
Other Subordinated Notes	2,250		—		—		—		—		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 provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2017 using both NYMEX and LLS fixed-price swaps, collars and three-way collars. Due to the volatility experienced and the previous downward trend in oil prices over the past two years, we have reduced our hedged level and duration of new derivative contracts; thus, the percentage of our forecasted production we have hedged and the duration of our hedges are less than what we have had in the recent past. However, we will continue to evaluate the production we hedge in light of our levels of debt, financial strength and expectation of future commodity prices. See also Note 4, Commodity Derivative Contracts, and Note 5, 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.

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Denbury Resources Inc.

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, 2017, our commodity derivative contracts were recorded at their fair value, which was a net liability of $17.7 million, a $51.6 million decrease from the $69.3 millionnet liability recorded at December 31, 2016.  Changes in this value are comprised of the expiration of commodity derivative contracts during the three months endedMarch 31, 2017, new commodity derivative contracts entered into during 2017 for future periods, and to the changes in oil futures prices between December 31, 2016 and March 31, 2017.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of March 31, 2017, and assuming both a 10% increase and decrease thereon, we would expect to make 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, 2017	$	(18,708	)
10% increase in prices	(32,273		)
10% decrease in prices	(5,142		)

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.

30

Denbury Resources Inc.

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, 2017, 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, that it is 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 2017, 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.

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Denbury Resources Inc.

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.

Settlement of Mississippi Environmental Matter

For the past two years, the Company has been in negotiations with the Mississippi Department of Environmental Quality (“MDEQ”) regarding 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. In late April 2017, we entered into an Agreed Order with the MDEQ settling the claims covered by the notice, which Agreed Order provides for the Company’s payment of a civil penalty of $195,000 and for it to maintain certain future well monitoring.

Riley Ridge Helium Supply Contract Claim

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

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.

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Denbury Resources Inc.

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 2017:

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 2017	288,474	$	3.72	—	$	210.1
February 2017	743	3.37		—	210.1
March 2017	207,058	2.58		—	210.1
Total	496,275			—

(1) Stock repurchases during the first quarter of 2017 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 and performance shares.

(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. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock as long as current commodity pricing and general economic conditions persist. 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 commencement of a common share repurchase program, and October 2015, 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.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Denbury Resources Inc.

Item 6. Exhibits

Exhibit No.	Exhibit
10(a)*	2017 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)*	2017 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(c)*	2017 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)*	2017 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)*	2017 Form of Oil Price Change vs. TSR Performance Award, under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)*	Officer Retirement Agreement, effective as of March 21, 2017, by and between Denbury Resources Inc. and Phil Rykhoek.
10(g)	Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 3, 2017, 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 May 4, 2017, 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.

* Included herewith.

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Denbury Resources Inc.

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 5, 2017	/s/ Mark C. Allen
	Mark C. Allen Sr. Vice President and Chief Financial Officer
May 5, 2017	/s/ Alan Rhoades
	Alan Rhoades Vice President and Chief Accounting Officer

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Denbury Resources Inc.

INDEX TO EXHIBITS

Exhibit No.	Exhibit
10(a)	2017 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)	2017 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(c)	2017 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)	2017 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)	2017 Form of Oil Price Change vs. TSR Performance Award, under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)	Officer Retirement Agreement, effective as of March 21, 2017, by and between Denbury Resources Inc. and Phil Rykhoek.
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.

36

EX-10.A

	
		
		
		Exhibit
	
	

EX-10.B

Exhibit 10(b)

$____________ Maximum Performance Cash    Date of Grant: January 3, 2017

2017 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:

(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

1

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) 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, 2020 (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) “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; provided that in the event of a Change of Control, the 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 day such Change of Control takes effect.

(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.

(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 two years thereafter, provided that in the event of a Change of Control, the Performance Period will end on the day 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.

2

(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, 2020 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 becomes 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.

(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.

3

(d) The percentages in Column 4 of the table below are based upon increments derived by dividing 100% by 18 (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 17 Peer Companies, then the 5.6% increment currently shown in Column 4 would become 5.9%).

(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 19 Companies, being ranked as ninth would equal a Performance Percentage of 11%). 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 19 Companies (expressed as a %)	Performance Percentage Scale (subject to interpolation)
1			100.0%	100%
2			94.4%	89%
3			88.9%	78%
4			83.3%	67%
5			77.8%	56%
6			72.2%	44%
7			66.7%	33%
8			61.1%	22%
9			55.6%	11%
10			50.0%	0%
11			44.4%	0%
12			38.9%	0%
13			33.3%	0%
14			27.8%	0%
15			22.2%	0%
16			16.7%	0%
17			11.1%	0%
18			5.6%	0%
19			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

4

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.

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.

5

(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, whereby Holder experiences such Separation prior to the last day of the Performance Period, Holder will not be entitled to receive any amount of Performance Cash pursuant to this Award. If there is a Post Separation Change of Control, whereby Holder experiences such Separation on or after the last day of the Performance Period, Holder 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 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. If and when any portion of this Award becomes taxable, the minimum statutory tax withholding required to be made by the Company, or other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company, shall be paid to the Company in cash, which cash may be withheld from 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. In the event that Holder does not file a written designation of Beneficiary, or where such Beneficiary predeceases the Holder, the following rules shall apply: (i) the Holder’s beneficiary designation for the basic life insurance benefits provided by the Company shall be Holder’s Beneficiary; and (ii) in the absence of such basic life insurance

6

beneficiary, or in the event that such basic life insurance beneficiary predeceases the 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 is 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]

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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.

	DENBURY RESOURCES INC.
By:
	Phil Rykhoek Chief Executive Officer	Mark C. Allen Senior Vice President and Chief Financial Officer

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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.

Holder Signature

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Appendix A

Peer Companies

California Resources Corporation (CRC)

Concho Resources, Inc. (CXO)

ConocoPhillips (COP)

Continental Resources Inc. (CLR)

Crescent Point Energy Corp. (CPG)

EOG Resources Inc. (EOG)

EP Energy Corp-CL A (EPE)

Hess Corporation (HES)

Marathon Oil Corporation (MRO)

MEG Energy Corporation (MEG.TO)

Murphy Oil Corporation (MUR)

Newfield Exploration Co (NFX)

Oasis Petroleum, Inc. (OAS)

Occidental Petroleum Corporation (OXY)

PDC Energy Inc. (PDCE)

Pioneer Natural Resources Company (PXD)

SM Energy Company (SM)

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. In the event that 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 it shall occupy the last position (or positions, if there are more than one such companies) in the TSR ranking.

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EX-10.C

Exhibit 10(c)

____________ Maximum Performance Shares    Date of Grant: January 3, 2017

2017 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 withthe 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 (“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

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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 excluding hedging revenues, gains (losses) on asset sales, and interest and other income 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, 2018 (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, 2017, and ending on December 31, 2017.

(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-

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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, 2018 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 Stock, 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 Stock 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 ratio to the lowest ratio.

(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 16 (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 15 Peer Companies, then the 6.3% increment currently shown in Column 4 would become 6.7%).

(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 17 Companies, being ranked as eleventh would equal a Performance Percentage of 75%). 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 17 Companies (expressed as a %)	Performance Percentage Scale (subject to interpolation)
1			100.0%	100%
2			93.8%	100%
3			87.5%	100%
4			81.3%	100%
5			75.0%	100%
6			68.8%	100%
7			62.5%	100%
8			56.3%	100%
9			50.0%	100%
10			43.8%	88%
11			37.5%	75%
12			31.3%	63%
13			25.0%	50%
14			18.8%	38%
15			12.5%	25%
16			6.3%	13%
17			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.

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(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, 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, whereby Holder experiences such Separation, prior to the last day of the Performance Period, Holder will be entitled to receive Performance Shares in an amount equal to the number of Maximum Performance Shares (without

5

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. If there is a Post Separation Change of Control, whereby Holder experiences such Separation on or after the last day of the Performance Period, Holder 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 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. If and when any portion of this Award becomes taxable, the minimum statutory tax withholding required to be made by the Company, or other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company, shall be paid to the Company, as applicable, in cash, by delivery of Stock, which Stock may be in whole or in part Stock subject to this Award, based on the Fair Market Value of such Stock on the Vesting Date, or via payroll deduction. The Holder, in his sole discretion, may direct that the Company withhold at any rate which is in excess of the minimum withholding rate described in the preceding sentence, but not in excess of the highest incremental tax rate for Holder, and such additional directed withholding will be made in the same manner as described in the preceding sentence.

9.Issuance of Stock. Without limitation, Holder shall not have any of the rights and privileges of an owner of 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 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 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. In the event that Holder does not file a written designation of Beneficiary, or where such Beneficiary predeceases the Holder, the following rules shall apply: (i) the Holder’s beneficiary designation for the basic life insurance benefits provided by the Company shall be Holder’s Beneficiary;

6

and (ii) in the absence of such basic life insurance beneficiary, or in the event that such basic life insurance beneficiary predeceases the 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)

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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 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]

8

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.

	DENBURY RESOURCES INC.
By:
	Phil Rykhoek Chief Executive Officer	Mark C. Allen Senior Vice President and Chief Financial Officer

9

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.

Holder Signature

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EX-10.D

Exhibit 10(d)

$_________ Maximum Performance Cash     Date of Grant: January 3, 2017

2017 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 withthe 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

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(“FASC”) 932-235-50 (“FAS 69”) in its Form 10-K for the Performance Period), divided by (y) its total revenues from continuing operations excluding hedging revenues, gains (losses) on asset sales, and interest and other income 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, 2018 (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, 2017, and ending on December 31, 2017.

(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.

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(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, 2018 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 becomes 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 ratio to the lowest ratio.

(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 16 (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 15 Peer Companies, then the 6.3% increment currently shown in Column 4 would become 6.7%).

(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 17 Companies, being ranked as eighth would equal a Performance Percentage of 13%). 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 17 Companies (expressed as a %)	Performance Percentage Scale (subject to interpolation)
1			100.0%	100%
2			93.8%	88%
3			87.5%	75%
4			81.3%	63%
5			75.0%	50%
6			68.8%	38%
7			62.5%	25%
8			56.3%	13%
9			50.0%	0%
10			43.8%	0%
11			37.5%	0%
12			31.3%	0%
13			25.0%	0%
14			18.8%	0%
15			12.5%	0%
16			6.3%	0%
17			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, Holder will not be entitled to receive any amount of Performance Cash pursuant to 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.

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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.

(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, whereby Holder experiences such Separation prior to the last day of the Performance Period, Holder will not be entitled to receive any amount of Performance Cash pursuant to this Award. If there is a Post Separation Change of Control, whereby Holder experiences such Separation on or after the last day of the Performance Period, Holder 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 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. If and when any portion of this Award becomes taxable, the minimum statutory tax withholding required to be made by the Company, or other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company, shall be paid to the Company in cash, which cash may be withheld from 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

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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. In the event that Holder does not file a written designation of Beneficiary, or where such Beneficiary predeceases the Holder, the following rules shall apply: (i) the Holder’s beneficiary designation for the basic life insurance benefits provided by the Company shall be Holder’s Beneficiary; and (ii) in the absence of such basic life insurance beneficiary, or in the event that such basic life insurance beneficiary predeceases the 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 is 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

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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]

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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.

	DENBURY RESOURCES INC.
By:
	Phil Rykhoek Chief Executive Officer	Mark C. Allen Senior Vice President and Chief Financial Officer

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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.

Holder Signature

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EX-10.E

Exhibit 10(e)

$__________Maximum Performance Cash     Date of Grant: January 3, 2017

2017 OIL PRICE CHANGE

VS.

TSR PERFORMANCE AWARD

2004 OMNIBUS STOCK AND INCENTIVE PLAN

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”).

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) “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.

(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.

(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 for each 10 trading days immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured.

(e) “Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company.

(f) “Change of Control” or “CIC” means, without limitation, the same as it does in the Plan.

(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.

(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, 2020 (i.e., the Vesting Date).

(i) “Disability” means, without limitation, the same as it does in the Plan.

(j) “Earned Performance Cash” means the amount of Performance Cash which is earned during the Performance Period as described and calculated in Section 6.

(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; provided that in the event of a Change of Control, the 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 date such Change of Control takes effect.

(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; provided that in the event of a Change of Control, the price equals the 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 the Change of Control.

(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.

(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 two years thereafter; provided that in the event of a Change of Control, the Performance Period will end on the day such Change of Control takes effect.

(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.

(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.

(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.

(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.

(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.

(u) “TSR Relative to Oil Price Change” means, the result, expressed as a percentage, of the calculation set out in Section 4(c) hereof.

(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).

(w) “Vesting Date” means March 31, 2020 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:

(a) Annual TSR shall be calculated for the periods specified below as follows:

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(i) Annual TSR for the Company for each Calendar Year within the Performance Period shall equal the result of the following calculation:

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:

(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:

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:

(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

(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

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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.

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), (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, whereby Holder experiences such Separation, prior to the last day of the Performance Period, Holder will be entitled to receive Performance Cash in an amount equal to Target Performance Cash (without any

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right to receive any additional Performance Cash 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. If there is a Post Separation Change of Control, whereby Holder experiences such Separation on or after the last day of the Performance Period, Holder 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 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. If and when any portion of this Award becomes taxable, the minimum statutory tax withholding required to be made by the Company, or other withholding rate as determined by the Committee in its discretion if determined not to be detrimental to the Company, shall be paid to the Company in cash, which cash may be withheld from 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. In the event that Holder does not file a written designation of Beneficiary, or where such Beneficiary predeceases the Holder, the following rules shall apply: (i) the Holder’s beneficiary designation for the basic life insurance benefits provided by the Company shall be Holder’s Beneficiary; and (ii) in the absence of such basic life insurance beneficiary, or in the event that such basic life insurance beneficiary predeceases the 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.

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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 is 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]

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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.

	DENBURY RESOURCES INC.
By:
	Phil Rykhoek Chief Executive Officer	Mark C. Allen Senior Vice President and Chief Financial Officer

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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.

Holder Signature

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EX-10.F

Exhibit 10(f)

OFFICER RETIREMENT AGREEMENT

THIS OFFICER RETIREMENT AGREEMENT (this “Agreement”) is entered into by and between Denbury Resources Inc., a Delaware corporation (“DRI,” and together with its subsidiaries, collectively, the “Company”), and Phil Rykhoek (“Rykhoek”), and is effective as of the Effective Date (as defined in Section 9(c) below).

WITNESSETH:

WHEREAS, Rykhoek has been employed by the Company since June of 1995 and, immediately prior to the Officer Retirement Date (as defined below), served as DRI’s Chief Executive Officer;

WHEREAS, DRI and Rykhoek have reached certain agreements (i) as to the terms and conditions of Rykhoek’s retirement as an officer, director, member and/or manager of the Company, as applicable, and (ii) with respect to Rykhoek’s continued employment (as a non-officer employee) related to certain matters described herein; and

WHEREAS, Rykhoek has been in a position of special responsibility and trust with the Company during his employment, with access to highly sensitive, valuable, confidential and proprietary information regarding, among other things, the Company’s methods of operations, current and future business plans and strategies, personnel and finances, and other confidential and/or non-public information of the Company;

NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, and other valuable consideration, the receipt and sufficiency of which is hereby acknowledged, DRI and Rykhoek agree as follows:

1.Retirement as Officer. Rykhoek and DRI agree that effective as of June 30, 2017 (the “Officer Retirement Date”), Rykhoek shall retire as (a) Chief Executive Officer of DRI, and (b) an officer, director, member and/or manager of all DRI subsidiaries, as applicable, and Rykhoek shall not thereafter serve the Company in an officer’s, director’s, member’s or manager’s capacity

2.Special Compensation Benefits and Consideration. In exchange for, and in reliance on, the promises and covenants Rykhoek makes in this Agreement, and subject to the terms and conditions contained herein, including, without limitation, Section 18 hereof, the Company covenants and agrees to provide Rykhoek with the following special compensation benefits and consideration (the “Retirement Benefits”):

(a)the total amount of $7,020,000.00 in cash (the “Cash Amount”), which Cash Amount shall be paid to Rykhoek in two (2) installments, with the first such installment in an amount equal to $4,290,000.00 to be paid on the next regularly scheduled Company payroll date following the Officer Retirement Date, and the second and final installment in the amount of $2,730,000.00 to be paid on the next regularly scheduled Company payroll date following the Employment Termination Date (as herein defined); provided, that, on or immediately prior to

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the date on which any payment of the Cash Amount is to be made to Rykhoek or, if earlier, the date on which an amount is required to be included in the income of Rykhoek as a result of such payment, Rykhoek shall be required to pay to the Company, in cash, or the Company shall otherwise withhold from the payment of the Cash Amount to Rykhoek, the amount which the Company reasonably determines to be necessary in order for the Company to comply with applicable federal or state tax withholding and the collection of employment taxes.

(b)the amount of $682,500.00 in cash (the “Bonus Amount”), which Bonus Amount shall constitute bonus compensation, prorated for 2017 through the Officer Retirement Date, and which shall be paid to Rykhoek on the next regularly scheduled Company payroll date following the Officer Retirement Date; provided, that, on or immediately prior to the date on which payment of the Bonus Amount is to be made to Rykhoek or, if earlier, the date on which an amount is required to be included in the income of Rykhoek as a result of such payment, Rykhoek shall be required to pay to the Company, in cash, or the Company shall otherwise withhold from the payment of the Bonus Amount to Rykhoek, the amount which the Company reasonably determines to be necessary in order for the Company to comply with applicable federal or state tax withholding and the collection of employment taxes.

(c)during the Continuation Period (as defined below), the applicable premium payment under COBRA, when due, for Rykhoek and his qualified beneficiaries for the cost of benefit continuation under the Company’s major medical benefit plan, dental plan and vision insurance program, but excluding coverage under the Company’s flexible spending account plan and other insurance or other benefits provided by the Company (“COBRA Benefits”) in which Rykhoek has enrolled for the 2017 plan year, as such COBRA Benefits change as permitted by COBRA, beginning on July 1, 2017 and continuing and ending on December 31, 2018 (the “Continuation Period”); provided, that, the payment of such premium(s) shall be subject to the Company’s compliance with applicable federal or state tax withholding and the collection of employment taxes; provided, further, that, if Rykhoek does not properly elect COBRA coverage in accordance with the applicable benefit plans, Rykhoek will not receive the COBRA Benefits. For purposes of clarity, the COBRA Benefits provided pursuant to this Section 2(c) will run concurrently with any period of COBRA coverage Rykhoek may be entitled to receive under applicable law and the applicable benefit plans, determined without regard to this Section 2(c).

The Company’s payment of the Retirement Benefits is subject to applicable federal, state, and local taxes and withholding, specifically including the withholding from any benefits payable under Sections 2(a), 2(b) and 2(c). Without limitation of the foregoing, the Retirement Benefits provided under Section 2(c) shall also be reported as additional taxable compensation to Rykhoek, and Rykhoek shall be required to pay to the Company, in cash, or the Company shall otherwise withhold from the payment of such benefits to, or on behalf of, Rykhoek, the amount which the Company reasonably determines to be

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necessary in order for the Company to comply with applicable federal or state tax withholding and the collection of employment taxes.

Notwithstanding anything to the contrary contained herein, no Retirement Benefits or any other amounts or benefits shall be due or otherwise payable, or commence or otherwise be provided, under this Agreement if this Agreement is revoked by Rykhoek pursuant to, and in accordance with, Section 9(c).

3.Equity Awards; Cash Awards. Those equity awards and cash awards, if any, to the extent held by Rykhoek immediately prior to the Officer Retirement Date shall be treated, governed and interpreted according to the terms of such awards, and as applicable, of DRI’s equity compensation plans under which they have been issued, including the vesting provisions thereof, and in a manner which accommodates both (a) Rykhoek’s transition from a full-time employee to a part-time employee under the terms of Section 4 below, and (b) Rykhoek no longer being an officer of the Company as provided in Section 1 above. The parties agree that the payment or settlement of any applicable awards may be made and effectuated in a manner that the parties agree upon to, among other things, accommodate tax treatment and/or planning with respect to either party.

4.Continued Employment. Rykhoek shall be employed by the Company on a part-time basis for work on requested matters for the period (the “Employment Period”) commencing on the Officer Retirement Date and ending on January 31, 2018 (the “Employment Termination Date”), and in lieu of and in replacement of Rykhoek’s current salary, during the Employment Period Rykhoek shall be paid a salary at the rate of $48,000.00 per year (pro-rated as applicable for the Employment Period) in accordance with, and subject to, the Company’s payroll policies that apply to other employees of the Company. Rykhoek’s employment shall not require him to render services to the Company on a full-time basis, but consistent with the provisions of Section 6(d) hereof, on a basis as requested from time to time by DRI’s Chief Executive Officer, Chief Financial Officer or General Counsel, at such places as may reasonably be agreed upon. In the event that Rykhoek is requested to work more than two (2) full days during any calendar month during the Employment Period, Rykhoek shall be entitled to be paid an additional $2,000.00 per day for each additional full day worked, or a commensurate proportion of such $2,000.00 amount for less than a full day’s work. In connection with Rykhoek’s part-time employment by the Company during the Employment Period, Rykhoek shall be entitled to reimbursement for reasonable and necessary expenses (including reasonable and necessary travel expenses) incurred in furtherance of the Company’s business in accordance with this Section 4 and Section 6(d), and otherwise in accordance with the Company’s policies, and upon presentation of documentation in accordance with the expense reimbursement policies of the Company as they may exist from time to time, and submission to the Company of adequate documentation in accordance with federal income tax regulations.

5.Non-Eligibility for Company Plans. Rykhoek acknowledges, agrees and understands that after the Officer Retirement Date Rykhoek will not be eligible to receive awards under DRI’s equity compensation plans made available to employees, nor will he be eligible to receive any severance benefits under the terms of any of DRI’s severance protection plans.

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6.Rykhoek’s Non-Competition and Other Covenants and Agreements. In consideration of the special compensation, benefits and consideration received, or to be received, by Rykhoek, to which Rykhoek acknowledges he is not otherwise entitled (other than the Bonus Amount), and the other agreements and consideration of DRI which are contained herein, Rykhoek agrees to the following covenants as reasonable and necessary for the protection of the Company’s business interests:

(a)    Definitions:

“Competing Business” means any person or entity that competes with or would compete with or displace, or that engages in any other activities so similar in nature or purpose to those of the Company set forth below so as to compete with, or displace or attempt to compete with or displace, in the Gulf Coast, Rocky Mountain and/or Permian Basin regions (i) any of the activities of the Company which involve or encompass the purchase, ownership or development of CO₂, in natural, anthropogenic or any other form, CO₂ pipelines, or the injection of CO₂ into previously producing oil fields for the purpose of tertiary recovery of remaining oil, or (ii) the purchase, ownership or development of conventional oil fields with remaining oil potentially recoverable through CO₂ enhanced oil recovery operations.

“Covered Persons” means any person employed by the Company either as an employee, consultant or advisor as of the Officer Retirement Date, or hired by the Company prior to the Non-Solicitation Termination Date (as defined in Section 6(b)(ii) below).

(b)No Unfair Competition; Non-Solicitation Agreement. The parties agree that during the course of his employment, Rykhoek had access to, and the benefit of, the Company’s confidential information as more fully set forth in Section 6(g) herein. To protect the Company’s interest in its proprietary and confidential information, contacts and relationships, and as a material incentive for DRI to enter into this Agreement, as well as in exchange for the compensation specified herein, Rykhoek covenants and agrees that he will not, either directly or indirectly (whether personally or through another business, entity or person), (i) for the period commencing on the Officer Retirement Date and ending on January 31, 2020 (the “Non-Competition Termination Date”), work for, supervise, assist or participate in, a Competing Business in any capacity (as owner, employee, consultant, advisor, contractor, officer, director, lender, investor, agent, or otherwise) or otherwise engage in any Competing Business, and (ii) for the period commencing on the Officer Retirement Date and ending on January 31, 2021 (the “Non-Solicitation Termination Date”), (1) recruit, solicit, or induce, (2) attempt to recruit, solicit or induce, or (3) encourage others to recruit, solicit or induce, any Covered Person to diminish, curtail, divert, or cancel its or their business relationship with, or employment by, the Company, specifically including providing, directly or indirectly, a

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reference to a recruiter, acquaintance or competitor that a Covered Person may be amenable to recruitment from a third party.

Rykhoek agrees that this Section 6(b) creates a narrowly tailored restraint of competition by Rykhoek that is designed to avoid unfair competition and irreparable harm to the Company, and does not constitute a general restraint from Rykhoek engaging in a lawful profession or a general covenant against competition in the oil and gas industry. To this end, within the constraints of the preceding provisions of this Section 6(b), DRI agrees that this Section 6(b) will not prohibit Rykhoek’s work, engagement, or investment in the oil and gas industry so long as such work, engagement or investment does not involve Rykhoek or entities, persons or groups for whom Rykhoek works, consults or invests (x) competing with or displacing the specified activities of the Company in those geographic areas or regions enumerated above in Section 6(a), or (y) using the Company’s data or non-public business plans disclosed or known to Rykhoek during his employment by the Company. Nothing in this Section 6 will prohibit the ownership of less than 10% of the equity of an entity so long as this is not a controlling interest.

It is expressly understood and agreed that the Company and Rykhoek consider the restrictions contained in this Section 6(b) to be reasonable and necessary for the purposes of preserving and protecting the confidential information and other legitimate business interests of the Company; nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, over-broad as to geographic area or scope of activity, or otherwise unenforceable, the Company and Rykhoek intend for the restrictions herein set forth to be modified by such court so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.

(c)No Personal Use of CompanyResources. Rykhoek covenants and agrees that he will not utilize any Company resources, including, but not limited to, maps, seismic information, feasibility studies, personnel, computers, software, books and records, or any other corporate assets, for his own account or for the account of any entity, persons or groups for whom he works or consults or in which he invests.

(d)Cooperation and Assistance.In exchange for the compensation, covenants, and other good and valuable consideration provided by DRI herein, Rykhoek covenants and agrees that he will, until the Non-Competition Termination Date, (i) provide whatever cooperation and/or assistance is needed for any legal matters, proceedings or issues the Company may face, and (ii) cooperate with, and assist the Company and its employees in effecting, an orderly transition of all functions, duties and responsibilities of Rykhoek as an officer to one or more other employees of the Company, as the Company shall reasonably request. Additionally, Rykhoek agrees to provide such assistance in a professional manner, and in no event take any action that does, or could reasonably, create a conflict of interest between him and the Company, or that could subject either him

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or the Company to civil or criminal liability or is contrary to the policies or procedures of the Company.

(e)Non-disparagement. Rykhoek covenants and agrees that he will refrain from engaging in any conduct, verbal or otherwise, that would disparage or harm the reputation of DRI or its former and present parents, subsidiaries, and/or affiliates, along with its predecessors, successors and/or assigns, if any, as well as their respective former and present directors, officers, managers, general or limited partners, representatives, agents, employees and/or attorneys, if any, jointly and severally (collectively, the “DRI Released Parties”), and Rykhoek further covenants and agrees that he will not say anything of a disparaging nature about the operations, management, or performance of the DRI Released Parties. Such restricted conduct shall include, but not be limited to, any negative statements made orally or in writing by Rykhoek about any of the DRI Released Parties. DRI, on behalf of its Board of Directors and senior management (collectively, “DRI Senior Management”), covenants and agrees that DRI Senior Management will refrain from engaging in any conduct, verbal or otherwise, that would disparage or harm the reputation of Rykhoek. Such restricted conduct shall include, but not be limited to, any negative statements made orally or in writing by DRI Senior Management about Rykhoek.

(f)Exceptions. Nothing in this Agreement shall prohibit Rykhoek from (i) providing testimony in response to a valid subpoena, court order, regulatory request or other judicial, administrative or legal process or otherwise as required by law; provided, that, to the fullest extent permitted by law, Rykhoek agrees to notify the Company within three (3) days after receiving any request for testimony or information in response to a subpoena, court order, regulatory request or other judicial, administrative or legal process or otherwise as required by law, or (ii) reporting possible violations of federal law or regulation to any governmental agency or entity, including, but not limited to, the Department of Justice, the Securities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal law or regulation, and Rykhoek shall not be required to notify the Company that he has made any such reports or disclosures described in this clause (ii) except as otherwise provided by applicable law.

(g)Confidential Information and Property. Other than (i) the Company-issued laptop, iPad and cell-phone which Rykhoek is currently using and entitled to retain (subject to the Company’s policies and procedures), and (ii) certain additional immaterial, non-confidential and non-proprietary Company property, equipment and other tangible items which senior management of DRI determines Rykhoek is entitled to retain, Rykhoek covenants and agrees that he has returned, or within two (2) business days after the Officer Retirement Date will return, to the Company any and all Company property, equipment and other tangible items, including, without limitation, keys, building access cards and corporate credit cards, and any and all originals and/or copies of confidential information relating to the business of the Company or any of the other DRI

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Released Parties. Rykhoek further covenants and agrees (A) to not destroy, alter, erase, or otherwise change any software, data, or other information belonging to the DRI Released Parties, and (B) that the Company may (1) withhold from the Retirement Benefits an amount equal to the value of Company property, equipment and tangible things Rykhoek fails to return, (2) withhold from the Retirement Benefits any monies Rykhoek owes the Company, including, but not limited to, charges to the Company corporate credit card for which Rykhoek did not submit a valid expense report, unused travel advances, salary draws, etc., and (3) withhold any and all Retirement Benefits which would otherwise be paid or made available to Rykhoek pursuant to this Agreement until such time as Rykhoek has fully complied with the terms of this Section 6(g). Rykhoek further covenants and agrees that he will not, directly or indirectly, disclose to anyone, or use for his own benefit or the benefit of anyone other than the Company, (x) this Agreement, its existence or terms (provided, that, the prohibition on disclosure provided in this clause (x) shall not apply to (aa) Rykhoek’s spouse or any professional advisors engaged by Rykhoek in connection with a review of this Agreement; provided, further, that, Rykhoek’s spouse and any such advisors are informed and agree to be bound by the prohibition on disclosure contained in this clause (x), or (bb) publicly disclosed terms of this Agreement or its existence), or (y) any confidential information that Rykhoek has received through his employment with the Company. “Confidential information” shall include any information that has been disclosed or made available to, or created by, Rykhoek, and which was at the time of disclosure, availability or creation confidential or proprietary to the Company, and involves or relates to the Company’s current and future business plans and strategies, methods of operations or operational techniques, financial, management and/or employee information, information regarding the Company’s practices and processes, or any other non-public information. Rykhoek further agrees that in the event it appears that he will be compelled by law or judicial process to disclose any such confidential information to avoid potential liability, he will notify the Company in writing immediately upon his receipt (and in no event less than twenty-four (24) hours after receipt) of a subpoena or other legal process. The obligations set forth in this Section 6(g) shall be in addition to any other confidentiality obligations that Rykhoek may have to the Company or any of the DRI Released Parties, and Rykhoek further acknowledges that the injury the DRI Released Parties will suffer in the event of Rykhoek’s breach of any covenant or agreement set forth in this Section 6(g) cannot be compensated by monetary damages alone, and Rykhoek therefore agrees that the DRI Released Parties, in addition to and without limiting any other remedies or otherwise, shall have the right to obtain any injunctive or equitable relief against Rykhoek without notice and without posting a bond.

7.Mutually Dependent. The provisions of Section 4 above regarding Rykhoek’s continued employment and DRI’s continuing obligations to Rykhoek which are related thereto, and the covenants and agreements of Rykhoek set forth in Section 6 above, are mutually dependent, and Rykhoek understands and agrees that a violation of any of the provisions of Section 6 above may be considered a material breach of this Agreement, and further acknowledges and agrees that irreparable harm to the Company would result from a breach by

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him of any such provisions. Accordingly, notwithstanding any provision of this Agreement to the contrary, Rykhoek will permanently forfeit any rights to continued employment by the Company as set out under the provisions of Section 4 above, and the Company may immediately terminate such employment, beginning on the date that either (i) Rykhoek violates any provision of Section 6 above, or (ii) all or any part of, or the application of, Section 6 above is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in an action between Rykhoek and DRI, and on such date any continuing obligations of the Company to Rykhoek tied to his continued employment shall be extinguished.

8.General and Complete Release and Waiver. For and in consideration of the payments and benefits provided to be made under the provisions of Section 2 above, and the continued employment of Rykhoek under the provisions of Section 4 hereof, as well as the covenants and other consideration of DRI contained herein, the receipt and sufficiency of which are hereby acknowledged by Rykhoek, Rykhoek, on behalf of himself and his family, assigns, representatives, agents, and/or heirs, if any (collectively with Rykhoek, the “Rykhoek Parties”), hereby covenants not to sue and fully, finally and forever generally releases, acquits and forever discharges the DRI Released Parties, and/or any one of them, from any and all claims, demands, actions or liabilities of whatever kind or character, whether known or unknown, which the Rykhoek Parties, or any one of them, has or might claim to have against the DRI Released Parties, and/or any one of them, for any and all injuries, damages (actual or punitive), losses or attorneys’ fees, if any, incurred by any Rykhoek Party arising out of or in connection with any occurrence which transpired prior to the Officer Retirement Date, including, without limitation:

(a)all claims and causes of action arising under contract, tort, statute, or other common law, including, without limitation, breach of contract, fraud, fraudulent inducement, estoppel, misrepresentation, express or implied duties of good faith and fair dealing, wrongful discharge, discrimination, retaliation, harassment, negligence, gross negligence, false imprisonment, assault and battery, conspiracy, intentional or negligent infliction of emotional distress, slander, libel, defamation, refusal to perform an illegal act and invasion of privacy;

(b)all claims and causes of action arising under any federal, state, or local law, regulation, or ordinance, including, without limitation, claims under the AGE DISCRIMINATION IN EMPLOYMENT ACT, as amended, the Civil Rights Act of 1964, as amended, the Civil Rights Act of 1866, the Americans With Disabilities Act, the Fair Labor Standards Act, the Family and Medical Leave Act, the Employee Retirement Income Security Act as amended (except for vested benefits to which he is entitled), the Texas Commission on Human Rights Act, the Texas Labor Code, the Texas Government Code, The Dodd Frank Wall Street Reform and Consumer Protection Act, as amended, The Sarbanes Oxley Act of 2002, as amended, as well as any claims for compensation of any nature whatsoever, employee benefits, vacation pay (except as otherwise provided by Company policy), expense reimbursement, consulting, equity awards, severance pay, pension or profit sharing benefits, health or welfare benefits, bonus compensation (other than the Bonus Amount), commissions, deferred compensation or other remuneration, or employment benefits or compensation, except as specifically set forth in Section 2, “Special Compensation Benefits and

8

Consideration,” Section 3, “Equity Awards; Cash Awards” (with respect to equity awards held by Rykhoek immediately prior to the Officer Retirement Date), and Section 4, “Continued Employment;”

(c)all claims and causes of action for past or future loss of pay or benefits, expenses, damages for pain and suffering, mental anguish or emotional distress damages, liquidated damages, punitive damages, compensatory damages, injunctive relief, attorneys’ fees, interest, court costs, physical or mental injury, damage to reputation, and any other injury, loss, damage or expense or any other legal or equitable remedy of any kind whatsoever;

(d)all claims and causes of action arising out of or in any way connected with, directly or indirectly, Rykhoek’s employment with the Company, or any incident thereof, including, without limitation, (i) his treatment by the Company, (ii) the terms and conditions of his employment, (iii) the manner or amounts in which Rykhoek was paid or compensated by the Company, (iv) the separation of Rykhoek’s employment, and (v) this Agreement, including any claim that Rykhoek has been fraudulently induced to enter into this Agreement; and

(e)all claims and causes of action of any kind or character which could have been alleged in any lawsuit or administrative charge, claim or proceeding that could have been filed against the DRI Released Parties (or any one of them) by any Rykhoek Party on its own behalf or on behalf of any other person.

Nothing in this Agreement will prevent Rykhoek from filing a charge or complaint with the Equal Employment Opportunity Commission or any other federal or state administrative agency, or participating in any investigation conducted by any federal or state administrative agency; provided, however, that, Rykhoek agrees that any right to personal legal or equitable relief he may have in connection with any such charge, complaint or investigation is hereby waived, forfeited and barred, except as otherwise expressly provided by law.

Except with respect to the Bonus Amount, Rykhoek acknowledges and agrees that the compensation referenced in Section 2 above does not constitute monies to which he would otherwise be entitled as a result of his prior or current employment with the Company, and that these monies constitute fair and adequate compensation for the promises and covenants of Rykhoek set forth in this Agreement. Rykhoek agrees and acknowledges that, following the Officer Retirement Date, no further amounts are due to him for cash compensation of any nature whatsoever, including salary, severance pay, performance cash or bonuses (other than the Bonus Amount), or for equity awards, employee benefits, deferred compensation, commissions, vacation pay (except as may otherwise be provided by Company policy), pension, profit sharing benefits, health or welfare benefits, expense reimbursement, consulting, outplacement services, attorneys’ fees, pay in lieu of notice, or for any other amounts, except as specifically set forth in Section 2, “Special Compensation Benefits and Consideration,” Section 3, “Equity Awards; Cash Awards” (with respect to equity awards held by Rykhoek immediately prior to the Officer Retirement Date), and Section 4, “Continued Employment.”

9

9.Consultation with Attorney and Review Period.

(a)Rykhoek is advised, and acknowledges that he has been advised, to consult with an attorney (at his sole cost) prior to executing this Agreement concerning the meaning, import, and legal significance of this Agreement. Rykhoek acknowledges that he has read this Agreement, as signified by his signature below, and is voluntarily executing the same after, if sought, advice of counsel for the purposes and consideration herein expressed.

(b)Rykhoek affirms, acknowledges and agrees that (i) he has read and understands the terms of this Agreement, (ii) he is over the age of eighteen (18) years and is otherwise competent to execute this Agreement, (iii) he was given or provided this Agreement on March 1, 2017, and has been given and provided the opportunity to consider and accept this Agreement until 5:00 p.m. (CST) on March 21, 2017 (a period of not less than twenty-one (21) days following the date Rykhoek was provided this Agreement) by signing it and returning it to James S. Matthews, Senior Vice President and General Counsel of DRI, at the address provided in Section 11 below, after which time it would have expired and be void if not received, (iv) any changes to this Agreement from the one that was initially provided on March 1, 2017 as a result of negotiation between him and the Company, whether material or immaterial, did not restart or extend the running of the applicable 21-day period of time in which he had to sign this Agreement, (v) he is entering into this Agreement knowingly and voluntarily and without any undue influence or pressures, (vi) this Agreement includes a release of any claim that Rykhoek may have under the Age Discrimination in Employment Act, and (vii) this Agreement represents and constitutes a full and final resolution of any and all claims, if any, which the Rykhoek Parties (or any one of them) may have against the DRI Released Parties (or any one of them).

(c)Rykhoek acknowledges that he shall be entitled to revoke this Agreement at any time prior to the expiration of seven (7) days after the date of execution of this Agreement by Rykhoek by providing written notice of such revocation to James S. Matthews, Senior Vice President and General Counsel of DRI, at the address provided in Section 11 below. This Agreement does not become effective or enforceable until the revocation period has passed. As used herein, “Effective Date” means the eighth (8^th) calendar day after Rykhoek provides a signed Agreement to James S. Matthews, Senior Vice President and General Counsel of DRI, at the address provided in Section 11 below, provided Rykhoek does not revoke the Agreement pursuant to, and in accordance with, this Section 9(c).

10.Governing Law. This Agreement shall be governed by, and construed under, the laws of the State of Texas.

11.Notice. Any notice, payment, demand or communication required or permitted to be given by this Agreement shall be deemed to have been sufficiently given or served for all purposes if delivered personally to and signed for by the party or to any officer of the party to

10

whom the same is directed, or if sent by registered or certified mail, return receipt requested, postage and charges prepaid, addressed to such party at the address set forth below or to such other address as shall have been furnished in writing by such party for whom the communication is intended. Any such notice shall be deemed to be given on the date so delivered.

Denbury Resources Inc.

5320 Legacy Drive

Plano, Texas 75024

Attention: James S. Matthews

SVP and General Counsel

Phil Rykhoek

6631 Via Positano

Unit 411

Irving, Texas 75039

12.Severability. In the event that any one or more of the provisions contained in this Agreement is for any reason held to be unenforceable in any respect under the laws of any applicable State or of the United States of America, such unenforceability will not affect any other provision of this Agreement, but with respect only to the jurisdiction holding the provision to be unenforceable, this Agreement will then be construed as if such unenforceable provision or provisions had never been contained herein.

13.Entire Agreement. This Agreement constitutes the sole agreement between the parties and supersedes any and all other agreements, oral or written, relating to the subject matter covered by the Agreement, with the exception of (i) any indemnity agreement which may exist between DRI and Rykhoek, and which indemnity agreement shall remain in force subject to its terms and independent of this Agreement, and (ii) the terms of DRI’s equity compensation plans and the award agreements made thereunder which are not otherwise specifically addressed in this Agreement.

14.Waiver. Any waiver or breach of any of the terms or conditions of this Agreement shall not operate as a waiver of any other breach of such terms or conditions, or any other terms or conditions, nor shall any failure to enforce any provision hereof operate as a waiver of such provision or any other provision hereof.

15.Assignment. This Agreement is personal to Rykhoek and the rights and interests of Rykhoek hereunder may not be sold, transferred, assigned or pledged.

16.Successors. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, representatives and successors (including specifically any successor to DRI by merger, reorganization or otherwise).

17.Disputes.

(a)If any dispute arises under this Agreement arising out of, related to or in connection with, the payment of amounts provided hereunder to be

11

paid by DRI to Rykhoek, the timing of such payments or their calculation, or questions regarding the breach of the terms hereof or any issue of arbitrability (a “Dispute”), and the Dispute cannot be settled through direct discussions by the parties within a reasonable amount of time, DRI and Rykhoek agree that such Dispute shall be referred to and finally resolved by confidential binding arbitration in accordance with the provisions of Exhibit A hereto. The award of the arbitrator will be the exclusive remedy of the parties for such Dispute.

(b)Notwithstanding Section 17(a), the parties acknowledge that money damages would not be a sufficient remedy for any breach of Section 6(b), (d), (e), and/or (g) by Rykhoek. Therefore, the parties agree that the Company may resort to Texas state courts having equity jurisdiction in and for Collin County, Texas and the United States District Court for the Northern District of Texas, to enforce Sections 6(b), (d), (e), and/or (g) of this Agreement by injunctive relief. Additionally, the parties agree that the Company may enforce Rykhoek’s promises made in Sections 6(b), (d), (e), and/or (g) without posting a bond and without giving notice to the maximum extent permitted by law. Furthermore, in the event of a breach and/or threatened breach by Rykhoek, the Company shall be entitled to terminate any payments then owing to Rykhoek under this Agreement. The foregoing remedies shall not be deemed the exclusive remedies for a breach and/or threatened breach of Section 6(b), (d), (e), and/or (g) of this Agreement, but shall be in addition to all remedies available at law or in equity to the Company, including, without limitation, the recovery of damages from Rykhoek.

(c)Jurisdiction and venue of any action relating to this Agreement or Rykhoek’s employment by the Company (subject to the provisions of Section 17(a) hereof) shall be in the federal or state courts sitting in, or having jurisdiction over, Plano, Collin County, Texas.

18.Consequences of Breach. Without limitation of the terms and provisions of this Agreement, including, without limitation, Section 8 hereof, Rykhoek (a) agrees that he will indemnify and hold each of the DRI Released Parties harmless from any loss, cost, damage, or expense (including attorneys’ fees, except as prohibited by law) incurred by any of them arising out of Rykhoek’s breach of any portion of this Agreement, (b) agrees and understands that the Company’s obligation to make any payments or to provide any benefits under this Agreement, and Rykhoek’s entitlement to and retention of any Retirement Benefits that the Company has agreed to provide him herein, is expressly conditioned upon Rykhoek’s ongoing fulfillment of his promises, covenants and obligations herein, and (c) agrees, to the extent permitted by law, to immediately return or repay the amounts he has received from the Company in connection with this Agreement in excess of $500.00 (or as otherwise determined by a court of competent jurisdiction) upon a finding or ruling by a court of competent jurisdiction that Rykhoek breached a provision of this Agreement. In the event DRI concludes or, in good faith, suspects that Rykhoek has breached this Agreement, no additional payments will be provided under this

12

Agreement unless and until the Company is so ordered to make such payment by a court of competent jurisdiction.

19.No Admission. The parties agree that this Agreement does not constitute an admission of any kind by the Company, any DRI Released Party or Rykhoek.

20.Amendments. Any modification of this Agreement or additional obligation assumed by any party in connection with this Agreement shall be binding only if evidenced in writing signed by both parties to this Agreement or an authorized representative of each party. Additionally, this Agreement cannot be changed or terminated orally, but may be changed only through written addendum or amendment executed by both parties.

21.Remedies. In addition to the other remedies provided herein or by applicable law, any breach by Rykhoek of any of the terms and/or conditions contained in this Agreement shall give the Company the right to discontinue the performance of any unperformed duties and obligations under this Agreement to the extent permitted by applicable law. In the event Rykhoek breaches any term or condition of this Agreement, any delay by DRI to enforce this Agreement (or any term or condition hereof) shall not be deemed a waiver, acceptance, or acquiescence. Without limitation of any other provision of this Agreement, including, without limitation, Section 14 hereof, no waiver shall bind DRI unless supported by consideration, executed in writing, and delivered to Rykhoek by an authorized officer of DRI.

22.Counterparts; Signatures. This Agreement may be executed in several counterparts, each of which shall be deemed an original and all of which shall constitute one Agreement; it being understood that the parties need not sign the same counterparts. The exchange of copies of this Agreement and of signature pages by facsimile transmission, by electronic mail in “portable document format” (“.pdf”') form, or by any other electronic means, or by combination of such means, shall constitute effective execution and delivery of this Agreement as to the parties and may be used in lieu of the original Agreement for all purposes. Signatures of the parties transmitted by any means shall be deemed to be their original signatures for all purposes.

23.Representations and Warranties. By executing this Agreement, Rykhoek acknowledges that he: (a) is not relying upon any statements, understandings, representations, expectations, or agreements other than those expressly set forth in this Agreement, (b) has made his own investigation of the facts and is relying solely upon his own knowledge and, if applicable, the advice of his own legal counsel, (c) knowingly waives any claim that he was induced to enter into this Agreement by any misrepresentation or nondisclosure and any right to rescind or avoid this Agreement based upon presently existing facts, known or unknown, (d) is entering into this Agreement freely and voluntarily, and (e) has carefully read and understands all of the provisions of this Agreement. The parties stipulate that the Company is relying upon these representations and warranties in entering into this Agreement. These representations and warranties shall survive the execution of this Agreement.

PLEASE READ THIS AGREEMENT CAREFULLY. IT CONTAINS A RELEASE OF ALL KNOWN AND UNKNOWN CLAIMS.

13

THE UNDERSIGNED ACKNOWLEDGE THAT THEY HAVE CAREFULLY READ THE FOREGOING AGREEMENT, THAT THEY UNDERSTAND ALL OF ITS TERMS, AND THAT THEY ARE ENTERING INTO IT VOLUNTARILY.

[Signature Page to Follow]

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IN WITNESS WHEREOF, the parties hereto affixed their signatures hereunder as of the date set forth below their signature blocks, to be effective as of the Effective Date.

DENBURY RESOURCES INC.
By:	/s/ James S. Matthews
Name:	James S. Matthews
Title:	Senior Vice President and General Counsel
Date:	March 21, 2017

PHIL RYKHOEK
/s/ Phil Rykhoek
Date:	March 21, 2017

[Signature Page]

EXHIBIT A

DISPUTE RESOLUTION PROCEDURES

1.Applicable Law/Arbitration. Venue for the arbitration provided under Section 17(a) of the Agreement shall be in Plano, Collin County, Texas. The parties waive their right to file a lawsuit in a court of law to prosecute any Dispute.

2.Negotiation. When a Dispute has arisen and negotiations have reached an impasse, either party may give the other party written notice of the Dispute. In the event such notice is given, the parties shall attempt to resolve the Dispute promptly by negotiation. Within ten (10) days after delivery of the notice, the receiving party shall submit to the other a written response. Thereafter, the parties shall promptly attempt to resolve the Dispute.

3.Confidentiality of Settlement Negotiations. All negotiations and proceedings pursuant to Section 2 above are confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence and any additional confidentiality protections provided by applicable law.

4.Commencement of Arbitration. If the Dispute has not been resolved by negotiation within fifteen (15) days of the disputing party’s notice, or if the parties have failed to confer within fifteen (15) days after delivery of the notice, either party may then initiate arbitration by providing written notice of arbitration to the other party. In order to be valid, the notice shall contain a precise and complete statement of the Dispute. Within fifteen (15) days of receipt of the notice initiating arbitration, the receiving party shall respond by providing a written response which shall include its precise and complete response to the Dispute, and which includes any counter Dispute that the responding party may have.

5.Selection of Arbitrator. The arbitration shall be conducted and decided by a single neutral arbitrator that is mutually agreeable to the parties and knowledgeable and experienced in the type of matter that is the subject of the Dispute using the CPR (defined below) rules. Once selected, the arbitrator shall not have any ex parte communications with either party.

6.Arbitration Process. The arbitration hearing shall commence within a reasonable time after the selection of the arbitrator, as set by the arbitrator. The arbitrator shall allow the parties to engage in pre-hearing discovery, to include exchanging (a) requests for and production of relevant documents, (b) up to fifteen (15) interrogatories, (c) up to fifteen (15) requests for admissions, and producing for deposition and at the arbitration hearing, up to four (4) persons within each parties’ control. Any additional discovery shall only occur by agreement of the parties or as ordered by the arbitrator upon a finding of good cause. The arbitration shall be conducted under the Rules of the CPR International Institute for Conflict Prevention & Resolution (“CPR”) in effect on the date of notice of the Dispute for dispute resolution rules for non-administered arbitration of business disputes. The parties may agree on such other rules to govern the arbitration that are not set out in this provision as they may mutually deem necessary.

A-1

7.Arbitration Decision. The arbitrator shall have the power to award interim relief, and to grant specific performance. The arbitrator may award interest at the “prime rate” as listed under “Market Data” in the Wall Street Journal on the date of any such award. Except as may be specifically limited elsewhere in this Exhibit A, the arbitrator’s decision may be based on such factors and evidence as the arbitrator deems fit.

8.Binding Arbitration Award. The award of the arbitrator shall be final, conclusive and binding. The award rendered by the arbitrator may be entered in any court having jurisdiction in respect thereof, including any court in which an injunction may have been sought.

A-2

EX-31.A

Exhibit 31(a)

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Phil Rykhoek, certify that:

1. I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

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;

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;

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:

(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;

(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;

(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

(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

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):

(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

(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.

May 5, 2017	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer

EX-31.B

Exhibit 31(b)

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark C. Allen, certify that:

1. I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

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;

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;

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:

(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;

(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;

(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

(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

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):

(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

(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.

May 5, 2017	/s/ Mark Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

EX-32

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, 2017 (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:

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

2. The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.

Dated:	May 5, 2017	/s/ Phil Rykhoek
		Phil Rykhoek
		Chief Executive Officer
Dated:	May 5, 2017	/s/ Mark C. Allen
		Mark C. Allen
		Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 30, 2017
Document And Company Information [Abstract]
Entity Registrant Name	Denbury Resources Inc.
Trading Symbol	DNR
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Central Index Key	0000945764
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		398,337,400

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 1,747	$ 1,606
Accrued production receivable		118,483	124,936
Trade and other receivables, net		55,653	43,900
Derivative assets		1,062	0
Other current assets		11,324	10,684
Total current assets		188,269	181,126
Oil and natural gas properties (using full cost accounting)
Proved properties		10,475,877	10,419,827
Unevaluated properties		951,220	927,819
CO2 properties		1,187,711	1,188,467
Pipelines and plants		2,285,435	2,285,812
Other property and equipment		373,537	378,776
Less accumulated depletion, depreciation, amortization and impairment		(11,255,392)	(11,212,327)
Net property and equipment		4,018,388	3,988,374
Other assets		102,002	105,078
Total assets		4,308,659	4,274,578
Current liabilities
Accounts payable and accrued liabilities		180,529	200,266
Oil and gas production payable		73,250	80,585
Derivative liabilities		18,799	69,279
Current maturities of long-term debt (including future interest payable of $50,349 and $50,349, respectively - see Note 2)	[1]	83,701	83,366
Total current liabilities		356,279	433,496
Long-term liabilities
Long-term debt, net of current portion (including future interest payable on $178,476 and $178,476, respectively - see Note 2)		2,956,385	2,909,732
Asset retirement obligations		151,390	146,807
Deferred tax liabilities, net		328,786	293,878
Other liabilities		22,060	22,217
Total long-term liabilities		3,458,621	3,372,634
Commitments and contingencies (Note 6)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding		0	0
Common stock, $.001 par value, 600,000,000 shares authorized; 402,706,108 and 402,334,655 shares issued, respectively		403	402
Paid-in capital in excess of par		2,540,057	2,534,670
Accumulated deficit		(1,997,455)	(2,018,989)
Treasury stock, at cost, 4,403,152 and 3,906,877 shares, respectively		(49,246)	(47,635)
Total stockholders' equity		493,759	468,448
Total liabilities and stockholders' equity		$ 4,308,659	$ 4,274,578

[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Current maturities of long-term debt	[1]	$ 83,701	$ 83,366
Long-term Debt and Capital Lease Obligations		$ 2,956,385	$ 2,909,732
Stockholders' equity
Preferred stock, par value (actual)		$ 0.001	$ 0.001
Preferred stock, shares authorized		25,000,000	25,000,000
Preferred stock, shares issued		0	0
Preferred stock, shares outstanding		0	0
Common stock, par value (actual)		$ 0.001	$ 0.001
Common stock, shares authorized		600,000,000	600,000,000
Common stock, shares issued		402,706,108	402,334,655
Treasury stock, shares		4,403,152	3,906,877
Future interest payable on 9% Senior Secured Second Lien Notes
Debt Instrument [Line Items]
Current maturities of long-term debt		$ 50,349	$ 50,349
Long-term Debt and Capital Lease Obligations		$ 178,476	$ 178,476

[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

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Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues and other income
Oil, natural gas, and related product sales	$ 266,178	$ 187,803
CO2 sales and transportation fees	5,388	6,272
Interest income and other income	3,888	769
Total revenues and other income	275,454	194,844
Expenses
Lease operating expenses	113,840	102,447
Marketing and plant operating expenses	14,065	13,194
CO2 discovery and operating expenses	593	607
Taxes other than income	22,440	20,092
General and administrative expenses	28,241	33,901
Interest, net of amounts capitalized of $4,654 and $5,780, respectively	27,178	42,171
Depletion, depreciation, and amortization	51,195	77,366
Commodity derivatives expense (income)	(24,602)	22,826
Gain on debt extinguishment	0	(94,991)
Write-down of oil and natural gas properties	0	256,000
Other expenses	0	1,544
Total expenses	232,950	475,157
Income (loss) before income taxes	42,504	(280,313)
Income tax provision (benefit)	20,974	(95,120)
Net income (loss)	$ 21,530	$ (185,193)
Net income (loss) per common share
Basic	$ 0.06	$ (0.53)
Diluted	$ 0.05	$ (0.53)
Weighted average common shares outstanding
Basic	389,397	347,235
Diluted	392,997	347,235

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Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Expenses
Capitalized interest	$ 4,654	$ 5,780

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities
Net income (loss)	$ 21,530	$ (185,193)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	51,195	77,366
Write-down of oil and natural gas properties	0	256,000
Deferred income taxes	34,909	(95,115)
Stock-based compensation	4,106	859
Commodity derivatives expense (income)	24,602	(22,826)
Receipt (payment) on settlements of commodity derivatives	(26,940)	72,227
Gain on debt extinguishment	0	(94,991)
Debt issuance costs and discounts	1,901	3,306
Other, net	(344)	(416)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	6,453	4,479
Trade and other receivables	(12,185)	812
Other current and long-term assets	643	1,437
Accounts payable and accrued liabilities	(23,890)	(53,548)
Oil and natural gas production payable	(7,335)	(7,572)
Other liabilities	(1,179)	(448)
Net cash provided by operating activities	24,262	2,029
Cash flows from investing activities
Oil and natural gas capital expenditures	(52,152)	(65,692)
Acquisitions of oil and natural gas properties	(16,222)	(224)
Pipelines and plants capital expenditures	(246)	(635)
Net proceeds from sales of oil and natural gas properties and equipment	415	0
Other	608	(403)
Net cash used in investing activities	(67,597)	(66,954)
Cash flows from financing activities
Bank repayments	(343,000)	(696,000)
Bank borrowings	397,000	831,000
Repurchases of senior subordinated notes	0	(55,521)
Pipeline financing and capital lease debt repayments	(7,055)	(7,387)
Other	(3,469)	(1,727)
Net cash provided by financing activities	43,476	70,365
Net increase in cash and cash equivalents	141	5,440
Cash and cash equivalents at beginning of period	1,606	2,812
Cash and cash equivalents at end of period	$ 1,747	$ 8,252

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Basis of Presentation

3 Months Ended

Mar. 31, 2017

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, 2016 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2017, our consolidated results of operations for the three months endedMarch 31, 2017 and 2016, and our consolidated cash flows for the three months ended March 31, 2017 and 2016.

Reclassifications

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

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock and nonvested performance-based equity awards.  For the three months endedMarch 31, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

	Three Months Ended
	March 31,
In thousands	2017	2016
Basic weighted average common shares outstanding	389,397	347,235
Potentially dilutive securities
Restricted stock and performance-based equity awards	3,600	—
Diluted weighted average common shares outstanding	392,997	347,235

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

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

	Three Months Ended
	March 31,
In thousands	2017	2016
Stock appreciation rights	5,044	7,412
Restricted stock and performance-based equity awards	1,229	5,097

2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a ceiling test write-down during the three months endedMarch 31, 2017.

Recent Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and early adoption is permitted. Effective January 1, 2017, we adopted ASU 2017-01. The adoption of ASU 2017-01 did not have a material impact on our current period consolidated financial statements.

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

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is still evaluating this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.

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Long-Term Debt

3 Months Ended

Mar. 31, 2017

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	2017			2016
Senior Secured Bank Credit Agreement	$	355,000		$	301,000
9% Senior Secured Second Lien Notes due 2021	614,919			614,919
6⅜% Senior Subordinated Notes due 2021	215,144			215,144
5½% Senior Subordinated Notes due 2022	772,912			772,912
4⅝% Senior Subordinated Notes due 2023	622,297			622,297
Other Subordinated Notes, including premium of $2 and $3, respectively	2,252			2,253
Pipeline financings	200,038			202,671
Capital lease obligations	43,649			48,718
Total debt principal balance	2,826,211			2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)	228,825			228,825
Issuance costs on senior secured second lien and senior subordinated notes	(14,950		)	(15,641		)
Total debt, net of debt issuance costs	3,040,086			2,993,098
Less: current maturities of long-term debt (1)	(83,701		)	(83,366		)
Long-term debt and capital lease obligations	$	2,956,385		$	2,909,732

(1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. In May 2017, as part of our semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with the next such redetermination scheduled for November 2017. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 3.2% as of March 31, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

In conjunction with the May 2017 borrowing base redetermination, we amended certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders. The amendments to the Bank Credit Agreement included the following:

• Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;

• Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

• Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and

• Increasing the applicable margin for ABR Loans and LIBOR Loans by 50 basis points such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum.

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

2016 Repurchases of Senior Subordinated Notes

During the first quarter of 2016, we repurchased a total of $152.3 million of our outstanding long-term indebtedness, consisting of $4.0 million principal amount of our 6⅜% Senior Subordinated Notes due 2021, $42.3 million principal amount of our 5½% Senior Subordinated Notes due 2022, and $106.0 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off, during the three months ended March 31, 2016. As of May 3, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on repurchases or other redemptions of our senior subordinated notes.

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Income Taxes

3 Months Ended

Mar. 31, 2017

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, 2017, we had $36.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of falling commodity prices, combined with a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $36.5 million during 2015 and 2016, which reduced the carrying value of these deferred tax assets to zero as of December 31, 2016. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.

As of March 31, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of March 31, 2017.

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Commodity Derivative Contracts

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Contracts

Note 4. Commodity Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2017, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of March 31, 2017, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range (1)				Weighted Average Price
							Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2017 Fixed-Price Swaps
Apr – June	NYMEX	22,000	$	41.20	–	46.50	$	43.99	$	—	$	—	$	—
Apr – June	LLS	7,000		42.65	–	46.65	45.35		—		—		—
2017 Collars
Oct – Dec	NYMEX	1,000	$	40.00	–	70.00	$	—	$	—	$	40.00	$	70.00
2017 Three-Way Collars(2)
July – Sept	NYMEX	14,500	$	40.00	–	70.25	$	—	$	30.00	$	40.00	$	69.09
July – Sept	LLS	2,000		41.00	–	69.25	—		31.00		41.00		69.25
Oct – Dec	NYMEX	11,000		40.00	–	70.20	—		30.00		40.00		69.67
Oct – Dec	LLS	1,000		41.00	–	70.25	—		31.00		41.00		70.25

(1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 5. Fair Value Measurements

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

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

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

• Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At March 31, 2017, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $2 thousand in the fair value of these instruments as of March 31, 2017.

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

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2017
Assets
Oil derivative contracts – current	$	—	$	971	$	91	$	1,062
Total Assets	$	—	$	971	$	91	$	1,062
Liabilities
Oil derivative contracts – current	$	—	$	18,799	$	—	$	18,799
Total Liabilities	$	—	$	18,799	$	—	$	18,799
December 31, 2016
Liabilities
Oil derivative contracts – current	$	—	$	68,753	$	526	$	69,279
Total Liabilities	$	—	$	68,753	$	526	$	69,279

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

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months endedMarch 31, 2017 and 2016:

	Three Months Ended
	March 31,
In thousands	2017			2016
Fair value of Level 3 instruments, beginning of period	$	(526	)	$	52,834
Fair value gains on commodity derivatives	617			281
Receipts on settlements of commodity derivatives	—			(30,075		)
Fair value of Level 3 instruments, end of period	$	91		$	23,040
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	236		$	133

We utilize an income approach to value our Level 3 costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:

	Fair Value at 3/31/2017 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	91	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2017	22.8% – 34.2%

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices. The estimated fair value of the principal amount of our debt as of March 31, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $2,231.3 million and $2,327.8 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 6. Commitments and Contingencies

Commitments

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

Litigation

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

Riley Ridge Helium Supply Contract Claim

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

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Additional Balance Sheet Details

3 Months Ended

Mar. 31, 2017

Disclosure Text Block [Abstract]

Additional Balance Sheet Details

Note 7. Additional Balance Sheet Details

Trade and Other Receivables, Net

	March 31,		December 31,
In thousands	2017		2016
Trade accounts receivable, net	$	17,346	$	20,084
Federal income tax receivable	14,054		—
Other receivables	24,253		23,816
Total	$	55,653	$	43,900

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2017

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.

Interim Financial Statements - Basis of Accounting, Policy

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Interim Financial Statements - Use of Estimates

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2017, our consolidated results of operations for the three months endedMarch 31, 2017 and 2016, and our consolidated cash flows for the three months ended March 31, 2017 and 2016

Reclassifications

Reclassifications

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

Net Income (Loss) per Common Share

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock and nonvested performance-based equity awards.  For the three months endedMarch 31, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

	Three Months Ended
	March 31,
In thousands	2017	2016
Basic weighted average common shares outstanding	389,397	347,235
Potentially dilutive securities
Restricted stock and performance-based equity awards	3,600	—
Diluted weighted average common shares outstanding	392,997	347,235

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

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

	Three Months Ended
	March 31,
In thousands	2017	2016
Stock appreciation rights	5,044	7,412
Restricted stock and performance-based equity awards	1,229	5,097

Oil and Natural Gas Properties Policy

2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing a full cost pool ceiling test write-down of $256.0 million during the three months ended March 31, 2016. We did not record a ceiling test write-down during the three months endedMarch 31, 2017.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and early adoption is permitted. Effective January 1, 2017, we adopted ASU 2017-01. The adoption of ASU 2017-01 did not have a material impact on our current period consolidated financial statements.

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

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is still evaluating this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.

Commodity Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2017, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

Fair Value Measurements

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

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

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

• Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At March 31, 2017, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $2 thousand in the fair value of these instruments as of March 31, 2017.

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

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Basis of Presentation (Tables)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Weighted average shares used in the basic and diluted net loss per common share

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

	Three Months Ended
	March 31,
In thousands	2017	2016
Basic weighted average common shares outstanding	389,397	347,235
Potentially dilutive securities
Restricted stock and performance-based equity awards	3,600	—
Diluted weighted average common shares outstanding	392,997	347,235

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

	Three Months Ended
	March 31,
In thousands	2017	2016
Stock appreciation rights	5,044	7,412
Restricted stock and performance-based equity awards	1,229	5,097

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

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	2017			2016
Senior Secured Bank Credit Agreement	$	355,000		$	301,000
9% Senior Secured Second Lien Notes due 2021	614,919			614,919
6⅜% Senior Subordinated Notes due 2021	215,144			215,144
5½% Senior Subordinated Notes due 2022	772,912			772,912
4⅝% Senior Subordinated Notes due 2023	622,297			622,297
Other Subordinated Notes, including premium of $2 and $3, respectively	2,252			2,253
Pipeline financings	200,038			202,671
Capital lease obligations	43,649			48,718
Total debt principal balance	2,826,211			2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)	228,825			228,825
Issuance costs on senior secured second lien and senior subordinated notes	(14,950		)	(15,641		)
Total debt, net of debt issuance costs	3,040,086			2,993,098
Less: current maturities of long-term debt (1)	(83,701		)	(83,366		)
Long-term debt and capital lease obligations	$	2,956,385		$	2,909,732

(1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

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Commodity Derivative Contracts (Tables)

3 Months Ended

Mar. 31, 2017

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, 2017, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range (1)				Weighted Average Price
							Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2017 Fixed-Price Swaps
Apr – June	NYMEX	22,000	$	41.20	–	46.50	$	43.99	$	—	$	—	$	—
Apr – June	LLS	7,000		42.65	–	46.65	45.35		—		—		—
2017 Collars
Oct – Dec	NYMEX	1,000	$	40.00	–	70.00	$	—	$	—	$	40.00	$	70.00
2017 Three-Way Collars(2)
July – Sept	NYMEX	14,500	$	40.00	–	70.25	$	—	$	30.00	$	40.00	$	69.09
July – Sept	LLS	2,000		41.00	–	69.25	—		31.00		41.00		69.25
Oct – Dec	NYMEX	11,000		40.00	–	70.20	—		30.00		40.00		69.67
Oct – Dec	LLS	1,000		41.00	–	70.25	—		31.00		41.00		70.25

(1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

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, 2017
Assets
Oil derivative contracts – current	$	—	$	971	$	91	$	1,062
Total Assets	$	—	$	971	$	91	$	1,062
Liabilities
Oil derivative contracts – current	$	—	$	18,799	$	—	$	18,799
Total Liabilities	$	—	$	18,799	$	—	$	18,799
December 31, 2016
Liabilities
Oil derivative contracts – current	$	—	$	68,753	$	526	$	69,279
Total Liabilities	$	—	$	68,753	$	526	$	69,279

Changes in fair value of Level 3 assets and liabilities

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months endedMarch 31, 2017 and 2016:

	Three Months Ended
	March 31,
In thousands	2017			2016
Fair value of Level 3 instruments, beginning of period	$	(526	)	$	52,834
Fair value gains on commodity derivatives	617			281
Receipts on settlements of commodity derivatives	—			(30,075		)
Fair value of Level 3 instruments, end of period	$	91		$	23,040
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	236		$	133

Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3)

The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:

	Fair Value at 3/31/2017 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	91	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2017	22.8% – 34.2%

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Additional Balance Sheet Details (Tables)

3 Months Ended

Mar. 31, 2017

Table Text Block [Abstract]

Trade and Other Receivables, Net

Trade and Other Receivables, Net

	March 31,		December 31,
In thousands	2017		2016
Trade accounts receivable, net	$	17,346	$	20,084
Federal income tax receivable	14,054		—
Other receivables	24,253		23,816
Total	$	55,653	$	43,900

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Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Weighted average shares used in the basic and diluted net income per common share
Basic weighted average common shares outstanding	389,397	347,235
Potentially dilutive securities
Restricted stock and performance-based equity awards	3,600	0
Diluted weighted average common shares outstanding	392,997	347,235

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Basis of Presentation (Antidilutive Securities) (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5,044	7,412
Restricted stock and performance-based equity awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,229	5,097

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Basis of Presentation (Details Textuals) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accounting Policies [Abstract]
Write-down of oil and natural gas properties	$ 0	$ 256,000

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Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Senior Secured Bank Credit Agreement		$ 355,000	$ 301,000
Pipeline financings		200,038	202,671
Capital lease obligations		43,649	48,718
Total debt principal balance		2,826,211	2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021	[1]	228,825	228,825
Total debt, net of debt issuance costs		3,040,086	2,993,098
Less: current maturities of long-term debt	[1]	(83,701)	(83,366)
Long-term debt and capital lease obligations		2,956,385	2,909,732
9% Senior Secured Second Lien Notes Due 2021
Debt Instrument [Line Items]
9% Senior Secured Second Lien Notes due 2021		614,919	614,919
Less: current maturities of long-term debt		$ (50,300)
Debt Instrument, Interest Rate, Stated Percentage		9.00%
Second Lien and Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Issuance costs on senior secured second lien and senior subordinated notes		$ (14,950)	(15,641)
Senior Subordinated Notes [Member] | 6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 215,144	215,144
Debt Instrument, Interest Rate, Stated Percentage		6.375%
Senior Subordinated Notes [Member] | 5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 772,912	772,912
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Senior Subordinated Notes [Member] | 4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 622,297	622,297
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Senior Subordinated Notes [Member] | Other Subordinated Notes
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 2,252	2,253
Including premium of		$ 2	$ 3

[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of March 31, 2017 include $50.3 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

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Long-Term Debt (Details Textuals)		3 Months Ended
	May 05, 2017 USD ($)	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	May 03, 2017 USD ($)
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%
Debt Instrument, Repurchased Face Amount			$ 152,300,000
Debt Instrument, Repurchase Amount			55,500,000
Gain on debt extinguishment		$ 0	94,991,000
Senior Secured Bank Credit Facility [Abstract]
Weighted average interest rate on Bank Credit Facility		3.20%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Current Ratio Requirement		1.0
Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Line of Credit, Borrowing Base	$ 1,050,000,000.00
Line of Credit Facility, Current Borrowing Capacity	$ 1,050,000,000.00
Senior subordinated notes available for repurchase				$ 148,300,000
Senior Subordinated Notes [Member] | 6 3/8% Senior Subordinated Notes due 2021
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount			4,000,000
Senior Subordinated Notes [Member] | 5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount			42,300,000
Senior Subordinated Notes [Member] | 4 5/8% Senior Subordinated Notes due 2023
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount			$ 106,000,000
Year 2017 | Q2 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	3.0
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2017 | Q3 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	3.0
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2017 | Q4 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	3.0
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2018 | Q1 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	3.0
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2018 | Q2 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2018 | Q3 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2018 | Q4 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2019 | Q1 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2019 | Q2 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Year 2019 | Q3 | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX	2.5
Consolidated EBITDAX to Consolidated Interest Charges	1.25
Base Rate [Member] | Minimum | Senior Secured Bank Credit Facility | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility	1.50%
Base Rate [Member] | Maximum | Senior Secured Bank Credit Facility | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Minimum | Senior Secured Bank Credit Facility | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum | Senior Secured Bank Credit Facility | Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility	3.50%

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Income Taxes (Details) - USD ($)	24 Months Ended
	Dec. 31, 2016	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local		$ 36,500,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 36,500,000
Unrecognized Tax Benefits		$ 5,400,000
Deferred Tax Assets, Net of Valuation Allowance	$ 0

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Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - Year 2017	Mar. 31, 2017 bbl / d $ / Barrel
Swap | Q2 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	22,000
Weighted average swap price	43.99
Swap | Q2 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	41.20
Swap | Q2 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	46.50
Swap | Q2 | LLS
Derivative [Line Items]
Volume per day | bbl / d	7,000
Weighted average swap price	45.35
Swap | Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	42.65
Swap | Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	46.65
Collar | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	1,000
Derivative, Floor Price	40.00
Derivative, Cap Price	70.00
Weighted average floor price	40.00
Weighted average ceiling price	70.00
Three-way Collar | Q3 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	14,500
Derivative, Floor Price	40.00
Derivative, Cap Price	70.25
Weighted average sold put price	30.00
Weighted average floor price	40.00
Weighted average ceiling price	69.09
Three-way Collar | Q3 | LLS
Derivative [Line Items]
Volume per day | bbl / d	2,000
Derivative, Floor Price	41.00
Derivative, Cap Price	69.25
Weighted average sold put price	31.00
Weighted average floor price	41.00
Weighted average ceiling price	69.25
Three-way Collar | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	11,000
Derivative, Floor Price	40.00
Derivative, Cap Price	70.20
Weighted average sold put price	30.00
Weighted average floor price	40.00
Weighted average ceiling price	69.67
Three-way Collar | Q4 | LLS
Derivative [Line Items]
Volume per day | bbl / d	1,000
Derivative, Floor Price	41.00
Derivative, Cap Price	70.25
Weighted average sold put price	31.00
Weighted average floor price	41.00
Weighted average ceiling price	70.25

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Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	$ 1,062	$ 0
Total Assets	1,062
Oil derivative contracts - current liability	18,799	69,279
Total Liabilities	18,799	69,279
Quoted Prices in Active Markets (Level 1)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	0
Total Assets	0
Oil derivative contracts - current liability	0	0
Total Liabilities	0	0
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	971
Total Assets	971
Oil derivative contracts - current liability	18,799	68,753
Total Liabilities	18,799	68,753
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	91
Total Assets	91
Oil derivative contracts - current liability	0	526
Total Liabilities	$ 0	$ 526

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Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of period	$ (526)	$ 52,834
Fair value gains on commodity derivatives	617	281
Receipts on settlements of commodity derivatives	0	(30,075)
Fair value of Level 3 instruments, end of period	91	23,040
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date	$ 236	$ 133

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Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 91	$ (526)	$ 23,040	$ 52,834
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	$ 91
Income Approach Valuation Technique | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	22.80%
Income Approach Valuation Technique | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	34.20%

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Fair Value Measurements (Details Textuals) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs	$ 2
Debt, Fair Value	$ 2,231,300	$ 2,327,800

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Commitments and Contingencies (Details) - Helium Supply Arrangement [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Long-term Purchase Commitment [Line Items]
Term of Long Term Supply Arrangement	20 years
Maximum Annual Payment In Event Of Shortfall	$ 8.0
Maximum Payment In Event Of Shortfall	$ 46.0

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Additional Balance Sheet Details Additional Balance Sheet Details (Trade and Other Receivables, Net Table) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Trade accounts receivable, net	$ 17,346	$ 20,084
Federal income tax receivable	14,054	0
Other receivables	24,253	23,816
Total	$ 55,653	$ 43,900