DENBURY INC - Quarter Report: 2017 September (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 September 30, 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 October 31, 2017
Common Stock, $.001 par value		402,170,359

Denbury Resources Inc.

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		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	3
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 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	15
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	34

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Mine Safety Disclosures	36
Item 5.	Other Information	36
Item 6.	Exhibits	37
	Signatures	38

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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)



	September 30,			December 31,
	2017			2016
Assets
Current assets
Cash and cash equivalents	$	57		$	1,606
Accrued production receivable	121,346			124,936
Trade and other receivables, net	55,318			43,900
Derivative assets	60			—
Other current assets	10,811			10,684
Total current assets	187,592			181,126
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	10,694,674			10,419,827
Unevaluated properties	957,060			927,819
CO₂ properties	1,190,190			1,188,467
Pipelines and plants	2,285,092			2,285,812
Other property and equipment	371,114			378,776
Less accumulated depletion, depreciation, amortization and impairment	(11,350,956		)	(11,212,327		)
Net property and equipment	4,147,174			3,988,374
Other assets	106,163			105,078
Total assets	$	4,440,929		$	4,274,578
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	183,063		$	200,266
Oil and gas production payable	69,737			80,585
Derivative liabilities	16,746			69,279
Current maturities of long-term debt (including future interest payable of $50,490 and $50,349, respectively – see Note 3)	85,002			83,366
Total current liabilities	354,548			433,496
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $153,196 and $178,476, respectively – see Note 3)	3,057,439			2,909,732
Asset retirement obligations	155,749			146,807
Derivative liabilities	4,263			—
Deferred tax liabilities, net	329,724			293,878
Other liabilities	21,759			22,217
Total long-term liabilities	3,568,934			3,372,634
Commitments and contingencies (Note 7)
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; 407,622,526 and 402,334,655 shares issued, respectively	408			402
Paid-in capital in excess of par	2,550,347			2,534,670
Accumulated deficit	(1,982,592		)	(2,018,989		)
Treasury stock, at cost, 5,382,584 and 3,906,877 shares, respectively	(50,716		)	(47,635		)
Total stockholders’ equity	517,447			468,448
Total liabilities and stockholders’ equity	$	4,440,929		$	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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues and other income
Oil, natural gas, and related product sales	$	259,030		$	239,930		$	776,088		$	674,401
CO₂sales and transportation fees	6,590			6,253			18,533			19,147
Interest income and other income	939			7,802			8,576			10,429
Total revenues and other income	266,559			253,985			803,197			703,977
Expenses
Lease operating expenses	117,768			106,522			342,926			308,988
Marketing and plant operating expenses	11,816			14,452			39,758			40,645
CO₂ discovery and operating expenses	1,346			861			2,452			2,539
Taxes other than income	20,233			20,401			62,848			59,997
General and administrative expenses	27,273			24,643			81,303			81,089
Interest, net of amounts capitalized of $9,416, $6,875, $22,217, and $18,944, respectively	24,546			24,778			75,785			103,007
Depletion, depreciation, and amortization	52,101			55,012			154,448			198,919
Commodity derivatives expense (income)	25,263			(21,224		)	(9,712		)	99,811
Gain on debt extinguishment	—			(7,826		)	—			(115,095		)
Write-down of oil and natural gas properties	—			75,521			—			810,921
Other expenses	—			—			—			36,232
Total expenses	280,346			293,140			749,808			1,627,053
Income (loss) before income taxes	(13,787		)	(39,155		)	53,389			(923,076		)
Income tax provision (benefit)	(14,229		)	(14,565		)	17,018			(332,625		)
Net income (loss)	$	442		$	(24,590	)	$	36,371		$	(590,451	)

Net income (loss) per common share
Basic	$	0.00		$	(0.06	)	$	0.09		$	(1.60	)
Diluted	$	0.00		$	(0.06	)	$	0.09		$	(1.60	)

Weighted average common shares outstanding
Basic	392,013			388,572			390,448			368,863
Diluted	393,023			388,572			392,625			368,863

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)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	36,371		$	(590,451	)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	154,448			198,919
Write-down of oil and natural gas properties	—			810,921
Deferred income taxes	35,846			(331,574		)
Stock-based compensation	12,215			9,682
Commodity derivatives expense (income)	(9,712		)	99,811
Receipt (payment) on settlements of commodity derivatives	(38,618		)	116,958
Gain on debt extinguishment	—			(115,095		)
Debt issuance costs and discounts	4,801			15,541
Other, net	(112		)	(3,271		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	3,590			(2,207		)
Trade and other receivables	(13,604		)	35,911
Other current and long-term assets	(4,734		)	(8,434		)
Accounts payable and accrued liabilities	(22,736		)	(57,830		)
Oil and natural gas production payable	(10,848		)	(13,290		)
Other liabilities	(4,048		)	(6,232		)
Net cash provided by operating activities	142,859			159,359

Cash flows from investing activities
Oil and natural gas capital expenditures	(197,982		)	(176,631		)
Acquisitions of oil and natural gas properties	(91,124		)	(560		)
Net proceeds from sales of oil and natural gas properties and equipment	1,412			47,232
Other	(6,314		)	(4,048		)
Net cash used in investing activities	(294,008		)	(134,007		)

Cash flows from financing activities
Bank repayments	(1,188,000		)	(1,362,500		)
Bank borrowings	1,382,000			1,447,500
Interest payments on senior secured notes treated as a reduction of debt	(25,139		)	—
Repurchases of senior subordinated notes	—			(76,708		)
Pipeline financing and capital lease debt repayments	(20,523		)	(21,510		)
Other	1,262			(11,673		)
Net cash provided by (used in) financing activities	149,600			(24,891		)
Net increase (decrease) in cash and cash equivalents	(1,549		)	461
Cash and cash equivalents at beginning of period	1,606			2,812
Cash and cash equivalents at end of period	$	57		$	3,273

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 September 30, 2017, our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and our consolidated cash flows for the nine months ended September 30, 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 and nine months ended September 30, 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		Nine Months Ended
	September 30,		September 30,
In thousands	2017	2016	2017	2016
Basic weighted average common shares outstanding	392,013	388,572	390,448	368,863
Potentially dilutive securities
Restricted stock and performance-based equity awards	1,010	—	2,177	—
Diluted weighted average common shares outstanding	393,023	388,572	392,625	368,863

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). For purposes of calculating diluted weighted average common shares during

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

the three and nine months ended September 30, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

The 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		Nine Months Ended
	September 30,		September 30,
In thousands	2017	2016	2017	2016
Stock appreciation rights	4,551	6,091	4,793	6,590
Restricted stock and performance-based equity awards	9,891	9,178	6,259	6,053

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 full cost pool ceiling test write-downs of $75.5 million, $479.4 million, and $256.0 million during the three months ended September 30, June 30 and March 31, 2016, respectively. We have not recorded a ceiling test write-down during the first nine months of 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. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements.

Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows.

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, 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 currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.

Note 2. Asset Acquisition and Assets Held for Sale

Asset Acquisition

On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $71.5 million, before customary closing adjustments. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties.

Assets Held for Sale

We began actively marketing for sale certain non-productive surface acreage in the Houston area during July 2017, which we currently anticipate selling during 2018. As of September 30, 2017, the carrying value of the land held for sale was $33.1 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.

Note 3. Long-Term Debt

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



	September 30,			December 31,
In thousands	2017			2016
Senior Secured Bank Credit Agreement	$	495,000		$	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 $1 and $3, respectively	2,251			2,253
Pipeline financings	195,258			202,671
Capital lease obligations	34,542			48,718
Total debt principal balance	2,952,323			2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021 ⁽¹⁾	203,686			228,825
Issuance costs on senior secured second lien and senior subordinated notes	(13,568		)	(15,641		)
Total debt, net of debt issuance costs	3,142,441			2,993,098
Less: current maturities of long-term debt ⁽¹⁾	(85,002		)	(83,366		)
Long-term debt and capital lease obligations	$	3,057,439		$	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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and our 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 (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019 and semiannual borrowing base redeterminations in May and November of each year. As part of our fall 2017 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 May 2018. 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 4.3% as of September 30, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

In May 2017, we entered into a Fourth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to amend 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, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased 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. In November 2017, we entered into a Fifth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we can incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:


•	A consolidated senior secured debt to consolidated EBITDAX covenant, 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;


•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and


•	A requirement to maintain a current ratio of 1.0 to 1.0.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.

2016 Senior Subordinated Notes Exchange

During May 2016, in privately negotiated transactions, we exchanged a total of $1,057.8 million of our existing senior subordinated notes for $614.9 million principal amount of our 2021 Senior Secured Notes plus 40.7 million shares of Denbury common stock, resulting in a net reduction from these exchanges of $442.9 million in our debt principal. As a result of this debt exchange, we recognized a gain of $12.0 million during the nine months ended September 30, 2016, which is included in “Gain on debt extinguishment” in the accompanying Consolidated Statements of Operations.

2016 Repurchases of Senior Subordinated Notes

During the first and third quarters of 2016, we repurchased a total of $181.9 million of our outstanding long-term indebtedness in open-market transactions for a total purchase price of $76.7 million, excluding accrued interest. In connection with these transactions, we recognized a $103.1 million gain on extinguishment, net of unamortized debt issuance costs written off, during the nine months ended September 30, 2016. As of November 6, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on open market or other repurchases or redemptions of our senior subordinated notes.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 4. 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. Our income taxes are based on an estimated statutory rate of approximately 38% in 2017 and 2016. Our effective tax rate for the three months ended September 30, 2017, differed from our estimated statutory rate, primarily due to the impact of recognizing a tax benefit of $8.6 million in the current quarter for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall (tax deduction less than book expense) of $2.1 million. With pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these items had a significant impact on the current quarter’s effective tax rate.

Note 5. Commodity Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 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.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of September 30, 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
Oct – Dec	NYMEX	12,000	$	48.40	–	50.13	$	49.76	$	—	$	—	$	—
2017 Three-Way Collars ⁽²⁾
Oct – Dec	NYMEX	14,000	$	40.00	–	70.20	$	—	$	31.07	$	41.07	$	65.79
Oct – Dec	LLS	1,000		41.00	–	70.25	—		31.00		41.00		70.25
2017 Collars
Oct – Dec	NYMEX	1,000	$	40.00	–	70.00	$	—	$	—	$	40.00	$	70.00
2018 Fixed-Price Swaps
Jan – Dec	NYMEX	15,500	$	50.00	–	50.40	$	50.13	$	—	$	—	$	—
2018 Three-Way Collars ⁽²⁾
Jan – Dec	NYMEX	15,000	$	45.00	–	56.60	$	—	$	36.50	$	46.50	$	53.88


2017 Basis Swaps ⁽³⁾
Dec	Argus LLS	5,000	$	4.15	–	4.15	$	4.15	$	—	$	—	$	—
2018 Basis Swaps ⁽³⁾
Jan – June	Argus LLS	2,500	$	3.13	–	3.15	$	3.13	$	—	$	—	$	—


(1)	Ranges presented for fixed-price swaps and basis 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.


(3)	The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

Note 6. Fair Value Measurements

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


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

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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 basis 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 September 30, 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 $100 thousand in the fair value of these instruments as of September 30, 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
September 30, 2017
Assets
Oil derivative contracts – current	$	—	$	58		$	2		$	60
Total Assets	$	—	$	58		$	2		$	60

Liabilities
Oil derivative contracts – current	$	—	$	(16,746	)	$	—		$	(16,746	)
Oil derivative contracts – long-term	—		(4,263		)	—			(4,263		)
Total Liabilities	$	—	$	(21,009	)	$	—		$	(21,009	)

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 and nine months ended September 30, 2017 and 2016:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands	2017			2016			2017			2016
Fair value of Level 3 instruments, beginning of period	$	99		$	240		$	(526	)	$	52,834
Fair value gains (losses) on commodity derivatives	(97		)	2,402			528			(2,134		)
Receipts on settlements of commodity derivatives	—			(3,167		)	—			(51,225		)
Fair value of Level 3 instruments, end of period	$	2		$	(525	)	$	2		$	(525	)

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date	$	(71	)	$	891		$	54		$	(525	)

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 9/30/2017 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	2	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017	15.4% – 33.4%

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, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of September 30, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $1,996.6 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 7. Commitments and Contingencies

Commitments

The Company has a CO₂ offtake agreement with Mississippi Power Company (“MSPC”), providing for our purchase of CO₂ generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO₂ from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO₂ from this facility for the foreseeable future.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Litigation

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

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility. The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are capped at $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium to the third-party purchaser under the helium supply contract. In a case originally filed in November 2014 by APMTG Helium, LLC, the third-party helium purchaser, after a week of trial during February 2017 on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed until November 27, 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 8. Additional Balance Sheet Details

Trade and Other Receivables, Net



	September 30,		December 31,
In thousands	2017		2016
Trade accounts receivable, net	$	15,319	$	20,084
Federal income tax receivable	11,687		—
Other receivables	28,312		23,816
Total	$	55,318	$	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. Oil prices are highly impacted by worldwide oil supply and demand and have historically been subject to significant price changes over short periods of time, including the early November 2017 move of NYMEX oil prices over $57 per Bbl for the first time in over two years. Over the last few years, we have been in a period of lower oil prices during which oil prices have generally averaged in the $30-$50 per Bbl range, which is roughly 50% lower than the oil price range over the 2011 through 2014 period. As a result of the lower oil price environment and its impact on our business, our focus has primarily been on preservation of cash and liquidity, together with cost reductions, rather than concentration on expansion and growth. Early in 2017, when we set our development capital budget at $300 million, the forecasted oil price for 2017 was projected to average in the low-to-mid $50’s per Bbl. Given that prices during the first three quarters of 2017 were lower than originally projected, to protect our cash and liquidity, in August 2017 we reduced our 2017 estimated development capital spending by $50 million from $300 million to $250 million (excluding acquisitions and capitalized interest).

Hurricane Harvey Impact. Due to conditions associated with Hurricane Harvey, in late-August the Company suspended operations and temporarily shut-in all production at its Houston area fields, representing net production of approximately 16,000 BOE/d. The impacted fields included Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel. Approximately 90% of the 16,000 BOE/d of net production shut-in as of August 27, 2017 had returned to production by September 6^th, and the only field that remained partially shut-in was Thompson Field. Thompson Field had net production just prior to the storm of approximately 1,000 BOE/d, nearly all of which has now been returned to production. The impact of Hurricane Harvey on third quarter 2017 production was approximately 2,000 BOE/d, and there was no significant damage to any of the fields. The primary impacts of the storm to date include temporarily shut-in production and cleanup and repair costs. During the third quarter of 2017, we incurred approximately $2.6 million in cleanup and repair costs related to Hurricane Harvey, and we currently estimate that additional cleanup and repair costs of approximately $4 million will be recorded to lease operating expenses during the fourth quarter of 2017. See Results of Operations – Production for further discussion of production changes.

Operating Highlights. We recognized net income of $0.4 million, or $0.00 per diluted common share, during the third quarter of 2017, compared to a net loss of $24.6 million, or $0.06 per diluted common share, during the third quarter of 2016. The primary drivers of our change in operating results between the comparative third quarters of 2017 and 2016 were the following:


•	Third quarter of 2016 results included a $75.5 million ($48.4 million net of tax) full cost pool ceiling test write-down of our oil and natural gas properties, offset in part by a $7.8 million gain on debt extinguishment.


•	Oil and natural gas revenues improved by $19.1 million, or 8%, in the third quarter of 2017, principally driven by a 10% improvement in realized oil prices, offset in part by a 2% decrease in average daily production volumes. Net realized oil price differentials improved by $1.23 per Bbl from the prior-year period.


•	Commodity derivatives expense increased by $46.5 million ($25.3 million of expense in the current-year period compared to $21.2 million of income in the prior-year period). This increase in expense was the result of losses from noncash fair value adjustments between the periods of $53.9 million, offset in part by a $7.4 million reduction in payments on derivative settlements.


•	Lease operating expenses increased by $11.2 million, or 11%, from the third quarter of 2016.

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Denbury Resources Inc.

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


•	Tax benefits of $8.6 million recognized in the current-year quarter related to enhanced oil recovery income tax credits.

We generated $65.7 million of cash flows from operating activities in the third quarter of 2017, a decrease of $30.8 million from the third quarter of 2016 levels. The decrease in cash flows from operations was due primarily to working capital changes ($2.6 million outflow during the third quarter of 2017 compared to a $34.8 million inflow during the third quarter of 2016).

Second Quarter 2017 Salt Creek Field Acquisition. On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $71.5 million (before customary closing adjustments). Salt Creek Field is an ongoing CO₂ flood, and tertiary production from the field was just over 2,200 Bbls/d, net to our interest, during the third quarter of 2017. Production from Salt Creek Field is expected to increase over the next several years with minimal capital spending. As of June 30, 2017, net to our interest, we estimated the field had proved oil reserves of approximately 17 MMBbls, including proved developed reserves of approximately 14 MMBbls.

First Quarter 2017 West Yellow Creek Field Acquisition. In March 2017, we acquired an approximate 48% non-operated working interest in West Yellow Creek Field in Mississippi for approximately $16 million (before closing adjustments). We estimate West Yellow Creek Field currently has approximately 2 MMBbls of proved oil reserves, net to our interest, but minimal production, as the operator is in the process of completing the conversion of 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 transaction, in which 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. For the first nine months of 2017, we generated cash flows from operations of $142.9 million, after giving affect to $52.4 million of negative cash flow due to working capital adjustments. We have been proactive in adjusting our capital spending in connection with the lower oil price environment over the past several years, and as discussed in the Overview above, in August 2017, we adjusted our anticipated full-year 2017 capital budget, excluding acquisitions and capitalized interest, from $300 million to $250 million. Based on our current forecasts and expected average oil prices in the mid-$50’s per Bbl for the remainder of 2017, we currently expect that our cash flow from operations would fund all but a modest amount of this development capital spending, after giving effect to interest accounted for as debt, but excluding acquisitions (see Capital Spending below for further discussion). If our cash flows from operations were to be less than our capital spending, we currently plan to fund those expenditures in the near term with incremental borrowings under our bank credit facility.

The preservation of cash and liquidity remains a significant priority for us in the current oil price environment. As of September 30, 2017, we had $495.0 million drawn on our $1.05 billion senior secured bank credit facility and $62.2 million of outstanding letters of credit, compared to $490.0 million outstanding as of June 30, 2017 and $301.0 million as of December 31, 2016. The $194.0 million increase in bank debt since December 31, 2016 is primarily due to $91.1 million of oil and natural gas property acquisitions in the first nine months of 2017, $52.4 million of cash outflows for working capital changes, and repayments of other non-bank debt of $45.7 million. Assuming oil prices remain at current levels in the mid-$50’s per Bbl for the remainder of the year, we currently expect our senior secured bank credit facility borrowings will end the year in a projected range of between $450 million and $475 million. With this level of bank borrowings, we should have around $500 million of liquidity under our bank line, which, coupled with continuing cost savings and liquidity preservation measures, should be sufficient to cover any foreseeable cash flow shortfall between our cash flows from operations and capital spending. The Company may also raise funds through asset sales or joint ventures, issuance of notes and/or equity, which would enable us to reduce our outstanding borrowings on the credit facility and further increase our available liquidity.

Since we do not expect oil prices to return in the foreseeable future to recent historical highs of 2014, we have adjusted, and continue to adjust, our business through efficiencies and cost reductions. Most recently, we completed a reduction in force in the third quarter of 2017, resulting in a reduction of approximately 15% of the Company’s workforce, principally comprised of personnel at the Company’s headquarters. With this reduction in force, coupled with other recently enacted or identified cost savings measures, we expect to exceed $50 million in cost reductions, many of which we are starting to see the benefits of now, and others that will be realized in 2018, and we continue to believe we have additional opportunities to reduce costs.

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Denbury Resources Inc.

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

In addition to reductions in our cost structure, we have reduced our debt levels over the last few years primarily through opportunistic debt exchanges and open market debt repurchases; however, given the current oil price environment we would like to achieve additional debt reductions. The flexibility in our capital structure and movements in the market price of our debt and equity securities may provide opportunities for debt refinancing or additional debt reduction over time, and we continue to explore and have discussions with bondholders from time to time regarding potential debt reduction transactions. 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, including debt for equity exchanges and/or convertible debt issuances, or future potential debt reduction with proceeds of issuances of equity, asset sales, joint ventures and other cash-generating activities. Any equity that we issue could lead to dilution of our current stockholders and affect our common stock price.

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 (as amended, the “Bank Credit Agreement”). As part of our fall 2017 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 May 2018. As of September 30, 2017, we had $495.0 million of debt outstanding and $62.2 million in letters of credit on the senior secured bank credit facility, leaving us with significant liquidity.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:


•	A consolidated senior secured debt to consolidated EBITDAX covenant, 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;


•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and


•	A requirement to maintain a current ratio of 1.0 to 1.0.

For our financial performance covenant calculations as of September 30, 2017, our ratio of consolidated senior secured debt to consolidated EBITDAX was 1.44 to 1.0 (with a maximum permitted ratio of 3.0 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 2.01 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was 2.69 to 1.0 (with 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 November 6, 2017, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our bank covenants during the foreseeable future.

Capital Spending. We currently anticipate that our full-year 2017 capital budget, excluding capitalized interest and acquisitions, will be approximately $250 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:


•	$135 million allocated for tertiary oil field expenditures;


•	$50 million allocated for other areas, primarily non-tertiary oil field expenditures;


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

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


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

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the nine months ended September 30, 2017 and 2016:



	Nine Months Ended
	September 30,
In thousands	2017		2016
Capital expenditures by project
Tertiary oil fields	$	98,797	$	90,392
Non-tertiary fields	41,023		19,142
Capitalized internal costs ⁽¹⁾	37,732		35,516
Oil and natural gas capital expenditures	177,552		145,050
CO₂ pipelines, sources and other	3,246		828
Capital expenditures, before acquisitions and capitalized interest	180,798		145,878
Acquisitions of oil and natural gas properties	91,015		10,888
Capital expenditures, before capitalized interest	271,813		156,766
Capitalized interest	22,217		18,944
Capital expenditures, total	$	294,030	$	175,710


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

For the nine months ended September 30, 2017, our capital expenditures and property acquisitions were funded with $142.9 million of cash flows from operations, with additional funds provided by borrowings on our Bank Credit Agreement. For the nine months ended September 30, 2016, our capital expenditures and property acquisitions were primarily funded with cash flows from operations, with additional funds provided by asset sales and borrowings on our Bank Credit Agreement.

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

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

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Denbury Resources Inc.

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

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 and nine months ended September 30, 2017 and 2016 are included in the following table:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-share and unit data	2017			2016			2017			2016
Operating results
Net income (loss) ⁽¹⁾	$	442		$	(24,590	)	$	36,371		$	(590,451	)
Net income (loss) per common share – basic ⁽¹⁾	0.00			(0.06		)	0.09			(1.60		)
Net income (loss) per common share – diluted ⁽¹⁾	0.00			(0.06		)	0.09			(1.60		)
Net cash provided by operating activities	65,651			96,415			142,859			159,359
Average daily production volumes
Bbls/d	58,376			59,297			58,182			62,451
Mcf/d	11,710			13,416			10,985			15,995
BOE/d ⁽²⁾	60,328			61,533			60,013			65,117
Operating revenues
Oil sales	$	256,621		$	237,053		$	768,912		$	666,441
Natural gas sales	2,409			2,877			7,176			7,960
Total oil and natural gas sales	$	259,030		$	239,930		$	776,088		$	674,401
Commodity derivative contracts ⁽³⁾
Receipt (payment) on settlements of commodity derivatives	$	89		$	(7,295	)	$	(38,618	)	$	116,958
Noncash fair value gains (losses) on commodity derivatives ⁽⁴⁾	(25,352		)	28,519			48,330			(216,769		)
Commodity derivatives income (expense)	$	(25,263	)	$	21,224		$	9,712		$	(99,811	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	47.78		$	43.45		$	48.41		$	38.95
Natural gas price per Mcf	2.24			2.33			2.39			1.82
Unit prices – including impact of derivative settlements ⁽³⁾
Oil price per Bbl	$	47.80		$	42.12		$	45.98		$	45.78
Natural gas price per Mcf	2.24			2.33			2.39			1.82
Oil and natural gas operating expenses
Lease operating expenses	$	117,768		$	106,522		$	342,926		$	308,988
Marketing expenses, net of third-party purchases, and plant operating expenses	9,706			11,225			29,758			33,707
Production and ad valorem taxes	18,418			17,983			57,548			52,201
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	46.67		$	42.38		$	47.37		$	37.80
Lease operating expenses	21.22			18.82			20.93			17.32
Marketing expenses, net of third-party purchases, and plant operating expenses	1.75			1.99			1.82			1.89
Production and ad valorem taxes	3.32			3.18			3.51			2.93
CO₂ sources – revenues and expenses
CO₂ sales and transportation fees	$	6,590		$	6,253		$	18,533		$	19,147
CO₂ discovery and operating expenses	(1,346		)	(861		)	(2,452		)	(2,539		)
CO₂ revenue and expenses, net	$	5,244		$	5,392		$	16,081		$	16,608


(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $75.5 million and $810.9 million for the three and nine months ended September 30, 2016, respectively.

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


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


(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 receipts on settlements of $0.1 million for the three months ended September 30, 2017 and payments on settlements of $38.6 million for the nine months ended September 30, 2017, compared to payments on settlements of $7.3 million for the three months ended September 30, 2016 and receipts on settlements of $117.0 million for the nine months ended September 30, 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, second, and third quarters of 2017 is shown below:



	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter
Operating Area	2016	2016	2016	2016	2017	2017	2017
Tertiary oil production
Gulf Coast region
Mature properties ⁽¹⁾	9,666	9,415	8,653	8,440	8,111	7,737	7,450
Delhi	3,971	3,996	4,262	4,387	4,991	4,965	4,619
Hastings	5,068	4,972	4,729	4,552	4,288	4,400	4,867
Heidelberg	5,346	5,246	5,000	4,924	4,730	4,996	4,927
Oyster Bayou	5,494	5,088	4,767	4,988	5,075	5,217	4,870
Tinsley	7,899	7,335	6,756	6,786	6,666	6,311	6,506
Total Gulf Coast region	37,444	36,052	34,167	34,077	33,861	33,626	33,239
Rocky Mountain region
Bell Creek	3,020	3,160	3,032	3,269	3,209	3,060	3,406
Salt Creek ⁽²⁾	—	—	—	—	—	23	2,228
Total Rocky Mountain region	3,020	3,160	3,032	3,269	3,209	3,083	5,634
Total tertiary oil production	40,464	39,212	37,199	37,346	37,070	36,709	38,873
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	673	1,017	963	745	1,342	1,004	867
Texas	6,148	4,104	4,234	5,143	4,333	5,002	4,024
Other	549	456	538	569	495	460	515
Total Gulf Coast region	7,370	5,577	5,735	6,457	6,170	6,466	5,406
Rocky Mountain region
Cedar Creek Anticline	17,778	16,325	16,017	15,186	15,067	15,124	14,535
Other	2,070	1,862	1,763	1,696	1,626	1,475	1,514
Total Rocky Mountain region	19,848	18,187	17,780	16,882	16,693	16,599	16,049
Total non-tertiary production	27,218	23,764	23,515	23,339	22,863	23,065	21,455
Total continuing production	67,682	62,976	60,714	60,685	59,933	59,774	60,328
Property sales
2016 property divestitures ⁽³⁾	1,669	1,530	819	—	—	—	—
Total production	69,351	64,506	61,533	60,685	59,933	59,774	60,328


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


(2)	Represents production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017.


(3)	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, and other minor property divestitures.

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

Total Production

Total continuing production during the third quarter of 2017 averaged 60,328 BOE/d, including 38,873 Bbls/d from tertiary properties and 21,455 BOE/d from non-tertiary properties. Total continuing production during 2016 excludes production from the Williston Assets that were sold during the third quarter of 2016 and other minor property divestitures, which production totaled 819 BOE/d during the third quarter of 2016. This total continuing production level was a slight increase of 554 BOE/d (1%) compared to second quarter of 2017 production levels of 59,774 BOE/d and represents a slight decrease of 386 BOE/d (1%) compared to third quarter of 2016 production levels. Due to conditions associated with Hurricane Harvey, the Company suspended operations and temporarily shut-in all production at its Houston area fields for an approximate 10-day period beginning August 27, 2017, representing net production of approximately 16,000 BOE/d. The impacted fields included Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel. Approximately 90% of the 16,000 BOE/d of net production shut-in had returned to production by September 6^th, and the only field that remained partially shut-in was Thompson Field. Thompson Field had net production just prior to the storm of approximately 1,000 BOE/d, nearly all of which has now been returned to production. The impact of Hurricane Harvey on third quarter 2017 production was approximately 2,000 BOE/d, and the full-year impact on 2017 production is expected to be between 500 and 700 BOE/d.

Our production during the three and nine months ended September 30, 2017 was 97% oil, slightly higher than our 96% oil production during the three and nine months ended September 30, 2016.

Tertiary Production

Oil production from our tertiary operations during the third quarter of 2017 increased 2,164 Bbls/d (6%) when comparing the second and third quarters of 2017 and increased 1,674 Bbls/d (5%) compared to the same period in 2016. The sequential and year-over-year increases in production were primarily due to the acquisition of a 23% non-operated working interest in Salt Creek Field during the second quarter of 2017, as well as the CO₂ enhanced oil recovery response from phase 5 development at Bell Creek Field and the redevelopment project at Hastings Field. The increases were slightly offset by natural production declines at our mature fields in the Gulf Coast region and the weather-related downtime at our Houston area fields resulting from Hurricane Harvey, as noted above.

Non-Tertiary Production

Continuing production from our non-tertiary operations averaged 21,455 BOE/d during the third quarter of 2017, a decrease of 1,610 BOE/d (7%) compared to the second quarter of 2017 and a decrease of 2,060 BOE/d (9%) compared to the third quarter of 2016 levels. The sequential and year-over-year decreases were primarily due to natural production declines at Cedar Creek Anticline and the weather-related downtime at our Houston area fields resulting from Hurricane Harvey, as noted above.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and nine months ended September 30, 2017 increased 8% and 15%, respectively, compared to these revenues for the same periods 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					Nine Months Ended
	September 30,					September 30,
	2017 vs. 2016					2017 vs. 2016
In thousands	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(4,700	)	(2	)%	$	(55,128	)	(8	)%
Increase in commodity prices	23,800			10	%	156,815			23	%
Total increase in oil and natural gas revenues	$	19,100		8	%	$	101,687		15	%

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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 first quarters, second quarters, third quarters and nine months ended September 30, 2017 and 2016:



	Three Months Ended																		Nine Months Ended
	March 31,						June 30,						September 30,						September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Average net realized prices:
Oil price per Bbl	$	50.31		$	30.71		$	47.16		$	43.38		$	47.78		$	43.45		$	48.41		$	38.95
Natural gas price per Mcf	2.50			1.70			2.46			1.50			2.24			2.33			2.39			1.82
Price per BOE	49.35			29.76			46.12			42.02			46.67			42.38			47.37			37.80
Average NYMEX differentials:
Oil per Bbl	$	(1.64	)	$	(3.02	)	$	(1.16	)	$	(2.18	)	$	(0.34	)	$	(1.57	)	$	(1.04	)	$	(2.51	)
Natural gas per Mcf	(0.57		)	(0.29		)	(0.69		)	(0.73		)	(0.72		)	(0.47		)	(0.67		)	(0.53		)

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. Our corporate-wide oil differential during the third quarter of 2017 was $0.34 per Bbl below NYMEX prices, which represents the best differential we have realized since the third quarter of 2013. 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 positive $0.01 per Bbl and a negative $0.77 per Bbl during the third quarters of 2017 and 2016, respectively, and a negative $0.78 per Bbl during the second quarter of 2017. 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 $2.37 per Bbl in the third quarter of 2017, an increase from the positive $1.73 per Bbl in the third quarter of 2016 and positive $1.95 per Bbl in the second quarter of 2017. During the third quarter of 2017, we sold approximately 65% 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 $0.98 per Bbl and $3.08 per Bbl below NYMEX during the third quarters of 2017 and 2016, respectively, and $1.96 per Bbl below NYMEX during the second quarter of 2017. 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 and nine months ended September 30, 2017 and 2016:



	Three Months Ended						Nine months ended
	September 30,						September 30,
In thousands	2017			2016			2017			2016
Receipt (payment) on settlements of commodity derivatives	$	89		$	(7,295	)	$	(38,618	)	$	116,958
Noncash fair value gains (losses) on commodity derivatives ⁽¹⁾	(25,352		)	28,519			48,330			(216,769		)
Total income (expense)	$	(25,263	)	$	21,224		$	9,712		$	(99,811	)

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(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

In order to provide a level of price protection to a portion of our oil production, we have entered into a combination of oil swaps, basis swaps, collars, and three-way collars for the fourth quarter of 2017 and throughout 2018. The following table summarizes our commodity derivative contracts as of November 6, 2017:



		Oct - 17	Nov - 17	Dec - 17	1H 2018	2H 2018
WTI NYMEX	Volumes Hedged (Bbls/d)	12,000	12,000	12,000	15,500	15,500
Fixed-Price Swaps	Swap Price ⁽¹⁾	$49.76	$49.76	$49.76	$50.13	$50.13
WTI NYMEX	Volumes Hedged (Bbls/d)	1,000	1,000	1,000	—	—
Collars	Ceiling Price / Floor ⁽¹⁾	$70 / $40	$70 / $40	$70 / $40	—	—
WTI NYMEX	Volumes Hedged (Bbls/d)	14,000	14,000	14,000	15,000	15,000
3-Way Collars	Ceiling Price / Floor / Sold Put Price ⁽¹⁾⁽²⁾	$65.79 / $41.07 / $31.07	$65.79 / $41.07 / $31.07	$65.79 / $41.07 / $31.07	$53.88 / $46.50 / $36.50	$53.88 / $46.50 / $36.50
Argus LLS	Volumes Hedged (Bbls/d)	1,000	1,000	1,000	—	—
3-Way Collars	Ceiling Price / Floor / Sold Put Price ⁽¹⁾⁽²⁾	$70.25 / $41 / $31	$70.25 / $41 / $31	$70.25 / $41 / $31	—	—
	Total Volumes Hedged (Bbls/d)	28,000	28,000	28,000	30,500	30,500

Argus LLS	Volumes Hedged (Bbls/d)	—	—	20,000	20,000	—
Basis Swaps⁽³⁾	Swap Price ⁽¹⁾	—	—	$4.16	$4.17	—


(1)	Averages are volume weighted.


(2)	If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and the sold put price.


(3)	The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the periods indicated.

Commodity derivative contracts in place for the fourth quarter of 2017 include swaps, basis swaps, collars and three-way collars. Based on current contracts in place and NYMEX oil futures prices as of November 6, 2017, which average in the mid-$50’s per Bbl for the remainder of 2017, limited settlements are currently expected during the fourth quarter of 2017. The details of our outstanding commodity derivative contracts at September 30, 2017, are included in Note 5, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements. Additionally, with the recent improvement in the basis differential between LLS and WTI pricing, we entered into basis swap contracts to lock-in that differential for a portion of our estimated oil production beginning December 2017 through the first half of 2018. Currently, our hedges in place for 2018 represent roughly half of our third quarter 2017 production levels. Depending on market conditions, we may continue to add to our existing 2018 hedges, and we may start to layer in hedges for 2019. 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				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2017		2016		2017		2016
Total lease operating expenses	$	117,768	$	106,522	$	342,926	$	308,988

Total lease operating expenses per BOE	$	21.22	$	18.82	$	20.93	$	17.32

Total lease operating expenses increased $11.2 million (11%) and $33.9 million (11%) on an absolute-dollar basis, or $2.40 (13%) and $3.61 (21%) on a per-BOE basis, during the three and nine months ended September 30, 2017, respectively, compared to levels in the same periods in 2016. Our lease operating expenses during the comparative third quarter periods were primarily impacted by operating expenses related to our non-operated working interest in Salt Creek Field, which was acquired on June 30, 2017, and to a lesser degree by additional expenses related to Hurricane Harvey in the third quarter of 2017 and higher CO₂ expense due to a CO₂ well workover during the third quarter of 2017. Offsetting these increases were lower expenses across various

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

categories, a portion of which is due to the downtime associated with fields impacted by Hurricane Harvey. The increase during the comparative nine-month periods was further 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. On a per-BOE basis, our lease operating expenses have been impacted given lower production due to Hurricane Harvey and the acquisition of Salt Creek Field, which has a higher operating cost than our corporate average.

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 third quarters of 2017 and 2016, approximately 55% and 57%, 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 $0.46 per Mcf during the third quarter of 2017, compared to $0.38 per Mcf during the third quarter of 2016 and the second quarter of 2017. These increases were primarily attributable to a CO₂ well workover completed during the third quarter of 2017.

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 $11.8 million and $14.5 million for the three months ended September 30, 2017 and 2016, respectively, and $39.8 million and $40.6 million for the nine months ended September 30, 2017 and 2016, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income was relatively unchanged during the three months ended September 30, 2017 compared to the same prior-year period and increased $2.9 million (5%) during the nine months ended September 30, 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						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE data and employees	2017			2016			2017			2016
Gross cash compensation and administrative costs	$	64,104		$	60,532		$	193,853		$	202,012
Gross stock-based compensation	4,252			7,034			15,684			14,159
Operator labor and overhead recovery charges	(32,211		)	(32,180		)	(96,319		)	(100,178		)
Capitalized exploration and development costs	(8,872		)	(10,743		)	(31,915		)	(34,904		)
Net G&A expense	$	27,273		$	24,643		$	81,303		$	81,089

G&A per BOE:
Net administrative costs	$	4.32		$	3.37		$	4.22		$	4.04
Net stock-based compensation	0.59			0.98			0.74			0.50
Net G&A expenses	$	4.91		$	4.35		$	4.96		$	4.54

Employees as of September 30	897			1,050

Our gross G&A expenses on an absolute-dollar basis were relatively flat during the three months ended September 30, 2017 and decreased $6.6 million (3%) during the nine months ended September 30, 2017 compared to the same periods in 2016, respectively. As part of our continued efforts to reduce overhead and operating costs, we reduced our employee headcount through

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Denbury Resources Inc.

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

involuntary workforce reductions in each of the last three years, which contributed to an overall headcount reduction of approximately 40% from year-end 2014 levels. The severance-related payments associated with the workforce reductions were approximately $6.8 million for 2017, recognized in the third quarter of 2017, and $9.3 million for 2016, recognized in the first quarter of 2016. The nine-month period ended September 30, 2017 was further impacted by lower professional services fees, partially offset by compensation associated with the retirement of our chief executive officer.

Net G&A expense on a per-BOE basis increased 13% and 9% during the three and nine months ended September 30, 2017, respectively, compared to levels in the same periods in 2016 due to lower capitalized exploration and development costs and lower production volumes during the 2017 periods, partially offset by the items previously mentioned impacting gross G&A. The three-month period was further impacted by the severance-related payments noted above.

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.

Interest and Financing Expenses



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE data and interest rates	2017			2016			2017			2016
Cash interest ⁽¹⁾	$	45,110		$	42,718		$	130,962		$	130,511
Less: interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes ⁽¹⁾	(12,604		)	(12,533		)	(37,761		)	(19,569		)
Noncash interest expense	1,456			1,468			4,801			11,009
Less: capitalized interest	(9,416		)	(6,875		)	(22,217		)	(18,944		)
Interest expense, net	$	24,546		$	24,778		$	75,785		$	103,007
Interest expense, net per BOE	$	4.42		$	4.38		$	4.63		$	5.77
Average debt principal outstanding	$	2,971,205		$	2,798,660		$	2,887,010		$	3,042,807
Average interest rate ⁽²⁾	6.1		%	6.1		%	6.0		%	5.7		%

(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 in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors.


(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 September 30, 2017 increased $2.4 million (6%) when compared to the prior-year period due primarily to a higher average interest rate and higher borrowings on our senior secured bank credit facility during the 2017 period. Interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes increased during the nine months ended September 30, 2017 when compared to the 2016 period, as the exchange transactions were completed during May 2016; therefore, the 2016 period does not include a full year of future interest on the 2021 Senior Secured Notes. Noncash interest expense during the nine months ended September 30, 2017 decreased when compared to the same prior-year period primarily due to the 2016 period including a $5.5 million write-off of debt issuance costs. Capitalized interest during the three and nine months ended September 30, 2017 increased $2.5 million (37%) and $3.3 million (17%), respectively, compared to the same periods in 2016, primarily due to an increase in the number of projects that qualify for interest capitalization.

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Denbury Resources Inc.

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

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2017		2016		2017		2016
Oil and natural gas properties	$	29,990	$	29,353	$	86,973	$	120,174
CO₂ properties, pipelines, plants and other property and equipment	22,111		25,659		67,475		78,745
Total DD&A	$	52,101	$	55,012	$	154,448	$	198,919

DD&A per BOE:
Oil and natural gas properties	$	5.40	$	5.24	$	5.31	$	6.79
CO₂properties, pipelines, plants and other property and equipment	3.99		4.48		4.12		4.36
Total DD&A cost per BOE	$	9.39	$	9.72	$	9.43	$	11.15

Write-down of oil and natural gas properties	$	—	$	75,521	$	—	$	810,921

The decrease in our oil and natural gas properties depletion during the nine months ended September 30, 2017 when compared to the same period in 2016 was 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 2017 when compared to production in the 2016 period.

The decrease in depletion and depreciation of our CO₂properties, pipelines, plants and other property and equipment 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.

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 full cost pool ceiling test write-downs of $75.5 million, $479.4 million and $256.0 million during the three months ended September 30, June 30 and March 31, 2016, respectively. We have not recorded a full cost pool ceiling test write-down during the first nine months of 2017.

Income Taxes



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE amounts and tax rates	2017			2016			2017			2016
Current income tax expense (benefit)	$	1,072		$	(1,046	)	$	(18,828	)	$	(1,051	)
Deferred income tax expense (benefit)	(15,301		)	(13,519		)	35,846			(331,574		)
Total income tax expense (benefit)	$	(14,229	)	$	(14,565	)	$	17,018		$	(332,625	)
Average income tax benefit per BOE	$	(2.57	)	$	(2.57	)	$	1.04		$	(18.64	)
Effective tax rate	103.2		%	37.2		%	31.9		%	36.0		%
Total net deferred tax liability	$	329,724		$	505,689

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Denbury Resources Inc.

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

The current income tax benefit for the nine months ended September 30, 2017, represents the estimated receivable associated with tax planning strategies that will allow us to recover alternative minimum tax credits. The deferred income tax benefits during the three and nine months ended September 30, 2016, were primarily due to the impact of the write-down of our oil and natural gas properties during the periods.

As of September 30, 2017, we had an estimated $49.2 million of enhanced oil recovery credits to carry forward related to our tertiary operations, $21.6 million of research and development credits, and $20.3 million of alternative minimum tax credits (net of $12.0 million and $8.8 million related to the estimated credits applied, and to be applied to our 2016 and 2017 tax returns, respectively) 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 2024 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						Nine Months Ended
	September 30,						September 30,
Per-BOE data	2017			2016			2017			2016
Oil and natural gas revenues	$	46.67		$	42.38		$	47.37		$	37.80
Receipt (payment) on settlements of commodity derivatives	0.02			(1.29		)	(2.36		)	6.55
Lease operating expenses	(21.22		)	(18.82		)	(20.93		)	(17.32		)
Production and ad valorem taxes	(3.32		)	(3.18		)	(3.51		)	(2.93		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.75		)	(1.99		)	(1.82		)	(1.89		)
Production netback	20.40			17.10			18.75			22.21
CO₂ sales, net of operating and exploration expenses	0.95			0.95			0.98			0.93
General and administrative expenses	(4.91		)	(4.35		)	(4.96		)	(4.54		)
Interest expense, net	(4.42		)	(4.38		)	(4.63		)	(5.77		)
Other	0.27			1.56			1.78			(0.98		)
Changes in assets and liabilities relating to operations	(0.46		)	6.15			(3.20		)	(2.92		)
Cash flows from operations	11.83			17.03			8.72			8.93
DD&A	(9.39		)	(9.72		)	(9.43		)	(11.15		)
Write-down of oil and natural gas properties	—			(13.34		)	—			(45.45		)
Deferred income taxes	2.76			2.39			(2.19		)	18.58
Gain on debt extinguishment	—			1.38			—			6.45
Noncash fair value gains (losses) on commodity derivatives ⁽¹⁾	(4.57		)	5.04			2.95			(12.14		)
Other noncash items	(0.55		)	(7.12		)	2.17			1.69
Net income (loss)	$	0.08		$	(4.34	)	$	2.22		$	(33.09	)

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


(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.

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, closing of proposed asset sales or the timing or proceeds thereof, estimated timing of commencement of CO₂ flooding of particular fields or areas, likelihood 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; accuracy of our cost estimates; availability of credit in the commercial banking market; 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, forest fires, or other natural occurrences; 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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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 September 30, 2017, we had $495.0 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 we 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 September 30, 2017:



In thousands	2017		2019		2021		2022		2023		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 4.3% at September 30, 2017)	$	—	$	495,000	$	—	$	—	$	—	$	495,000	$	495,000
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	—		—		614,919		—		—		614,919		600,345
6⅜% Senior Subordinated Notes due 2021	—		—		215,144		—		—		215,144		128,828
5½% Senior Subordinated Notes due 2022	—		—		—		772,912		—		772,912		440,328
4⅝% Senior Subordinated Notes due 2023	—		—		—		—		622,297		622,297		329,817
Other Subordinated Notes	2,250		—		—		—		—		2,250		2,250

See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil 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, fixed-price swaps enhanced with a sold put, and basis swaps. 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 2018 using both NYMEX and LLS fixed-price swaps, collars and three-way collars. Additionally, with the recent improvement in the basis differential between LLS and WTI pricing, we entered into basis swap contracts to lock-in that differential for a portion of our estimated oil production beginning December 2017 through the first half of 2018. Currently, our hedges in place for 2018 represent roughly half of our third quarter 2017 production levels. Depending on market conditions, we may continue to add to our existing 2018 hedges, and we may start to layer in hedges for 2019. See also Note 5, Commodity Derivative Contracts, and Note 6, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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

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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 instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

At September 30, 2017, our commodity derivative contracts were recorded at their fair value, which was a net liability of $20.9 million, a $25.3 million decrease from the $4.4 million net asset recorded at June 30, 2017, and a $48.4 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 and nine months ended September 30, 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 September 30, 2017.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of September 30, 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 September 30, 2017	$	(12,685	)
10% increase in prices	(66,466		)
10% decrease in prices	25,696

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 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 September 30, 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 third 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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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.

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 27, 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 third 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⁾
July 2017	926,368	$	1.52	—	$	210.1
August 2017	6,085	1.16		—	210.1
September 2017	44,576	1.10		—	210.1
Total	977,029			—


(1)	Shares purchased during the third quarter of 2017 were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted 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 industry 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
4(a)*		Second Supplemental Indenture for 6⅜% Senior Subordinated Notes due 2021, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(b)*		Second Supplemental Indenture for 4⅝% Senior Subordinated Notes due 2023, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(c)*		Second Supplemental Indenture for 5½% Senior Subordinated Notes due 2022, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(d)*		First Supplemental Indenture for 9% Senior Secured Second Lien Notes due 2021, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee and Collateral Trustee.
10(a)*		Form of Indemnification Agreement, dated as of September 1, 2017, by and between Denbury Resources Inc. and its officers and directors.
10(b)*		Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2017, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
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.

November 7, 2017		/s/ Mark C. Allen
		Mark C. Allen Executive Vice President and Chief Financial Officer

November 7, 2017		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

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INDEX TO EXHIBITS



Exhibit No.		Exhibit
4(a)		Second Supplemental Indenture for 6⅜% Senior Subordinated Notes due 2021, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(b)		Second Supplemental Indenture for 4⅝% Senior Subordinated Notes due 2023, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(c)		Second Supplemental Indenture for 5½% Senior Subordinated Notes due 2022, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(d)		First Supplemental Indenture for 9% Senior Secured Second Lien Notes due 2021, dated as of September 8, 2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee and Collateral Trustee.
10(a)		Form of Indemnification Agreement, dated as of September 1, 2017, by and between Denbury Resources Inc. and its officers and directors.
10(b)		Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2017, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
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.