UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☑   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2019

OR

☐   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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class:	Trading Symbol:	Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value	DNR	New York Stock Exchange

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 ☑  No ☐

Indicate by check mark whether the registrant has submitted electronically 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 ☑  No ☐

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	☑	Accelerated filer	☐	Non-accelerated filer	☐	Smaller reporting company	☐	Emerging growth company	☐
				(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. ☐

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of October 31, 2019, was 483,262,340.

Denbury Resources Inc.

Table of Contents

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018	3
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018	5
	Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Nine Months Ended September 30, 2019 and 2018	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	40
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
	Signatures	45

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

	September 30,			December 31,
	2019			2018
Assets
Current assets
Cash and cash equivalents	$	514		$	38,560
Accrued production receivable	127,216			125,788
Trade and other receivables, net	27,949			26,970
Derivative assets	55,615			93,080
Other current assets	11,491			11,896
Total current assets	222,785			296,294
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	11,315,866			11,072,209
Unevaluated properties	942,859			996,700
CO2 properties	1,199,339			1,196,795
Pipelines and plants	2,327,671			2,302,817
Other property and equipment	215,794			250,279
Less accumulated depletion, depreciation, amortization and impairment	(11,629,245		)	(11,500,190		)
Net property and equipment	4,372,284			4,318,610
Operating lease right-of-use assets	35,145			—
Derivative assets	11,483			4,195
Other assets	112,013			104,123
Total assets	$	4,753,710		$	4,723,222
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	159,256		$	198,380
Oil and gas production payable	58,881			61,288
Current maturities of long-term debt (including future interest payable of $85,909 and $85,303, respectively – see Note 4)	100,626			105,125
Operating lease liabilities	6,710			—
Total current liabilities	325,473			364,793
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $104,501 and $164,914, respectively – see Note 4)	2,409,683			2,664,211
Asset retirement obligations	175,716			174,470
Deferred tax liabilities, net	400,213			309,758
Operating lease liabilities	43,704			—
Other liabilities	52,801			68,213
Total long-term liabilities	3,082,117			3,216,652
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, 750,000,000 shares authorized; 473,213,227 and 462,355,725 shares issued, respectively	473			462
Paid-in capital in excess of par	2,698,158			2,685,211
Accumulated deficit	(1,339,232		)	(1,533,112		)
Treasury stock, at cost, 3,620,785 and 1,941,749 shares, respectively	(13,279		)	(10,784		)
Total stockholders’ equity	1,346,120			1,141,777
Total liabilities and stockholders’ equity	$	4,753,710		$	4,723,222

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
Revenues and other income
Oil, natural gas, and related product sales	$	293,192		$	379,628	$	918,190		$	1,095,214
CO2 sales and transportation fees	8,976			8,149		25,532			22,416
Purchased oil sales	5,468			265		8,274			1,668
Other income	7,817			6,931		12,274			15,972
Total revenues and other income	315,453			394,973		964,270			1,135,270
Expenses
Lease operating expenses	117,850			122,527		361,205			361,267
Transportation and marketing expenses	10,067			11,116		32,076			31,671
CO2 discovery and operating expenses	879			708		2,016			1,670
Taxes other than income	22,010			27,344		71,312			81,897
Purchased oil expenses	5,436			264		8,213			1,426
General and administrative expenses	18,266			21,579		54,697			61,223
Interest, net of amounts capitalized of $8,773, $9,514, $27,545 and $26,817, respectively	22,858			18,527		60,672			51,974
Depletion, depreciation, and amortization	55,064			51,316		170,625			156,711
Commodity derivatives expense (income)	(43,155		)	44,577		15,462			189,601
Gain on debt extinguishment	(5,874		)	—		(106,220		)	—
Other expenses	2,140			2,980		8,664			10,544
Total expenses	205,541			300,938		678,722			947,984
Income before income taxes	109,912			94,035		285,548			187,286
Income tax provision	37,050			15,616		91,668			39,067
Net income	$	72,862		$	78,419	$	193,880		$	148,219
Net income per common share
Basic	$	0.16		$	0.17	$	0.43		$	0.35
Diluted	$	0.14		$	0.17	$	0.41		$	0.33
Weighted average common shares outstanding
Basic	455,487			451,256		453,287			426,036
Diluted	547,205			458,450		490,054			455,934

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities
Net income	$	193,880		$	148,219
Adjustments to reconcile net income to cash flows from operating activities
Depletion, depreciation, and amortization	170,625			156,711
Deferred income taxes	90,454			42,741
Stock-based compensation	9,866			8,711
Commodity derivatives expense	15,462			189,601
Receipt (payment) on settlements of commodity derivatives	14,714			(149,738		)
Gain on debt extinguishment	(106,220		)	—
Debt issuance costs and discounts	7,607			4,980
Other, net	(6,862		)	(7,066		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(1,428		)	(17,140		)
Trade and other receivables	(147		)	139
Other current and long-term assets	27			(4,467		)
Accounts payable and accrued liabilities	(33,167		)	27,435
Oil and natural gas production payable	(1,819		)	(3,764		)
Other liabilities	(9,414		)	(2,832		)
Net cash provided by operating activities	343,578			393,530
Cash flows from investing activities
Oil and natural gas capital expenditures	(204,904		)	(210,504		)
Pipelines and plants capital expenditures	(25,965		)	(19,134		)
Net proceeds from sales of oil and natural gas properties and equipment	10,494			7,308
Other	5,797			5,598
Net cash used in investing activities	(214,578		)	(216,732		)
Cash flows from financing activities
Bank repayments	(641,000		)	(1,943,653		)
Bank borrowings	691,000			1,468,653
Proceeds from issuance of senior secured notes	—			450,000
Interest payments treated as a reduction of debt	(59,808		)	(37,233		)
Cash paid in conjunction with debt exchange	(125,268		)	—
Costs of debt financing	(11,017		)	(15,933		)
Pipeline financing and capital lease debt repayments	(10,279		)	(18,353		)
Other	5,470			(13,288		)
Net cash used in financing activities	(150,902		)	(109,807		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(21,902		)	66,991
Cash, cash equivalents, and restricted cash at beginning of period	54,949			15,992
Cash, cash equivalents, and restricted cash at end of period	$	33,047		$	82,983

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)

	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares	Amount								Shares	Amount			Total Equity
Balance – December 31, 2018	462,355,725	$	462	$	2,685,211		$	(1,533,112	)	1,941,749	$	(10,784	)	$	1,141,777
Issued or purchased pursuant to stock compensation plans	1,331,050	2		—			—			—	—			2
Issued pursuant to directors’ compensation plan	41,487	—		—			—			—	—			—
Stock-based compensation	—	—		4,306			—			—	—			4,306
Tax withholding – stock compensation	—	—		—			—			531,494	(1,091		)	(1,091		)
Net loss	—	—		—			(25,674		)	—	—			(25,674		)
Balance – March 31, 2019	463,728,262	464		2,689,517			(1,558,786		)	2,473,243	(11,875		)	1,119,320
Issued or purchased pursuant to stock compensation plans	400,850	—		—			—			—	—			—
Issued pursuant to directors’ compensation plan	37,367	—		—			—			—	—			—
Stock-based compensation	—	—		4,667			—			—	—			4,667
Tax withholding – stock compensation	—	—		—			—			1,661	(3		)	(3		)
Net income	—	—		—			146,692			—	—			146,692
Balance – June 30, 2019	464,166,479	464		2,694,184			(1,412,094		)	2,474,904	(11,878		)	1,270,676
Issued or purchased pursuant to stock compensation plans	9,046,748	9		(9		)	—			—	—			—
Stock-based compensation	—	—		3,983			—			—	—			3,983
Tax withholding – stock compensation	—	—		—			—			1,145,881	(1,401		)	(1,401		)
Net income	—	—		—			72,862			—	—			72,862
Balance – September 30, 2019	473,213,227	$	473	$	2,698,158		$	(1,339,232	)	3,620,785	$	(13,279	)	$	1,346,120

	Common Stock ($.001 Par Value)				Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares		Amount								Shares	Amount			Total Equity
Balance – December 31, 2017	402,549,346		$	403	$	2,507,828		$	(1,855,810	)	457,041	$	(4,256	)	$	648,165
Issued or purchased pursuant to stock compensation plans	378,595		—		—			—			—	—			—
Stock-based compensation	—		—		3,303			—			—	—			3,303
Tax withholding – stock compensation	—		—		—			—			330,826	(828		)	(828		)
Net income	—		—		—			39,578			—	—			39,578
Balance – March 31, 2018	402,927,941		403		2,511,131			(1,816,232		)	787,867	(5,084		)	690,218
Issued or purchased pursuant to stock compensation plans	36,437		—		—			—			—	—			—
Issued pursuant to notes conversion	55,249,999		55		161,995			—			—	—			162,050
Stock-based compensation	—		—		3,226			—			—	—			3,226
Tax withholding – stock compensation	—		—		—			—			18,451	(71		)	(71		)
Net income	—		—		—			30,222			—	—			30,222
Balance – June 30, 2018	458,214,377		458		2,676,352			(1,786,010		)	806,318	(5,155		)	885,645
Issued or purchased pursuant to stock compensation plans	4,248,522		4		(4		)	—			—	—			—
Issued pursuant to notes conversion	(44	)	—		(46		)	—			—	—			(46		)
Stock-based compensation	—		—		4,597			—			—	—			4,597
Tax withholding – stock compensation	—		—		—			—			1,087,564	(5,431		)	(5,431		)
Net income	—		—		—			78,419			—	—			78,419
Balance – September 30, 2018	462,462,855		$	462	$	2,680,899		$	(1,707,591	)	1,893,882	$	(10,586	)	$	963,184

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

6

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, 2018 (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, 2019, our consolidated results of operations for the three and nine months ended September 30, 2019 and 2018, our consolidated cash flows for the nine months ended September 30, 2019 and 2018, and our consolidated statements of changes in stockholders’ equity for the three and nine months ended September 30, 2019 and 2018.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018, “Purchased oil sales” is a new line item and includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from “Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant operating expenses, which were reclassified to “Other expenses,” and also purchases of oil from third-parties. Such reclassifications had no impact on our reported total revenues, expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:

In thousands	September 30, 2019		December 31, 2018
Cash and cash equivalents	$	514	$	38,560
Restricted cash included in other assets	32,533		16,389
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	33,047	$	54,949

Amounts included in restricted cash included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations.

7

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Net Income per Common Share

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income 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, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible.

The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating the basic and diluted net income per common share for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands	2019		2018		2019		2018
Numerator
Net income – basic	$	72,862	$	78,419	$	193,880	$	148,219
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	5,101		—		5,649		538
Net income – diluted	$	77,963	$	78,419	$	199,529	$	148,757
Denominator
Weighted average common shares outstanding – basic	455,487		451,256		453,287		426,036
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	865		7,194		2,489		6,983
Convertible senior notes(1)	90,853		—		34,278		22,915
Weighted average common shares outstanding – diluted	547,205		458,450		490,054		455,934

(1) For the nine months ended September 30, 2019, shares shown under “convertible senior notes” represent proration of the impact over the period of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 4, Long-Term Debt – 2019 Debt Reduction Transactions).

Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2019 and 2018, 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, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of the 2018 and 2019 periods.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
In thousands	2019	2018	2019	2018
Stock appreciation rights	2,011	2,689	2,043	2,824
Restricted stock and performance-based equity awards	7,996	—	5,859	203

8

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Recent Accounting Pronouncements

Recently Adopted

Leases. Effective January 1, 2019, we adopted Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”), and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842, using the modified retrospective method with an application date of January 1, 2019. ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. We elected the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow entities to recognize leases with terms of one year or less in their statement of operations, allow lease and non-lease components to be combined, and carry forward our accounting treatment for existing land easement agreements. The adoption of the new standards resulted in the recognition of $39.1 million of lease assets and $55.8 million of lease liabilities ($16.7 million of which related to previously-existing lease obligations) as of January 1, 2019, in our Unaudited Condensed Consolidated Balance Sheets, but did not materially impact our results of operations and had no impact on our cash flows. The additional lease assets and liabilities recorded on our balance sheet primarily related to our operating leases for office space, as the accounting for our financing leases and pipeline financings was relatively unchanged.

Not Yet Adopted

Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. Management is currently assessing the impact the adoption of ASU 2016-13 will have on our consolidated financial statements.

Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. The adoption of ASU 2018-13 is currently not expected to have a material effect on our consolidated financial statements, but may require enhanced footnote disclosures.

Note 2. Revenue Recognition

We record revenue in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO₂ contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets, which was $127.2 million and $125.8 million as of September 30, 2019 and December 31, 2018, respectively. The Company enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

9

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of Revenue

The following table summarizes our revenues by product type for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands	2019		2018		2019		2018
Oil sales	$	292,100	$	377,329	$	912,636	$	1,088,021
Natural gas sales	1,092		2,299		5,554		7,193
CO2 sales and transportation fees	8,976		8,149		25,532		22,416
Purchased oil sales	5,468		265		8,274		1,668
Total revenues	$	307,636	$	388,042	$	951,996	$	1,119,298

Note 3. Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Leases with a term of 12 months or less are not recorded on our balance sheet. During the third quarter of 2019, we exercised the early buyout option on our remaining finance leases. The table below reflects our operating lease assets and liabilities, which primarily consists of our office leases, and finance lease assets and liabilities:

	September 30,
In thousands	2019
Operating leases
Operating lease right-of-use assets	$	35,145
Operating lease liabilities - current	$	6,710
Operating lease liabilities - long-term	43,704
Total operating lease liabilities	$	50,414
Finance leases
Other property and equipment	$	—
Accumulated depreciation	—
Other property and equipment, net	$	—
Current maturities of long-term debt	$	—
Long-term debt, net of current portion	—
Total finance lease liabilities	$	—

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The majority of our leases contain renewal options, typically exercisable at our sole discretion. We record right-of-use assets and liabilities based on the present value of lease payments over the initial lease term, unless the option to extend the lease is reasonably certain, and utilize our incremental borrowing rate based on information available at the lease commencement date. The following weighted average remaining lease terms and discount rates related to our outstanding leases:

	September 30,
	2019
Weighted Average Remaining Lease Term
Operating leases	6.0 years
Finance leases	0 years
Weighted Average Discount Rate
Operating leases	6.8	%
Finance leases	—	%

Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. We have subleased part of the office space included in our operating leases for which we receive rental payments. The following table summarizes the components of lease costs and sublease income:

		Three Months Ended		Nine Months Ended
In thousands	Income Statement Presentation	September 30, 2019		September 30, 2019
Operating lease cost	General and administrative expenses	$	1,187	$	6,014
Finance lease cost
Amortization of right-of-use assets	Depletion, depreciation, and amortization	$	54	$	1,188
Interest on lease liabilities	Interest expense	2		40
Total finance lease cost		$	56	$	1,228
Sublease income	General and administrative expenses	$	964	$	3,331

Our statement of cash flows included the following activity related to our operating and finance leases:

	Nine Months Ended
In thousands	September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	7,335
Operating cash flows from interest on finance leases	40
Financing cash flows from finance leases	1,275
Right-of-use assets obtained in exchange for lease obligations
Operating leases	307
Finance leases	—

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes by year the maturities of our minimum lease payments as of September 30, 2019:

	Operating			Finance
In thousands	Leases			Leases
2019	$	2,479		$	—
2020	9,874			—
2021	10,042			—
2022	10,260			—
2023	10,300			—
Thereafter	18,604			—
Total minimum lease payments	61,559			—
Less: Amount representing interest	(11,145		)	—
Present value of minimum lease payments	$	50,414		$	—

The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted for under previous accounting guidance under FASC Topic 840, Leases, as of December 31, 2018:

	Operating
In thousands	Leases
2019	$	10,690
2020	9,776
2021	10,007
2022	10,223
2023	10,262
Thereafter	18,169
Total minimum lease payments	$	69,127

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 4. Long-Term Debt

The table below reflects long-term debt and capital lease obligations outstanding as of the dates indicated:

	September 30,			December 31,
In thousands	2019			2018
Senior Secured Bank Credit Agreement	$	50,000		$	—
9% Senior Secured Second Lien Notes due 2021	614,919			614,919
9¼% Senior Secured Second Lien Notes due 2022	455,668			455,668
7¾% Senior Secured Second Lien Notes due 2024	531,821			—
7½% Senior Secured Second Lien Notes due 2024	20,641			450,000
6⅜% Convertible Senior Notes due 2024	245,548			—
6⅜% Senior Subordinated Notes due 2021	51,304			203,545
5½% Senior Subordinated Notes due 2022	83,736			314,662
4⅝% Senior Subordinated Notes due 2023	211,695			307,978
Pipeline financings	171,067			180,073
Capital lease obligations	—			5,362
Total debt principal balance	2,436,399			2,532,207
Debt discount(1)	(105,426		)	—
Future interest payable(2)	190,410			250,218
Debt issuance costs	(11,074		)	(13,089		)
Total debt, net of debt issuance costs and discount	2,510,309			2,769,336
Less: current maturities of long-term debt(3)	(100,626		)	(105,125		)
Long-term debt and capital lease obligations	$	2,409,683		$	2,664,211

(1) Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $28.2 million and $77.2 million, respectively (see 2019 Debt Reduction Transactions below) as of September 30, 2019.

(2) Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors.

(3) Our current maturities of long-term debt as of September 30, 2019 include $85.9 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

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

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”), which has been amended periodically since that time. The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 (the “6⅜% Senior Subordinated Notes”), respectively, are not repaid or refinanced by each of their respective maturity dates. As part of our fall 2019 semiannual redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $615 million, with the next such redetermination being scheduled for May 2020. 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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

weighted average interest rate on borrowings under the Bank Credit Agreement was 4.7% as of September 30, 2019. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

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

• A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020, and 4.50 to 1.0 thereafter;

• A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. 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.

As of September 30, 2019, we were in compliance with all debt covenants under the Bank Credit Agreement. The above description of our Bank Credit Agreement and defined terms are contained in the Bank Credit Agreement and the amendments thereto.

2019 Debt Reduction Transactions

During the third quarter of 2019, we repurchased $11.0 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes due 2022 (the “5½% Senior Subordinated Notes”) in open market transactions for a total purchase price of $5.3 million, excluding accrued interest. In connection with these transactions, we recognized a $5.7 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the three and nine months ended September 30, 2019. Additionally, during October 2019, we repurchased principally through exchanges an additional $13.5 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes and $29.3 million in aggregate principal amount of our then outstanding 4⅝% Senior Subordinated Notes due 2023 (the “4⅝% Senior Subordinated Notes”) for $5.9 million in cash and issuance of 13.7 million shares of the Company’s common stock.

During June 2019, in a series of debt exchanges, we extended the maturities of our outstanding long-term debt and reduced the amount of our outstanding debt principal. As part of these transactions, holders exchanged a total of $468.4 million aggregate principal amount of our then outstanding senior subordinated notes for $102.6 million aggregate principal amount of new 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of new 2024 Convertible Senior Notes and $120.0 million of cash. The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of our 6⅜% Senior Subordinated Notes, $219.9 million aggregate principal amount of our 5½% Senior Subordinated Notes and $96.3 million aggregate principal amount of our 4⅝% Senior Subordinated Notes. In addition, holders also exchanged $425.4 million of 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes. In July 2019, holders exchanged an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. As a result, we recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $0.2 million and $100.5 million for the three and nine months ended September 30, 2019, in our Unaudited Condensed Consolidated Statements of Operations.

In accordance with FASC 470-50, Modifications and Extinguishments, the June 2019 exchange of our existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively. These debt discounts will be amortized as interest expense over the terms of these notes.

Separately, the June 2019 exchange of our existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the new 7¾% Senior Secured Notes, which discount will be amortized as interest expense over the term of these notes.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

7¾% Senior Secured Second Lien Notes due 2024

As part of the notes exchanges discussed above, in June 2019 we issued $528.0 million of 7¾% Senior Secured Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes and existing 7½% Senior Secured Notes (see 2019 Debt Reduction Transactions above). The 7¾% Senior Secured Notes, which carry a stated interest rate of 7.75% per annum, were recorded at approximately 94% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments, which equates to an effective yield to maturity of approximately 9.39%. In July 2019, we issued an additional $3.8 million of 7¾% Senior Secured Notes in exchange for $4.0 million of 7½% Senior Secured Notes, which were recorded at par. Interest on the 7¾% Senior Secured Notes is payable semiannually in arrears on February 15 and August 15 of each year, and mature on February 15, 2024. We may redeem the 7¾% Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.875% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7¾% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7¾% Senior Secured Notes at a price of 107.75% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7¾% Senior Secured Notes are not subject to any sinking fund requirements.

The 7¾% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

6⅜% Convertible Senior Notes due 2024

As part of the notes exchanges discussed above, in June 2019 we issued $245.5 million of 2024 Convertible Senior Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes (see 2019 Debt Reduction Transactions above). The 2024 Convertible Senior Notes, which carry a stated interest rate of 6.375% per annum, were recorded at approximately 67% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments, which equates to an effective yield to maturity of approximately 15.31%. Interest on the 2024 Convertible Senior Notes is payable semiannually in arrears on June 30 and December 30 of each year, beginning in December 2019, and mature on December 31, 2024. We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity. The 2024 Convertible Senior Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 370 shares of common stock per $1,000 principal amount of 2024 Convertible Senior Notes, which is equivalent to approximately 90.9 million shares of the Company’s common stock, subject to customary adjustments to the conversion rate and threshold price with respect to, among other things, stock dividends and distributions, mergers and reclassifications. The 2024 Convertible Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which is $2.43 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. Additionally, the Company may, based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to certain limitations, increase the conversion rate. Any such conversion rate increase would cause a proportional decrease in the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion into common stock at a lower price.

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.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2019, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of September 30, 2019, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range(1)				Weighted Average Price
							Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2019 Fixed-Price Swaps
Oct – Dec	NYMEX	2,000	$	60.00	–	61.20	$	60.60	$	—	$	—	$	—
Oct – Dec	Argus LLS	13,000		60.00	–	74.90	64.69		—		—		—
2019 Three-Way Collars(2)
Oct – Dec	NYMEX	23,000	$	55.00	–	75.45	$	—	$	48.57	$	56.61	$	69.04
Oct – Dec	Argus LLS	5,500		62.00	–	86.00	—		54.73		63.09		79.93
2020 Fixed-Price Swaps
Jan – Dec	NYMEX	2,000	$	60.00	–	61.00	$	60.59	$	—	$	—	$	—
Jan – Dec	Argus LLS	4,500		60.72	–	64.26	62.29		—		—		—
2020 Three-Way Collars(2)
Jan – June	NYMEX	16,000	$	55.00	–	82.65	$	—	$	48.17	$	57.62	$	64.19
Jan – June	Argus LLS	6,000		61.00	–	87.10	—		53.42		63.19		71.16
July – Dec	NYMEX	14,000		55.00	–	82.65	—		48.18		57.56		64.17
July – Dec	Argus LLS	4,000		61.00	–	87.10	—		53.50		63.16		72.99

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

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

Note 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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

• Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of September 30, 2019, 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 $230 thousand in the fair value of these instruments as of September 30, 2019.

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, 2019
Assets
Oil derivative contracts – current	$	—	$	46,099	$	9,516	$	55,615
Oil derivative contracts – long-term	—		9,799		1,684		11,483
Total Assets	$	—	$	55,898	$	11,200	$	67,098
December 31, 2018
Assets
Oil derivative contracts – current	$	—	$	81,621	$	11,459	$	93,080
Oil derivative contracts – long-term	—		2,030		2,165		4,195
Total Assets	$	—	$	83,651	$	13,624	$	97,275

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, 2019 and 2018:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands	2019			2018			2019			2018
Fair value of Level 3 instruments, beginning of period	$	6,073		$	(1,168	)	$	13,624		$	—
Fair value gains (losses) on commodity derivatives	6,450			(5,244		)	90			(6,412		)
Receipts on settlements of commodity derivatives	(1,323		)	—			(2,514		)	—
Fair value of Level 3 instruments, end of period	$	11,200		$	(6,412	)	$	11,200		$	(6,412	)
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	$	6,234		$	(5,244	)	$	6,540		$	(6,412	)

We utilize an income approach to value our Level 3 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 9/30/2019 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	11,200	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2019	22.6% – 41.3%

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 senior secured second lien notes, convertible senior 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, 2019 and December 31, 2018, excluding pipeline financing and capital lease obligations, was $1,768.0 million and $1,886.1 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury Notes, 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

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.  We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract.

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017) when the Company’s performance was not excused as provided in the contract. The Company has filed a notice of appeal of the trial court’s ruling to the Wyoming Supreme Court, the results and timing of which cannot be currently predicted.

The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions in the helium supply contract. The Company intends to continue to vigorously defend its position and pursue all of its rights.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract (including $14.2 million of liquidated damages for the contract years ending July 31, 2018 and July 31, 2019) plus $4.7 million of associated costs (through September 30, 2019), for a total of $50.7 million, included in “Other liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019.

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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, 2018 (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. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, and capital allocation and budgeting decisions. The table below outlines changes in our realized oil prices, before and after commodity hedging impacts, which shows that our net realized oil price after hedges has been within a range of roughly $59 and $62 per barrel for our most recent comparative periods:

	Three Months Ended						Nine Months Ended
	September 30, 2019		June 30, 2019		September 30, 2018		September 30,
							2019		2018
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	57.64	$	62.22	$	71.44	$	58.82	$	67.99
Oil price per Bbl - including impact of derivative settlements	59.23		61.92		59.78		59.77		58.63

With our continued focus on improving the Company’s financial position and preserving liquidity, we have based our 2019 budget on a flat $50 oil price, and our 2019 capital spending has been budgeted in a range of $240 million to $260 million, excluding capitalized interest and acquisitions. Based on our results for the first nine months of the year and our projections for the remainder of 2019, we estimate that our cash flow from operations will be significantly higher than our capital expenditures and result in Denbury generating significant excess cash flow during 2019. Also, during the third quarter we entered into additional oil commodity hedges for the fourth quarter of 2019 in order to provide a greater level of certainty in our 2019 cash flow. Additional information concerning our 2019 budget and plans is included below under Capital Resources and Liquidity – Overview.

Comparative Financial Results and Highlights. We recognized net income of $72.9 million, or $0.14 per diluted common share, during the third quarter of 2019, compared to net income of $78.4 million, or $0.17 per diluted common share, during the third quarter of 2018, with the slightly lower results generally reflective of lower oil and natural gas production levels and slightly lower oil prices, including the impact of our hedges. Additional details regarding the comparative period changes in our operating results and per diluted share amounts were the following:

• Realized oil prices, including the impact of derivative settlements, decreased by $0.55 per Bbl, or 1%, compared to the prior-year period. See Results of Operations – Oil and Natural Gas Revenues.

• Total production decreased by 2,740 BOE/d, or 5%, compared to the prior-year period. See Results of Operations – Production.

• Noncash fair value adjustments on commodity derivatives increased $18.1 million compared to the prior-year period. See Results of Operations – Commodity Derivative Contracts.

• Diluted common shares in the third quarter of 2019 include the impact of an additional 90.9 million shares, for a total diluted share count of 547.2 million shares, of the Company’s common stock issuable upon full conversion of our convertible senior

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notes which were issued in June 2019. See Note 1, Basis of Presentation – Net Income per Common Share, to the Unaudited Condensed Consolidated Financial Statements.

2019 Debt Reduction Transactions. During 2019, we have completed a series of debt exchanges and repurchases to extend the maturities of our outstanding long-term debt and reduce our debt principal as described below:

• During June 2019, through a series of debt exchanges, we extended the maturities of $348.4 million of our outstanding long-term debt to 2024 and reduced our debt principal by $120.0 million, whereby holders exchanged $468.4 million aggregate principal amount of our subordinated notes for:

– $245.5 million aggregate principal amount of our new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”);

– $102.6 million aggregate principal amount of new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”); and

–$120.0 million of cash.

• During June and July 2019, as part of creating a more liquid series of secured second lien debt due in 2024, we also exchanged $429.4 million of 7½% Senior Secured Second Lien Notes due 2024 for $429.2 million aggregate principal amount of 7¾% Senior Secured Notes. As a result of all of the above June and July note exchanges, we recognized a gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the nine months ended September 30, 2019, in our Unaudited Condensed Consolidated Statements of Operations.

• During the third quarter of 2019, we repurchased in open market transactions $11.0 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes due 2022 (the “5½% Senior Subordinated Notes”) for a total purchase price of $5.3 million, excluding accrued interest. In connection with these transactions, we recognized a $5.7 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the three and nine months ended September 30, 2019.

• During October 2019, we repurchased principally through exchanges an additional $13.5 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes and $29.3 million in aggregate principal amount of our then outstanding 4⅝% Senior Subordinated Notes due 2023 (the “4⅝% Senior Subordinated Notes”) for $5.9 million in cash and issuance of 13.7 million shares of the Company’s common stock. In the aggregate, during the third quarter and October 2019, we have repurchased $53.8 million (approximately 15%) of our $357.8 million aggregate principal amount of senior subordinated notes outstanding as of June 30, 2019, in exchange for approximately $11.2 million of cash (excluding accrued and unpaid interest) and issuance of 13.7 million shares of Denbury Common Stock.

The table below details the changes in our debt principal balances from December 31, 2018 to September 30, 2019, which excludes the October debt repurchases:

In thousands	December 31, 2018		Change			September 30, 2019
Senior Secured Bank Credit Agreement	$	—	$	50,000		$	50,000
9% Senior Secured Second Lien Notes due 2021	614,919		—			614,919
9¼% Senior Secured Second Lien Notes due 2022	455,668		—			455,668
7¾% Senior Secured Second Lien Notes due 2024	—		531,821			531,821
7½% Senior Secured Second Lien Notes due 2024	450,000		(429,359		)	20,641
6⅜% Convertible Senior Notes due 2024	—		245,548			245,548
6⅜% Senior Subordinated Notes due 2021	203,545		(152,241		)	51,304
5½% Senior Subordinated Notes due 2022	314,662		(230,926		)	83,736
4⅝% Senior Subordinated Notes due 2023	307,978		(96,283		)	211,695
Pipeline financings	180,073		(9,006		)	171,067
Capital lease obligations	5,362		(5,362		)	—
Total debt principal balance	$	2,532,207	$	(95,808	)	$	2,436,399

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July 2019 Citronelle Field Divestiture. On July 1, 2019, we closed the sale of one of our mature Gulf Coast fields, Citronelle Field, for $10 million. The sale had an effective date of May 1, 2019.

Exploitation Drilling Update. During the third quarter of 2019, we drilled two Mission Canyon wells, with initial production from one of the wells occurring at the end of September and initial production from the second well occurring in mid-October, which have a combined projected IP-30 rate of 1,000 barrels of oil per day.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flow from operations and availability of borrowing capacity under our senior secured bank credit facility. For the nine months ended September 30, 2019, we generated cash flow from operations of $343.6 million, after giving effect to $45.9 million of cash outflows for working capital changes primarily related to payments during the first nine months of the year for accrued compensation, accrued interest and accrued lease operating expenses. We have historically tried to limit our development capital spending so that it is roughly the same as, or less than, our cash flow from operations, and our 2019 cash flow from operations is currently expected to significantly exceed our planned $240 million to $260 million of development capital expenditures for the year. We have utilized a portion of our excess cash flow in 2019 to repurchase debt and improve our balance sheet as discussed above in Overview – 2019 Debt Reduction Transactions.

As of September 30, 2019, we had $50 million of outstanding borrowings on our $615 million senior secured bank credit facility, compared to no outstanding borrowings as of December 31, 2018 and $80 million as of June 30, 2019, leaving us with $510.5 million of borrowing base availability after consideration of $54.5 million of currently outstanding letters of credit. Based on our current 2019 projections using recent oil price futures, we currently expect to have the capacity to repay all of our outstanding borrowings on our senior secured bank credit facility by the end of the year.

As an additional source of potential liquidity, the Company has been engaged in two asset sale processes. In the first process, we have been actively marketing for sale surface land with no active oil and gas operations around our Conroe and Webster fields. To date, we have approximately $52 million of land sold or under contract associated with this process. During 2018, we completed approximately $6 million of land sales, and we completed $9 million of land sales during the third quarter of 2019 plus an additional $5 million in land sales in October 2019. The remaining $32 million under contract provides for purchase price payments to begin by mid-2021, subject to a number of conditions. We remain focused on a strategy that we believe will ultimately yield the highest value for the remaining land, and we expect significant additional value of the remaining parcels not yet sold or under contract to be realized over the next two years. In the second process, in 2018 we began the process of portfolio optimization through the marketing of mature fields located in Mississippi and Louisiana and Citronelle Field in Alabama. In connection with this process, we completed the sale of Lockhart Crossing Field for net proceeds of approximately $4 million during the third quarter of 2018 and closed the sale of Citronelle Field for approximately $10 million during July 2019. The pace and outcome of any sales of the remaining assets cannot be predicted at this time, but their successful completion could provide additional liquidity for financial or operational uses. Additionally, we are actively evaluating joint venture options for our Cedar Creek Anticline (“CCA”) CO₂ pipeline extension, including the possibility of raising third-party funds for all or a significant portion of our CCA pipeline capital spend in 2020. In addition, the Company may also raise funds through non-core asset sales or other joint venture transactions, or issuance of equity, which could enable us to further increase our available liquidity.

Over the last several years, we have been keenly focused on reducing leverage and improving the Company’s financial condition. In total, we have reduced our outstanding debt principal by $1.1 billion between December 31, 2014 and September 30, 2019, primarily through debt exchanges, opportunistic open market debt repurchases, and the conversion in the second quarter of 2018 of all of our then outstanding convertible senior notes into common stock. Our leverage metrics have improved considerably over the last several years, due primarily to our cost reduction efforts and our overall reduction in debt. In addition to the transactions which extended maturities of a portion of our existing debt (see Overview – 2019 Debt Reduction Transactions), these exchange transactions could further contribute to debt reduction of $245.5 million if all of the 2024 Convertible Senior Notes convert to Company common stock (based upon issuance of 90,852,760 shares at the current conversion rate of 370 shares of common stock per $1,000 principal amount of such notes). The 2024 Convertible Senior Notes provide for automatic conversion into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which is $2.43 per share, for 10 trading days in any period of 15 consecutive trading days; however, subject to satisfaction of conditions described more fully in Note 4 to the accompanying financial statements, the threshold price can be decreased by the Company’s Board of Directors to a lower price. In conjunction with our continuing efforts to improve the

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Company’s balance sheet, we plan to assess, and may engage in, potential debt reduction and/or maturity extension transactions of various types, with a primary focus on our near-term debt maturities, balanced with maintaining liquidity.

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”), which has been amended periodically since that time. The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 9% Senior Secured Second Lien Notes due in May 2021 (the “2021 Senior Secured Notes”) or 6⅜% Senior Subordinated Notes due 2021, respectively, are not repaid or refinanced by each of their respective maturity dates. As part of our fall 2019 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $615 million, with the next such redetermination scheduled for May 2020. The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

• A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020, and 4.50 to 1.0 thereafter;

• A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. 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.

Under these financial performance covenant calculations, as of September 30, 2019, our ratio of consolidated total debt to consolidated EBITDAX was 4.09 to 1.0 (with a maximum permitted ratio of 5.25 to 1.0), our consolidated senior secured debt to consolidated EBITDAX was 0.08 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 3.08 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was 3.01 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, 2019, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

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.

Capital Spending. We currently anticipate that our full-year 2019 capital spending, excluding capitalized interest and acquisitions, will be approximately $240 million to $260 million.  Capitalized interest is currently estimated at between $30 million and $40 million for 2019. The 2019 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:

• $100 million allocated for tertiary oil field expenditures;

• $70 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;

• $30 million to be spent on CO₂ sources and pipelines; and

• $50 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended
	September 30,
In thousands	2019		2018
Capital expenditure summary
Tertiary oil fields	$	72,333	$	107,133
Non-tertiary fields	55,939		51,714
Capitalized internal costs(1)	35,389		34,027
Oil and natural gas capital expenditures	163,661		192,874
CO2 pipelines, sources and other	25,778		22,345
Capital expenditures, before acquisitions and capitalized interest	189,439		215,219
Acquisitions of oil and natural gas properties	122		150
Capital expenditures, before capitalized interest	189,561		215,369
Capitalized interest	27,545		26,817
Capital expenditures, total	$	217,106	$	242,186

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

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various 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, 2018, 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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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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Operating Results Table

Certain of our operating results and statistics for the comparative three and nine months ended September 30, 2019 and 2018 are included in the following table:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-share and unit data	2019			2018			2019			2018
Operating results
Net income	$	72,862		$	78,419		$	193,880		$	148,219
Net income per common share – basic	0.16			0.17			0.43			0.35
Net income per common share – diluted	0.14			0.17			0.41			0.33
Net cash provided by operating activities	130,578			147,904			343,578			393,530
Average daily production volumes
Bbls/d	55,085			57,410			56,836			58,621
Mcf/d	8,135			10,623			9,681			11,275
BOE/d(1)	56,441			59,181			58,449			60,500
Operating revenues
Oil sales	$	292,100		$	377,329		$	912,636		$	1,088,021
Natural gas sales	1,092			2,299			5,554			7,193
Total oil and natural gas sales	$	293,192		$	379,628		$	918,190		$	1,095,214
Commodity derivative contracts(2)
Receipt (payment) on settlements of commodity derivatives	$	8,057		$	(61,611	)	$	14,714		$	(149,738	)
Noncash fair value gains (losses) on commodity derivatives(3)	35,098			17,034			(30,176		)	(39,863		)
Commodity derivatives income (expense)	$	43,155		$	(44,577	)	$	(15,462	)	$	(189,601	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	57.64		$	71.44		$	58.82		$	67.99
Natural gas price per Mcf	1.46			2.35			2.10			2.34
Unit prices – including impact of derivative settlements(2)
Oil price per Bbl	$	59.23		$	59.78		$	59.77		$	58.63
Natural gas price per Mcf	1.46			2.35			2.10			2.34
Oil and natural gas operating expenses
Lease operating expenses	$	117,850		$	122,527		$	361,205		$	361,267
Transportation and marketing expenses	10,067			11,116			32,076			31,671
Production and ad valorem taxes	20,220			25,387			65,780			75,782
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	56.46		$	69.73		$	57.54		$	66.31
Lease operating expenses	22.70			22.50			22.64			21.87
Transportation and marketing expenses	1.94			2.04			2.01			1.92
Production and ad valorem taxes	3.89			4.66			4.12			4.59
CO2 sources – revenues and expenses
CO2 sales and transportation fees	$	8,976		$	8,149		$	25,532		$	22,416
CO2 discovery and operating expenses	(879		)	(708		)	(2,016		)	(1,670		)
CO2 revenue and expenses, net	$	8,097		$	7,441		$	23,516		$	20,746

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

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

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(3) 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 $8.1 million and $14.7 million for the three and nine months ended September 30, 2019, compared to payments on settlements of $61.6 million and $149.7 million for the three and nine months ended September 30, 2018, respectively. 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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Production

Average daily production by area for each of the four quarters of 2018 and for the first, second, and third quarters of 2019 is shown below:

	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter
Operating Area	2018	2018	2018	2018	2019	2019	2019
Tertiary oil production
Gulf Coast region
Delhi	4,169	4,391	4,383	4,526	4,474	4,486	4,256
Hastings	5,704	5,716	5,486	5,480	5,539	5,466	5,513
Heidelberg	4,445	4,330	4,376	4,269	3,987	4,082	4,297
Oyster Bayou	5,056	4,961	4,578	4,785	4,740	4,394	3,995
Tinsley	6,053	5,755	5,294	5,033	4,659	4,891	4,541
West Yellow Creek	57	142	240	375	436	586	728
Mature properties(1)	6,726	6,725	6,612	6,748	6,479	6,448	6,415
Total Gulf Coast region	32,210	32,020	30,969	31,216	30,314	30,353	29,745
Rocky Mountain region
Bell Creek	4,050	4,010	3,970	4,421	4,650	5,951	4,686
Salt Creek	2,002	2,049	2,274	2,107	2,057	2,078	2,213
Other	—	—	6	20	52	41	58
Total Rocky Mountain region	6,052	6,059	6,250	6,548	6,759	8,070	6,957
Total tertiary oil production	38,262	38,079	37,219	37,764	37,073	38,423	36,702
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	875	901	1,038	1,023	1,034	1,025	873
Texas	4,386	4,947	4,533	4,319	4,345	4,243	4,268
Other	44	—	5	6	10	6	6
Total Gulf Coast region	5,305	5,848	5,576	5,348	5,389	5,274	5,147
Rocky Mountain region
Cedar Creek Anticline	14,437	15,742	14,208	14,961	14,987	14,311	13,354
Other	1,485	1,490	1,409	1,343	1,313	1,305	1,238
Total Rocky Mountain region	15,922	17,232	15,617	16,304	16,300	15,616	14,592
Total non-tertiary production	21,227	23,080	21,193	21,652	21,689	20,890	19,739
Total continuing production	59,489	61,159	58,412	59,416	58,762	59,313	56,441
Property sales
Citronelle(2)	387	388	416	451	456	406	—
Lockhart Crossing(3)	462	447	353	—	—	—	—
Total production	60,338	61,994	59,181	59,867	59,218	59,719	56,441

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

(2) Includes production from Citronelle Field sold in July 2019.

(3) Includes production from Lockhart Crossing Field sold in the third quarter of 2018.

Total continuing production during the third quarter of 2019 averaged 56,441 BOE/d, including 36,702 Bbls/d, or 65%, from tertiary properties and 19,739 BOE/d from non-tertiary properties. Total continuing production excludes production from Citronelle Field sold in July 2019 and, for prior-year periods, excludes production from Lockhart Crossing Field sold in the third quarter of

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2018. This total continuing production level represents a decrease of 2,872 BOE/d (5%) compared to total continuing production levels in the second quarter of 2019 and a decrease of 1,971 BOE/d (3%) compared to third quarter of 2018 continuing production. The sequential decrease was primarily due to an expected reduction in production at Bell Creek Field associated with planned maintenance at our primary CO₂ source in the Rocky Mountain region. Third quarter 2019 production was also lowered by approximately 400 BOE/d due to unplanned downtime from power outages and flooding caused by Tropical Storm Imelda. The year-over-year decrease in production was also impacted by lower production at Tinsley Field primarily due to planned downtime and preventative maintenance, slightly offset by production increases at West Yellow Creek Field. Our production during the three and nine months ended September 30, 2019 was 98% and 97% oil, respectively, consistent with oil production during the prior-year periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and nine months ended September 30, 2019 decreased 23% and 16%, respectively, compared to these revenues for the same periods in 2018.  The changes in our oil and natural gas revenues are due to changes in production quantities and realized 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,
	2019 vs. 2018					2019 vs. 2018
In thousands	Decrease in Revenues			Percentage Decrease in Revenues		Decrease in Revenues			Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(17,579	)	(5	)%	$	(37,126	)	(3	)%
Decrease in realized commodity prices	(68,857		)	(18	)%	(139,898		)	(13	)%
Total decrease in oil and natural gas revenues	$	(86,436	)	(23	)%	$	(177,024	)	(16	)%

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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, 2019 and 2018:

	Three Months Ended																		Nine Months Ended
	March 31,						June 30,						September 30,						September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Average net realized prices
Oil price per Bbl	$	56.50		$	64.25		$	62.22		$	68.24		$	57.64		$	71.44		$	58.82		$	67.99
Natural gas price per Mcf	2.68			2.44			2.01			2.21			1.46			2.35			2.10			2.34
Price per BOE	55.27			62.61			60.80			66.57			56.46			69.73			57.54			66.31
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	4.26		$	2.05		$	4.85		$	1.12		$	3.11		$	3.21		$	4.08		$	2.10
Natural gas per Mcf	(0.10		)	0.10			0.10			0.04			(0.24		)	0.06			(0.06		)	0.07
Rocky Mountain region
Oil per Bbl	$	(2.56	)	$	(0.06	)	$	(1.48	)	$	(0.84	)	$	(1.65	)	$	(0.54	)	$	(1.85	)	$	(0.47	)
Natural gas per Mcf	(0.28		)	(0.92		)	(1.13		)	(1.25		)	(1.61		)	(1.05		)	(0.90		)	(1.07		)
Total Company
Oil per Bbl	$	1.63		$	1.29		$	2.35		$	0.39		$	1.30		$	1.84		$	1.79		$	1.16
Natural gas per Mcf	(0.20		)	(0.40		)	(0.50		)	(0.62		)	(0.87		)	(0.51		)	(0.47		)	(0.51		)

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.

• Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a positive $3.11 per Bbl and a positive $3.21 per Bbl during the third quarters of 2019 and 2018, respectively, and a positive $4.85 per Bbl during the second quarter of 2019. Generally, our Gulf Coast region differentials are positive to NYMEX and highly correlated to the changes in prices of Light Louisiana Sweet crude oil, which have generally strengthened over the past year, although recent Gulf Coast region differentials have softened.

• Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.65 per Bbl and $0.54 per Bbl below NYMEX during the third quarters of 2019 and 2018, respectively, and $1.48 per Bbl below NYMEX during the second quarter of 2019. 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. Although our differentials in the Rocky Mountain region have weakened somewhat from a year ago, they have improved from the differentials we experienced in the fourth quarter of 2018 and first quarter of 2019.

CO₂ Revenues and Expenses

We sell approximately 15% to 20% of our produced CO₂ from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO₂ sales as “CO₂ sales and transportation fees” with the corresponding costs recognized as “CO₂ discovery and operating expenses” in our Unaudited Condensed Consolidated Statements of Operations.

Purchased Oil Revenues and Expenses

From time to time, we market third-party production for sale in exchange for a fee. We recognize the revenue received on these oil sales as “Purchased oil sales” and the expenses incurred to market and transport the oil as “Purchased oil expenses” in our 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

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, 2019 and 2018:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
In thousands	2019		2018			2019			2018
Receipt (payment) on settlements of commodity derivatives	$	8,057	$	(61,611	)	$	14,714		$	(149,738	)
Noncash fair value gains (losses) on commodity derivatives(1)	35,098		17,034			(30,176		)	(39,863		)
Total income (expense)	$	43,155	$	(44,577	)	$	(15,462	)	$	(189,601	)

(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.

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 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. See Note 5, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, 2019, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of November 6, 2019:

		4Q 2019	1H 2020	2H 2020
WTI NYMEX	Volumes Hedged (Bbls/d)	2,000	2,000	2,000
Fixed-Price Swaps	Swap Price(1)	$60.60	$60.59	$60.59
Argus LLS	Volumes Hedged (Bbls/d)	13,000	4,500	4,500
Fixed-Price Swaps	Swap Price(1)	$64.69	$62.29	$62.29
WTI NYMEX	Volumes Hedged (Bbls/d)	23,000	19,000	17,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price(1)(2)	$48.57 / $56.61 / $69.04	$48.14 / $57.21 / $63.44	$48.15 / $57.10 / $63.33
Argus LLS	Volumes Hedged (Bbls/d)	5,500	7,000	5,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price(1)(2)	$54.73 / $63.09 / $79.93	$53.07 / $62.45 / $70.00	$53.00 / $62.13 / $71.00
	Total Volumes Hedged (Bbls/d)	43,500	32,500	28,500

(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.

Based on current contracts in place and NYMEX oil futures prices as of November 6, 2019, which averaged approximately $56 per Bbl, we currently expect that we would receive cash payments of approximately $15 million during the remainder of 2019 upon settlement of the 2019 contracts, the amount of which is dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2019 fixed-price swaps which have weighted average prices of $60.60 per Bbl and $64.69 per Bbl for NYMEX and LLS hedges, respectively, and weighted average floor prices of our 2019 three-way collars of $56.61 per Bbl and $63.09 per Bbl for NYMEX and LLS hedges, respectively. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

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Denbury Resources Inc.

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

Production Expenses

Lease Operating Expenses

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2019		2018		2019		2018
Total lease operating expenses	$	117,850	$	122,527	$	361,205	$	361,267
Total lease operating expenses per BOE	$	22.70	$	22.50	$	22.64	$	21.87

Total lease operating expenses decreased $4.7 million (4%) on an absolute-dollar basis, but slightly increased $0.20 (1%) on a per-BOE basis, during the three months ended September 30, 2019, compared to the same prior-year period. The decrease on an absolute-dollar basis was primarily due to lower workover expense, lower power and fuel costs, and lower CO₂ expense due to planned maintenance at our primary CO₂ source in the Rocky Mountain region during the quarter. Lease operating expenses on an absolute-dollar basis was relatively unchanged on a sequential-quarter basis from the second quarter of 2019 and for the nine months ended September 30, 2019, compared to levels in the same period in 2018, but increased $1.00 (5%) on a per-BOE basis from the second quarter of 2019 and increased $0.77 (4%) on a per-BOE basis during the nine months ended September 30, 2019, compared to the same prior-year period. The increases on a per-BOE basis for the comparative periods were due to a decrease in total production.

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 2019 and 2018, approximately 55% and 52%, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us (our net revenue interest). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what we pay third parties for CO₂, our average cost of CO₂ was approximately $0.37 per Mcf during the third quarter of 2019, including taxes paid on CO₂ production but excluding depletion, depreciation and amortization of capital expended at our CO₂ source fields and industrial sources. This per-Mcf CO₂ cost during the third quarter of 2019 was lower than the $0.41 per Mcf comparable measure during the third quarter of 2018 due to lower utilization of industrial-source CO₂ in our Rocky Mountain region, but higher than the $0.33 per Mcf comparable measure during the second quarter of 2019 due to higher utilization of industrial-sourced CO₂ in our Gulf Coast region, which has a higher average cost than our naturally-occurring CO₂ sources.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $10.1 million and $11.1 million for the three months ended September 30, 2019 and 2018, respectively, and $32.1 million and $31.7 million for the nine months ended September 30, 2019 and 2018, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $5.3 million (20%) during the three months ended September 30, 2019, compared to the same prior-year period and decreased $10.6 million (13%) during the nine months ended September 30, 2019, compared to the same period in 2018, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.

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Denbury Resources Inc.

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

General and Administrative Expenses (“G&A”)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE data and employees	2019			2018			2019			2018
Gross cash compensation and administrative costs	$	53,969		$	57,765		$	162,589		$	172,287
Gross stock-based compensation	3,983			4,597			12,958			11,126
Operator labor and overhead recovery charges	(29,865		)	(31,586		)	(90,480		)	(94,910		)
Capitalized exploration and development costs	(9,821		)	(9,197		)	(30,370		)	(27,280		)
Net G&A expense	$	18,266		$	21,579		$	54,697		$	61,223
G&A per BOE
Net cash administrative costs	$	2.94		$	3.31		$	2.81		$	3.18
Net stock-based compensation	0.58			0.65			0.62			0.53
Net G&A expenses	$	3.52		$	3.96		$	3.43		$	3.71
Employees as of September 30	826			847

Our net G&A expenses on an absolute-dollar basis decreased $3.3 million (15%) and $6.5 million (11%), or $0.44 (11%) and $0.28 (8%) on a per-BOE basis, during the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018, primarily due to our continued focus on cost reduction efforts and reduction in performance-based compensation.

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	2019			2018			2019			2018
Cash interest(1)	$	48,297		$	46,515		$	144,616		$	138,660
Less: interest not reflected as expense for financial reporting purposes(1)	(21,372		)	(21,186		)	(64,006		)	(64,849		)
Noncash interest expense	1,060			2,712			3,517			4,980
Amortization of debt discount(2)	3,646			—			4,090			—
Less: capitalized interest	(8,773		)	(9,514		)	(27,545		)	(26,817		)
Interest expense, net	$	22,858		$	18,527		$	60,672		$	51,974
Interest expense, net per BOE	$	4.40		$	3.40		$	3.80		$	3.15
Average debt principal outstanding(3)	$	2,374,422		$	2,542,712		$	2,491,015		$	2,611,225
Average cash interest rate(4)	8.1		%	7.3		%	7.7		%	7.1		%

(1) Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt relates to our 2021 Senior Secured Notes, 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”), and our previously

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Denbury Resources Inc.

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

outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023. See below for further discussion.

(2) Represents amortization of debt discounts of $1.2 million and $1.4 million related to the 7¾% Senior Secured Notes during the three and nine months ended September 30, 2019, respectively, and $2.4 million and $2.7 million related to the 2024 Convertible Senior Notes during the three and nine months ended September 30, 2019, respectively.

(3) Excludes debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.

(4) Includes commitment fees but excludes debt issue costs and amortization of discount.

As reflected in the table above, cash interest expense during the three and nine months ended September 30, 2019 increased $1.8 million (4%) and $6.0 million (4%), respectively, when compared to the prior-year periods due primarily to an increase in our weighted-average interest rate.

Future interest payable related to our 2021 Senior Secured Notes and 2022 Senior Secured Notes is accounted for in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors, whereby most of the future interest was recorded as debt as of the transaction date, which will be reduced as semiannual interest payments are made. Future interest payable recorded as debt totaled $190.4 million as of September 30, 2019. Therefore, interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be approximately $86 million lower annually than the actual cash interest payments on our 2021 Senior Secured Notes and 2022 Senior Secured Notes.

As more fully described in Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, the June 2019 debt exchange transactions were accounted for in accordance with FASC 470-50, Modifications and Extinguishments, whereby our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at discounts to their principal amounts of $29.6 million and $79.9 million, respectively. These debt discounts will be amortized as interest expense over the terms of the notes; therefore, future interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be higher than the actual cash interest payments on our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes by approximately $8 million in 2019, $16 million in 2020, $19 million in 2021, $21 million in 2022, $25 million in 2023 and $21 million in 2024.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2019		2018		2019		2018
Oil and natural gas properties	$	39,304	$	32,559	$	116,249	$	97,788
CO2 properties, pipelines, plants and other property and equipment	15,760		18,757		54,376		58,923
Total DD&A	$	55,064	$	51,316	$	170,625	$	156,711
DD&A per BOE
Oil and natural gas properties	$	7.57	$	5.98	$	7.29	$	5.92
CO2 properties, pipelines, plants and other property and equipment	3.03		3.45		3.40		3.57
Total DD&A cost per BOE	$	10.60	$	9.43	$	10.69	$	9.49

The increase in our oil and natural gas properties depletion during the three and nine months ended September 30, 2019, when compared to the same periods in 2018, was primarily due to an increase in depletable costs resulting from increases in our capitalized costs and future development costs associated with our reserves base.

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Denbury Resources Inc.

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

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE amounts and tax rates	2019			2018			2019			2018
Current income tax expense (benefit)	$	(859	)	$	(1,888	)	$	1,214		$	(3,674	)
Deferred income tax expense	37,909			17,504			90,454			42,741
Total income tax expense	$	37,050		$	15,616		$	91,668		$	39,067
Average income tax expense per BOE	$	7.13		$	2.87		$	5.75		$	2.37
Effective tax rate	33.7		%	16.6		%	32.1		%	20.9		%
Total net deferred tax liability	$	400,213		$	249,264

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 25% in 2019 and 2018. Our effective tax rate for the three and nine months ended September 30, 2019 was higher than our estimated statutory rate, primarily due to establishment of a valuation allowance against a portion of our business interest expense deduction that we estimate will be disallowed. The Tax Cuts and Jobs Act (“The Act”), which was enacted on December 22, 2017, revised the rules regarding the deductibility of business interest expense by limiting that deduction to 30% of adjusted taxable income (as defined), with disallowed amounts being carried forward to future taxable years. Based on our evaluation, using information existing as of the balance sheet date, of the near-term ability to utilize the tax benefits associated with our 2019 disallowed business interest expense, we have established a valuation allowance through our annual estimated effective income tax rate for that portion of our business interest expense that is currently expected to exceed the allowed limitation under The Act.

The current income tax benefits for the three and nine months ended September 30, 2018, represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

As of September 30, 2019, we had estimated amounts available for carry forward of $55.5 million of enhanced oil recovery credits related to our tertiary operations, $21.6 million of research and development credits, and $18.9 million of alternative minimum tax credits. The alternative minimum tax credits are fully refundable by 2021 and are recorded as a receivable on the balance sheet.  The enhanced oil recovery credits and research and development credits do not begin to expire until 2025 and 2031, respectively.

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Denbury Resources Inc.

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

Per-BOE Data

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Per-BOE data	2019			2018			2019			2018
Oil and natural gas revenues	$	56.46		$	69.73		$	57.54		$	66.31
Receipt (payment) on settlements of commodity derivatives	1.56			(11.32		)	0.92			(9.07		)
Lease operating expenses	(22.70		)	(22.50		)	(22.64		)	(21.87		)
Production and ad valorem taxes	(3.89		)	(4.66		)	(4.12		)	(4.59		)
Transportation and marketing expenses	(1.94		)	(2.04		)	(2.01		)	(1.92		)
Production netback	29.49			29.21			29.69			28.86
CO2 sales, net of operating and exploration expenses	1.56			1.37			1.47			1.26
General and administrative expenses	(3.52		)	(3.96		)	(3.43		)	(3.71		)
Interest expense, net	(4.40		)	(3.40		)	(3.80		)	(3.15		)
Other	1.09			1.49			0.48			0.61
Changes in assets and liabilities relating to operations	0.93			2.46			(2.88		)	(0.04		)
Cash flows from operations	25.15			27.17			21.53			23.83
DD&A	(10.60		)	(9.43		)	(10.69		)	(9.49		)
Deferred income taxes	(7.30		)	(3.21		)	(5.67		)	(2.59		)
Gain on extinguishment of debt	1.13			—			6.66			—
Noncash fair value gains (losses) on commodity derivatives(1)	6.75			3.13			(1.89		)	(2.41		)
Other noncash items	(1.10		)	(3.26		)	2.21			(0.37		)
Net income	$	14.03		$	14.40		$	12.15		$	8.97

(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, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.

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, and information regarding the financial position, business strategy, production and reserve growth, possible or assumed future results of operations, and other plans and objectives for the future operations of Denbury, and general economic conditions 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 their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels or extend debt maturities, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations

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

or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and 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, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO₂ flooding of particular fields or areas, including Cedar Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO₂ injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of 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, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, the likelihood and extent of an economic slowdown, and other variables surrounding 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, 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; evolving political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; trade disputes and resulting tariffs or international economic sanctions; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit in the commercial banking or other debt markets; 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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Denbury Resources Inc.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

As of September 30, 2019, we had $2.2 billion of fixed-rate long-term debt outstanding and $50.0 million of outstanding borrowings on our variable-rate 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 senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices.  The following table presents the principal and fair values of our outstanding debt as of September 30, 2019.

In thousands	2021		2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 4.7% at September 30, 2019)	$	50,000	$	—	$	—	$	—	$	50,000	$	50,000
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	614,919		—		—		—		614,919		579,315
9¼% Senior Secured Second Lien Notes due 2022	—		455,668		—		—		455,668		402,674
7¾% Senior Secured Second Lien Notes due 2024	—		—		—		531,821		531,821		410,832
7½% Senior Secured Second Lien Notes due 2024	—		—		—		20,641		20,641		14,655
6⅜% Convertible Senior Notes due 2024	—		—		—		245,548		245,548		145,021
6⅜% Senior Subordinated Notes due 2021	51,304		—		—		—		51,304		36,342
5½% Senior Subordinated Notes due 2022	—		83,736		—		—		83,736		42,915
4⅝% Senior Subordinated Notes due 2023	—		—		211,695		—		211,695		86,266

See Note 4, 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 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. Depending on market conditions, we may continue to add to our existing 2020 hedges. 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, 2019, our commodity derivative contracts were recorded at their fair value, which was a net asset of $67.1 million, a $35.1 million increase from the $32.0 million net asset recorded at June 30, 2019, and a $30.2 million decrease from the $97.3 million net asset recorded at December 31, 2018.  These changes are primarily related to the expiration of commodity derivative contracts during the three and nine months ended September 30, 2019, new commodity derivative contracts entered into during 2019 for future periods, and to the changes in oil futures prices between December 31, 2018 and September 30, 2019.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of September 30, 2019, and assuming both a 10% increase and decrease thereon, we would expect to receive or 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, 2019	$	87,275
10% increase in prices	23,998
10% decrease in prices	138,375

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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Denbury Resources Inc.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.  As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2019, 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 2019, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Denbury Resources Inc.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, litigation is subject to inherent uncertainties. We 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, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract.

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017) when the Company’s performance was not excused as provided in the contract. The Company has filed a notice of appeal of the trial court’s ruling to the Wyoming Supreme Court, the results and timing of which cannot be currently predicted.

The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions in the helium supply contract. The Company intends to continue to vigorously defend its position and pursue all of its rights.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract (including $14.2 million of liquidated damages for the contract years ending July 31, 2018 and July 31, 2019) plus $4.7 million of associated costs (through September 30, 2019), for a total of $50.7 million, included in “Other liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019.

Environmental Protection Agency Matter Concerning Certain Fields

The Company has been in discussions with the Environmental Protection Agency (“EPA”) over the past several years regarding the EPA’s contention that it has causes of action under the Clean Water Act (“CWA”) related to releases (principally between 2008 and 2013) of oil and produced water containing small amounts of oil in the Citronelle Field in southern Alabama and several fields in Mississippi.

In September, the previously disclosed proposed Consent Decree among the Company, the United States, and the State of Mississippi resolving the allegations of CWA violations became effective upon the District Court entering the Consent Decree as a judgment of the court. The Consent Decree requires the Company to pay civil penalties totaling $3.5 million in the aggregate to the United States and the State of Mississippi, which payments have been made. The Consent Decree further requires the implementation of enhancements to the Company’s mechanical integrity program designed to minimize the occurrence and impact of any future releases at the Mississippi fields, and the performance of other relief such as enhanced training and reporting requirements with respect to the Mississippi fields.

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Denbury Resources Inc.

Item 1A. Risk Factors

Please refer to Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 other than as detailed below.

If we cannot meet the “price criteria” for continued listing on the NYSE, the NYSE may delist our common stock, which could have an adverse impact on the trading volume, liquidity and market price of our common stock, or the trading prices of our 6⅜% Convertible Senior Notes due 2024.

If we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for a failure to maintain compliance with the NYSE price criteria listing standards. As of November 6, 2019, the average closing price of our common stock over the immediately preceding 30 consecutive trading-day period was $1.07. Despite NYSE rules and processes that provide a period of time to cure non-compliance with this NYSE standard (during which time the issuer’s common stock generally continues to be traded on the NYSE), there is no assurance that trading prices of our common stock or other steps we take would be successful in assuring our long-term listing on the NYSE. A delisting of our common stock from the NYSE would likely reduce the liquidity and market price of our common stock, (along with the trading prices of our 6⅜% Convertible Senior Notes due 2024), reduce the number of investors willing to hold or acquire our common stock, and negatively impact our ability to raise equity financing.

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Denbury Resources Inc.

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

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the third quarter of 2019:

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 2019	1,141,341	$	1.22	—	$	210.1
August 2019	—	—		—	210.1
September 2019	4,540	1.13		—	210.1
Total	1,145,881			—

(1) Shares purchased during the third quarter of 2019 were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted and performance shares.

(2) In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock in the near future. 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.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Denbury Resources Inc.

Item 6. Exhibits

Exhibit No.	Exhibit
10(a)	Collateral Trust Joinder, dated as of July 1, 2019, by and between Wilmington Trust, National Association, as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 2, 2019).
10(b)	Priority Confirmation Joinder, dated as of July 1, 2019, by and between JPMorgan Chase Bank, N.A., as Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.2 on Form 8-K filed by the Company on July 2, 2019).
10(c)*	2019 Form of Restricted Stock Unit Award to officers pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
31(a)*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, has been formatted in Inline XBRL.

* Included herewith.

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Denbury Resources Inc.

SIGNATURES

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

	DENBURY RESOURCES INC.
November 7, 2019	/s/ Mark C. Allen
	Mark C. Allen Executive Vice President and Chief Financial Officer
November 7, 2019	/s/ Alan Rhoades
	Alan Rhoades Vice President and Chief Accounting Officer

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