DENBURY INC - Quarter Report: 2017 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, 2017

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



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

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

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

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




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

Denbury Resources Inc.

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		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	3
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29
Item 4.	Controls and Procedures	31

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	34
	Signatures	35

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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)



	Three Months Ended March 31,
	2017			2016
Revenues and other income
Oil, natural gas, and related product sales	$	266,178		$	187,803
CO₂sales and transportation fees	5,388			6,272
Interest income and other income	3,888			769
Total revenues and other income	275,454			194,844
Expenses
Lease operating expenses	113,840			102,447
Marketing and plant operating expenses	14,065			13,194
CO₂ discovery and operating expenses	593			607
Taxes other than income	22,440			20,092
General and administrative expenses	28,241			33,901
Interest, net of amounts capitalized of $4,654 and $5,780, respectively	27,178			42,171
Depletion, depreciation, and amortization	51,195			77,366
Commodity derivatives expense (income)	(24,602		)	22,826
Gain on debt extinguishment	—			(94,991		)
Write-down of oil and natural gas properties	—			256,000
Other expenses	—			1,544
Total expenses	232,950			475,157
Income (loss) before income taxes	42,504			(280,313		)
Income tax provision (benefit)	20,974			(95,120		)
Net income (loss)	$	21,530		$	(185,193	)

Net income (loss) per common share
Basic	$	0.06		$	(0.53	)
Diluted	$	0.05		$	(0.53	)

Weighted average common shares outstanding
Basic	389,397			347,235
Diluted	392,997			347,235

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)



	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	21,530		$	(185,193	)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	51,195			77,366
Write-down of oil and natural gas properties	—			256,000
Deferred income taxes	34,909			(95,115		)
Stock-based compensation	4,106			859
Commodity derivatives expense (income)	(24,602		)	22,826
Receipt (payment) on settlements of commodity derivatives	(26,940		)	72,227
Gain on debt extinguishment	—			(94,991		)
Debt issuance costs and discounts	1,901			3,306
Other, net	(344		)	(416		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	6,453			4,479
Trade and other receivables	(12,185		)	812
Other current and long-term assets	643			1,437
Accounts payable and accrued liabilities	(23,890		)	(53,548		)
Oil and natural gas production payable	(7,335		)	(7,572		)
Other liabilities	(1,179		)	(448		)
Net cash provided by operating activities	24,262			2,029

Cash flows from investing activities
Oil and natural gas capital expenditures	(52,152		)	(65,692		)
Acquisitions of oil and natural gas properties	(16,222		)	(224		)
Pipelines and plants capital expenditures	(246		)	(635		)
Net proceeds from sales of oil and natural gas properties and equipment	415			—
Other	608			(403		)
Net cash used in investing activities	(67,597		)	(66,954		)

Cash flows from financing activities
Bank repayments	(343,000		)	(696,000		)
Bank borrowings	397,000			831,000
Repurchases of senior subordinated notes	—			(55,521		)
Pipeline financing and capital lease debt repayments	(7,055		)	(7,387		)
Other	(3,469		)	(1,727		)
Net cash provided by financing activities	43,476			70,365
Net increase in cash and cash equivalents	141			5,440
Cash and cash equivalents at beginning of period	1,606			2,812
Cash and cash equivalents at end of period	$	1,747		$	8,252

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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

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

Reclassifications

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

Net Income (Loss) per Common Share

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

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



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

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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



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

2016 Write-Down of Oil and Natural Gas Properties

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

Recent Accounting Pronouncements

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

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

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Long-Term Debt

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



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

(1)

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

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

Senior Secured Bank Credit Facility

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

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


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


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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


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


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

2016 Repurchases of Senior Subordinated Notes

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

Note 3. Income Taxes

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

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

Note 4. Commodity Derivative Contracts

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

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

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



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


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

(2)

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

Note 5. Fair Value Measurements

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


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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

•

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

•

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

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

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



	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2017
Assets
Oil derivative contracts – current	$	—	$	971	$	91	$	1,062
Total Assets	$	—	$	971	$	91	$	1,062

Liabilities
Oil derivative contracts – current	$	—	$	18,799	$	—	$	18,799
Total Liabilities	$	—	$	18,799	$	—	$	18,799

December 31, 2016
Liabilities
Oil derivative contracts – current	$	—	$	68,753	$	526	$	69,279
Total Liabilities	$	—	$	68,753	$	526	$	69,279

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 Fair Value Measurements

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



	Three Months Ended
	March 31,
In thousands	2017			2016
Fair value of Level 3 instruments, beginning of period	$	(526	)	$	52,834
Fair value gains on commodity derivatives	617			281
Receipts on settlements of commodity derivatives	—			(30,075		)
Fair value of Level 3 instruments, end of period	$	91		$	23,040

The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	236		$	133

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



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

Other Fair Value Measurements

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

Note 6. Commitments and Contingencies

Commitments

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

Litigation

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

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Notes to Unaudited Condensed Consolidated Financial Statements

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

Riley Ridge Helium Supply Contract Claim

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

Note 7. Additional Balance Sheet Details

Trade and Other Receivables, Net



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

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Denbury Resources Inc.

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

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

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

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

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

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

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

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

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

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

CAPITAL RESOURCES AND LIQUIDITY

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

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

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

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

Senior Secured Bank Credit Facility. In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). In May

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Denbury Resources Inc.

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

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


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


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


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


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

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

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

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


•	$175 million allocated for tertiary oil field expenditures;


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


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


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

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Denbury Resources Inc.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the three months ended March 31, 2017 and 2016:



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


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

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

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

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

Our commitments and obligations consist of those detailed as of December 31, 2016, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations.

RESULTS OF OPERATIONS

Our tertiary operations represent a significant portion of our overall operations and are our primary long-term strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play, and we have outlined certain of these differences in our Form 10-K and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.

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Denbury Resources Inc.

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

Operating Results Table

Certain of our operating results and statistics for the comparative three months ended March 31, 2017 and 2016 are included in the following table:



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


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


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

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


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

(4)

Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were payments on settlements of $26.9 million for the three months ended March 31, 2017 compared to receipts on settlements of $72.2 million for the three months ended March 31, 2016. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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Denbury Resources Inc.

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

Production

Average daily production by area for each of the four quarters of 2016 and for the first quarter of 2017 is shown below:



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


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


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

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Denbury Resources Inc.

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

Total Production

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

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

Tertiary Production

Oil production from our tertiary operations during the first quarter of 2017 decreased 276 Bbls/d (1%) when comparing the fourth quarter of 2016 and the first quarter of 2017 and decreased 3,394 Bbls/d (8%) compared to the same period in 2016. These decreases were primarily due to natural production declines at most of our fields in the Gulf Coast region due to the lower capital expenditure level throughout 2016 and downtime at Hastings Field as we expand our tertiary development and perform conformance work, partially offset by both increased production due to continued CO₂enhanced oil recovery response and natural gas liquids volumes from the plant at Delhi Field in the Gulf Coast region, which began operation in late 2016. The year-to-year first quarter decline in production was further offset by increased quarterly production at Bell Creek Field in the Rocky Mountain region.

Non-Tertiary Production

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

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2017 increased 42% compared to these revenues for the same period in 2016. The changes in our oil and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:



	Three Months Ended
	March 31,
	2017 vs. 2016
In thousands	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(27,288	)	(14	)%
Increase in commodity prices	105,663			56	%
Total increase in oil and natural gas revenues	$	78,375		42	%

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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, 2017 and 2016:



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

Our average net realized oil price, excluding the impact of commodity derivative contracts, increased 64% during the first quarter of 2017 from the average price received during the first quarter of 2016 and increased 5% when compared to the fourth quarter of 2016. Company-wide average oil price differentials in the first quarter of 2017 were $1.64 per Bbl below NYMEX, compared to an average differential of $3.02 per Bbl below NYMEX in the first quarter of 2016 and $1.22 per Bbl below NYMEX in the fourth quarter of 2016. Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials. Additional information about our oil differentials in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.

Our average NYMEX oil differential in the Gulf Coast region was a negative $1.42 per Bbl and a negative $1.95 per Bbl during the first quarter of 2017 and 2016, respectively, and a negative $0.81 per Bbl during the fourth quarter of 2016. These differentials are impacted significantly by the changes in prices received for our crude oil sold under LLS index prices relative to the change in NYMEX prices, as well as various other price adjustments such as those noted above. The quarterly average LLS-to-NYMEX differential (on a trade-month basis) was a positive $1.58 per Bbl in the first quarter of 2017, consistent with a positive $1.60 per Bbl in the first quarter of 2016 and a slight increase from the positive $1.42 per Bbl in the fourth quarter of 2016. During the first quarter of 2017, we sold approximately 60% of our crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.

NYMEX oil differentials in the Rocky Mountain region averaged $2.09 per Bbl and $5.04 per Bbl below NYMEX during the first quarter of 2017 and 2016, respectively, and $2.06 per Bbl below NYMEX during the fourth quarter of 2016. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2017 and 2016:



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


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

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Denbury Resources Inc.

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

Based on current futures prices as of May 3, 2017, which average approximately $48 per Bbl for the second quarter of 2017, and the fixed-price swaps that we have in place, we currently expect that we will make cash payments of approximately $13 million during the second quarter of 2017 upon settlement of these contracts, the amount of which is dependent upon fluctuations in future NYMEX prices in relation to the fixed prices of these swaps, which have a weighted average price of $44.32 per Bbl. Commodity derivative contracts in place for the second half of 2017 solely include collars and three-way collars. Based on current contracts in place and NYMEX oil futures prices as of May 3, 2017, minimal or no settlements are currently expected during the second half of 2017. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil and natural gas derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations. The details of our outstanding commodity derivative contracts at March 31, 2017, are included in Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements. Also, see Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion on our commodity derivative contracts.

Production Expenses

Lease Operating Expenses



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

Total lease operating expenses per BOE	$	21.11	$	16.23

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

Currently, our CO₂ expense comprises approximately 20% of our typical tertiary lease operating expenses, and for the CO₂ reserves we already own, consists of CO₂ production expenses, and for the CO₂ reserves we do not own, consists of our purchase of CO₂ from royalty and working interest owners and industrial sources. During the first quarters of 2017 and 2016, approximately 57% and 56%, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us (our net revenue interest). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what we pay third parties for CO₂, including taxes paid on CO₂ production but excluding depletion, depreciation and amortization of capital expended at our CO₂ source fields and industrial sources, our average cost of CO₂ was approximately $0.41 per Mcf during the first quarter of 2017, compared to $0.33 per Mcf during the first quarter of 2016 and $0.39 per Mcf during the fourth quarter of 2016. The increase when compared to the first quarter of 2016 was partially attributable to increases in the cost of CO₂ due to increases in oil prices, and further impacted by a lower utilization of CO₂ in the 2017 period, while certain pipeline and processing costs are relatively fixed. The 2017 period increase when compared to the fourth quarter of 2016 was primarily impacted by higher utilization of industrial-sourced CO₂, which has a higher average cost than our naturally-occurring CO₂ sources. As we anticipate additional industrial-sourced CO₂ volumes from MSPC coming into our CO₂ supply during the second quarter of 2017, we expect that our per-Mcf cost of CO₂ could trend higher; however, utilizing industrial-sourced CO₂ significantly reduces the future capital we would otherwise have to spend at Jackson Dome and provides a long-term consistent source of CO₂.

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Denbury Resources Inc.

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

Marketing and Plant Operating Expenses

Marketing and plant operating expenses primarily consist of amounts incurred relating to the marketing, processing, and transportation of oil and natural gas production, and to a lesser extent expenses related to our Riley Ridge gas processing facility. Marketing and plant operating expenses were $14.1 million and $13.2 million for the three months ended March 31, 2017 and 2016, respectively.

Taxes Other Than Income

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

General and Administrative Expenses (“G&A”)



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

G&A per BOE:
Net administrative costs	$	4.48		$	5.29
Net stock-based compensation	0.76			0.08
Net G&A expenses	$	5.24		$	5.37

Employees as of March 31	1,061			1,096

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

Net G&A expense on a per-BOE basis decreased 2% during the three months ended March 31, 2017 compared to levels in the same period in 2016. The change was primarily based upon the changes noted in gross cash compensation and administrative costs, partially offset by lower operating and overhead recovery charges, lower capitalized exploration and development costs, and lower production volumes.

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

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition, salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities.

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Denbury Resources Inc.

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

Interest and Financing Expenses



	Three Months Ended
	March 31,
In thousands, except per-BOE data and interest rates	2017			2016
Cash interest ⁽¹⁾	$	42,500		$	44,645
Less: interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes ⁽¹⁾	(12,569		)	—
Noncash interest expense	1,901			3,306
Less: capitalized interest	(4,654		)	(5,780		)
Interest expense, net	$	27,178		$	42,171
Interest expense, net per BOE	$	5.04		$	6.68
Average debt principal outstanding	$	2,818,832		$	3,326,140
Average interest rate ⁽²⁾	6.0		%	5.4		%

(1)

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


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

As reflected in the table above, cash interest during the three months ended March 31, 2017, decreased when compared to the same period in 2016 due primarily to repurchasing a total of $181.9 million principal amount of our existing senior subordinated notes at a discount to par value in open-market transactions during 2016. For the three months ended March 31, 2017, $12.6 million of interest on our 2021 Senior Secured Notes was accounted for as debt, and is therefore not reflected as interest expense in the Unaudited Condensed Consolidated Statements of Operations in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors. Noncash interest expense during the three months ended March 31, 2017 decreased when compared to the same prior year period primarily due to the prior-year period including a $1.0 million write-off of debt issuance costs associated with our senior secured bank credit facility following the February 2016 amendment which reduced our lender commitments. Capitalized interest during the three months ended March 31, 2017 decreased $1.1 million (19%) compared to the same period in 2016, primarily due to a reduction in the number of projects that qualify for interest capitalization.

Depletion, Depreciation, and Amortization (“DD&A”)



	Three Months Ended
	March 31,
In thousands, except per-BOE data	2017		2016
Oil and natural gas properties	$	27,818	$	50,016
CO₂ properties, pipelines, plants and other property and equipment	23,377		27,350
Total DD&A	$	51,195	$	77,366

DD&A per BOE:
Oil and natural gas properties	$	5.16	$	7.98
CO₂properties, pipelines, plants and other property and equipment	4.33		4.28
Total DD&A cost per BOE	$	9.49	$	12.26

Write-down of oil and natural gas properties	$	—	$	256,000

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Denbury Resources Inc.

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

We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and costs. In addition, under full cost accounting rules, the divestiture of oil and gas properties generally does not result in gain or loss recognition; instead, the proceeds of the disposition reduce the full cost pool. As such, our DD&A rate has changed significantly over time, and it may continue to change in the future. DD&A of oil and natural gas properties decreased 44% on an absolute-dollar basis during the three months ended March 31, 2017 compared to the same period in 2016. On a per-BOE basis, DD&A of oil and natural gas properties decreased 35% during the three months ended March 31, 2017, compared to the same period in 2016. These decreases were primarily due to a reduction in depletable costs associated with our reserves base resulting from the full cost pool ceiling test write-downs recognized during 2016 and an overall reduction in future development costs, partially offset by reductions in proved oil and natural gas reserve quantities. The per-BOE decrease was also partially offset by a decrease in production volumes during the first quarter of 2017 when compared to production in the 2016 period.

Depletion and depreciation of our CO₂properties, pipelines, plants and other property and equipment decreased 15% on an absolute-dollar basis and increased 1% on a per-BOE basis during the three months ended March 31, 2017, compared to the same period in 2016. The decrease on an absolute-dollar basis between periods was primarily due to a decrease in plant depreciation due to the accelerated depreciation charge at the Riley Ridge gas processing facility during the fourth quarter of 2016, while the slight increase on a per-BOE basis was primarily driven by the decrease in oil and natural gas production volumes between the first quarters of 2016 and 2017.

2016 Write-Down of Oil and Natural Gas Properties

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

Income Taxes



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

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

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Denbury Resources Inc.

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

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

As of March 31, 2017, we had an estimated $51.1 million of enhanced oil recovery credits to carry forward related to our tertiary operations, $21.6 million of research and development credits, and $29.0 million of alternative minimum tax credits (net of $12.1 million related to the estimated credits to be applied to our 2016 tax return) that can be utilized to reduce our current income taxes during 2017 or future years. The enhanced oil recovery credits and research and development credits do not begin to expire until 2023 and 2031, respectively.

Per-BOE Data

The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.



	Three Months Ended
	March 31,
Per-BOE data	2017			2016
Oil and natural gas revenues	$	49.35		$	29.76
Receipt (payment) on settlements of commodity derivatives	(5.00		)	11.44
Lease operating expenses	(21.11		)	(16.23		)
Production and ad valorem taxes	(3.86		)	(2.72		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.87		)	(1.84		)
Production netback	17.51			20.41
CO₂ sales, net of operating and exploration expenses	0.89			0.89
General and administrative expenses	(5.24		)	(5.37		)
Interest expense, net	(5.04		)	(6.68		)
Other	3.33			(0.24		)
Changes in assets and liabilities relating to operations	(6.95		)	(8.69		)
Cash flows from operations	4.50			0.32
DD&A	(9.49		)	(12.26		)
Write-down of oil and natural gas properties	—			(40.56		)
Deferred income taxes	(6.47		)	15.07
Gain on debt extinguishment	—			15.05
Noncash fair value gains (losses) on commodity derivatives ⁽¹⁾	9.56			(15.06		)
Other noncash items	5.89			8.10
Net income (loss)	$	3.99		$	(29.34	)


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

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Denbury Resources Inc.

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

CRITICAL ACCOUNTING POLICIES

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

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus the length or severity of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, future interest rates, availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, estimated timing of commencement of CO₂ flooding of particular fields or areas, dates of completion of to-be-constructed industrial plants and the initial date of capture of CO₂ from such plants, timing of CO₂ injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, potential increases in regional or worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, long-term forecasts of production, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our estimated original oil in place, operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.

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Denbury Resources Inc.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. As of March 31, 2017, we had $355.0 million of debt outstanding on our senior secured bank credit facility. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in light of credit downgrades in February 2016, we were required to provide a $41.3 million letter of credit to the lessor, which we provided on March 4, 2016. The letter of credit may be drawn upon in the event Denbury Onshore or Denbury fail to make a payment due under the pipeline financing lease agreement or upon other specified defaults set out in the pipeline financing lease agreement (filed as Exhibit 99.1 to the Form 8-K filed with the SEC on June 5, 2008). The fair values of our 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices. The following table presents the principal cash flows and fair values of our outstanding debt as of March 31, 2017:



In thousands	2017		2019		2021		2022		2023		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 3.2% at March 31, 2017)	$	—	$	355,000	$	—	$	—	$	—	$	355,000	$	355,000
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	—		—		614,919		—		—		614,919		646,464
6⅜% Senior Subordinated Notes due 2021	—		—		215,144		—		—		215,144		175,880
5½% Senior Subordinated Notes due 2022	—		—		—		772,912		—		772,912		599,007
4⅝% Senior Subordinated Notes due 2023	—		—		—		—		622,297		622,297		452,721
Other Subordinated Notes	2,250		—		—		—		—		2,250		2,250

See Note 2, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

Oil and Natural Gas Derivative Contracts

Historically, we have entered into oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2017 using both NYMEX and LLS fixed-price swaps, collars and three-way collars. Due to the volatility experienced and the previous downward trend in oil prices over the past two years, we have reduced our hedged level and duration of new derivative contracts; thus, the percentage of our forecasted production we have hedged and the duration of our hedges are less than what we have had in the recent past. However, we will continue to evaluate the production we hedge in light of our levels of debt, financial strength and expectation of future commodity prices. See also Note 4, Commodity Derivative Contracts, and Note 5, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

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Denbury Resources Inc.

For accounting purposes, we do not apply hedge accounting treatment to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

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

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of March 31, 2017, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:



	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts
Based on:
Futures prices as of March 31, 2017	$	(18,708	)
10% increase in prices	(32,273		)
10% decrease in prices	(5,142		)

Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments of our commodity derivative contracts due to changes in commodity prices as reflected in the above table would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil and natural gas production to which those commodity derivative contracts relate.

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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, 2017, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the first quarter of fiscal 2017, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Denbury Resources Inc.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Settlement of Mississippi Environmental Matter

For the past two years, the Company has been in negotiations with the Mississippi Department of Environmental Quality (“MDEQ”) regarding a February 2015 notice from the MDEQ related to a discharge of materials at the West Heidelberg Field in Jasper County, Mississippi in the third quarter of 2013. In late April 2017, we entered into an Agreed Order with the MDEQ settling the claims covered by the notice, which Agreed Order provides for the Company’s payment of a civil penalty of $195,000 and for it to maintain certain future well monitoring.

Riley Ridge Helium Supply Contract Claim

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

Item 1A. Risk Factors

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

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

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the first quarter of 2017:



Month	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) ⁽²⁾
January 2017	288,474	$	3.72	—	$	210.1
February 2017	743	3.37		—	210.1
March 2017	207,058	2.58		—	210.1
Total	496,275			—


(1)	Stock repurchases during the first quarter of 2017 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted and performance shares.

(2)

In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock as long as current commodity pricing and general economic conditions persist. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

Between early October 2011, when we announced commencement of a common share repurchase program, and October 2015, we repurchased 64.4 million shares of Denbury common stock (approximately 16.0% of our outstanding shares of common stock at September 30, 2011) for $951.8 million, with no repurchases made since October 2015.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit No.		Exhibit
10(a)*		2017 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)*		2017 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(c)*		2017 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)*		2017 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)*		2017 Form of Oil Price Change vs. TSR Performance Award, under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)*		Officer Retirement Agreement, effective as of March 21, 2017, by and between Denbury Resources Inc. and Phil Rykhoek.
10(g)		Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 3, 2017, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 4, 2017, File No. 001-12935).
31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive Data Files.


*	Included herewith.

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SIGNATURES

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



		DENBURY RESOURCES INC.

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

May 5, 2017		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

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INDEX TO EXHIBITS



Exhibit No.		Exhibit
10(a)		2017 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)		2017 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(c)		2017 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)		2017 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(e)		2017 Form of Oil Price Change vs. TSR Performance Award, under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(f)		Officer Retirement Agreement, effective as of March 21, 2017, by and between Denbury Resources Inc. and Phil Rykhoek.
31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Interactive Data Files.