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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
OR

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

For the transition period from _______ to ________

Commission file number: 001-12935
logo.jpg
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.


Table of Contents

 
 
 
 
 
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019
 
 
 
 
 
 
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



3


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.


4


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

CO2 sales 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.


5


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.


6


Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity
(Dollar amounts in thousands)

 
Common Stock
($.001 Par Value)
 
Paid-In
Capital in
Excess of
Par
 
Retained
Earnings (Accumulated Deficit)
 
Treasury Stock
(at cost)
 
 
 
Shares
 
Amount
Shares
 
Amount
Total Equity
Balance – December 31, 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
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.


7


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


8


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.



9


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


10


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).



11


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.



12


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





13


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.


14


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.

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, differed from our estimated statutory rate, primarily due to tax changes enacted by the CARES Act which resulted in the full release of a $24.5 million 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.

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


15


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
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:


16


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.



17


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


18


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





19


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.



20


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.



21


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.

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. 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.



22


Denbury Resources Inc.
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.

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.

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.


23


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations


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


24


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

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


25


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating Results Table

Certain of our operating results and statistics for the comparative three months ended March 31, 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”).


26


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

(3)
See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.
(4)
Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were 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.


27


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production

Average daily production by area for each of the four quarters of 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


28


Denbury Resources Inc.
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
)%



29


Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

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