DENBURY INC - Quarter Report: 2015 March (Form 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, 2015

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 jurisdiction of incorporation or organization)		(I.R.S. Employer Identification 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.




Class		Outstanding at April 30, 2015
Common Stock, $.001 par value		356,932,779

Denbury Resources Inc.

Table of Contents




		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	3
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014	4
	Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three Months Ended March 31, 2015 and 2014	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	37

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosures	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
	Signatures	41

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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,
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	6,021		$	23,153
Accrued production receivable	148,125			181,761
Trade and other receivables, net	139,904			156,955
Derivative assets	421,702			440,359
Deferred tax assets	42,268			—
Other current assets	10,634			10,452
Total current assets	768,654			812,680
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	9,873,513			9,782,337
Unevaluated properties	933,566			918,406
CO₂ properties	1,171,815			1,162,538
Pipelines and plants	2,272,184			2,269,564
Other property and equipment	465,886			468,051
Less accumulated depletion, depreciation, amortization and impairment	(4,536,890		)	(4,248,652		)
Net property and equipment	10,180,074			10,352,244
Derivative assets	19,456			66,187
Goodwill	1,283,590			1,283,590
Other assets	216,282			213,101
Total assets	$	12,468,056		$	12,727,802
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities	$	234,541		$	394,758
Oil and gas production payable	110,454			128,170
Deferred tax liabilities	—			81,727
Current maturities of long-term debt	36,679			35,470
Total current liabilities	381,674			640,125
Long-term liabilities
Long-term debt, net of current portion	3,596,085			3,535,900
Asset retirement obligations	128,599			126,411
Deferred tax liabilities	2,752,857			2,694,842
Other liabilities	25,360			26,668
Total long-term liabilities	6,502,901			6,383,821
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; 415,665,644 and 411,779,911 shares issued, respectively	416			412
Paid-in capital in excess of par	3,238,914			3,230,418
Retained earnings	3,262,508			3,392,465
Accumulated other comprehensive loss	(192		)	(209		)
Treasury stock, at cost, 58,651,623 and 58,415,507 shares, respectively	(918,165		)	(919,230		)
Total stockholders' equity	5,583,481			5,703,856
Total liabilities and stockholders' equity	$	12,468,056		$	12,727,802

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)



	Three Months Ended March 31,
	2015			2014
Revenues and other income
Oil, natural gas, and related product sales	$	297,470		$	623,846
CO₂ and helium sales and transportation fees	6,972			10,761
Interest income and other income	3,207			7,137
Total revenues and other income	307,649			641,744
Expenses
Lease operating expenses	141,084			170,379
Marketing and plant operating expenses	11,685			16,786
CO₂ and helium discovery and operating expenses	947			5,205
Taxes other than income	26,679			45,945
General and administrative expenses	46,280			43,693
Interest, net of amounts capitalized of $8,409 and $5,756, respectively	40,099			48,834
Depletion, depreciation, and amortization	149,958			141,130
Commodity derivatives expense (income)	(83,076		)	76,669
Write-down of oil and natural gas properties	146,200			—
Total expenses	479,856			548,641
Income (loss) before income taxes	(172,207		)	93,103
Income tax provision (benefit)	(64,461		)	34,793
Net income (loss)	$	(107,746	)	$	58,310

Net income (loss) per common share
Basic	$	(0.31	)	$	0.17
Diluted	$	(0.31	)	$	0.17

Dividends declared per common share	$	0.0625		$	0.0625

Weighted average common shares outstanding
Basic	350,688			350,747
Diluted	350,688			352,925

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Comprehensive Operations

(In thousands)



	Three Months Ended March 31,
	2015			2014
Net income (loss)	$	(107,746	)	$	58,310
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $11 and $13, respectively	17			15
Total other comprehensive income	17			15
Comprehensive income (loss)	$	(107,729	)	$	58,325

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)



	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities
Net income (loss)	$	(107,746	)	$	58,310
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	149,958			141,130
Write-down of oil and natural gas properties	146,200			—
Deferred income taxes	(66,036		)	30,175
Stock-based compensation	7,849			8,346
Commodity derivatives expense (income)	(83,076		)	76,669
Settlements of commodity derivatives	148,465			(27,169		)
Amortization of debt issuance costs and discounts	2,221			3,520
Other, net	(2,359		)	(2,297		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	33,636			(24,937		)
Trade and other receivables	16,828			6,372
Other current and long-term assets	(6,136		)	(5,459		)
Accounts payable and accrued liabilities	(83,248		)	(52,580		)
Oil and natural gas production payable	(17,716		)	3,916
Other liabilities	(1,076		)	(1,138		)
Net cash provided by operating activities	137,764			214,858

Cash flows from investing activities
Oil and natural gas capital expenditures	(162,192		)	(198,237		)
Acquisitions of oil and natural gas properties	(261		)	—
CO₂ capital expenditures	(14,855		)	(15,909		)
Pipelines and plants capital expenditures	(12,455		)	(22,597		)
Purchases of other assets	(2,965		)	(1,645		)
Other	150			1,634
Net cash used in investing activities	(192,578		)	(236,754		)

Cash flows from financing activities
Bank repayments	(595,000		)	(815,000		)
Bank borrowings	665,000			1,075,000
Common stock repurchase program	—			(211,356		)
Cash dividends paid	(22,068		)	(21,727		)
Other	(10,250		)	(9,316		)
Net cash provided by financing activities	37,682			17,601
Net decrease in cash and cash equivalents	(17,132		)	(4,295		)
Cash and cash equivalents at beginning of period	23,153			12,187
Cash and cash equivalents at end of period	$	6,021		$	7,892

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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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, 2014 (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, 2015, our consolidated results of operations for the three months ended March 31, 2015 and 2014, and our consolidated cash flows for the three months ended March 31, 2015 and 2014.

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 stock options, stock appreciation rights ("SARs"), nonvested restricted stock and nonvested performance-based equity awards. For the three months ended March 31, 2015 and 2014, 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	2015	2014
Basic weighted average common shares outstanding	350,688	350,747
Potentially dilutive securities
Restricted stock, stock options, SARs and performance-based equity awards	—	2,178
Diluted weighted average common shares outstanding	350,688	352,925

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 per common share (although all non-performance-based restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three months ended March 31, 2014, the nonvested restricted stock, stock options, SARs, and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity.

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	2015	2014
Stock options and SARs	10,507	4,254
Restricted stock and performance-based equity awards	2,948	21

Oil and Natural Gas Properties

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

We recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015, with first-day-of-the-month prices for the preceding 12 months, after adjustments for market differentials by field, of $79.55 per Bbl for crude oil and $3.95 per Mcf for natural gas. If oil prices remain at or near late-April 2015 levels in subsequent periods, we expect that we could record significantly larger write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2015.

Goodwill

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Recent Accounting Pronouncements

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. Management is currently assessing the impact the adoption of ASU 2015-03 will have on our consolidated financial statements.

Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination, and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect 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. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2017, and early adoption is prohibited. However, in April 2015, the FASB proposed delaying the effective date for one year. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 will have on our consolidated financial statements.

Note 2. Long-Term Debt

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



	March 31,			December 31,
In thousands	2015			2014
Bank Credit Agreement	$	465,000		$	395,000
6⅜% Senior Subordinated Notes due 2021	400,000			400,000
5½% Senior Subordinated Notes due 2022	1,250,000			1,250,000
4⅝% Senior Subordinated Notes due 2023	1,200,000			1,200,000
Other Subordinated Notes, including premium of $10 and $11, respectively	2,744			2,746
Pipeline financings	218,486			220,583
Capital lease obligations	96,534			103,041
Total	3,632,764			3,571,370
Less: current obligations	(36,679		)	(35,470		)
Long-term debt and capital lease obligations	$	3,596,085		$	3,535,900

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

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 an initial borrowing base of $3.0 billion and aggregate lender commitments of $1.6 billion. Loans under the Bank Credit Agreement mature in December 2019. The weighted average interest rate on borrowings outstanding as of March 31, 2015, under the Bank Credit Agreement was 1.5%. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee ranging from 0.3% to 0.375% per annum. As of March 31, 2015, we were in compliance with all debt covenants under the Bank Credit Agreement.

In connection with the borrowing base redetermination completed in early May 2015 under our Bank Credit Agreement, we elected to maintain our aggregate lender commitments at $1.6 billion; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion. Because we continue to maintain a significant cushion between our borrowing base and the aggregate lender commitments, this borrowing base reduction has no impact on our liquidity. Redeterminations under our Bank Credit Agreement occur annually, making our next scheduled redetermination in May 2016.

In conjunction with the May 2015 redetermination, we also entered into the First Amendment to the Bank Credit Agreement (the "First Amendment"). This First Amendment restructures certain financial covenants in 2016, 2017, and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows:

•

In 2016 and 2017, suspend the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant of 4.25 to 1.0 and replace it with a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 2.5 to 1.0 during the same time period. Currently, only debt under our Bank Credit Agreement would be considered consolidated senior secured debt for purposes of this ratio.

•

Beginning in the first quarter of 2018, reinstate the ratio of consolidated total net debt to consolidated EBITDAX covenant utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ended March 31, 2018, 5.5 to 1.0 for the second quarter ended June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ended September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ended March 31, 2019.


•	In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0.

The restructuring of covenants through the First Amendment were executed in consideration of a fee paid to the lenders. The First Amendment has no impact on the current ratio financial performance covenant, which will remain in place in 2015 and beyond. All of the above descriptions of financial covenants are qualified by the express language and defined terms contained in the Bank Credit Agreement filed on December 15, 2014, as Exhibit 10.1 to our Current Report on Form 8-K or the First Amendment, which is filed as Exhibit 10(a) to this Quarterly Report on Form 10-Q.

Note 3. Stockholders' Equity

Dividends

During January of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share. Dividends totaling $22.1 million and $21.7 million were paid to stockholders during the three months ended March 31, 2015 and 2014, respectively. See Note 8, Subsequent Event, for details regarding the dividend declared and to be paid in the second quarter of 2015.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Stock Repurchase Program

Under our board-authorized share repurchase program, we repurchased 12.4 million shares of Denbury common stock for $200.4 million during the first quarter of 2014. In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty and to protect our financial position.

Employee Stock Purchase Program

We previously provided for an Employee Stock Purchase Plan (the "Plan") in which funds from eligible employees, together with Company contributions, were used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter. The Plan was terminated, effective at the end of the offering period ending on March 31, 2015, as all of the previously authorized shares reserved for issuance under the Plan had been issued.

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.

From time to time, we enter 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. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted 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. For the past several years, we have employed a strategy to hedge a substantial portion of our forecasted production approximately 18 months to two years in the future (from the then-current quarter), as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending and dividends in those future periods. Due to the significant and rapid decline in oil prices over the last six months, we have deferred entering into new derivative contracts through the first quarter of 2015; 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. In April 2015, we began entering into new oil hedging positions in order to provide more certainty to our future cash flows. As of May 5, 2015, these fixed-price swaps and collars, which are not reflected in the table below and which comprise both NYMEX and LLS hedges, include (1) fixed-price swaps covering an additional 15,000 Bbls per day in the second quarter of 2016, with weighted-average prices of approximately $63 per Bbl and (2) collars covering an additional 4,500 Bbls per day and 5,000 Bbls per day in the second and third quarters of 2016, respectively, with weighted-average floors of approximately $56 per Bbl and weighted-average ceilings of approximately $72 per Bbl.

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, 2015, 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.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of March 31, 2015, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic:



Months	Index Price	Volume ⁽²⁾	Contract Prices ⁽¹⁾
			Range ⁽³⁾				Weighted Average Price
			Range ⁽³⁾				Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2015 Enhanced Swaps ⁽⁴⁾
Apr – June	NYMEX	8,000	$	90.00	–	90.00	$	90.00	$	65.75	$	—	$	—
Apr – June	LLS	16,000		93.20	–	94.00	93.65		68.00		—		—
July – Sept	NYMEX	10,000		90.00	–	90.10	90.02		65.30		—		—
July – Sept	LLS	16,000		93.20	–	94.00	93.65		68.00		—		—
Oct – Dec	NYMEX	12,000		91.15	–	94.00	92.42		68.00		—		—
Oct – Dec	LLS	8,000		93.80	–	96.50	94.94		68.00		—		—
2015 Collars
Apr – June	NYMEX	30,000	$	80.00	–	95.25	$	—	$	—	$	80.00	$	94.72
Apr – June	LLS	4,000		85.00	–	102.50	—		—		85.00		101.75
July – Sept	NYMEX	28,000		80.00	–	95.25	—		—		80.00		95.05
July – Sept	LLS	4,000		85.00	–	100.00	—		—		85.00		99.50
2015 Three-Way Collars ⁽⁵⁾
Oct – Dec	NYMEX	10,000	$	85.00	–	102.00	$	—	$	68.00	$	85.00	$	99.00
Oct – Dec	LLS	8,000		88.00	–	104.25	—		68.00		88.00		100.99
2016 Enhanced Swaps ⁽⁴⁾
Jan – Mar	NYMEX	12,000	$	90.65	–	93.35	$	92.43	$	68.00	$	—	$	—
Jan – Mar	LLS	8,000		93.70	–	95.45	94.81		68.50		—		—
Apr – June	NYMEX	2,000		90.35	–	90.35	90.35		68.00		—		—
Apr – June	LLS	6,000		93.30	–	93.50	93.38		70.00		—		—
2016 Three-Way Collars⁽⁵⁾
Jan – Mar	NYMEX	10,000	$	85.00	–	101.25	$	—	$	68.00	$	85.00	$	99.85
Jan – Mar	LLS	6,000		88.00	–	103.15	—		68.00		88.00		102.10
Apr – June	NYMEX	2,000		85.00	–	95.50	—		68.00		85.00		95.50
Apr – June	LLS	2,000		88.00	–	98.25	—		70.00		88.00		98.25

Natural Gas Contracts:
2015 Collars
Apr – Dec	NYMEX	8,000	$	4.00	–	4.53	$	—	$	—	$	4.00	$	4.51


(1)	Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.


(2)	Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively.


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

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Notes to Unaudited Condensed Consolidated Financial Statements

(4)

An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes, and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes.

(5)

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.

•

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 and natural gas derivatives that are based on NYMEX pricing. The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, including 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, 2015, instruments in this category include non-exchange-traded oil derivatives that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, since the instruments are based on regional pricing other than NYMEX, certain inputs to the valuation are less observable. 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 $0.9 million in the fair value of these instruments as of March 31, 2015.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2015
Assets:
Oil and natural gas derivative contracts – current	$	—	$	270,126	$	151,576	$	421,702
Oil and natural gas derivative contracts – long-term	—		6,017		13,439		19,456
Total Assets	$	—	$	276,143	$	165,015	$	441,158

December 31, 2014
Assets:
Oil and natural gas derivative contracts – current	$	—	$	283,238	$	157,121	$	440,359
Oil and natural gas derivative contracts – long-term	—		34,862		31,325		66,187
Total Assets	$	—	$	318,100	$	188,446	$	506,546

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

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2015 and 2014:



	Three Months Ended
	March 31,
In thousands	2015			2014
Fair value of Level 3 instruments, beginning of period	$	188,446		$	6,709
Fair value adjustments on commodity derivatives	25,085			(12,806		)
Receipt on settlements of commodity derivatives	(48,516		)	—
Fair value of Level 3 instruments, end of period	$	165,015		$	(6,097	)

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date	$	23,099		$	(12,806	)

We utilize an income approach to value our Level 3 enhanced swaps, costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 3/31/2015 (in thousands)		Valuation Technique	Unobservable Input	Range
Oil derivative contracts	$	165,015	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2015	25.8% – 38.2%

Other Fair Value Measurements

The carrying value of loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our debt as of March 31, 2015 and December 31, 2014, excluding pipeline financing and capital lease obligations, was $2,998.6 million and $2,938.6 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

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.

Delhi Field Release

In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was discovered (and reported) within an area of the Denbury-operated Delhi Field located in northern Louisiana. We completed our remediation efforts with respect to such release during the fourth quarter of 2013; however, we continue to monitor the impacted area to confirm the effectiveness of the remediation efforts. Virtually all of our total cost estimate of $130.8 million has been incurred.

We maintain insurance policies to cover certain costs, damages and claims related to releases of well fluids and remediation. We received a $25.0 million cost reimbursement in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess insurance coverage. We have not reached any agreement with our remaining carriers as to further reimbursements, but given our belief that under our policies we are entitled to reimbursement of between approximately one-third and two-thirds of our total costs, we have filed suit to pursue further reimbursements, the ultimate outcome of which cannot be predicted.

In March 2015, Evolution Petroleum Company ("Evolution"), the parent of the entity which sold Denbury Onshore, LLC ("Denbury Onshore") its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the Texas district court in Houston since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury Onshore and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining "payout" as defined in the agreements, and the extent and terms of assignment of reversionary interests in the Unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury Onshore in connection with the June 2013 Delhi Field release, and for the first time estimated its damages attributable to its allegations in the case as exceeding $200 million. The amended petition also adds a claim for unspecified punitive damages. There has only been limited discovery in the case to

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

date, and Evolution has not specified the basis for the amount of its claimed damages estimate. The case is currently set for trial in October 2015. We believe Evolution's claims in the First Amended Petition relating to the June 2013 Delhi Field release are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.

Note 7. Additional Balance Sheet Details

Accounts Payable and Accrued Liabilities



	March 31,		December 31,
In thousands	2015		2014
Accounts payable	$	52,662	$	64,604
Accrued interest	45,883		48,255
Accrued lease operating expenses	38,197		56,798
Accrued exploration and development costs	26,560		90,939
Accrued compensation	24,517		62,513
Taxes payable	16,697		39,816
Other	30,025		31,833
Total	$	234,541	$	394,758

Note 8. Subsequent Event

Dividend Declaration

On April 28, 2015, the Board of Directors declared a dividend of $0.0625 per share on our outstanding common stock, payable on June 30, 2015, to stockholders of record at the close of business on May 26, 2015.

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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, 2014 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

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

Operating Highlights. Our financial results have been significantly impacted by the decrease in realized oil prices, which decreased from $97.69 per Bbl in the first quarter of 2014 to $46.02 in the first quarter of 2015. During the first quarter of 2015, we recognized a net loss of $107.7 million, or $0.31 per diluted common share, compared to net income of $58.3 million, or $0.17 per diluted common share, during the first quarter of 2014. The change in income between the first quarter of 2015 and 2014 was primarily due to a 52% ($326 million) decline in our oil and natural gas revenues between the periods, which was primarily all oil-price related, and a full cost pool ceiling test write-down of our oil and natural gas properties totaling $146.2 million ($90.6 million net of tax) during the first quarter of 2015, also due to declines in oil prices. Offsetting these negative impacts was a $159.7 million reduction in our commodity derivative expense, and lower operating expenses consisting of a $29.3 million (17%) decrease in lease operating expenses, a $19.3 million (42%) decrease in taxes other than income, and an $8.7 million (18%) decrease in interest, net. The $159.7 million positive change in commodity derivatives expense (income) between the two periods was principally due to receipts of $148.5 million upon settlement of derivative contracts in the first quarter of 2015 compared to payments of $27.2 million in the prior-year quarter.

We generated $137.8 million of cash flows from operating activities in the first quarter of 2015, compared to $337.7 million in the fourth quarter of 2014 and $214.9 million in the prior-year first quarter. The decrease in cash flows from operations was due primarily to lower oil prices, which caused a decrease in oil revenues, partially offset by significant positive changes in derivative settlements and, to a lesser extent, reductions in lease operating expenses, taxes other than income, interest expense, and changes in working capital items. Despite the significant decrease in oil prices, at current oil futures prices, we currently expect to generate cash flow above and beyond our capital expenditures and dividends for 2015.

During the first quarter of 2015, our oil and natural gas production, which was 95% oil, averaged 74,356 BOE/d, compared to an average of 73,718 BOE/d produced during the first quarter of 2014. This slight increase in production is attributable to a 5% increase in our tertiary oil production, offset by a 4% decline in production from our non-tertiary properties.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $46.02 per Bbl during the first quarter of 2015, a decrease of 53% compared to $97.69 per Bbl realized during the first quarter of 2014 and a decrease of 35% compared to $70.80 per Bbl realized during the fourth quarter of 2014. The oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) was $2.81 per Bbl below NYMEX prices in the first quarter of 2015, compared to a negative $0.91 per Bbl NYMEX differential in the first quarter of 2014, and a negative $2.24 per Bbl NYMEX differential in the fourth quarter of 2014. This decline in our oil price differential in comparison to its level in the first quarter of 2014 was driven by a decrease in the Light Louisiana Sweet ("LLS") index premium, partially offset by a decrease in the Rocky Mountain region discount relative to NYMEX oil prices.

One of our primary focuses in 2014 and 2015 has been to reduce costs throughout the organization, through a number of internal initiatives. For example, excluding Delhi remediation costs and insurance reimbursements and unplanned Riley Ridge well workovers in 2014, our recurring lease operating expenses per BOE decreased each sequential quarter in 2014 and the first

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Denbury Resources Inc.

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

quarter of 2015, and decreased a total of 20% between the fourth quarter of 2013 and the first quarter of 2015, with decreases realized in most categories of lease operating expenses, the most significant of which including workover costs, power costs, CO₂ costs, and certain third-party contractor and vendor costs. On a sequential-quarter basis, lease operating expenses, excluding Delhi Field remediation costs, decreased 10% between the fourth quarter of 2014 and the first quarter of 2015. Our goal is to continue to reduce both capital project costs and per-barrel operating costs, and we believe such reductions are possible, especially in light of the recent decline in oil prices.

Recent Oil Price Decline and Impact on Our Business. Although oil prices have historically been volatile, during the second half of 2014 and continuing into 2015, oil prices dropped rapidly, with NYMEX prices declining from $107 per Bbl in June 2014 to less than $44 per Bbl in March 2015. In response to the decline in oil prices, we (1) significantly reduced projected 2015 capital spending to $550 million, or roughly half of 2014 levels, (2) suspended our share repurchase program, and (3) declared dividends for the first two quarters of 2015 at a rate of $0.25 per common share on an annualized basis, which is a level consistent with our 2014 dividend rate.

As a result of the significant decrease in pricing during the fourth quarter of 2014 and its continued decline in the first quarter of 2015, we recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015. See Results of Operations – Full Cost Pool Ceiling Test Write-Down and Note 1, Basis of Presentation – Oil and Natural Gas Properties, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding the ceiling test.

Oil prices generally constitute the largest single variable in our operating results. For the past several years, we have employed a strategy of hedging a substantial portion of our forecasted production, approximately 18 months to two years into the future (from the then-current quarter), to mitigate the risks associated with fluctuations during periods of oil price declines. We have hedges covering approximately 80% of our forecasted total production for the second and third quarters of 2015 and just over half for the fourth quarter of 2015, which will help mitigate the impact of the continued low oil price environment on our 2015 cash flows and operating results; however, for any portion of our forecasted production that is unhedged, we are fully exposed to any further decrease in oil prices. For 2016, we have significantly fewer hedges and at a lower price, and thus, the impact of continued low oil prices on our cash flows and operating results during those time periods will be more impactful. See Results of Operations – Commodity Derivative Contracts and Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability for borrowings under our bank credit facility. Our business is capital intensive, and it is common for oil and natural gas companies our size to reinvest most or all of their cash flow into developing new assets. We generally attempt to balance our capital expenditures and dividends with cash flows from operations, and for 2015, at current oil futures prices, we currently expect to generate cash flow above and beyond our capital expenditures and dividends. Our cash flow from operations during the first quarter of 2015 was lower than the $214.9 million generated during the same prior year period, due primarily to lower oil prices, which caused a decrease in oil revenues, partially offset by significant positive changes in derivative settlements and, to a lesser extent, reductions in lease operating expenses, taxes other than income, interest expense, and working capital items.

As discussed in the Overview above, we have been proactive in adjusting our 2015 capital spending and dividend plans in connection with the current lower oil price environment. We project that we will have adequate capital resources and liquidity for the foreseeable future because (1) we have significant borrowing capacity on our bank credit facility (see Note 2, Long-Term Debt and Bank Credit Facility below); (2) we have commodity derivative contracts in place to cover a significant portion of our forecasted oil production for 2015 that will lessen the impact of the current lower oil price environment (see Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative contracts); (3) generally, we plan to fund both our projected capital expenditures and dividends with cash flows from operations; (4) we can significantly reduce our capital expenditures for some time if necessary as we have done in 2015, and still maintain relatively flat or slightly lower production levels as a result of the unique characteristics of CO₂ EOR operations; and (5) the maturity dates of all but a minor amount of our senior subordinated notes occur seven or more years in the future, and carry attractive fixed interest rates ranging between 4⅝% and 6⅜%.

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Denbury Resources Inc.

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

If oil prices remain at relatively low levels beyond 2015, our cash flows from operations will likely be significantly lower than current levels, as our commodity derivative contracts presently in place for 2016 cover significantly less forecasted oil production and are at lower prices. Therefore, we continue to focus on reducing our operating costs so as to preserve as much of our operating margin as possible in this lower oil price environment, and if this low oil price environment persists, we intend to continue to make adjustments to our capital spending plans to preserve our financial health. Fortunately, some of our costs, such as CO₂ purchases and production taxes, adjust proportionally with changes in the price of oil. We also expect that our cost of services and equipment will continue to come down in this lower oil price environment, but this likely will not reflect as large a percentage decrease as the decrease in the price of oil. Although we can reduce capital spending and maintain production at relatively flat or slightly lower production levels for some time, after a period of time our production will begin to decline significantly, which will further lower our cash flow from operations.

2015 Capital Spending. We anticipate that our full-year 2015 capital budget, excluding acquisitions, will be $550 million, which includes approximately $85 million in capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods. This combined 2015 capital budget amount, excluding acquisitions, is comprised of the following:


•	$320 million allocated for tertiary oil field expenditures;


•	$100 million allocated for other areas, primarily non-tertiary oil field expenditures;


•	$30 million to be spent on CO₂ sources;


•	$15 million for pipeline construction; and


•	$85 million for other capital items such as capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.

During the three months ended March 31, 2015, we incurred capital expenditures of $111.1 million, excluding acquisitions. See additional detail on our expenditures in the Capital Expenditure Summary below.

Based on oil and natural gas commodity futures prices in early May 2015, our current production forecast, and our commodity derivative contracts covering a substantial portion of our anticipated 2015 production, we currently anticipate that our 2015 cash flows from operations will be in excess of our combined 2015 capital budget and currently-planned dividend payments. Although our outstanding borrowings on our bank credit facility increased by $70.0 million from December 31, 2014, to $465.0 million at March 31, 2015, due primarily to the timing of cash outflows to cover working capital items in the first quarter of 2015, we currently expect to use any excess cash flow from operations for the remainder of 2015 to pay down borrowings on our bank credit facility to levels below those outstanding as of December 31, 2014. If prices were to decrease further or changes in operating results were to cause us to have a reduction in anticipated 2015 cash flows below our currently forecasted operating cash flows, we would likely further reduce our capital expenditures or reduce our targeted dividend payment, with ample availability on our bank credit facility to cover any potential shortfall. If we further reduce our capital spending due to lower cash flows, any sizeable reduction could lower our anticipated production levels in future years.

Bank Credit Facility. In connection with the borrowing base redetermination completed in early May 2015 under our Bank Credit Agreement, we elected to maintain our aggregate lender commitments at $1.6 billion; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion. Because we continue to maintain a $1.0 billion cushion between our borrowing base and the aggregate lender commitments, even after this borrowing base reduction, and because we had availability of $1.1 billion with respect to our aggregate lender commitments as of March 31, 2015, this borrowing base reduction has no impact on our liquidity. Redeterminations under our Bank Credit Agreement occur annually, making our next scheduled redetermination in May 2016.

This Bank Credit Agreement contains certain restrictive covenants, plus two principal financial performance covenants to maintain (1) a ratio of consolidated total net debt to consolidated EBITDAX of not more than 4.25 to 1.0 and (2) a ratio of consolidated current assets to consolidated current liabilities ("current ratio") not less than 1.0. For these financial performance covenant calculations as of March 31, 2015, our ratio of consolidated total net debt to consolidated EBITDAX was 2.78 to 1.0, and our current ratio was 4.25, and we currently project to be in compliance with the covenants through the remainder of 2015.

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Denbury Resources Inc.

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

Although we currently expect to meet our financial covenants in 2015, if oil prices were to remain at lower levels for a longer period of time, we could have issues in meeting our debt to EBITDAX covenant in 2016, as we are not as well hedged after 2015. Therefore, in conjunction with the May 2015 redetermination, we entered into the First Amendment to the Bank Credit Agreement (the "First Amendment") under which we modified certain financial covenants in 2016, 2017 and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows:

•


•	In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0.

Dividends. During the first quarter of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share. Dividends totaling $22.1 million and $21.7 million were paid to stockholders during the three months ended March 31, 2015 and 2014, respectively. See Note 8, Subsequent Event, to the Unaudited Condensed Consolidated Financial Statements for details regarding the dividend declared in the second quarter of 2015. An annual dividend rate of $0.25 per common share would result in total dividend payments of approximately $89 million to our stockholders in 2015. The declaration and payment of future dividends are at the discretion of our Board of Directors, and the amount thereof will depend on our results of operations, financial condition, capital requirements, level of indebtedness, market conditions, and other factors deemed relevant by the Board of Directors.

Insurance Recoveries to Cover Costs of 2013 Delhi Field Release. We completed our remediation efforts related to the release of well fluids at the Denbury-operated Delhi Field during the fourth quarter of 2013. As of March 31, 2015, virtually all of our total cost estimate of $130.8 million had been incurred.

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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 of capital expenditures includes accrued capital for the three months ended March 31, 2015 and 2014:



	Three Months Ended
	March 31,
In thousands	2015		2014
Capital expenditures by project
Tertiary oil fields	$	42,900	$	123,901
Non-tertiary fields	30,984		54,851
Capitalized interest and internal costs ⁽¹⁾	25,580		24,219
Oil and natural gas capital expenditures	99,464		202,971
CO₂ pipelines	779		3,244
CO₂ sources ⁽²⁾	9,852		13,262
CO₂ capitalized interest and other	1,003		1,146
Capital expenditures, before acquisitions	111,098		220,623
Acquisitions of oil and natural gas properties	261		—
Capital expenditures, total	$	111,359	$	220,623


(1)	Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.


(2)	Includes capital expenditures related to the Riley Ridge gas processing facility.

Capital expenditures during the three months ended March 31, 2015, reflect a significant reduction in accrued capital based on the decrease in capital spending in 2015. For the first three months of 2015 and 2014, our capital expenditures and property acquisitions were fully funded with cash flow from operations.

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include operating leases for office space and various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.

Our commitments and obligations consist of those detailed as of December 31, 2014 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 ended March 31, 2015 and 2014 are included in the following table:



	Three Months Ended
	March 31,
In thousands, except per share and unit data	2015			2014
Operating results
Net income (loss)	$	(107,746	)	$	58,310
Net income (loss) per common share – basic	(0.31		)	0.17
Net income (loss) per common share – diluted	(0.31		)	0.17
Dividends declared per common share	0.0625			0.0625
Net cash provided by operating activities	137,764			214,858
Average daily production volumes
Bbls/d	70,564			69,834
Mcf/d	22,752			23,299
BOE/d ⁽¹⁾	74,356			73,718
Operating revenues
Oil sales	$	292,270		$	613,980
Natural gas sales	5,200			9,866
Total oil and natural gas sales	$	297,470		$	623,846
Commodity derivative contracts ⁽²⁾
Receipt (payment) on settlements of commodity derivatives	$	148,465		$	(27,169	)
Noncash fair value adjustments on commodity derivatives ⁽³⁾	(65,389		)	(49,500		)
Commodity derivatives income (expense)	$	83,076		$	(76,669	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	46.02		$	97.69
Natural gas price per Mcf	2.54			4.71
Unit prices – including impact of derivative settlements ⁽²⁾
Oil price per Bbl	$	69.28		$	93.46
Natural gas price per Mcf	2.91			4.41
Oil and natural gas operating expenses
Lease operating expenses	$	141,084		$	170,379
Marketing expenses, net of third-party purchases, and plant operating expenses	9,843			12,263
Production and ad valorem taxes	22,899			42,414
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	44.45		$	94.03
Lease operating expenses	21.08			25.68
Marketing expenses, net of third-party purchases, and plant operating expenses	1.47			1.84
Production and ad valorem taxes	3.42			6.39
CO₂ sources and helium – revenues and expenses
CO₂ and helium sales and transportation fees	$	6,972		$	10,761
CO₂ and helium discovery and operating expenses	(947		)	(5,205		)
CO₂ and helium revenue and expenses, net	$	6,025		$	5,556


(1)	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


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

(3)

Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from "Commodity derivatives expense (income)" in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represents only the net change between periods of the fair market values of commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $148.5 million for the three months ended March 31, 2015, and payments on settlements of $27.2 million for the three months ended March 31, 2014. We believe that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to "Commodity derivatives expense (income)" in order to differentiate noncash fair market value adjustments from settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for "Commodity derivatives expense (income)" in the Unaudited Condensed Consolidated Statements of Operations.

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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 2014 and for the first quarter of 2015 is shown below:



	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter
Operating Area	2014	2014	2014	2014	2015
Tertiary oil production
Gulf Coast region
Mature properties:
Brookhaven	1,877	1,818	1,767	1,579	1,612
Eucutta	2,181	2,150	2,224	1,995	1,905
Mallalieu	1,837	1,839	1,869	1,653	1,574
Other mature properties ⁽¹⁾	6,283	6,156	6,189	5,864	5,710
Total mature properties	12,178	11,963	12,049	11,091	10,801
Delhi ⁽²⁾	4,708	4,543	4,377	3,743	3,551
Hastings	4,618	4,759	4,917	4,811	4,694
Heidelberg	5,325	5,609	5,721	6,164	6,027
Oyster Bayou	4,055	4,415	4,605	5,638	5,861
Tinsley	8,430	8,518	8,310	8,767	8,928
Total Gulf Coast region	39,314	39,807	39,979	40,214	39,862
Rocky Mountain region
Bell Creek	578	1,090	1,648	1,659	1,965
Total Rocky Mountain region	578	1,090	1,648	1,659	1,965
Total tertiary oil production	39,892	40,897	41,627	41,873	41,827
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	2,513	2,319	2,346	2,099	1,761
Texas	6,444	6,508	5,537	6,677	6,490
Other	1,031	1,049	1,083	1,082	1,006
Total Gulf Coast region	9,988	9,876	8,966	9,858	9,257
Rocky Mountain region
Cedar Creek Anticline	19,007	19,155	18,623	18,553	18,522
Other	4,831	5,392	4,594	4,591	4,750
Total Rocky Mountain region	23,838	24,547	23,217	23,144	23,272
Total non-tertiary production	33,826	34,423	32,183	33,002	32,529
Total production	73,718	75,320	73,810	74,875	74,356


(1)	Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.


(2)	The average daily Delhi Field production amounts for the fourth quarter of 2014 and the first quarter of 2015 reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.

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Denbury Resources Inc.

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

Total Production

Total production during the first quarter of 2015 averaged 74,356 BOE/d, a slight increase compared to first quarter of 2014 production levels of 73,718 BOE/d, as production increases at our newer tertiary floods offset the decreases in our mature properties and lower production resulting from the decrease in ownership interest at Delhi Field as of November 1, 2014, due to a contractual reversionary assignment of approximately 25% of our interest to the seller of the field. Our production during the three months ended March 31, 2015 was 95% oil, consistent with oil production during the three months ended March 31, 2014 and December 31, 2014.

Tertiary Production

Oil production from our tertiary operations during the first quarter of 2015 increased 1,935 Bbls/d (5%) compared to tertiary production levels in the same period in 2014 and was relatively unchanged when comparing tertiary production between the first quarter of 2015 and fourth quarter of 2014. The year-over-year increase was primarily due to production growth in response to continued field development and expansion of facilities in our tertiary floods at Heidelberg, Oyster Bayou, and Tinsley fields in our Gulf Coast region, and Bell Creek Field in our Rocky Mountain region. Partially offsetting the increases were production declines in our mature tertiary fields, as well as the decrease in our ownership interest in Delhi Field due to the November 1, 2014, contractual reversionary assignment of approximately 25% of our interest to the seller of the field, the effectiveness, timing, and scope of which are subject to ongoing litigation.

Non-Tertiary Production

Production from our non-tertiary operations averaged 32,529 BOE/d during the first quarter of 2015, a decrease of 1,297 BOE/d (4%) compared to the first quarter of 2014 levels, and decreased slightly (1%) when compared to the fourth quarter of 2014 levels. These decreases from the first quarter of 2014 were primarily due to declines at our Mississippi non-tertiary fields and Cedar Creek Anticline ("CCA"). Additionally, natural gas production at Riley Ridge remained shut-in during the first quarter of 2015, compared to averaging 1,639 Mcf/d (273 BOE/d) in the first quarter of 2014. We currently expect natural gas production at Riley Ridge will continue to be shut-in due to natural gas supply well failures related to sulfur build-up in those wells until sometime in 2016. Production from our other non-tertiary properties is generally on decline, and in some instances the decline is pronounced when non-tertiary wells are shut in as part of an initiation or expansion of our tertiary floods in a field or an area of a field.

Oil and Natural Gas Revenues

Our oil and natural gas revenues decreased 52% during the three months ended March 31, 2015 compared to these revenues for the same period in 2014. 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,
	2015 vs. 2014
In thousands	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Increase in production	$	5,406		1	%
Decrease in commodity prices	(331,782		)	(53	)%
Total decrease in revenues	$	(326,376	)	(52	)%

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Denbury Resources Inc.

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, 2015 and 2014:



	Three Months Ended
	March 31,
	2015			2014
Net realized prices:
Oil price per Bbl	$	46.02		$	97.69
Natural gas price per Mcf	2.54			4.71
Price per BOE	44.45			94.03
NYMEX differentials:
Oil per Bbl	$	(2.81	)	$	(0.91	)
Natural gas per Mcf	(0.28		)	(0.02		)

As reflected in the table above, our average net realized oil price, excluding the impact of commodity derivative contracts, decreased 53% during the first quarter of 2015 from the average price received during the first quarter of 2014. Company-wide average oil price differentials in the first quarter of 2015 were $2.81 per Bbl below NYMEX, compared to an average differential of $0.91 per Bbl below NYMEX in the first quarter of 2014. During the first quarter of 2015, we sold approximately 42% of our crude oil at prices based on the LLS index price, approximately 23% at prices 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. These percentages were consistent with those realized during the first quarter of 2014. The oil differentials we received in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors and location differentials. Our average NYMEX oil differential in the Gulf Coast region was a negative $0.29 per Bbl and a positive $3.05 per Bbl during the three months ended March 31, 2015 and 2014, respectively, and a positive $1.20 per Bbl during the three months ended December 31, 2014. 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. This quarterly average LLS-to-NYMEX differential (on a trade-month basis) decreased from a positive $6.06 per Bbl in the first quarter of 2014 to a positive $3.16 per Bbl in the fourth quarter of 2014 and a positive $2.60 per Bbl in the first quarter of 2015, with the two most recent quarters being more representative of longer-term historical differentials.

NYMEX oil differentials in the Rocky Mountain region averaged $7.75 per Bbl and $9.06 per Bbl below NYMEX during the three months ended March 31, 2015 and 2014, respectively, and $9.28 per Bbl below NYMEX during the three months ended December 31, 2014. Differentials in the Rocky Mountain region can move significantly over short periods of time due to refinery and transportation issues, but are showing signs of greater stability as infrastructure and takeaway capacity improve in the region.

Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be quite large, the absolute impact of these changes on our results has historically been minor, as natural gas sales represented only approximately 2% of our oil and natural gas revenues during the three months ended March 31, 2015.

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Denbury Resources Inc.

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

Commodity Derivative Contracts

The following tables summarize the impact our oil and natural gas derivative contracts had on our operating results for the three months ended March 31, 2015 and 2014:



	Three Months Ended March 31,
	2015			2014			2015			2014			2015			2014
In thousands	Crude Oil Derivative Contracts						Natural Gas Derivative Contracts						Total Commodity Derivative Contracts
Receipt (payment) on settlements of commodity derivatives	$	147,716		$	(26,559	)	$	749		$	(610	)	$	148,465		$	(27,169	)
Noncash fair value adjustments on commodity derivatives ⁽¹⁾	(65,122		)	(48,854		)	(267		)	(646		)	(65,389		)	(49,500		)
Total income (expense)	$	82,594		$	(75,413	)	$	482		$	(1,256	)	$	83,076		$	(76,669	)


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

For the remainder of 2015, we have commodity derivative contracts consisting of a combination of enhanced swaps, collars, and three-way collars covering a total of 58,000 Bbls/d for the second and third quarters of 2015 and 38,000 Bbls/d for the fourth quarter of 2015. Roughly half of these 2015 derivative contracts are collars and three-way collars, so the variability in potential cash flows from these types of hedges exposes us to more downside price risk than our enhanced swaps. These 2015 collars and three-way collars, which include both NYMEX and LLS hedges, have a weighted average floor of approximately $82 per Bbl (approximately $81 per Bbl and $87 per Bbl for NYMEX and LLS hedges, respectively) and a weighted average ceiling price of approximately $97 per Bbl (approximately $95 per Bbl and $101 per Bbl for NYMEX and LLS hedges, respectively). Our three-way collars and enhanced swaps all include sold puts that have a weighted average price of approximately $67 per Bbl. The sold puts for our three-way collars and enhanced swaps limit the benefit that our hedges provide us to the extent that oil prices remain below the price of our sold puts.

Changes in commodity prices and the expiration of contracts 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, 2015, 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.

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

Production Expenses

Lease Operating Expense



	Three Months Ended
	March 31,
In thousands, except per-BOE data	2015		2014
Lease operating expense
Tertiary	$	85,459	$	97,698
Non-tertiary	55,625		72,681
Total lease operating expense	$	141,084	$	170,379

Lease operating expense per BOE
Tertiary	$	22.70	$	27.21
Non-tertiary	19.00		23.87
Total lease operating expense per BOE	21.08		25.68

We have seen many of our lease operating costs decline as a result of our cost reduction efforts throughout 2014 and early 2015, as well as general market decreases in the prices of many of the components of these costs. Total lease operating expenses decreased $29.3 million (17%) on an absolute-dollar basis or $4.60 (18%) on a per-BOE basis during the three months ended March 31, 2015 compared to 2014 levels. When comparing the first quarter of 2015 to the fourth quarter of 2014, lease operating expenses, excluding Delhi Field remediation costs, decreased $14.9 million (10%) on an absolute-dollar basis or $1.56 (7%) on a per-BOE basis. The year-over-year and sequential quarter declines were due to cost decreases in most categories of lease operating expenses, the most significant of which including (1) a decrease in workover costs, (2) lower power cost and usage, (3) lower CO₂ expense resulting from a decrease in Gulf Coast region CO₂ injection volumes and a decrease in the cost of CO₂during both comparative periods, which correlates with oil prices, and (4) lower third-party contractor and vendor expenses such as contract labor and chemical costs.

Tertiary lease operating expenses decreased $12.2 million (13%) on an absolute-dollar basis or $4.51 (17%) on a per-barrel basis during the first quarter of 2015 compared to the first quarter of 2014. When comparing the first quarter of 2015 to the fourth quarter of 2014, tertiary lease operating expenses, excluding Delhi Field remediation costs, decreased $7.4 million (8%) or $1.40 (6%) on a per-barrel basis. The year-over-year and sequential quarter declines were primarily due to (1) lower workover costs, (2) lower power costs due to lower rates and usage, (3) lower CO₂ expense resulting from a decrease in Gulf Coast region CO₂ injection volumes and a decrease in the cost of CO₂ during both comparative periods, which correlates with oil prices, and (4) lower third-party contractor and vendor expenses such as contract labor and chemical costs. Although there was a sequential-quarter increase in company-wide CO₂ utilization due to increased injection volumes at our newest tertiary flood at Bell Creek Field in the Rocky Mountain region, CO₂ utilization in the Gulf Coast region decreased 1% sequentially and 7% when compared to prior year as a result of improved efficiency and utilization of CO₂ for those fields. The reduction in CO₂ utilization is in part due to our innovation and improvement initiatives, under which we are doing a bottom-up review of each of our fields. In addition, our operating costs on a per-barrel basis have improved from the first quarter of 2014, as our expense at Bell Creek Field has decreased on a per-BOE basis when comparing the first quarter of 2015 to the same period in 2014, due primarily to continued production increases. For any specific field, we expect our tertiary lease operating expense per barrel to be high initially, as we experienced in 2013 and 2014 with our Bell Creek flood, and then decrease as production increases, ultimately leveling off until production begins to decline in the later life of the field, when operating expense per barrel will again increase.

Currently, our CO₂ expense comprises approximately one-fourth 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 three months ended March 31, 2015 and 2014, approximately 63% and 65%, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us. The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production

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

cost of the CO₂ we own with what we pay third parties for CO₂, our average cost of CO₂ during the first quarter of 2015 was approximately $0.29 per Mcf, including taxes paid on CO₂ production but excluding depletion and depreciation of capital. This rate during the first quarter of 2015 was lower than the $0.32 per Mcf comparable measure during the fourth quarter of 2014 and $0.35 per Mcf during the first quarter of 2014, primarily driven by reductions in commodity costs due to the significant decline in oil prices. Including the cost of depreciation and amortization of capital expended at our CO₂ source fields and industrial sources, but excluding depreciation of our CO₂ pipelines, our cost of CO₂ was $0.39 per Mcf and $0.46 per Mcf during the first quarters of 2015 and 2014, respectively.

Non-tertiary lease operating expenses decreased $17.1 million (23%) on an absolute-dollar basis and $4.87 (20%) on a per-BOE basis between the three months ended March 31, 2015 and 2014, and decreased $7.5 million (12%) on an absolute-dollar basis and $1.79 (9%) on a per-BOE basis between the fourth quarter of 2014 and the first quarter of 2015. The year-over-year and sequential quarter decreases were primarily due to lower workover costs, repairs and maintenance costs, and other third-party costs for contract labor and consulting services during the first quarter of 2015.

Marketing and Plant Operating Expenses

Marketing and plant operating expenses primarily consist of amounts incurred relating to the marketing, processing, and transportation of oil and natural gas production, as well as expenses related to our Riley Ridge gas processing facility. Marketing and plant operating expenses decreased $5.1 million (30%) between the three months ended March 31, 2015 and 2014, primarily due to reductions in marketing, compression, and plant processing fees, as well as reductions related to the Riley Ridge gas processing facility, which is currently shut-in.

Taxes Other Than Income

Taxes other than income includes ad valorem, production and franchise taxes. Taxes other than income decreased $19.3 million during the three months ended March 31, 2015, compared to the same period in 2014. The levels of taxes other than income during most periods are generally aligned with fluctuations in oil and natural gas revenues. The decrease in 2015 is also attributable to severance tax reductions at Hastings Field and Oyster Bayou Field, which reduced severance taxes by approximately $1 million in the first quarter of 2015 related to state-approved enhanced oil recovery project exemptions that were approved in the second half of 2014 and reduce severance taxes for those fields for approximately the next seven years.

General and Administrative Expenses ("G&A")



	Three Months Ended
	March 31,
In thousands, except per-BOE data and employees	2015			2014
Gross cash compensation and administrative costs	$	95,280		$	91,997
Gross stock-based compensation	11,059			11,226
Operator labor and overhead recovery charges	(42,128		)	(43,140		)
Capitalized exploration and development costs	(17,931		)	(16,390		)
Net G&A expense	$	46,280		$	43,693

G&A per BOE:
Net administrative costs	$	5.89		$	5.46
Net stock-based compensation	1.03			1.13
Net G&A expense	$	6.92		$	6.59

Employees as of March 31	1,496			1,498

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

Gross cash compensation and administrative costs on an absolute-dollar basis increased $3.3 million (4%) primarily due to higher employee-related insurance costs and professional service fees between the three months ended March 31, 2015 and 2014. Net G&A expense increased $2.6 million (6%) on an absolute-dollar basis and $0.33 (5%) on a per-BOE basis over the same period, primarily based on the changes noted in gross cash compensation and administrative costs, as total operator labor and overhead recovery charges and capitalized exploration and developments costs remained relatively unchanged on a combined basis.

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. Capitalized exploration and development costs increased 9% between the three months ended March 31, 2015 and 2014, primarily due to increased compensation costs subject to capitalization.

Interest and Financing Expenses



	Three Months Ended
	March 31,
In thousands, except per-BOE data and interest rates	2015			2014
Cash interest expense	$	46,287		$	51,071
Noncash interest expense	2,221			3,519
Less: capitalized interest	(8,409		)	(5,756		)
Interest expense, net	$	40,099		$	48,834
Interest expense, net per BOE	$	5.99		$	7.36
Average debt outstanding	$	3,615,918		$	3,521,495



Average interest rate ⁽¹⁾	5.1	%	5.8	%


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

As reflected in the table above, our average interest rate declined between the first quarter of 2014 and 2015 due to our April 2014 long-term debt refinancing, whereby we issued $1.25 billion of 5½% Senior Subordinated Notes due 2022 to replace our $996.3 million of 8¼% Senior Subordinated Notes due 2020. Capitalized interest during the first quarter of 2015 was $2.7 million (46%) higher than the prior-year period primarily due to incremental capitalized interest on projects that qualify for interest capitalization.

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Denbury Resources Inc.

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

Depletion, Depreciation and Amortization ("DD&A")



	Three Months Ended
	March 31,
In thousands, except per-BOE data	2015		2014
Depletion and depreciation of oil and natural gas properties	$	116,347	$	108,159
Depletion and depreciation of CO₂ properties	8,212		7,958
Asset retirement obligations	2,327		2,201
Depreciation of pipelines, plants and other property and equipment	23,072		22,812
Total DD&A	$	149,958	$	141,130

DD&A per BOE:
Oil and natural gas properties	$	17.73	$	16.63
CO₂, pipelines, plants and other property and equipment	4.68		4.64
Total DD&A cost per BOE	$	22.41	$	21.27

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. Depletion and depreciation of oil and natural gas properties and asset retirement obligations increased 8% on an absolute-dollar basis and 7% on a per-BOE basis between the three months ended March 31, 2015 and 2014 as a result of a higher depletion rate per BOE compared to the same period in 2014 due to higher development costs. When comparing these costs in the first quarter of 2015 to those in the fourth quarter of 2014, depletion and depreciation of oil and natural gas properties and asset retirement obligations decreased $6.5 million (5%) on an absolute-dollar basis and $0.44 (2%) on a per-BOE basis.

Depletion and depreciation of our CO₂ properties, pipelines, plants and other property and equipment increased 2% on an absolute-dollar basis and remained relatively flat on a per-BOE basis during the three months ended March 31, 2015, compared to the same period in 2014, primarily due to a slight increase in CO₂ properties, pipelines, and plants subject to depreciation as a result of continued development as well as a reduction in CO₂ reserves primarily related to production.

Full Cost Pool Ceiling Test Write-Down

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. NYMEX prices decreased precipitously in the fourth quarter of 2014 and ended the first quarter of 2015 at $47.60 per Bbl, with first-day-of-the-month prices for the preceding 12 months, after adjustments for market differentials by field, of $79.55 per Bbl for crude oil and $3.95 per Mcf for natural gas. These prices represent a decrease of 13% and 8% in crude oil and natural gas prices, respectively, compared to adjusted prices used to calculate the December 31, 2014, full cost ceiling value. Because of the significant decrease in pricing during the fourth quarter of 2014 and its continued decline in the first quarter of 2015, we recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015. If oil prices remain at or near late-April 2015 levels in subsequent periods, we expect that we could record significantly larger write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2015. The possibility and amount of any future write-down or impairment is difficult to predict, and will depend, in part, upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures and operating costs.

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Denbury Resources Inc.

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

Impairment Assessment of Goodwill

We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of March 31, 2015. Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of March 31, 2015, we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on March 31, 2015, NYMEX oil and natural gas futures prices for the next five years, which ranged from approximately $52 per Bbl to $64 per Bbl for oil and $3 per MMBtu to $4 per MMBtu for natural gas, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment significantly exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the first quarter of 2015, nor have we recorded a goodwill impairment historically. The cushion between the implied fair value of goodwill and book value of goodwill is due to our enterprise value declining at a slower rate than NYMEX oil futures prices, which were used in the step-two valuation of our oil reserves. A significant change in the assumptions noted above, including future oil and natural gas prices, or a significant decrease in our enterprise value could lead to an impairment of goodwill in future periods. For example, calculations based upon future oil and natural gas prices approximately 20% higher than those at March 31, 2015, without a change in enterprise value or change in other cash flow assumptions, likely would have required a partial impairment of goodwill at March 31, 2015.

Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Impairment Assessment of Goodwill in the Form 10-K for a complete discussion of the goodwill impairment test, including a discussion of relevant inputs, factors resulting in the deficit of enterprise value to book value, and the resulting cushion between implied fair value of goodwill and book value of goodwill.

Income Taxes



	Three Months Ended
	March 31,
In thousands, except per-BOE amounts and tax rates	2015			2014
Current income tax expense	$	1,575		$	4,618
Deferred income tax expense (benefit)	(66,036		)	30,175
Total income tax expense (benefit)	$	(64,461	)	$	34,793
Average income tax expense (benefit) per BOE	$	(9.63	)	$	5.24
Effective tax rate	37.4		%	37.4		%

Our income taxes are based on estimated statutory rates of approximately 38% in the first quarters of 2015 and 2014. Our effective tax rate for the three months ended March 31, 2015 was slightly lower than our estimated statutory rate, primarily due to the impact of the tax benefit from the ceiling test write-down recorded at March 31, 2015. Our effective tax rate for the first quarter of 2014 was slightly below our estimated statutory rate, primarily due to the utilization of the domestic production activities deduction. The amounts recorded as current income tax expense represent our federal taxes, reduced by enhanced oil recovery credits, plus our state income taxes, during the three months ended March 31, 2015 and 2014.

As of March 31, 2015, we had an estimated $42.8 million of enhanced oil recovery credits to carry forward related to our tertiary operations and $34.8 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2015 or future years. These enhanced oil recovery credits do not begin to expire until 2024. Since the ability to earn additional enhanced oil recovery credits is currently based upon a phased-out IRS reference price cap of approximately $52 per Bbl, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to continue to decline from those realized in early May 2015.

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

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	2015			2014
Oil and natural gas revenues	$	44.45		$	94.03
Receipt (payment) on settlements of commodity derivatives	22.19			(4.10		)
Lease operating expenses	(21.08		)	(25.68		)
Production and ad valorem taxes	(3.42		)	(6.39		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.47		)	(1.84		)
Production netback	40.67			56.02
CO₂ and helium sales, net of operating and exploration expenses	0.90			0.84
General and administrative expenses	(6.92		)	(6.59		)
Interest expense, net	(5.99		)	(7.36		)
Other	0.55			0.60
Changes in assets and liabilities relating to operations	(8.62		)	(11.13		)
Cash flows from operations	20.59			32.38
DD&A	(22.41		)	(21.27		)
Write-down of oil and natural gas properties	(21.85		)	—
Deferred income taxes	9.87			(4.55		)
Noncash fair value adjustments on commodity derivatives	(9.78		)	(7.46		)
Other noncash items	7.48			9.69
Net income (loss)	$	(16.10	)	$	8.79

CRITICAL ACCOUNTING POLICIES

For additional discussion of our critical accounting policies, which remain unchanged, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K.

FORWARD-LOOKING INFORMATION

The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted production, cash flows and capital expenditures, levels of dividend payments in future periods, drilling activity or methods including the timing and location thereof, pending or planned acquisitions or dispositions, development activities, estimated timing of completion of pipeline construction and the cost thereof, timing of CO₂ injections and initial production responses thereto, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and their availability, helium reserves, potential reserves, percentages of recoverable original oil in place, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, cost and availability of equipment and services, liquidity, availability of capital, borrowing capacity, regulatory matters, prospective legislation affecting the oil and gas industry, mark-to-market values, possible asset impairments, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the range of potential insurance recoveries, estimates of costs of remedial activities, changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future

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

plans. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "to our knowledge," "anticipate," "projected," "preliminary," "should," "assume," "believe," "may," or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and the Company's 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 or on behalf of the Company. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil and/or natural gas prices and consequently in the prices received or demand for the Company's 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; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial and credit markets; general economic conditions; competition; government regulations, including tax and environmental; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements including, without limitation, the Company's most recent Form 10-K.

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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, 2015, we had $465.0 million in outstanding borrowings on our 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 the event of significant downgrades of our corporate credit rating by the rating agencies, certain credit enhancements can be required from us, and possibly other remedies made available under the lease.

The following table presents the principal balances of our debt, by maturity date, as of March 31, 2015:



In thousands	2015		2017		2019		2021		2022		2023		Total
Variable rate debt:
Bank Credit Facility (weighted average interest rate of 1.5% at March 31, 2015)	$	—	$	—	$	465,000	$	—	$	—	$	—	$	465,000
Fixed rate debt:
6⅜% Senior Subordinated Notes due 2021	—		—		—		400,000		—		—		400,000
5½% Senior Subordinated Notes due 2022	—		—		—		—		1,250,000		—		1,250,000
4⅝% Senior Subordinated Notes due 2023	—		—		—		—		—		1,200,000		1,200,000
Other Subordinated Notes	484		2,250		—		—		—		—		2,734

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

From time to time, we enter 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. These contracts have historically consisted of price floors, collars, three-way collars, fixed-price swaps, and fixed-price swaps enhanced with a sold put. We do not hold or issue derivative financial instruments for trading purposes. 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. For 2015, we have entered into a combination of enhanced swaps, collars, and three-way collars covering a total of 58,000 Bbls/d for the first three quarters of 2015 and 38,000 Bbls/d for the fourth quarter of 2015. Roughly half of these 2015 derivative contracts are collars and three-way collars, so the variability in potential cash flows from these types of hedges exposes us to more downside price risk than fixed-price swaps. In addition, the sold puts that are part of our three-way collars and enhanced swaps limit the benefit our hedges provide us to the extent oil prices remain below the price of our sold puts. We anticipate that we may use more fixed-price swaps in the future or a combination of fixed-price swaps and collars as we look to provide more certainty around our cash flows in order to execute on our capital development plans, pay dividends and retain a healthy balance sheet. See Notes 4 and 5 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 oil and natural gas 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 bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

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For accounting purposes, we do not apply hedge accounting treatment to our oil and natural gas derivative contracts. This means that any changes in the fair value of these 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, 2015, our commodity derivative contracts were recorded at their fair value, which was a net asset of $441.2 million, a $65.3 million decrease from the $506.5 million net asset recorded at December 31, 2014. This change is related to the expiration of commodity derivative contracts during the three months ended March 31, 2015 and to the changes in oil and natural gas futures prices between December 31, 2014 and March 31, 2015.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices and natural gas futures prices as of March 31, 2015, and assuming both a 10% increase and decrease thereon, we would expect to receive payments on our crude oil and natural gas derivative contracts as shown in the following table:



	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts		Natural Gas Derivative Contracts
Based on:
Futures prices as of March 31, 2015	$	464,908	$	2,659
10% increase in prices	433,921		2,107
10% decrease in prices	495,886		3,210

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 or natural gas production to which those commodity derivative contracts relate.

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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, 2015, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the first quarter of fiscal 2015, 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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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, litigation is subject to inherent uncertainties. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our business or finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

In mid-2006, Denbury Onshore, LLC ("Denbury Onshore") purchased its original interest in the Delhi Field in northeastern Louisiana from NGS Sub Corp, ("NGS"), a subsidiary of Evolution Petroleum Corporation (together with its subsidiaries, "Evolution"). Under the purchase documents, Denbury Onshore committed to develop the enhanced production of a specific portion of Delhi Field, the Holt Bryant Unit, and after Denbury Onshore's receipt of a defined level of net cash flow from the Unit (as defined in the agreements, "payout"), to assign reversionary interests in the Unit back to NGS. After several years of dispute regarding payout calculations and related contractual terms, in December 2013, Evolution filed suit against Denbury Onshore in the 133rd Judicial District Court in Houston, Harris County, Texas for unspecified damages, alleging breach of contract, and requesting declaratory judgment as to various provisions of the purchase documents and accompanying oil and gas conveyancing instruments, including as to the method of calculation and timing of payout, the sharing of various costs, and the timing and extent of post-payout assignments from Denbury Onshore to NGS (the "Original Petition"). In February 2014, we filed an answer and counterclaim denying Evolution's claims and alleging breach of contract by Evolution for failing to convey the full interest for which we paid and violating our preferential purchase rights, and asking for declaratory judgment as to purchase document terms, including those pertaining to the determination of payout, the assignment provisions of the documents, and cost sharing.

In March 2015, Evolution filed its First Amended Petition, adding allegations of negligence and gross negligence against Denbury Onshore in connection with the June 2013 Delhi Field release of well fluids, the remediation of which was completed in the fourth quarter of 2013 (see Note 6, Commitments and Contingencies to our Unaudited Condensed Consolidated Financial Statements). Evolution claims for the first time in the First Amended Petition, that it estimates its damages attributable to its allegations in the case exceed $200 million. The First Amended Petition also adds a claim for unspecified punitive damages. There has only been limited discovery in the case to date, and Evolution has not specified the basis for the amount of its claimed damages estimate. The case is currently set for trial in October 2015. We believe that Evolution's claims in the First Amended Petition relating to the June 2013 Delhi Field release are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.

Item 1A. Risk Factors

Information with respect to the Company's risk factors has been incorporated by reference to Item 1A of the Form 10-K. There have been no material changes to the risk factors contained in the Form 10-K since its filing.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the first quarter of 2015:



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 2015	453,450	$	7.66	—	$	221.9
February 2015	2,806	8.00		—	221.9
March 2015	133,340	7.31		—	221.9
Total	589,596			—

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(1)	Stock repurchases during the first quarter of 2015 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights.

(2)

In October 2011, the Company's Board of Directors approved a common share repurchase program for up to $500 million of Denbury's common stock. During 2012 and 2013, the Board of Directors increased the dollar amount of Denbury common shares that could be purchased under the program to an aggregate of up to $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any time. In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty in order to protect our financial strength and preserve liquidity. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

Between early October 2011, when we announced the commencement of a common share repurchase program, and March 31, 2015, we repurchased 60.0 million shares of Denbury common stock (approximately 14.9% of our outstanding shares of common stock at September 30, 2011) for $940.0 million, or $15.68 per share.

Item 3. Defaults upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

In conjunction with the May 2015 redetermination of our Bank Credit Agreement, we entered into the First Amendment on May 4, 2015, under which we modified certain financial covenants in 2016, 2017, and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over next several years. The restructuring of covenants through the First Amendment were executed in consideration of a fee paid to the lenders. The foregoing description is qualified in its entirety by reference to the full text of the First Amendment, which is filed as Exhibit 10(a) to this Quarterly Report on Form 10-Q. See also Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Bank Credit Facility and Note 2, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding the First Amendment.

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Item 6. Exhibits



Exhibit No.		Exhibit
10(a)*		First Amendment to Amended and Restated Credit Agreement, dated as of May 4, 2015, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
10(b)*		Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as of May 6, 2015.
10(c)*		Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of May 6, 2015.
10(d)*		2015 Form of Restricted Share Award to officers under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)*		2015 Form of TSR Performance Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)*		2015 Form of TSR Performance Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(g)*		2015 Form of Capital Efficiency Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(h)*		2015 Form of Capital Efficiency Performance Share Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(i)*		2015 Form of Growth and Income Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(j)*		2015 Form of Growth and Income Performance Share Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
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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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		DENBURY RESOURCES INC.

May 6, 2015		/s/ Mark C. Allen
		Mark C. Allen Sr. Vice President and Chief Financial Officer

May 6, 2015		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

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INDEX TO EXHIBITS



Exhibit No.		Exhibit
10(a)		First Amendment to Amended and Restated Credit Agreement, dated as of May 4, 2015, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
10(b)		Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as of May 6, 2015.
10(c)		Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of May 6, 2015.
10(d)		2015 Form of Restricted Share Award to officers under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)		2015 Form of TSR Performance Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)		2015 Form of TSR Performance Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(g)		2015 Form of Capital Efficiency Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(h)		2015 Form of Capital Efficiency Performance Share Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(i)		2015 Form of Growth and Income Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(j)		2015 Form of Growth and Income Performance Share Award for Phil Rykhoek under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
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.

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