DENBURY INC - Quarter Report: 2020 March (Form 10-Q)

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 March 31, 2020

☐ 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 April 30, 2020, was 506,481,777.

EXPLANATORY NOTE

As previously disclosed in the Current Report on Form 8-K filed by Denbury Resources Inc. (the “Company” or “Denbury”) on May 7, 2020, the Company expected that the filing of this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 (the “Report”), originally due on May 11, 2020, would be delayed due to disruptions caused by the COVID-19 coronavirus (“COVID-19”) pandemic. In particular, the ongoing COVID-19 pandemic’s effect on economic activity across the globe resulted in a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. These events have worsened a deteriorated oil market which followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. These significant and rapid changes required complex accounting judgments and revisions of estimates upon which the Company’s financial statements are based, which required additional time for compilation, preparation, and review necessary to prepare the Company’s Quarterly Report.

The Company relied on Release No. 34-88465 issued by the Securities and Exchange Commission on March 25, 2020, pursuant to Section 36 of the Securities Exchange Act of 1934, as amended, to delay the filing of this Quarterly Report.

Denbury Resources Inc.

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		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019	4
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2020 and 2019	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019	6
	Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2020 and 2019	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	41

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
	Signatures	47

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)



	March 31,			December 31,
	2020			2019
Assets
Current assets
Cash and cash equivalents	$	6,917		$	516
Accrued production receivable	72,470			139,407
Trade and other receivables, net	41,497			18,318
Derivative assets	125,724			11,936
Other current assets	10,312			10,434
Total current assets	256,920			180,611
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	11,683,339			11,447,680
Unevaluated properties	636,656			872,910
CO₂ properties	1,198,902			1,198,846
Pipelines and plants	2,335,198			2,329,078
Other property and equipment	217,066			212,334
Less accumulated depletion, depreciation, amortization and impairment	(11,854,989		)	(11,688,020		)
Net property and equipment	4,216,172			4,372,828
Operating lease right-of-use assets	32,886			34,099
Other assets	101,113			104,329
Total assets	$	4,607,091		$	4,691,867
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	106,546		$	183,832
Oil and gas production payable	46,921			62,869
Derivative liabilities	—			8,346
Current maturities of long-term debt (including future interest payable of $83,751 and $86,054, respectively – see Note 4)	98,212			102,294
Operating lease liabilities	7,044			6,901
Total current liabilities	258,723			364,242
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $59,998 and $78,860, respectively – see Note 4)	2,185,984			2,232,570
Asset retirement obligations	173,214			177,108
Deferred tax liabilities, net	406,021			410,230
Operating lease liabilities	40,112			41,932
Other liabilities	53,592			53,526
Total long-term liabilities	2,858,923			2,915,366
Commitments and contingencies (Note 8)
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; 508,415,378 and 508,065,495 shares issued, respectively	508			508
Paid-in capital in excess of par	2,742,303			2,739,099
Accumulated deficit	(1,247,298		)	(1,321,314		)
Treasury stock, at cost, 1,828,444 and 1,652,771 shares, respectively	(6,068		)	(6,034		)
Total stockholders’ equity	1,489,445			1,412,259
Total liabilities and stockholders’ equity	$	4,607,091		$	4,691,867

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)



	Three Months Ended March 31,
	2020			2019
Revenues and other income
Oil, natural gas, and related product sales	$	229,624		$	294,577
CO₂sales and transportation fees	8,028			8,570
Purchased oil sales	3,721			215
Other income	828			2,090
Total revenues and other income	242,201			305,452
Expenses
Lease operating expenses	109,270			125,423
Transportation and marketing expenses	9,621			10,773
CO₂ discovery and operating expenses	752			556
Taxes other than income	19,686			23,785
Purchased oil expenses	3,661			213
General and administrative expenses	9,733			18,925
Interest, net of amounts capitalized of $9,452 and $10,534, respectively	19,946			17,398
Depletion, depreciation, and amortization	96,862			57,297
Commodity derivatives expense (income)	(146,771		)	83,377
Gain on debt extinguishment	(18,994		)	—
Write-down of oil and natural gas properties	72,541			—
Other expenses	2,494			4,138
Total expenses	178,801			341,885
Income (loss) before income taxes	63,400			(36,433		)
Income tax benefit	(10,616		)	(10,759		)
Net income (loss)	$	74,016		$	(25,674	)

Net income (loss) per common share
Basic	$	0.15		$	(0.06	)
Diluted	$	0.14		$	(0.06	)

Weighted average common shares outstanding
Basic	494,259			451,720
Diluted	586,190			451,720

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)



	Three Months Ended March 31,
	2020			2019
Cash flows from operating activities
Net income (loss)	$	74,016		$	(25,674	)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	96,862			57,297
Write-down of oil and natural gas properties	72,541			—
Deferred income taxes	(4,209		)	(9,478		)
Stock-based compensation	2,453			3,263
Commodity derivatives expense (income)	(146,771		)	83,377
Receipt on settlements of commodity derivatives	24,638			8,206
Gain on debt extinguishment	(18,994		)	—
Debt issuance costs and discounts	4,926			1,263
Other, net	(673		)	908
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	66,937			(21,591		)
Trade and other receivables	(22,914		)	1,024
Other current and long-term assets	2,539			(387		)
Accounts payable and accrued liabilities	(72,607		)	(35,966		)
Oil and natural gas production payable	(15,948		)	4,605
Other liabilities	(954		)	(2,481		)
Net cash provided by operating activities	61,842			64,366

Cash flows from investing activities
Oil and natural gas capital expenditures	(46,016		)	(86,986		)
Pipelines and plants capital expenditures	(6,294		)	(1,682		)
Net proceeds from sales of oil and natural gas properties and equipment	40,543			104
Other	(4,521		)	(3,237		)
Net cash used in investing activities	(16,288		)	(91,801		)

Cash flows from financing activities
Bank repayments	(161,000		)	(103,000		)
Bank borrowings	161,000			103,000
Interest payments treated as a reduction of debt	(18,211		)	—
Cash paid in conjunction with debt repurchases	(14,171		)	—
Pipeline financing and capital lease debt repayments	(3,690		)	(4,108		)
Other	(2,953		)	(1,099		)
Net cash used in financing activities	(39,025		)	(5,207		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	6,529			(32,642		)
Cash, cash equivalents, and restricted cash at beginning of period	33,045			54,949
Cash, cash equivalents, and restricted cash at end of period	$	39,574		$	22,307

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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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		Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity
Balance – December 31, 2019	508,065,495	$	508	$	2,739,099	$	(1,321,314	)	1,652,771	$	(6,034	)	$	1,412,259
Issued or purchased pursuant to stock compensation plans	312,516	—		—		—			—	—			—
Issued pursuant to directors’ compensation plan	37,367	—		—		—			—	—			—
Stock-based compensation	—	—		3,204		—			—	—			3,204
Tax withholding – stock compensation	—	—		—		—			175,673	(34		)	(34		)
Net income	—	—		—		74,016			—	—			74,016
Balance – March 31, 2020	508,415,378	$	508	$	2,742,303	$	(1,247,298	)	1,828,444	$	(6,068	)	$	1,489,445



	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares	Amount		Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2019 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2020, our consolidated results of operations for the three months ended March 31, 2020 and 2019, our consolidated cash flows for the three months ended March 31, 2020 and 2019, and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2020 and 2019.

Risks and Uncertainties

In March 2020, the World Health Organization declared the ongoing COVID-19 outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in the worldwide demand for oil, which worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Although OPEC+ has subsequently reached an agreement to curtail production, it is estimated that the near-term impact on global oil demand is significantly greater than the magnitude of production curtailments, and storage centers in the United States and around the world could potentially reach maximum storage levels. Together, these events have caused oil prices to plummet since the first week of March 2020, which has continued, and is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond.

Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. Because the realized oil prices we have received since early March 2020 have been significantly reduced, our operating cash flow and liquidity have been adversely affected. The extent of the impact on our operational and financial performance is dependent upon future developments that drive domestic and global oil supply and demand, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and future levels of domestic and global oil production.

Industry Conditions, Liquidity, Management’s Plans, and Going Concern

As discussed above, COVID-19 has had a significant impact on oil prices, which directly impacts our business in many ways. The decrease in oil prices directly impacts the operating cash flow we are able to generate from our production, and if prices are too low, it may not be economic for us to produce certain of our properties. The decrease in oil prices may also impact our other sources of liquidity, potentially reducing our borrowing capacity under our bank credit facility. Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our bank credit facility. As of May 13, 2020, our bank credit facility availability was $520.3 million, based on a $615 million borrowing base and $94.7 million of

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

letters of credit currently outstanding. Our most significant cash outlays relate to our development capital expenditures, current period operating expenses, and our debt service obligations.

Our senior secured bank credit facility and the indentures related to our senior secured second lien notes, senior convertible notes, and senior subordinated notes are subject to a variety of covenants. Throughout 2019 and the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance financial covenants, as well as covenants within our long-term note indentures. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year.

Our senior secured bank credit facility matures on December 9, 2021, provided that the maturity date may be accelerated to earlier dates in 2021 (February 12, 2021, May 14, 2021 or August 13, 2021) if certain defined liquidity ratios are not met, or if our 9% Senior Secured Second Lien Notes due May 15, 2021 (the “2021 Senior Secured Notes”) or our 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”) are not repaid or refinanced by each of their respective maturity dates. Our maintenance financial covenants contained in our senior secured bank credit facility are described in Note 4, Long-Term Debt.

In this low oil price environment and period of uncertainty, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted development capital spending by 44% from initial levels and to less than half of 2019 levels, (2) by continuing to focus on reducing our operating and overhead costs, and (3) by restructuring certain of our three-way collars covering 14,500 barrels per day into fixed-price swaps for the second through fourth quarters of 2020 to increase downside protection against current and potential further declines in oil prices. As the ability to fund our full 2020 development capital budget with cash flow from operations and asset sale proceeds is dependent in part upon future commodity pricing, which we cannot predict nor control, we expect to fund any potential shortfall with incremental borrowings under our senior secured bank credit facility. There can be no assurances that we will be able to fund any potential shortfall with borrowings under our senior secured bank credit facility.

Collectively, the above factors, along with the materially adverse change in industry market conditions and our cash flow over the past few months, have substantially diminished our ability to repay, refinance, or restructure our $584.7 million outstanding principal balance of 2021 Senior Secured Notes and have raised substantial doubt about our ability to continue as a going concern. Because the actions described above are not sufficient to significantly mitigate the substantial doubt about our ability to continue as a going concern over the next twelve months from the issuance of these financial statements, we have engaged advisors to assist with the evaluation of a range of strategic alternatives and are engaged in discussions with our lenders and bondholders regarding a potential comprehensive restructuring of our indebtedness. There can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transaction. The condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

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 months ended March 31, 2019, “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.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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	March 31, 2020		December 31, 2019
Cash and cash equivalents	$	6,917	$	516
Restricted cash included in other assets	32,657		32,529
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	39,574	$	33,045

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.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, 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 (loss) and weighted average shares used for purposes of calculating the basic and diluted net income (loss) per common share for the periods indicated:



	Three Months Ended
	March 31,
In thousands	2020		2019
Numerator
Net income (loss) – basic	$	74,016	$	(25,674	)
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	5,857		—
Net income (loss) – diluted	$	79,873	$	(25,674	)

Denominator
Weighted average common shares outstanding – basic	494,259		451,720
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	1,078		—
Convertible senior notes⁽¹⁾	90,853		—
Weighted average common shares outstanding – diluted	586,190		451,720


(1)	For the three months ended March 31, 2020, shares shown under “convertible senior notes” represent 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.

Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three months ended March 31, 2020, 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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of the 2020 period.

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



	Three Months Ended
	March 31,
In thousands	2020	2019
Stock appreciation rights	1,528	2,091
Restricted stock and performance-based equity awards	14,007	8,350

Oil and Natural Gas Properties

Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base in the course of these properties being developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. Given the significant recent declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, as well as the uncertainty of future oil prices from demand destruction caused by the pandemic, we recognized an impairment of $244.9 million of our unevaluated costs during the three months ended March 31, 2020, whereby these costs were transferred to the full cost amortization base.

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

We recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020, with first-day-of-the-month prices for the preceding 12 months averaging $55.17 per Bbl for crude oil and $1.68 per MMBtu for natural gas, after adjustments for market differentials by field. If oil prices were to remain at or near early-May 2020 levels in subsequent periods, we currently expect that we would also record significant write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020.

Impairment Assessment of Long-Lived Assets

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO₂ properties and pipelines. Given the significant recent declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region).

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

We perform our long-lived asset impairment test by comparing the net carrying costs of our two long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and no impairment was recorded.

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows.

Recent Accounting Pronouncements

Recently 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. Effective January 1, 2020, we adopted ASU 2016-13. The implementation of this standard did not have a material impact 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. Effective January 1, 2020, we adopted ASU 2018-13. The implementation of this standard did not have a material impact on our consolidated financial statements or footnote disclosures.

Not Yet Adopted

Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this ASU are effective beginning on March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. We are currently evaluating the impact this guidance may have on our consolidated financial statements and related footnote disclosures.

Income Taxes. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and early adoption is permitted. We are currently evaluating the impact this guidance may have on our consolidated financial statements and related footnote disclosures.

Note 2. Divestiture

On March 4, 2020, we closed a farm-down transaction for the sale of half of our working interest positions in four southeast Texas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. The sale had an effective date of January 1, 2019. We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. 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 $72.5 million and $139.4 million as of March 31, 2020 and December 31, 2019, 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.

Disaggregation of Revenue

The following table summarizes our revenues by product type for the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
In thousands	2020		2019
Oil sales	$	228,577	$	291,965
Natural gas sales	1,047		2,612
CO₂ sales and transportation fees	8,028		8,570
Purchased oil sales	3,721		215
Total revenues	$	241,373	$	303,362

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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 outstanding as of the dates indicated:



	March 31,			December 31,
In thousands	2020			2019
Senior Secured Bank Credit Agreement	$	—		$	—
9% Senior Secured Second Lien Notes due 2021	584,709			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	20,641			20,641
6⅜% Convertible Senior Notes due 2024	245,548			245,548
6⅜% Senior Subordinated Notes due 2021	51,304			51,304
5½% Senior Subordinated Notes due 2022	58,426			58,426
4⅝% Senior Subordinated Notes due 2023	135,960			135,960
Pipeline financings	163,748			167,439
Total debt principal balance	2,247,825			2,281,726
Debt discount⁽¹⁾	(97,873		)	(101,767		)
Future interest payable⁽²⁾	143,749			164,914
Debt issuance costs	(9,505		)	(10,009		)
Total debt, net of debt issuance costs and discount	2,284,196			2,334,864
Less: current maturities of long-term debt⁽³⁾	(98,212		)	(102,294		)
Long-term debt	$	2,185,984		$	2,232,570


(1)	Consists of discounts related to our 7¾% Senior Secured Second Lien Notes due 2024 and 6⅜% Convertible Senior Notes due 2024 of $25.7 million and $72.2 million, respectively, as of March 31, 2020.


(2)	Future interest payable represents most of the interest due over the terms of our 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 March 31, 2020 include $83.8 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 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 be accelerated to earlier dates in 2021 (February 12, 2021, May 14, 2021 or August 13, 2021) if certain defined liquidity ratios are not met, or if the 2021 Senior Secured Notes due in May 2021 or 2021 Senior Subordinated Notes due in August 2021 are not repaid or refinanced by each of their respective maturity dates. The borrowing base under the Bank Credit Agreement is evaluated semi-annually, generally around May 1 and November 1. As of May 13, 2020, the bank group has not yet completed the process for the spring redetermination, and therefore the borrowing base and commitment levels currently remain at $615 million. The Company currently anticipates that the bank group will complete the redetermination process over the next several weeks, and it is currently uncertain if there will be any change to the borrowing base or banks’ commitment levels. 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. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include borrowing base availability under the senior secured bank credit facility, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding.

As of March 31, 2020, we were in compliance with all debt covenants under the Bank Credit Agreement. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year. The above description of our Bank Credit Agreement and defined terms are contained in the Bank Credit Agreement and the amendments thereto.

2020 Repurchases of Senior Secured Notes

During March 2020, we repurchased a total of $30.2 million in aggregate principal amount of our 2021 Senior Secured Notes in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, we recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

Note 5. Income Taxes

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to provide certain taxpayer relief as a result of the COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the modified rules on the deductibility of business interest expense for 2019 and 2020, a five-year carryback period for net operating losses generated after 2017 and before 2021, and the acceleration of refundable alternative minimum tax credits.

Note 6. 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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2020, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of March 31, 2020, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:



Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range⁽¹⁾				Weighted Average Price
			Range⁽¹⁾				Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2020 Fixed-Price Swaps
Apr – Dec	NYMEX	13,500	$	36.25	–	61.00	$	40.52	$	—	$	—	$	—
Apr – Dec	Argus LLS	7,500		35.00	–	64.26	51.67		—		—		—
2020 Three-Way Collars⁽²⁾
Apr – June	NYMEX	11,500	$	55.00	–	82.65	$	—	$	47.95	$	57.18	$	63.44
Apr – June	Argus LLS	7,000		58.00	–	87.10	—		52.93		62.09		69.54
July – Dec	NYMEX	9,500		55.00	–	82.65	—		47.93		57.00		63.25
July – Dec	Argus LLS	5,000		58.00	–	87.10	—		52.80		61.63		70.35


(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 oil prices average less than the sold put price, our receipts on settlement would be limited to the difference between the floor price and the sold put price for the contracted volumes.

Note 7. Fair Value Measurements

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


•	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 and 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 December 31, 2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input.

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

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



	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
March 31, 2020
Assets
Oil derivative contracts – current	$	—	$	125,724		$	—		$	125,724
Total Assets	$	—	$	125,724		$	—		$	125,724

December 31, 2019
Assets
Oil derivative contracts – current	$	—	$	8,503		$	3,433		$	11,936
Total Assets	$	—	$	8,503		$	3,433		$	11,936

Liabilities
Oil derivative contracts – current	$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)
Total Liabilities	$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
In thousands	2020			2019
Fair value of Level 3 instruments, beginning of period	$	1,609		$	13,624
Transfers out of Level 3	(1,609		)	—
Fair value losses on commodity derivatives	—			(9,047		)
Receipts on settlements of commodity derivatives	—			(891		)
Fair value of Level 3 instruments, end of period	$	—		$	3,686

The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date	$	—		$	(6,481	)

Instruments previously categorized as Level 3 included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX, whereby the implied volatilities utilized were developed using a benchmark, which was considered a significant unobservable input. The transfers between Level 3 and Level 2 during the period generally relate to changes in the significant relevant observable and unobservable inputs that are available for the fair value measurements of such financial instruments.

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 March 31, 2020 and December 31, 2019, excluding pipeline financing obligations, was $490.4 million and $1,833.1 million, respectively, which decrease is primarily driven by a decrease in quoted market prices. 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 8. 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.

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages 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). 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 of the helium supply contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Briefing for the appeal by the Company and APMTG is currently expected to be completed in late May or early June, after which oral arguments are anticipated to be scheduled and heard prior to the Wyoming Supreme Court entering its judgment on the appeal. The timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to extend over the next six to nine months.

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 plus $5.7 million of associated costs (through March 31, 2020), for a total of $51.7 million, included in “Other liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020. The Company has a $32.8 million letter of credit posted as security in this case as part of the appeal process.

Note 9. Additional Balance Sheet Details

Trade and Other Receivables, Net



	March 31,		December 31,
In thousands	2020		2019
Commodity derivative settlement receivables	$	15,396	$	675
Trade accounts receivable, net	13,504		12,630
Federal income tax receivable, net	11,054		2,987
Other receivables	1,543		2,026
Total	$	41,497	$	18,318

Accounts Payable and Accrued Liabilities



	March 31,		December 31,
In thousands	2020		2019
Accounts payable	$	26,134	$	29,077
Accrued lease operating expenses	21,141		26,686
Accrued interest	16,176		25,253
Taxes payable	10,461		21,274
Accrued compensation	7,187		36,366
Accrued exploration and development costs	4,671		7,811
Other	20,776		37,365
Total	$	106,546	$	183,832

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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, 2019 (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 this Form 10-Q as well as 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 98% 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, for our most recent comparative periods:



	Three Months Ended
	March 31, 2020		December 31, 2019		March 31, 2019
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	45.96	$	56.58	$	56.50
Oil price per Bbl - including impact of derivative settlements	50.92		58.30		58.09

Recent Developments in Response to Oil Price Declines. In January and February 2020, NYMEX oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in early March 2020 due to the combination of OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 coronavirus (“COVID-19”) pandemic, resulting in NYMEX oil prices averaging approximately $30 per Bbl in March. NYMEX oil prices continued to decline in April 2020 to an average of $17 per Bbl in response to uncertainty about the duration of the COVID-19 pandemic and storage constraints in the United States resulting from over-supply of produced oil, which are also expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially longer. In response to these developments, we have implemented the following operational and financial measures:


•	Reduced budgeted 2020 capital spending by $80 million, or 44%, to approximately $95 million to $105 million;


•	Deferred the Cedar Creek Anticline CO₂ tertiary flood development project beyond 2020;


•	Implemented cost reduction measures including shutting down compressors or delaying well repairs and workovers that are uneconomic and by reducing performance-based compensation for employees; and

•

Restructured approximately 50% of our three-way collars covering 14,500 barrels per day (“Bbls/d”) into fixed-price swaps for the second quarter through fourth quarters of 2020 in order to increase downside protection. Our current hedge portfolio covers 39,500 Bbls/d for the second quarter of 2020 and 35,500 Bbls/d for the second half of 2020, with over half of those contracts consisting of fixed-price swaps and the remainder consisting of three-way collars.

As a result of these measures and due to continued uncertainty with respect to (1) future oil prices, (2) the duration, spread and severity of the COVID-19 pandemic in future periods, along with the impact of mitigation steps taken in response to the pandemic, (3) limitations in storage and/or takeaway capacity, or (4) the potential for voluntary or regulatory production curtailment actions, we have currently suspended our previously provided production and financial guidance for 2020, other than budgeted levels of development capital.

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Denbury Resources Inc.

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

Comparative Financial Results and Highlights. We recognized net income of $74.0 million, or $0.14 per diluted common share, during the first quarter of 2020, compared to a net loss of $25.7 million, or $0.06 per diluted common share, during the first quarter of 2019. The primary drivers of our change in operating results and per diluted share amounts were the following:


•	Oil and natural gas revenues decreased by $65.0 million (22%), with 18% of the decrease due to lower commodity prices and 4% of the decrease due to lower production, offset in part by an improvement in derivative commodity settlements of $16.4 million from the prior-year period;


•	Commodity derivatives expense improved by $230.1 million ($83.4 million of expense during the first quarter of 2019 compared to $146.8 million of income during the first quarter of 2020), resulting from a $213.7 million gain on noncash fair value changes and $16.4 million increase in cash receipts upon settlement between the first quarters of 2019 and 2020;


•	A $72.5 million full cost pool ceiling test write-down as a result of the impairment and transfer of $244.9 million of unevaluated costs to the full cost amortization base as a result of the decline in NYMEX oil prices, along with a $37.4 million accelerated depreciation charge related to impaired unevaluated properties (see Results of Operations – Depletion, Depreciation, and Amortization);


•	A noncash gain on debt extinguishment of $19.0 million in the first quarter of 2020 (see 2020 Repurchases of Senior Secured Notes below); and


•	Reductions across numerous expense categories, the most significant being $16.2 million in lease operating expenses, $9.2 million in general and administrative expenses, and $4.1 million in taxes other than income.

2020 Repurchases of Senior Secured Notes. During March 2020, we repurchased a total of $30.2 million in aggregate principal amount of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes) in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, we recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

Sale of Working Interests in Certain Texas Fields. On March 4, 2020, we closed the farm-down transaction for the sale of half of our nearly 100% working interest portion in four southeast Texas oil fields (consisting of Webster, Thompson, Manvel and East Hastings) for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser (the “Gulf Coast Working Interests Sale”). The sale had an effective date of January 1, 2019.

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, which has been supplemented most recently by the working interests sale in March 2020 and periodically by asset sale proceeds associated with sales of surface land with no active oil and natural gas operations. Our most significant cash outlays relate to our development capital expenditures, current period operating expenses, and our debt service obligations.

For the three months ended March 31, 2020, we generated cash flow from operations of $61.8 million, while incurring capital expenditures of $38.8 million and capitalized interest of $9.5 million, resulting in approximately $35 million of cash flow in excess of capital expenditures (excluding $42.9 million of working capital changes, but including $21.4 million of interest payments treated as a repayment of debt in our financial statements).

As discussed above, NYMEX oil prices have decreased significantly since the beginning of 2020, decreasing from nearly $60 per barrel in early January to around $25 per barrel in mid-May and considerably lower during the month of April 2020. This decrease in the market prices for our production directly reduce our operating cash flow and indirectly impact our other sources of potential liquidity, such as possibly lowering our borrowing capacity under our revolving credit facility, as our borrowing capacity and borrowing costs are generally related to the estimated value of our proved reserves.

In this low oil price environment, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted development capital spending by 44% from initial levels and to less than half of 2019 levels, (2) by continuing to focus on reducing our operating and overhead costs, and (3) by restructuring certain of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second through fourth quarters of 2020 to increase downside protection against current and potential further declines in oil prices.

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Denbury Resources Inc.

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

Although we have no significant maturities of debt in 2020, our significant maturities in 2021 and 2022 include $584.7 million of 2021 Senior Secured Notes maturing on May 15, 2021 and $455.7 million of 9¼% Senior Secured Second Lien Notes due 2022 maturing on March 31, 2022 (the “2022 Senior Secured Notes”).

Senior Secured Bank Credit Facility. In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (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 be accelerated to earlier dates in 2021 if certain defined liquidity ratios are not met, or if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”) are not repaid or refinanced by each of their respective maturity dates, as follows:


•	To February 12, 2021, if on that date the sum of the of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Secured Notes;


•	To May 14, 2021, if either (a) prior to that date the 2021 Senior Secured Notes have not been repaid or otherwise redeemed in full, or (b) on that date the sum of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Subordinated Notes; or


•	To August 13, 2021, if prior to that date the 2021 Senior Subordinated Notes have not been repaid or otherwise redeemed in full.

As of March 31, 2020, we had no outstanding borrowings on our $615 million senior secured bank credit facility, consistent with December 31, 2019, leaving us with $520.3 million of borrowing base availability after consideration of $94.7 million of letters of credit currently outstanding. The borrowing base under the Bank Credit Agreement is evaluated semi-annually, generally around May 1 and November 1. As of May 15, 2020, the bank group has not yet completed the process for the spring redetermination, and therefore the borrowing base and commitment levels currently remain at $615 million. The Company currently anticipates that the bank group will complete the redetermination process over the next several weeks, and it is currently uncertain if there will be any change to the borrowing base or banks’ commitment levels. 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 (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

As of March 31, 2020, we were in compliance with all debt covenants under the Bank Credit Agreement. Under these financial performance covenant calculations, as of March 31, 2020, our ratio of consolidated total debt to consolidated EBITDAX was 3.88 to 1.0 (with a maximum permitted ratio of 5.25 to 1.0), our consolidated senior secured debt to consolidated EBITDAX was 0.00 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 3.04 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was 4.11 to 1.0 (with a required ratio of not less than 1.0 to 1.0). However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year.

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.

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

Going Concern. Our senior secured bank credit facility and the indentures related to our senior secured second lien notes, senior convertible notes, and senior subordinated notes are subject to a variety of covenants. Throughout 2019 and the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance financial covenants, as well as covenants within our long-term note indentures. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year.

In this low oil price environment and period of uncertainty, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted development capital spending by 44% from initial levels and to less than half of 2019 levels, (2) by continuing to focus on reducing our operating and overhead costs, and (3) by restructuring certain of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second through fourth quarters of 2020 to increase downside protection against current and potential further declines in oil prices. As the ability to fund our full 2020 development capital budget with cash flow from operations and asset sale proceeds is dependent in part upon future commodity pricing, which we cannot predict nor control, we expect to fund any potential shortfall with incremental borrowings under our senior secured bank credit facility. There can be no assurances that we will be able to fund any potential shortfall with borrowings under our senior secured bank credit facility.

Capital Spending. We currently anticipate that our full-year 2020 capital spending, excluding capitalized interest and acquisitions, will be approximately $95 million to $105 million. This 2020 capital expenditure amount of between $95 million to $105 million, which was revised on March 31, 2020, excluding capitalized interest and acquisitions, is an $80 million, or 44%, reduction from the late-February 2020 estimate of between $175 million and $185 million in response to the more than 50% decline in NYMEX WTI prices during March 2020 as a result of the COVID-19 pandemic, which worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts, and continuing uncertainty about their combined economic impact, especially on oil demand and prices. Although OPEC+ has subsequently reached an agreement to curtail production, it is estimated that the near-term impact on global oil demand is significantly greater than the magnitude of production curtailments, and storage centers in the United States and around the world could potentially reach maximum storage levels. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. The 2020 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:


•	$35 million allocated for tertiary oil field expenditures;


•	$25 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;


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


•	$30 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
In thousands	2020		2019
Capital expenditure summary
Tertiary oil fields	$	14,726	$	26,028
Non-tertiary fields	10,954		21,674
Capitalized internal costs⁽¹⁾	8,881		11,890
Oil and natural gas capital expenditures	34,561		59,592
CO₂ pipelines, sources and other	4,224		1,571
Capital expenditures, before acquisitions and capitalized interest	38,785		61,163
Acquisitions of oil and natural gas properties	42		29
Capital expenditures, before capitalized interest	38,827		61,192
Capitalized interest	9,452		10,534
Capital expenditures, total	$	48,279	$	71,726


(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, 2019, 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 months ended March 31, 2020 and 2019 are included in the following table:



	Three Months Ended
	March 31,
In thousands, except per-share and unit data	2020			2019
Operating results
Net income (loss)⁽¹⁾	$	74,016		$	(25,674	)
Net income (loss) per common share – basic⁽¹⁾	0.15			(0.06		)
Net income (loss) per common share – diluted⁽¹⁾	0.14			(0.06		)
Net cash provided by operating activities	61,842			64,366
Average daily production volumes
Bbls/d	54,649			57,414
Mcf/d	7,899			10,827
BOE/d⁽²⁾	55,965			59,218
Operating revenues
Oil sales	$	228,577		$	291,965
Natural gas sales	1,047			2,612
Total oil and natural gas sales	$	229,624		$	294,577
Commodity derivative contracts⁽³⁾
Receipt on settlements of commodity derivatives	$	24,638		$	8,206
Noncash fair value gains (losses) on commodity derivatives⁽⁴⁾	122,133			(91,583		)
Commodity derivatives income (expense)	$	146,771		$	(83,377	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	45.96		$	56.50
Natural gas price per Mcf	1.46			2.68
Unit prices – including impact of derivative settlements⁽³⁾
Oil price per Bbl	$	50.92		$	58.09
Natural gas price per Mcf	1.46			2.68
Oil and natural gas operating expenses
Lease operating expenses	$	109,270		$	125,423
Transportation and marketing expenses	9,621			10,773
Production and ad valorem taxes	17,987			22,034
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	45.09		$	55.27
Lease operating expenses	21.46			23.53
Transportation and marketing expenses	1.89			2.02
Production and ad valorem taxes	3.53			4.13
CO₂ sources – revenues and expenses
CO₂ sales and transportation fees	$	8,028		$	8,570
CO₂ discovery and operating expenses	(752		)	(556		)
CO₂ revenue and expenses, net	$	7,276		$	8,014


(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $72.5 million for the three months ended March 31, 2020.


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

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

(4)

Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $24.6 million and $8.2 million for the three months ended March 31, 2020 and 2019, 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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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production

Average daily production by area for each of the four quarters of 2019 and for the first quarter of 2020 is shown below:



	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter
Operating Area	2019	2019	2019	2019	2020
Tertiary oil production
Gulf Coast region
Delhi	4,474	4,486	4,256	4,085	3,813
Hastings	5,539	5,466	5,513	5,097	5,232
Heidelberg	3,987	4,082	4,297	4,409	4,371
Oyster Bayou	4,740	4,394	3,995	4,261	3,999
Tinsley	4,659	4,891	4,541	4,343	4,355
West Yellow Creek	436	586	728	807	775
Mature properties⁽¹⁾	6,479	6,448	6,415	6,347	6,386
Total Gulf Coast region	30,314	30,353	29,745	29,349	28,931
Rocky Mountain region
Bell Creek	4,650	5,951	4,686	5,618	5,731
Salt Creek	2,057	2,078	2,213	2,223	2,149
Grieve	52	41	58	60	50
Total Rocky Mountain region	6,759	8,070	6,957	7,901	7,930
Total tertiary oil production	37,073	38,423	36,702	37,250	36,861
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	1,034	1,025	873	952	748
Texas	3,298	3,224	3,165	3,212	3,419
Other	10	6	6	5	6
Total Gulf Coast region	4,342	4,255	4,044	4,169	4,173
Rocky Mountain region
Cedar Creek Anticline	14,987	14,311	13,354	13,730	13,046
Other	1,313	1,305	1,238	1,192	1,105
Total Rocky Mountain region	16,300	15,616	14,592	14,922	14,151
Total non-tertiary production	20,642	19,871	18,636	19,091	18,324
Total continuing production	57,715	58,294	55,338	56,341	55,185
Property sales
Gulf Coast Working Interests Sale⁽²⁾	1,047	1,019	1,103	1,170	780
Citronelle⁽³⁾	456	406	—	—	—
Total production	59,218	59,719	56,441	57,511	55,965


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


(2)	Includes non-tertiary production related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields.


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

Total continuing production during the first quarter of 2020 averaged 55,185 BOE/d, including 36,861 Bbls/d from tertiary properties and 18,324 BOE/d from non-tertiary properties. Total continuing production excludes production related to the Gulf Coast Working Interests Sale completed in early March 2020 and, for prior-year periods, excludes production from Citronelle

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

Field sold in July 2019. This total continuing production level represents a decrease of 1,156 BOE/d (2%) compared to total continuing production levels in the fourth quarter of 2019 and a decrease of 2,530 BOE/d (4%) compared to first quarter of 2019 continuing production. The sequential and year-over-year decreases were most significantly attributable to production declines at Cedar Creek Anticline, partially offset by production increases from Bell Creek Field’s phase 5 development. Our production during the three months ended March 31, 2020 was 98% oil, slightly higher than our 97% oil production during the prior-year period.

As a result of the significant decline in oil prices, we have focused our efforts to optimize cash flow through evaluating production economics and shutting in production where validated. Beginning in late March and accelerating through April 2020, we estimate that approximately 2,000 BOE/d of uneconomic production was shut-in during April as a result of those efforts. In May 2020, we continued evaluations around expected oil prices and production costs, and have shut-in additional production, bringing the total shut-in production to approximately 8,500 BOE/d. We plan to continue this routine evaluation to assess levels of uneconomic production based on our expectations for wellhead oil prices and variable production costs and will actively make decisions to either shut-in additional production or bring production back online as conditions warrant. As a result of these actions, along with reduced capital and workover spend, we expect production to decline from the first quarter to the second quarter. Production could be further curtailed by future regulatory actions or limitations in storage and/or takeaway capacity.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2020 decreased 22% compared to these revenues for the same period in 2019. 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
	March 31,
	2020 vs. 2019
In thousands	Decrease in Revenues			Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(13,090	)	(4	)%
Decrease in realized commodity prices	(51,863		)	(18	)%
Total decrease in oil and natural gas revenues	$	(64,953	)	(22	)%

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

Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
	2020			2019
Average net realized prices
Oil price per Bbl	$	45.96		$	56.50
Natural gas price per Mcf	1.46			2.68
Price per BOE	45.09			55.27
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	1.18		$	4.26
Natural gas per Mcf	(0.06		)	(0.10		)
Rocky Mountain region
Oil per Bbl	$	(2.78	)	$	(2.56	)
Natural gas per Mcf	(0.91		)	(0.28		)
Total Company
Oil per Bbl	$	(0.38	)	$	1.63
Natural gas per Mcf	(0.41		)	(0.20		)

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 $1.18 per Bbl and $4.26 per Bbl during the first quarters of 2020 and 2019, respectively, and a positive $0.90 per Bbl during the fourth 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 weakened over the past year, although Gulf Coast region differentials slightly increased between the fourth quarter of 2019 and first quarter of 2020.

•

Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $2.78 per Bbl and $2.56 per Bbl below NYMEX during the first quarters of 2020 and 2019, respectively, and $2.48 per Bbl below NYMEX during the fourth 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.

The discussion above does not reflect the rapid and precipitous drop in demand for oil caused by the COVID-19 pandemic, which in turn has caused oil prices to plummet since the first week of March 2020. These events have worsened a deteriorated oil market which followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has caused storage constraints resulting from over-supply of produced oil and reduced refinery run rates, all of which currently are expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially longer. Oil prices are expected to continue to be volatile as a result of these events, and as changes in oil inventories, oil demand and economic performance are reported.

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.

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Denbury Resources Inc.

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

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
In thousands	2020		2019
Receipt on settlements of commodity derivatives	$	24,638	$	8,206
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	122,133		(91,583		)
Total income (expense)	$	146,771	$	(83,377	)


(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 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of March 31, 2020, 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 May 14, 2020:



		2Q 2020	2H 2020
WTI NYMEX	Volumes Hedged (Bbls/d)	13,500	13,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$40.52	$40.52
Argus LLS	Volumes Hedged (Bbls/d)	7,500	7,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$51.67	$51.67
WTI NYMEX	Volumes Hedged (Bbls/d)	11,500	9,500
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$47.95 / $57.18 / $63.44	$47.93 / $57.00 / $63.25
Argus LLS	Volumes Hedged (Bbls/d)	7,000	5,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$52.93 / $62.09 / $69.54	$52.80 / $61.63 / $70.35
	Total Volumes Hedged (Bbls/d)	39,500	35,500


(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 May 14, 2020, which averaged approximately $29 per Bbl, we currently expect that we would receive cash payments of approximately $135 million upon settlement of our April through December 2020 contracts. Of this estimated amount, the majority relates to our fixed-price swaps, which settlement amount is dependent upon fluctuations in future oil prices in relation to the prices of our 2020 fixed-price swaps which have weighted average prices of $40.52 per Bbl and $51.67 per Bbl for NYMEX and LLS hedges, respectively. Settlements with respect

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

to our 2020 three-way collars are currently limited to the extent oil prices remain below the price of our sold puts. The weighted average differences between the floor and sold put prices of our 2020 three-way collars are $9.13 per Bbl and $8.97 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.

Production Expenses

Lease Operating Expenses



	Three Months Ended
	March 31,
In thousands, except per-BOE data	2020		2019
Total lease operating expenses	$	109,270	$	125,423

Total lease operating expenses per BOE	$	21.46	$	23.53

Total lease operating expenses decreased $16.2 million (13%) on an absolute-dollar basis, or $2.07 (9%) on a per-BOE basis, during the three months ended March 31, 2020, compared to the same prior-year period. The decrease on an absolute-dollar basis was primarily due to lower expenses across nearly all expense categories, with the largest decreases in workover expense, CO₂ purchase expense, and power and fuel costs. Compared to the fourth quarter of 2019, lease operating expenses decreased $6.7 million (6%) on an absolute-dollar basis primarily due to lower company and contract labor, but decreased $0.47 (2%) on a per-BOE basis due to lower production in the first quarter of 2020.

Currently, our CO₂ expense comprises approximately 20% of our typical tertiary lease operating expenses, and for the CO₂ reserves we already own, consists of CO₂ production expenses, and for the CO₂ reserves we do not own, consists of our purchase of CO₂ from royalty and working interest owners and industrial sources. During the first quarters of 2020 and 2019, approximately 52% and 56%, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us (our net revenue interest). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what we pay third parties for CO₂, our average cost of CO₂ was approximately $0.36 per Mcf during the first quarter of 2020, 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 first quarter of 2020 was lower than the $0.39 per Mcf comparable measure during the first quarter of 2019 due to a decrease in the costs of industrial-sourced CO₂ in the Rocky Mountain region, but higher than the $0.34 per Mcf comparable measure during the fourth quarter of 2019 due to higher utilization of industrial-sourced CO₂ in our operations, 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 $9.6 million and $10.8 million for the three months ended March 31, 2020 and 2019, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $4.1 million (17%) during the three months ended March 31, 2020, compared to the same prior-year period, 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
	March 31,
In thousands, except per-BOE data and employees	2020			2019
Gross cash compensation and administrative costs	$	40,436		$	54,701
Gross stock-based compensation	3,204			4,306
Operator labor and overhead recovery charges	(27,485		)	(29,875		)
Capitalized exploration and development costs	(6,422		)	(10,207		)
Net G&A expense	$	9,733		$	18,925

G&A per BOE
Net cash administrative costs	$	1.43		$	2.94
Net stock-based compensation	0.48			0.61
Net G&A expenses	$	1.91		$	3.55

Employees as of March 31	718			843

Our net G&A expenses on an absolute-dollar basis decreased $9.2 million (49%), or $1.64 (46%) on a per-BOE basis, during the three months ended March 31, 2020 compared to the same period in 2019, primarily due to reduced employee headcount resulting from our December 2019 voluntary separation program and reductions 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
	March 31,
In thousands, except per-BOE data and interest rates	2020			2019
Cash interest⁽¹⁾	$	45,826		$	47,948
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾	(21,354		)	(21,279		)
Noncash interest expense	1,031			1,263
Amortization of debt discount⁽²⁾	3,895			—
Less: capitalized interest	(9,452		)	(10,534		)
Interest expense, net	$	19,946		$	17,398
Interest expense, net per BOE	$	3.92		$	3.26
Average debt principal outstanding⁽³⁾	$	2,187,615		$	2,540,628
Average cash interest rate⁽⁴⁾	8.4		%	7.5		%

(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 and 2022 Senior Secured Notes. See below for further discussion.

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


(2)	Represents amortization of debt discounts of $1.3 million and $2.6 million related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) during the three months ended March 31, 2020, 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 months ended March 31, 2020 decreased $2.1 million (4%) when compared to the prior-year period due primarily to a decrease in our average debt principal outstanding as a result of the June 2019 debt exchange transactions and debt repurchases completed in the second half of 2019 and first quarter of 2020. Meanwhile, net interest expense increased $2.5 million (15%) due to the amortization of the debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes and a decrease in capitalized interest as a result of a reduction in the number of projects that qualify for interest capitalization.

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 $143.7 million as of March 31, 2020. Therefore, interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be approximately $84 million lower annually than the actual cash interest payments on our 2021 Senior Secured Notes and 2022 Senior Secured Notes.

The June 2019 debt exchange transactions were accounted for in accordance with FASC 470-50, Modifications and Extinguishments, whereby our 7¾% Senior Secured Notes and 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 7¾% Senior Secured Notes and 2024 Convertible Senior Notes by approximately $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
	March 31,
In thousands, except per-BOE data	2020		2019
Oil and natural gas properties	$	42,569	$	36,835
CO₂ properties, pipelines, plants and other property and equipment	16,925		20,462
Accelerated depreciation charge⁽¹⁾	37,368		—
Total DD&A	$	96,862	$	57,297

DD&A per BOE
Oil and natural gas properties	$	8.36	$	6.91
CO₂properties, pipelines, plants and other property and equipment	3.32		3.84
Accelerated depreciation charge⁽¹⁾	7.34		—
Total DD&A cost per BOE	$	19.02	$	10.75

Write-down of oil and natural gas properties	$	72,541	$	—


(1)	Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.

The increase in our oil and natural gas properties depletion during the three months ended March 31, 2020, when compared to the same period in 2019, was primarily due to a decrease in proved oil and natural gas reserve volumes. In addition, we recorded accelerated depreciation of $37.4 million related to impaired unevaluated properties that were transferred to the full cost pool.

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

Full Cost Pool Ceiling Test

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. NYMEX prices decreased precipitously in the first quarter of 2020, ending the period at $20.48 per Bbl, with representative oil and natural gas prices used in estimating our March 31, 2020 reserves averaging $55.17 per Bbl for crude oil and $1.68 per MMBtu for natural gas, after adjustments for market differentials by field. While representative oil prices utilized were roughly consistent with adjusted prices used to calculate the December 31, 2019 full cost ceiling value, the decline in NYMEX oil prices in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic contributed to the impairment and transfer of $244.9 million of our unevaluated costs to the full cost amortization base during the three months ended March 31, 2020. Primarily as a result of adding these additional costs to the amortization base, we recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020. If oil prices were to remain at or near early-May 2020 levels in subsequent periods, we currently expect that we would also record significant write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020. The possibility and amount of any future write-down or impairment is difficult to predict, and will depend, in part, upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures and operating costs.

Impairment Assessment of Long-lived Assets

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices (management’s assumption of 2020 oil prices at strip pricing, gradually increasing to a long-term oil price of $65 per Bbl beginning in 2026, and gas futures pricing were used for the March 31, 2020 analysis), projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows.

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

Income Taxes



	Three Months Ended
	March 31,
In thousands, except per-BOE amounts and tax rates	2020			2019
Current income tax benefit	$	(6,407	)	$	(1,281	)
Deferred income tax benefit	(4,209		)	(9,478		)
Total income tax benefit	$	(10,616	)	$	(10,759	)
Average income tax benefit per BOE	$	(2.09	)	$	(2.02	)
Effective tax rate	(16.7		)%	29.5		%
Total net deferred tax liability	$	406,021		$	300,280

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 2020 and 2019. Our effective tax rate for the three months ended March 31, 2020 was lower than our estimated statutory rate, primarily due to the full release of a valuation allowance against a portion of our business interest expense deduction that we previously estimated would be disallowed, offset by the establishment of a valuation allowance on a portion of our enhanced oil recovery credits that currently are not expected to be utilized. The Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) signed into law in March 2020, among other provisions, modified the rules regarding the deductibility of business interest expense that were established by the Tax Cuts and Jobs Act of December 2017, increasing the limitation threshold from 30% to 50% of Adjusted Taxable Income (as defined) for 2019 and 2020. In addition, for the 2020 year, a taxpayer may elect to use its 2019 Adjusted Taxable Income in lieu of its 2020 Adjusted Taxable Income. Due to these modifications, we now expect to fully deduct our business interest expense in 2018, 2019 and 2020 and have fully released our previously recorded valuation allowance of $24.5 million during the three months ended March 31, 2020. We evaluated all of our deferred tax assets in consideration of the CARES Act provisions and the book full cost pool ceiling test write-down and accelerated depreciation charge recorded in the financial statements for the period ended March 31, 2020. 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 enhanced oil recovery credits (expiring in 2024), we have established a valuation allowance of $11.0 million for the portion of our enhanced oil recovery credits that is currently not expected to be realized.

The current income tax benefits for the three months ended March 31, 2020 and 2019, represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

As of March 31, 2020, after adjusting our attribute balances due to the CARES Act, we had estimated amounts available for carry forward of $54.2 million of enhanced oil recovery credits related to our tertiary operations, $21.6 million of research and development credits, and $11.1 million of alternative minimum tax credits. The alternative minimum tax credits are currently recorded as a receivable on the balance sheet. The enhanced oil recovery credits and research and development credits do not begin to expire until 2024 and 2031, respectively.

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

Per-BOE Data

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



	Three Months Ended
	March 31,
Per-BOE data	2020			2019
Oil and natural gas revenues	$	45.09		$	55.27
Receipt on settlements of commodity derivatives	4.84			1.54
Lease operating expenses	(21.46		)	(23.53		)
Production and ad valorem taxes	(3.53		)	(4.13		)
Transportation and marketing expenses	(1.89		)	(2.02		)
Production netback	23.05			27.13
CO₂ sales, net of operating and exploration expenses	1.43			1.51
General and administrative expenses	(1.91		)	(3.55		)
Interest expense, net	(3.92		)	(3.26		)
Other	1.92			0.53
Changes in assets and liabilities relating to operations	(8.43		)	(10.28		)
Cash flows from operations	12.14			12.08
DD&A – excluding accelerated depreciation charge	(11.68		)	(10.75		)
DD&A – accelerated depreciation charge⁽¹⁾	(7.34		)	—
Write-down of oil and natural gas properties	(14.24		)	—
Deferred income taxes	0.83			1.78
Gain on extinguishment of debt	3.73			—
Noncash fair value gains (losses) on commodity derivatives⁽²⁾	23.98			(17.18		)
Other noncash items	7.11			9.25
Net income (loss)	$	14.53		$	(4.82	)


(1)	Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.


(2)	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,

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

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 refinance or extend the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs of oil and natural gas reserves and the effect of these factors upon our ability to continue as a going concern, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations 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, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, the extent and length of the drop in worldwide oil demand due to the COVID-19 coronavirus, 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 plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility and the related impact on our ability to continue as a going concern, our ability to refinance our senior debt maturing in 2021 and the related impact on our ability to continue as a going concern, the outcome of any discussions with our lenders and bondholders regarding the terms of a potential restructuring of our indebtedness or recapitalization of the Company and any resulting dilution for our stockholders, 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 and maturity dates of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; access to and 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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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

As of March 31, 2020, we had $2.1 billion of fixed-rate long-term debt outstanding and no outstanding borrowings on our variable-rate senior secured bank credit facility. 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 March 31, 2020.



In thousands	2021		2022		2023		2024		Total		Fair Value
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	$	584,709	$	—	$	—	$	—	$	584,709	$	172,168
9¼% Senior Secured Second Lien Notes due 2022	—		455,668		—		—		455,668		112,819
7¾% Senior Secured Second Lien Notes due 2024	—		—		—		531,821		531,821		79,029
7½% Senior Secured Second Lien Notes due 2024	—		—		—		20,641		20,641		2,942
6⅜% Convertible Senior Notes due 2024	—		—		—		245,548		245,548		103,118
6⅜% Senior Subordinated Notes due 2021	51,304		—		—		—		51,304		8,053
5½% Senior Subordinated Notes due 2022	—		58,426		—		—		58,426		2,496
4⅝% Senior Subordinated Notes due 2023	—		—		135,960		—		135,960		9,778

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 6, Commodity Derivative Contracts, and Note 7, 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.

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.

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At March 31, 2020, our commodity derivative contracts were recorded at their fair value, which was a net asset of $125.7 million, a $122.1 million increase from the $3.6 million net asset recorded at December 31, 2019. These changes are primarily related to the expiration or early termination of commodity derivative contracts during the three months ended March 31, 2020, new commodity derivative contracts entered into during 2020 for future periods, and to the changes in oil futures prices between December 31, 2019 and March 31, 2020.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of March 31, 2020, and assuming both a 10% increase and decrease thereon, we would expect to receive payments on our crude oil derivative contracts outstanding at March 31, 2020 as shown in the following table:



	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts
Based on:
Futures prices as of March 31, 2020	$	127,641
10% increase in prices	110,749
10% decrease in prices	144,518

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2020, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the first quarter of fiscal 2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, litigation is subject to inherent uncertainties. 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

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, 2019. 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, 2019, other than as detailed below.

The current outbreak of COVID-19 has adversely impacted our business, financial condition, liquidity and results of operations and is likely to have a continuing adverse impact for a significant period of time.

The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. These events have worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.

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The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since early March 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. Although we have reduced our 2020 capital expenditures budget by 44%, our lower levels of cash flow could affect our borrowing capacity and have required us to shut-in production that has become uneconomic. These conditions have also increased the difficulty in repaying, refinancing or restructuring our long-term debt, which is necessary in order to maintain our continuing financial viability, as separately described in the other risk factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand. The COVID-19 pandemic may also intensify the risks described in the other risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Oil prices remaining at current levels will significantly reduce our cash flow and liquidity to a degree that threatens our continued financial viability.

Beginning in the first week of March 2020, the simultaneous surplus in world oil market supply (Saudi Arabia oil production hikes following OPEC+ production cut disagreements) and significant reduction in demand (as the scope of the spread, severity and resulting containment efforts of the COVID-19 pandemic became clear) have caused oil prices to plummet. NYMEX oil prices averaged approximately $22 per Bbl during the last 10 trading days of March 2020, continuing to decline to an average of $17 per Bbl in April 2020 before increasing slightly to an average of $24 per Bbl during the first 10 trading days of May 2020.

As previously described in “Risk Factors” under Item 1A of our 2019 annual report on Form 10-K filed with the SEC on February 27, 2020, oil prices are the most important determinant of our operational and financial success. The reduction in our cash flows from operations since early March 2020, and the possibility of a continued reduction in cash flows for an indeterminant period of time, impairs our ability to make budgeted property development expenditures to support our oil production, pay oilfield operating expenses, and pay interest on our outstanding debt. Secondarily, this level of reduced cash flow may affect our ability to borrow under our senior secured credit facility, could require us to shut-in uneconomic production, or further impair the carrying value of our oil and natural gas reserves.

Moreover, on a long-term basis, it is difficult to predict the impact of the COVID-19 pandemic on the level of future economic activity, which will affect future demand for oil, and consequently, our business.

We have engaged advisers to assist us in, among other things, analyzing various alternatives to address our liquidity and capital structure.

We have engaged advisors to assist us in, among other things, analyzing various alternatives to address our liquidity and capital structure. We may seek to extend our maturities and/or reduce the overall principal amount of our debt through exchange offers, other liability management, recapitalization and/or restructuring transactions. As part of the evaluation of alternatives, we also are engaged in discussions with our lenders and bondholders regarding a potential comprehensive restructuring of our indebtedness. Any comprehensive restructuring of our indebtedness and capital structure may require a substantial impairment or conversion of our indebtedness to equity, as well as impairment, losses or substantial dilution for our stockholders and other stakeholders, which may result in our stockholders receiving minimal, if any, recovery for their existing shares and may place our stockholders at significant risk of losing some or all of their investment.

The outcome of our restructuring discussions and other efforts to address our liquidity and capital structure is uncertain and could adversely affect our business, financial condition and results of operations.

Our potential inability to comply with the financial covenants in our senior secured bank credit facility or to repay, refinance or restructure our notes due in 2021 have raised substantial doubt about our ability to continue as a going concern.

Our senior secured bank credit facility is subject to a variety of covenants. Throughout 2019 and the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance

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Denbury Resources Inc.

financial covenants. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year. Additionally, these conditions have substantially diminished our ability to repay, refinance, or restructure our $584.7 million outstanding principal balance of 2021 Senior Secured Notes. Our ability to satisfy the maintenance financial covenants in our senior secured bank credit facility and refinance or repay our 2021 Senior Secured Notes have raised substantial doubt about our ability to continue as a going concern.

An inability to repay, refinance or restructure our 2021 Senior Secured Notes or our inability to comply with the required financial ratios or financial condition tests under our senior secured bank credit facility could result in the acceleration of all such indebtedness and cross-default our other debt. If that should occur, we would likely be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If the amounts outstanding under our senior secured bank credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.

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

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the first quarter of 2020:



Month	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)⁽²⁾
January 2020	2,531	$	0.99	—	$	210.1
February 2020	1,553	0.91		—	210.1
March 2020	171,589	0.18		—	210.1
Total	175,673			—


(1)	Shares purchased during the first quarter of 2020 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. The last repurchases under this program took place in October 2015. 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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Item 6. Exhibits



Exhibit No.		Exhibit
3		Third Amended and Restated Bylaws of Denbury Resources Inc., as of March 26, 2020 (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on March 31, 2020, File No. 001-12935).
10(a)*		2020 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)*		2020 Form of TSR Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.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 March 31, 2020, has been formatted in Inline XBRL.


*	Included herewith.

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SIGNATURES

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



		DENBURY RESOURCES INC.

May 18, 2020		/s/ Mark C. Allen
		Mark C. Allen Executive Vice President and Chief Financial Officer

May 18, 2020		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer