10-Q 1 dnr-20150331x10q.htm FORM 10-Q DNR - 2015.03.31 - 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
þ   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2015
OR

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

For the transition period from _______ to ________

Commission file number: 001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)

Delaware
 
20-0467835
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
5320 Legacy Drive,
Plano, TX
 
 
75024
(Address of principal executive offices)
 
(Zip Code)

Registrant's telephone number, including area code:
 
(972) 673-2000

Not applicable
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller reporting company)
 

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
 
 
 
Class
 
Outstanding at April 30, 2015
Common Stock, $.001 par value
 
356,932,779





Denbury Resources Inc.


Table of Contents

 
 
 
 
 
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


- 2 -

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements


Denbury Resources Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
 
 
March 31,
 
December 31,
 
 
2015
 
2014
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
6,021

 
$
23,153

Accrued production receivable
 
148,125

 
181,761

Trade and other receivables, net
 
139,904

 
156,955

Derivative assets
 
421,702

 
440,359

Deferred tax assets
 
42,268

 

Other current assets
 
10,634

 
10,452

Total current assets
 
768,654

 
812,680

Property and equipment
 
 

 
 

Oil and natural gas properties (using full cost accounting)
 
 

 
 

Proved properties
 
9,873,513

 
9,782,337

Unevaluated properties
 
933,566

 
918,406

CO2 properties
 
1,171,815

 
1,162,538

Pipelines and plants
 
2,272,184

 
2,269,564

Other property and equipment
 
465,886

 
468,051

Less accumulated depletion, depreciation, amortization and impairment
 
(4,536,890
)
 
(4,248,652
)
Net property and equipment
 
10,180,074

 
10,352,244

Derivative assets
 
19,456

 
66,187

Goodwill
 
1,283,590

 
1,283,590

Other assets
 
216,282

 
213,101

Total assets
 
$
12,468,056

 
$
12,727,802

Liabilities and Stockholders' Equity
 
 
 
 
Current liabilities
 
 

 
 

Accounts payable and accrued liabilities
 
$
234,541

 
$
394,758

Oil and gas production payable
 
110,454

 
128,170

Deferred tax liabilities
 

 
81,727

Current maturities of long-term debt
 
36,679

 
35,470

Total current liabilities
 
381,674

 
640,125

Long-term liabilities
 
 

 
 

Long-term debt, net of current portion
 
3,596,085

 
3,535,900

Asset retirement obligations
 
128,599

 
126,411

Deferred tax liabilities
 
2,752,857

 
2,694,842

Other liabilities
 
25,360

 
26,668

Total long-term liabilities
 
6,502,901

 
6,383,821

Commitments and contingencies (Note 6)
 


 


Stockholders' equity
 
 
 
 
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
 

 

Common stock, $.001 par value, 600,000,000 shares authorized; 415,665,644 and 411,779,911 shares issued, respectively
 
416

 
412

Paid-in capital in excess of par
 
3,238,914

 
3,230,418

Retained earnings
 
3,262,508

 
3,392,465

Accumulated other comprehensive loss
 
(192
)
 
(209
)
Treasury stock, at cost, 58,651,623 and 58,415,507 shares, respectively
 
(918,165
)
 
(919,230
)
Total stockholders' equity
 
5,583,481

 
5,703,856

Total liabilities and stockholders' equity
 
$
12,468,056

 
$
12,727,802

 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

- 3 -

Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)

 
 
Three Months Ended March 31,
 
 
2015
 
2014
Revenues and other income
 
 
 
 
Oil, natural gas, and related product sales
 
$
297,470

 
$
623,846

CO2 and helium sales and transportation fees
 
6,972

 
10,761

Interest income and other income
 
3,207

 
7,137

Total revenues and other income
 
307,649

 
641,744

Expenses
 
 

 
 

Lease operating expenses
 
141,084

 
170,379

Marketing and plant operating expenses
 
11,685

 
16,786

CO2 and helium discovery and operating expenses
 
947

 
5,205

Taxes other than income
 
26,679

 
45,945

General and administrative expenses
 
46,280

 
43,693

Interest, net of amounts capitalized of $8,409 and $5,756, respectively
 
40,099

 
48,834

Depletion, depreciation, and amortization
 
149,958

 
141,130

Commodity derivatives expense (income)
 
(83,076
)
 
76,669

Write-down of oil and natural gas properties
 
146,200

 

Total expenses
 
479,856

 
548,641

Income (loss) before income taxes
 
(172,207
)
 
93,103

Income tax provision (benefit)
 
(64,461
)
 
34,793

Net income (loss)
 
$
(107,746
)
 
$
58,310

 
 
 
 
 
Net income (loss) per common share
 
 
 
 
Basic
 
$
(0.31
)
 
$
0.17

Diluted
 
$
(0.31
)
 
$
0.17

 
 
 
 
 
Dividends declared per common share
 
$
0.0625

 
$
0.0625

 
 
 
 
 
Weighted average common shares outstanding
 
 

 
 

Basic
 
350,688

 
350,747

Diluted
 
350,688

 
352,925


See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

- 4 -

Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Comprehensive Operations
(In thousands)

 
 
Three Months Ended March 31,
 
 
2015
 
2014
Net income (loss)
 
$
(107,746
)
 
$
58,310

Other comprehensive income, net of income tax:
 
 

 
 

Interest rate lock derivative contracts reclassified to income, net of tax of $11 and $13, respectively
 
17

 
15

Total other comprehensive income
 
17

 
15

Comprehensive income (loss)
 
$
(107,729
)
 
$
58,325

 
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,
 
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
(107,746
)
 
$
58,310

Adjustments to reconcile net income (loss) to cash flows from operating activities
 
 
 
 

Depletion, depreciation, and amortization
 
149,958

 
141,130

Write-down of oil and natural gas properties
 
146,200

 

Deferred income taxes
 
(66,036
)
 
30,175

Stock-based compensation
 
7,849

 
8,346

Commodity derivatives expense (income)
 
(83,076
)
 
76,669

Settlements of commodity derivatives
 
148,465

 
(27,169
)
Amortization of debt issuance costs and discounts
 
2,221

 
3,520

Other, net
 
(2,359
)
 
(2,297
)
Changes in assets and liabilities, net of effects from acquisitions
 
 

 
 

Accrued production receivable
 
33,636

 
(24,937
)
Trade and other receivables
 
16,828

 
6,372

Other current and long-term assets
 
(6,136
)
 
(5,459
)
Accounts payable and accrued liabilities
 
(83,248
)
 
(52,580
)
Oil and natural gas production payable
 
(17,716
)
 
3,916

Other liabilities
 
(1,076
)
 
(1,138
)
Net cash provided by operating activities
 
137,764

 
214,858

 
 
 
 
 
Cash flows from investing activities
 
 

 
 

Oil and natural gas capital expenditures
 
(162,192
)
 
(198,237
)
Acquisitions of oil and natural gas properties
 
(261
)
 

CO2 capital expenditures
 
(14,855
)
 
(15,909
)
Pipelines and plants capital expenditures
 
(12,455
)
 
(22,597
)
Purchases of other assets
 
(2,965
)
 
(1,645
)
Other
 
150

 
1,634

Net cash used in investing activities
 
(192,578
)
 
(236,754
)
 
 
 
 
 
Cash flows from financing activities
 
 

 
 

Bank repayments
 
(595,000
)
 
(815,000
)
Bank borrowings
 
665,000

 
1,075,000

Common stock repurchase program
 

 
(211,356
)
Cash dividends paid
 
(22,068
)
 
(21,727
)
Other
 
(10,250
)
 
(9,316
)
Net cash provided by financing activities
 
37,682

 
17,601

Net decrease in cash and cash equivalents
 
(17,132
)
 
(4,295
)
Cash and cash equivalents at beginning of period
 
23,153

 
12,187

Cash and cash equivalents at end of period
 
$
6,021

 
$
7,892


See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

- 6 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


Note 1. Basis of Presentation

Organization and Nature of Operations

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014 (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, 2015, our consolidated results of operations for the three months ended March 31, 2015 and 2014, and our consolidated cash flows for the three months ended March 31, 2015 and 2014.

Reclassifications

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

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of stock options, stock appreciation rights ("SARs"), nonvested restricted stock and nonvested performance-based equity awards.  For the three months ended March 31, 2015 and 2014, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2015
 
2014
Basic weighted average common shares outstanding
 
350,688

 
350,747

Potentially dilutive securities
 
 

 
 

Restricted stock, stock options, SARs and performance-based equity awards
 

 
2,178

Diluted weighted average common shares outstanding
 
350,688

 
352,925



- 7 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all non-performance-based restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares during the three months ended March 31, 2014, the nonvested restricted stock, stock options, SARs, and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity.

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
 
2015
 
2014
Stock options and SARs
 
10,507

 
4,254

Restricted stock and performance-based equity awards
 
2,948

 
21


Oil and Natural Gas Properties

Ceiling Test. 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 those costs have previously been incurred by the Company. 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 $146.2 million during the three months ended March 31, 2015, with first-day-of-the-month prices for the preceding 12 months, after adjustments for market differentials by field, of $79.55 per Bbl for crude oil and $3.95 per Mcf for natural gas. If oil prices remain at or near late-April 2015 levels in subsequent periods, we expect that we could record significantly larger 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 2015.

Goodwill

We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of March 31, 2015. Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of March 31, 2015, we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on March 31, 2015, NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment significantly exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the first quarter of 2015, nor have we recorded a goodwill impairment historically.


- 8 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Recent Accounting Pronouncements

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. Management is currently assessing the impact the adoption of ASU 2015-03 will have on our consolidated financial statements.
 
Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination, and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect on our consolidated financial statements.

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2017, and early adoption is prohibited. However, in April 2015, the FASB proposed delaying the effective date for one year. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 will have on our consolidated financial statements.
 
Note 2. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
 
 
March 31,
 
December 31,
In thousands
 
2015
 
2014
Bank Credit Agreement
 
$
465,000

 
$
395,000

6⅜% Senior Subordinated Notes due 2021
 
400,000

 
400,000

5½% Senior Subordinated Notes due 2022
 
1,250,000

 
1,250,000

4⅝% Senior Subordinated Notes due 2023
 
1,200,000

 
1,200,000

Other Subordinated Notes, including premium of $10 and $11, respectively
 
2,744

 
2,746

Pipeline financings
 
218,486

 
220,583

Capital lease obligations
 
96,534

 
103,041

Total
 
3,632,764

 
3,571,370

Less: current obligations
 
(36,679
)
 
(35,470
)
Long-term debt and capital lease obligations
 
$
3,596,085

 
$
3,535,900



- 9 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

The ultimate parent company in our corporate structure, Denbury Resources Inc. ("DRI"), is the sole issuer of all of our outstanding 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 certain of such notes are minor subsidiaries.

Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the "Bank Credit Agreement"). The Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base of $3.0 billion and aggregate lender commitments of $1.6 billion. Loans under the Bank Credit Agreement mature in December 2019. The weighted average interest rate on borrowings outstanding as of March 31, 2015, under the Bank Credit Agreement was 1.5%. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee ranging from 0.3% to 0.375% per annum. As of March 31, 2015, we were in compliance with all debt covenants under the Bank Credit Agreement.

In connection with the borrowing base redetermination completed in early May 2015 under our Bank Credit Agreement, we elected to maintain our aggregate lender commitments at $1.6 billion; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion. Because we continue to maintain a significant cushion between our borrowing base and the aggregate lender commitments, this borrowing base reduction has no impact on our liquidity. Redeterminations under our Bank Credit Agreement occur annually, making our next scheduled redetermination in May 2016.

In conjunction with the May 2015 redetermination, we also entered into the First Amendment to the Bank Credit Agreement (the "First Amendment"). This First Amendment restructures certain financial covenants in 2016, 2017, and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows:

In 2016 and 2017, suspend the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant of 4.25 to 1.0 and replace it with a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 2.5 to 1.0 during the same time period. Currently, only debt under our Bank Credit Agreement would be considered consolidated senior secured debt for purposes of this ratio.
Beginning in the first quarter of 2018, reinstate the ratio of consolidated total net debt to consolidated EBITDAX covenant utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ended March 31, 2018, 5.5 to 1.0 for the second quarter ended June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ended September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ended March 31, 2019.
In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0.

The restructuring of covenants through the First Amendment were executed in consideration of a fee paid to the lenders. The First Amendment has no impact on the current ratio financial performance covenant, which will remain in place in 2015 and beyond. All of the above descriptions of financial covenants are qualified by the express language and defined terms contained in the Bank Credit Agreement filed on December 15, 2014, as Exhibit 10.1 to our Current Report on Form 8-K or the First Amendment, which is filed as Exhibit 10(a) to this Quarterly Report on Form 10-Q.

Note 3. Stockholders' Equity

Dividends

During January of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share. Dividends totaling $22.1 million and $21.7 million were paid to stockholders during the three months ended March 31, 2015 and 2014, respectively. See Note 8, Subsequent Event, for details regarding the dividend declared and to be paid in the second quarter of 2015.

- 10 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


Stock Repurchase Program

Under our board-authorized share repurchase program, we repurchased 12.4 million shares of Denbury common stock for $200.4 million during the first quarter of 2014. In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty and to protect our financial position.

Employee Stock Purchase Program

We previously provided for an Employee Stock Purchase Plan (the "Plan") in which funds from eligible employees, together with Company contributions, were used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter. The Plan was terminated, effective at the end of the offering period ending on March 31, 2015, as all of the previously authorized shares reserved for issuance under the Plan had been issued.

Note 4. Commodity Derivative Contracts

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

From time to time, we enter 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. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. For the past several years, we have employed a strategy to hedge a substantial portion of our forecasted production approximately 18 months to two years in the future (from the then-current quarter), as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending and dividends in those future periods. Due to the significant and rapid decline in oil prices over the last six months, we have deferred entering into new derivative contracts through the first quarter of 2015; thus, the percentage of our forecasted production we have hedged and the duration of our hedges are less than what we have had in the recent past. In April 2015, we began entering into new oil hedging positions in order to provide more certainty to our future cash flows. As of May 5, 2015, these fixed-price swaps and collars, which are not reflected in the table below and which comprise both NYMEX and LLS hedges, include (1) fixed-price swaps covering an additional 15,000 Bbls per day in the second quarter of 2016, with weighted-average prices of approximately $63 per Bbl and (2) collars covering an additional 4,500 Bbls per day and 5,000 Bbls per day in the second and third quarters of 2016, respectively, with weighted-average floors of approximately $56 per Bbl and weighted-average ceilings of approximately $72 per Bbl.

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, 2015, 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.

- 11 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of March 31, 2015, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic:
Months
 
Index Price
 
Volume (2)
 
Contract Prices (1)
Range (3)
 
Weighted Average Price
Swap
 
Sold Put
 
Floor
 
Ceiling
Oil Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
8,000
 
$
90.00
90.00

 
$
90.00

 
$
65.75

 
$

 
$

Apr – June
 
LLS
 
16,000
 
 
93.20
94.00

 
93.65

 
68.00

 

 

July – Sept
 
NYMEX
 
10,000
 
 
90.00
90.10

 
90.02

 
65.30

 

 

July – Sept
 
LLS
 
16,000
 
 
93.20
94.00

 
93.65

 
68.00

 

 

Oct – Dec
 
NYMEX
 
12,000
 
 
91.15
94.00

 
92.42

 
68.00

 

 

Oct – Dec
 
LLS
 
8,000
 
 
93.80
96.50

 
94.94

 
68.00

 

 

2015 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
30,000
 
$
80.00
95.25

 
$

 
$

 
$
80.00

 
$
94.72

Apr – June
 
LLS
 
4,000
 
 
85.00
102.50

 

 

 
85.00

 
101.75

July – Sept
 
NYMEX
 
28,000
 
 
80.00
95.25

 

 

 
80.00

 
95.05

July – Sept
 
LLS
 
4,000
 
 
85.00
100.00

 

 

 
85.00

 
99.50

2015 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
10,000
 
$
85.00
102.00

 
$

 
$
68.00

 
$
85.00

 
$
99.00

Oct – Dec
 
LLS
 
8,000
 
 
88.00
104.25

 

 
68.00

 
88.00

 
100.99

2016 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
12,000
 
$
90.65
93.35

 
$
92.43

 
$
68.00

 
$

 
$

Jan – Mar
 
LLS
 
8,000
 
 
93.70
95.45

 
94.81

 
68.50

 

 

Apr – June
 
NYMEX
 
2,000
 
 
90.35
90.35

 
90.35

 
68.00

 

 

Apr – June
 
LLS
 
6,000
 
 
93.30
93.50

 
93.38

 
70.00

 

 

2016 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
10,000
 
$
85.00
101.25

 
$

 
$
68.00

 
$
85.00

 
$
99.85

Jan – Mar
 
LLS
 
6,000
 
 
88.00
103.15

 

 
68.00

 
88.00

 
102.10

Apr – June
 
NYMEX
 
2,000
 
 
85.00
95.50

 

 
68.00

 
85.00

 
95.50

Apr – June
 
LLS
 
2,000
 
 
88.00
98.25

 

 
70.00

 
88.00

 
98.25

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – Dec
 
NYMEX
 
8,000
 
$
4.00
4.53

 
$

 
$

 
$
4.00

 
$
4.51


(1)
Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
(2)
Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively.
(3)
Ranges presented for enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

(4)
An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes, and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes.
(5)
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes, and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Note 5. Fair Value Measurements

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

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

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 and natural gas derivatives that are based on NYMEX pricing. The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and 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, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At March 31, 2015, instruments in this category include non-exchange-traded oil derivatives that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, since the instruments are based on regional pricing other than NYMEX, certain inputs to the valuation are less observable. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $0.9 million in the fair value of these instruments as of March 31, 2015.


- 13 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

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, 2015
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Oil and natural gas derivative contracts – current
 
$

 
$
270,126

 
$
151,576

 
$
421,702

Oil and natural gas derivative contracts – long-term
 

 
6,017

 
13,439

 
19,456

Total Assets
 
$

 
$
276,143

 
$
165,015

 
$
441,158

 
 
 
 
 
 
 
 
 
December 31, 2014
 
 

 
 

 
 

 
 

Assets:
 
 

 
 

 
 

 
 

Oil and natural gas derivative contracts – current
 
$

 
$
283,238

 
$
157,121

 
$
440,359

Oil and natural gas derivative contracts – long-term
 

 
34,862

 
31,325

 
66,187

Total Assets
 
$

 
$
318,100

 
$
188,446

 
$
506,546


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.

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, 2015 and 2014:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2015
 
2014
Fair value of Level 3 instruments, beginning of period
 
$
188,446

 
$
6,709

Fair value adjustments on commodity derivatives
 
25,085

 
(12,806
)
Receipt on settlements of commodity derivatives
 
(48,516
)
 

Fair value of Level 3 instruments, end of period
 
$
165,015

 
$
(6,097
)
 
 
 
 
 
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date
 
$
23,099

 
$
(12,806
)

We utilize an income approach to value our Level 3 enhanced swaps, costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is

- 14 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
 
 
Fair Value at
3/31/2015
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Range
Oil derivative contracts
 
$
165,015

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2015
 
25.8% – 38.2%

Other Fair Value Measurements

The carrying value of 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 fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our debt as of March 31, 2015 and December 31, 2014, excluding pipeline financing and capital lease obligations, was $2,998.6 million and $2,938.6 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 6. Commitments and Contingencies

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

Delhi Field Release

In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was discovered (and reported) within an area of the Denbury-operated Delhi Field located in northern Louisiana. We completed our remediation efforts with respect to such release during the fourth quarter of 2013; however, we continue to monitor the impacted area to confirm the effectiveness of the remediation efforts. Virtually all of our total cost estimate of $130.8 million has been incurred.

We maintain insurance policies to cover certain costs, damages and claims related to releases of well fluids and remediation. We received a $25.0 million cost reimbursement in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess insurance coverage. We have not reached any agreement with our remaining carriers as to further reimbursements, but given our belief that under our policies we are entitled to reimbursement of between approximately one-third and two-thirds of our total costs, we have filed suit to pursue further reimbursements, the ultimate outcome of which cannot be predicted.

In March 2015, Evolution Petroleum Company ("Evolution"), the parent of the entity which sold Denbury Onshore, LLC ("Denbury Onshore") its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the Texas district court in Houston since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury Onshore and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining "payout" as defined in the agreements, and the extent and terms of assignment of reversionary interests in the Unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury Onshore in connection with the June 2013 Delhi Field release, and for the first time estimated its damages attributable to its allegations in the case as exceeding $200 million. The amended petition also adds a claim for unspecified punitive damages. There has only been limited discovery in the case to

- 15 -


Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

date, and Evolution has not specified the basis for the amount of its claimed damages estimate. The case is currently set for trial in October 2015. We believe Evolution's claims in the First Amended Petition relating to the June 2013 Delhi Field release are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.

Note 7. Additional Balance Sheet Details

Accounts Payable and Accrued Liabilities
 
 
March 31,
 
December 31,
In thousands
 
2015
 
2014
Accounts payable
 
$
52,662

 
$
64,604

Accrued interest
 
45,883

 
48,255

Accrued lease operating expenses
 
38,197

 
56,798

Accrued exploration and development costs
 
26,560

 
90,939

Accrued compensation
 
24,517

 
62,513

Taxes payable
 
16,697

 
39,816

Other
 
30,025

 
31,833

Total
 
$
234,541

 
$
394,758


Note 8. Subsequent Event

Dividend Declaration

On April 28, 2015, the Board of Directors declared a dividend of $0.0625 per share on our outstanding common stock, payable on June 30, 2015, to stockholders of record at the close of business on May 26, 2015.


- 16 -


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, 2014 (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 Part II of this report, 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.

Operating Highlights. Our financial results have been significantly impacted by the decrease in realized oil prices, which decreased from $97.69 per Bbl in the first quarter of 2014 to $46.02 in the first quarter of 2015. During the first quarter of 2015, we recognized a net loss of $107.7 million, or $0.31 per diluted common share, compared to net income of $58.3 million, or $0.17 per diluted common share, during the first quarter of 2014. The change in income between the first quarter of 2015 and 2014 was primarily due to a 52% ($326 million) decline in our oil and natural gas revenues between the periods, which was primarily all oil-price related, and a full cost pool ceiling test write-down of our oil and natural gas properties totaling $146.2 million ($90.6 million net of tax) during the first quarter of 2015, also due to declines in oil prices. Offsetting these negative impacts was a $159.7 million reduction in our commodity derivative expense, and lower operating expenses consisting of a $29.3 million (17%) decrease in lease operating expenses, a $19.3 million (42%) decrease in taxes other than income, and an $8.7 million (18%) decrease in interest, net. The $159.7 million positive change in commodity derivatives expense (income) between the two periods was principally due to receipts of $148.5 million upon settlement of derivative contracts in the first quarter of 2015 compared to payments of $27.2 million in the prior-year quarter.

We generated $137.8 million of cash flows from operating activities in the first quarter of 2015, compared to $337.7 million in the fourth quarter of 2014 and $214.9 million in the prior-year first quarter. The decrease in cash flows from operations was due primarily to lower oil prices, which caused a decrease in oil revenues, partially offset by significant positive changes in derivative settlements and, to a lesser extent, reductions in lease operating expenses, taxes other than income, interest expense, and changes in working capital items. Despite the significant decrease in oil prices, at current oil futures prices, we currently expect to generate cash flow above and beyond our capital expenditures and dividends for 2015.

During the first quarter of 2015, our oil and natural gas production, which was 95% oil, averaged 74,356 BOE/d, compared to an average of 73,718 BOE/d produced during the first quarter of 2014. This slight increase in production is attributable to a 5% increase in our tertiary oil production, offset by a 4% decline in production from our non-tertiary properties.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $46.02 per Bbl during the first quarter of 2015, a decrease of 53% compared to $97.69 per Bbl realized during the first quarter of 2014 and a decrease of 35% compared to $70.80 per Bbl realized during the fourth quarter of 2014. The oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) was $2.81 per Bbl below NYMEX prices in the first quarter of 2015, compared to a negative $0.91 per Bbl NYMEX differential in the first quarter of 2014, and a negative $2.24 per Bbl NYMEX differential in the fourth quarter of 2014. This decline in our oil price differential in comparison to its level in the first quarter of 2014 was driven by a decrease in the Light Louisiana Sweet ("LLS") index premium, partially offset by a decrease in the Rocky Mountain region discount relative to NYMEX oil prices.

One of our primary focuses in 2014 and 2015 has been to reduce costs throughout the organization, through a number of internal initiatives.  For example, excluding Delhi remediation costs and insurance reimbursements and unplanned Riley Ridge well workovers in 2014, our recurring lease operating expenses per BOE decreased each sequential quarter in 2014 and the first

- 17 -


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

quarter of 2015, and decreased a total of 20% between the fourth quarter of 2013 and the first quarter of 2015, with decreases realized in most categories of lease operating expenses, the most significant of which including workover costs, power costs, CO2 costs, and certain third-party contractor and vendor costs. On a sequential-quarter basis, lease operating expenses, excluding Delhi Field remediation costs, decreased 10% between the fourth quarter of 2014 and the first quarter of 2015. Our goal is to continue to reduce both capital project costs and per-barrel operating costs, and we believe such reductions are possible, especially in light of the recent decline in oil prices.

Recent Oil Price Decline and Impact on Our Business. Although oil prices have historically been volatile, during the second half of 2014 and continuing into 2015, oil prices dropped rapidly, with NYMEX prices declining from $107 per Bbl in June 2014 to less than $44 per Bbl in March 2015. In response to the decline in oil prices, we (1) significantly reduced projected 2015 capital spending to $550 million, or roughly half of 2014 levels, (2) suspended our share repurchase program, and (3) declared dividends for the first two quarters of 2015 at a rate of $0.25 per common share on an annualized basis, which is a level consistent with our 2014 dividend rate.

As a result of the significant decrease in pricing during the fourth quarter of 2014 and its continued decline in the first quarter of 2015, we recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015. See Results of Operations Full Cost Pool Ceiling Test Write-Down and Note 1, Basis of Presentation Oil and Natural Gas Properties, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding the ceiling test.

Oil prices generally constitute the largest single variable in our operating results. For the past several years, we have employed a strategy of hedging a substantial portion of our forecasted production, approximately 18 months to two years into the future (from the then-current quarter), to mitigate the risks associated with fluctuations during periods of oil price declines. We have hedges covering approximately 80% of our forecasted total production for the second and third quarters of 2015 and just over half for the fourth quarter of 2015, which will help mitigate the impact of the continued low oil price environment on our 2015 cash flows and operating results; however, for any portion of our forecasted production that is unhedged, we are fully exposed to any further decrease in oil prices. For 2016, we have significantly fewer hedges and at a lower price, and thus, the impact of continued low oil prices on our cash flows and operating results during those time periods will be more impactful. See Results of Operations – Commodity Derivative Contracts and Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability for borrowings under our bank credit facility. Our business is capital intensive, and it is common for oil and natural gas companies our size to reinvest most or all of their cash flow into developing new assets. We generally attempt to balance our capital expenditures and dividends with cash flows from operations, and for 2015, at current oil futures prices, we currently expect to generate cash flow above and beyond our capital expenditures and dividends. Our cash flow from operations during the first quarter of 2015 was lower than the $214.9 million generated during the same prior year period, due primarily to lower oil prices, which caused a decrease in oil revenues, partially offset by significant positive changes in derivative settlements and, to a lesser extent, reductions in lease operating expenses, taxes other than income, interest expense, and working capital items.

As discussed in the Overview above, we have been proactive in adjusting our 2015 capital spending and dividend plans in connection with the current lower oil price environment. We project that we will have adequate capital resources and liquidity for the foreseeable future because (1) we have significant borrowing capacity on our bank credit facility (see Note 2, Long-Term Debt and Bank Credit Facility below); (2) we have commodity derivative contracts in place to cover a significant portion of our forecasted oil production for 2015 that will lessen the impact of the current lower oil price environment (see Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative contracts); (3) generally, we plan to fund both our projected capital expenditures and dividends with cash flows from operations; (4) we can significantly reduce our capital expenditures for some time if necessary as we have done in 2015, and still maintain relatively flat or slightly lower production levels as a result of the unique characteristics of CO2 EOR operations; and (5) the maturity dates of all but a minor amount of our senior subordinated notes occur seven or more years in the future, and carry attractive fixed interest rates ranging between 4⅝% and 6⅜%.

- 18 -


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


If oil prices remain at relatively low levels beyond 2015, our cash flows from operations will likely be significantly lower than current levels, as our commodity derivative contracts presently in place for 2016 cover significantly less forecasted oil production and are at lower prices. Therefore, we continue to focus on reducing our operating costs so as to preserve as much of our operating margin as possible in this lower oil price environment, and if this low oil price environment persists, we intend to continue to make adjustments to our capital spending plans to preserve our financial health. Fortunately, some of our costs, such as CO2 purchases and production taxes, adjust proportionally with changes in the price of oil. We also expect that our cost of services and equipment will continue to come down in this lower oil price environment, but this likely will not reflect as large a percentage decrease as the decrease in the price of oil. Although we can reduce capital spending and maintain production at relatively flat or slightly lower production levels for some time, after a period of time our production will begin to decline significantly, which will further lower our cash flow from operations.

2015 Capital Spending. We anticipate that our full-year 2015 capital budget, excluding acquisitions, will be $550 million, which includes approximately $85 million in capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.  This combined 2015 capital budget amount, excluding acquisitions, is comprised of the following:

$320 million allocated for tertiary oil field expenditures;
$100 million allocated for other areas, primarily non-tertiary oil field expenditures;
$30 million to be spent on CO2 sources;
$15 million for pipeline construction; and
$85 million for other capital items such as capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.

During the three months ended March 31, 2015, we incurred capital expenditures of $111.1 million, excluding acquisitions.  See additional detail on our expenditures in the Capital Expenditure Summary below.

Based on oil and natural gas commodity futures prices in early May 2015, our current production forecast, and our commodity derivative contracts covering a substantial portion of our anticipated 2015 production, we currently anticipate that our 2015 cash flows from operations will be in excess of our combined 2015 capital budget and currently-planned dividend payments. Although our outstanding borrowings on our bank credit facility increased by $70.0 million from December 31, 2014, to $465.0 million at March 31, 2015, due primarily to the timing of cash outflows to cover working capital items in the first quarter of 2015, we currently expect to use any excess cash flow from operations for the remainder of 2015 to pay down borrowings on our bank credit facility to levels below those outstanding as of December 31, 2014. If prices were to decrease further or changes in operating results were to cause us to have a reduction in anticipated 2015 cash flows below our currently forecasted operating cash flows, we would likely further reduce our capital expenditures or reduce our targeted dividend payment, with ample availability on our bank credit facility to cover any potential shortfall. If we further reduce our capital spending due to lower cash flows, any sizeable reduction could lower our anticipated production levels in future years.

Bank Credit Facility. In connection with the borrowing base redetermination completed in early May 2015 under our Bank Credit Agreement, we elected to maintain our aggregate lender commitments at $1.6 billion; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion. Because we continue to maintain a $1.0 billion cushion between our borrowing base and the aggregate lender commitments, even after this borrowing base reduction, and because we had availability of $1.1 billion with respect to our aggregate lender commitments as of March 31, 2015, this borrowing base reduction has no impact on our liquidity. Redeterminations under our Bank Credit Agreement occur annually, making our next scheduled redetermination in May 2016.

This Bank Credit Agreement contains certain restrictive covenants, plus two principal financial performance covenants to maintain (1) a ratio of consolidated total net debt to consolidated EBITDAX of not more than 4.25 to 1.0 and (2) a ratio of consolidated current assets to consolidated current liabilities ("current ratio") not less than 1.0. For these financial performance covenant calculations as of March 31, 2015, our ratio of consolidated total net debt to consolidated EBITDAX was 2.78 to 1.0, and our current ratio was 4.25, and we currently project to be in compliance with the covenants through the remainder of 2015.

- 19 -


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


Although we currently expect to meet our financial covenants in 2015, if oil prices were to remain at lower levels for a longer period of time, we could have issues in meeting our debt to EBITDAX covenant in 2016, as we are not as well hedged after 2015. Therefore, in conjunction with the May 2015 redetermination, we entered into the First Amendment to the Bank Credit Agreement (the "First Amendment") under which we modified certain financial covenants in 2016, 2017 and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows:

In 2016 and 2017, suspend the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant of 4.25 to 1.0 and replace it with a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 2.5 to 1.0 during the same time period. Currently, only debt under our Bank Credit Agreement would be considered consolidated senior secured debt for purposes of this ratio. If this covenant had been in place as of March 31, 2015, our ratio of senior secured debt to consolidated EBITDAX would have been 0.36 to 1.0 as of that date.
Beginning in the first quarter of 2018, reinstate the ratio of consolidated total net debt to consolidated EBITDAX covenant utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ended March 31, 2018, 5.5 to 1.0 for the second quarter ended June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ended September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ended March 31, 2019.
In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0.

The restructuring of covenants through the First Amendment were executed in consideration of a fee paid to the lenders. The First Amendment has no impact on the current ratio financial performance covenant, which will remain in place in 2015 and beyond. All of the above descriptions of financial covenants are qualified by the express language and defined terms contained in the Bank Credit Agreement filed on December 15, 2014, as Exhibit 10.1 to our Current Report on Form 8-K or the First Amendment, which is filed as Exhibit 10(a) to this Quarterly Report on Form 10-Q.

Dividends. During the first quarter of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share. Dividends totaling $22.1 million and $21.7 million were paid to stockholders during the three months ended March 31, 2015 and 2014, respectively. See Note 8, Subsequent Event, to the Unaudited Condensed Consolidated Financial Statements for details regarding the dividend declared in the second quarter of 2015. An annual dividend rate of $0.25 per common share would result in total dividend payments of approximately $89 million to our stockholders in 2015. The declaration and payment of future dividends are at the discretion of our Board of Directors, and the amount thereof will depend on our results of operations, financial condition, capital requirements, level of indebtedness, market conditions, and other factors deemed relevant by the Board of Directors.

Insurance Recoveries to Cover Costs of 2013 Delhi Field Release. We completed our remediation efforts related to the release of well fluids at the Denbury-operated Delhi Field during the fourth quarter of 2013. As of March 31, 2015, virtually all of our total cost estimate of $130.8 million had been incurred.

We maintain insurance policies to cover certain costs, damages and claims related to releases of well fluids and remediation. We received a $25.0 million cost reimbursement in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess insurance coverage. We have not reached any agreement with our remaining carriers as to further reimbursements, but given our belief that under our policies we are entitled to reimbursement of between approximately one-third and two-thirds of our total costs, we have filed suit to pursue further reimbursements, the ultimate outcome of which cannot be predicted.


- 20 -


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

Capital Expenditure Summary. The following table of capital expenditures includes accrued capital for the three months ended March 31, 2015 and 2014:
 
 
Three Months Ended
 
 
March 31,
In thousands
 
2015
 
2014
Capital expenditures by project
 
 
 
 
Tertiary oil fields
 
$
42,900

 
$
123,901

Non-tertiary fields
 
30,984

 
54,851

Capitalized interest and internal costs (1)
 
25,580

 
24,219

Oil and natural gas capital expenditures
 
99,464

 
202,971

CO2 pipelines
 
779

 
3,244

CO2 sources (2)
 
9,852

 
13,262

CO2 capitalized interest and other
 
1,003

 
1,146

Capital expenditures, before acquisitions
 
111,098

 
220,623

Acquisitions of oil and natural gas properties
 
261

 

Capital expenditures, total
 
$
111,359

 
$
220,623


(1)
Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.
(2)
Includes capital expenditures related to the Riley Ridge gas processing facility.

Capital expenditures during the three months ended March 31, 2015, reflect a significant reduction in accrued capital based on the decrease in capital spending in 2015. For the first three months of 2015 and 2014, our capital expenditures and property acquisitions were fully funded with cash flow from operations.

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

Our commitments and obligations consist of those detailed as of December 31, 2014 in our Form 10-K under Management's Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Commitments and Obligations.

RESULTS OF OPERATIONS

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

- 21 -


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, 2015 and 2014 are included in the following table:
 
 
Three Months Ended
 
 
March 31,
In thousands, except per share and unit data
 
2015
 
2014
Operating results
 
 
 
 
Net income (loss)
 
$
(107,746
)
 
$
58,310

Net income (loss) per common share – basic
 
(0.31
)
 
0.17

Net income (loss) per common share – diluted
 
(0.31
)
 
0.17

Dividends declared per common share
 
0.0625

 
0.0625

Net cash provided by operating activities
 
137,764

 
214,858

Average daily production volumes
 
 

 
 

Bbls/d
 
70,564

 
69,834

Mcf/d
 
22,752

 
23,299

BOE/d (1)
 
74,356

 
73,718

Operating revenues
 
 

 
 

Oil sales
 
$
292,270

 
$
613,980

Natural gas sales
 
5,200

 
9,866

Total oil and natural gas sales
 
$
297,470

 
$
623,846

Commodity derivative contracts (2)
 
 

 
 

Receipt (payment) on settlements of commodity derivatives
 
$
148,465

 
$
(27,169
)
Noncash fair value adjustments on commodity derivatives (3)
 
(65,389
)
 
(49,500
)
Commodity derivatives income (expense)
 
$
83,076

 
$
(76,669
)
Unit prices – excluding impact of derivative settlements
 
 

 
 

Oil price per Bbl
 
$
46.02

 
$
97.69

Natural gas price per Mcf
 
2.54

 
4.71

Unit prices – including impact of derivative settlements (2)
 
 
 
 

Oil price per Bbl
 
$
69.28

 
$
93.46

Natural gas price per Mcf
 
2.91

 
4.41

Oil and natural gas operating expenses
 
 
 
 

Lease operating expenses
 
$
141,084

 
$
170,379

Marketing expenses, net of third-party purchases, and plant operating expenses
 
9,843

 
12,263

Production and ad valorem taxes
 
22,899

 
42,414

Oil and natural gas operating revenues and expenses per BOE
 
 
 
 

Oil and natural gas revenues
 
$
44.45

 
$
94.03

Lease operating expenses
 
21.08

 
25.68

Marketing expenses, net of third-party purchases, and plant operating expenses
 
1.47

 
1.84

Production and ad valorem taxes
 
3.42

 
6.39

CO2 sources and helium – revenues and expenses
 
 

 
 

CO2 and helium sales and transportation fees
 
$
6,972

 
$
10,761

CO2 and helium discovery and operating expenses
 
(947
)
 
(5,205
)
CO2 and helium revenue and expenses, net
 
$
6,025

 
$
5,556


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

- 22 -


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

(2)
See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.
(3)
Noncash fair value adjustments 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 adjustments on commodity derivatives represents only the net change between periods of the fair market values of commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $148.5 million for the three months ended March 31, 2015, and payments on settlements of $27.2 million for the three months ended March 31, 2014. We believe that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to "Commodity derivatives expense (income)" in order to differentiate noncash fair market value adjustments from 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 to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments 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.


- 23 -


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 2014 and for the first quarter of 2015 is shown below:
 
 
Average Daily Production (BOE/d)
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
 
First
Quarter
Operating Area
 
2014
 
2014
 
2014
 
2014
 
 
2015
Tertiary oil production
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
Mature properties:
 
 
 
 
 
 
 
 
 
 
 
Brookhaven
 
1,877

 
1,818

 
1,767

 
1,579

 
 
1,612

Eucutta
 
2,181

 
2,150

 
2,224

 
1,995

 
 
1,905

Mallalieu
 
1,837

 
1,839

 
1,869

 
1,653

 
 
1,574

Other mature properties (1)
 
6,283

 
6,156

 
6,189

 
5,864

 
 
5,710

Total mature properties
 
12,178

 
11,963

 
12,049

 
11,091

 
 
10,801

Delhi (2)
 
4,708

 
4,543

 
4,377

 
3,743

 
 
3,551

Hastings
 
4,618

 
4,759

 
4,917

 
4,811

 
 
4,694

Heidelberg
 
5,325

 
5,609

 
5,721

 
6,164

 
 
6,027

Oyster Bayou
 
4,055

 
4,415

 
4,605

 
5,638

 
 
5,861

Tinsley
 
8,430

 
8,518

 
8,310

 
8,767

 
 
8,928

Total Gulf Coast region
 
39,314


39,807

 
39,979

 
40,214

 

39,862

Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
Bell Creek
 
578

 
1,090

 
1,648

 
1,659

 
 
1,965

Total Rocky Mountain region
 
578

 
1,090

 
1,648

 
1,659

 
 
1,965

Total tertiary oil production
 
39,892

 
40,897

 
41,627

 
41,873

 
 
41,827

Non-tertiary oil and gas production
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
Mississippi
 
2,513

 
2,319

 
2,346

 
2,099

 
 
1,761

Texas
 
6,444

 
6,508

 
5,537

 
6,677

 
 
6,490

Other
 
1,031

 
1,049

 
1,083

 
1,082

 
 
1,006

Total Gulf Coast region
 
9,988

 
9,876

 
8,966

 
9,858

 
 
9,257

Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline
 
19,007

 
19,155

 
18,623

 
18,553

 
 
18,522

Other
 
4,831

 
5,392

 
4,594

 
4,591

 
 
4,750

Total Rocky Mountain region
 
23,838

 
24,547

 
23,217

 
23,144

 
 
23,272

Total non-tertiary production
 
33,826

 
34,423

 
32,183

 
33,002

 

32,529

Total production
 
73,718

 
75,320

 
73,810

 
74,875

 
 
74,356


(1)
Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.
(2)
The average daily Delhi Field production amounts for the fourth quarter of 2014 and the first quarter of 2015 reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.


- 24 -


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

Total Production

Total production during the first quarter of 2015 averaged 74,356 BOE/d, a slight increase compared to first quarter of 2014 production levels of 73,718 BOE/d, as production increases at our newer tertiary floods offset the decreases in our mature properties and lower production resulting from the decrease in ownership interest at Delhi Field as of November 1, 2014, due to a contractual reversionary assignment of approximately 25% of our interest to the seller of the field. Our production during the three months ended March 31, 2015 was 95% oil, consistent with oil production during the three months ended March 31, 2014 and December 31, 2014.

Tertiary Production

Oil production from our tertiary operations during the first quarter of 2015 increased 1,935 Bbls/d (5%) compared to tertiary production levels in the same period in 2014 and was relatively unchanged when comparing tertiary production between the first quarter of 2015 and fourth quarter of 2014. The year-over-year increase was primarily due to production growth in response to continued field development and expansion of facilities in our tertiary floods at Heidelberg, Oyster Bayou, and Tinsley fields in our Gulf Coast region, and Bell Creek Field in our Rocky Mountain region. Partially offsetting the increases were production declines in our mature tertiary fields, as well as the decrease in our ownership interest in Delhi Field due to the November 1, 2014, contractual reversionary assignment of approximately 25% of our interest to the seller of the field, the effectiveness, timing, and scope of which are subject to ongoing litigation.

Non-Tertiary Production

Production from our non-tertiary operations averaged 32,529 BOE/d during the first quarter of 2015, a decrease of 1,297 BOE/d (4%) compared to the first quarter of 2014 levels, and decreased slightly (1%) when compared to the fourth quarter of 2014 levels. These decreases from the first quarter of 2014 were primarily due to declines at our Mississippi non-tertiary fields and Cedar Creek Anticline ("CCA"). Additionally, natural gas production at Riley Ridge remained shut-in during the first quarter of 2015, compared to averaging 1,639 Mcf/d (273 BOE/d) in the first quarter of 2014. We currently expect natural gas production at Riley Ridge will continue to be shut-in due to natural gas supply well failures related to sulfur build-up in those wells until sometime in 2016. Production from our other non-tertiary properties is generally on decline, and in some instances the decline is pronounced when non-tertiary wells are shut in as part of an initiation or expansion of our tertiary floods in a field or an area of a field.

Oil and Natural Gas Revenues

Our oil and natural gas revenues decreased 52% during the three months ended March 31, 2015 compared to these revenues for the same period in 2014.  The changes in our oil and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
 
 
Three Months Ended
 
 
March 31,
 
 
2015 vs. 2014
In thousands
 
Increase (Decrease) in Revenues
 
Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
 
 
 
 
Increase in production
 
$
5,406

 
1
 %
Decrease in commodity prices
 
(331,782
)
 
(53
)%
Total decrease in revenues
 
$
(326,376
)
 
(52
)%


- 25 -


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, 2015 and 2014:
 
 
Three Months Ended
 
 
March 31,
 
 
2015
 
2014
Net realized prices:
 
 
 
 
Oil price per Bbl
 
$
46.02

 
$
97.69

Natural gas price per Mcf
 
2.54

 
4.71

Price per BOE
 
44.45

 
94.03

NYMEX differentials:
 
 

 
 

Oil per Bbl
 
$
(2.81
)
 
$
(0.91
)
Natural gas per Mcf
 
(0.28
)
 
(0.02
)

As reflected in the table above, our average net realized oil price, excluding the impact of commodity derivative contracts, decreased 53% during the first quarter of 2015 from the average price received during the first quarter of 2014.  Company-wide average oil price differentials in the first quarter of 2015 were $2.81 per Bbl below NYMEX, compared to an average differential of $0.91 per Bbl below NYMEX in the first quarter of 2014. During the first quarter of 2015, we sold approximately 42% of our crude oil at prices based on the LLS index price, approximately 23% at prices partially tied to the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region. These percentages were consistent with those realized during the first quarter of 2014. The oil differentials we received in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors and location differentials. Our average NYMEX oil differential in the Gulf Coast region was a negative $0.29 per Bbl and a positive $3.05 per Bbl during the three months ended March 31, 2015 and 2014, respectively, and a positive $1.20 per Bbl during the three months ended December 31, 2014. These differentials are impacted significantly by the changes in prices received for our crude oil sold under LLS index prices relative to the change in NYMEX prices.  This quarterly average LLS-to-NYMEX differential (on a trade-month basis) decreased from a positive $6.06 per Bbl in the first quarter of 2014 to a positive $3.16 per Bbl in the fourth quarter of 2014 and a positive $2.60 per Bbl in the first quarter of 2015, with the two most recent quarters being more representative of longer-term historical differentials.

NYMEX oil differentials in the Rocky Mountain region averaged $7.75 per Bbl and $9.06 per Bbl below NYMEX during the three months ended March 31, 2015 and 2014, respectively, and $9.28 per Bbl below NYMEX during the three months ended December 31, 2014. Differentials in the Rocky Mountain region can move significantly over short periods of time due to refinery and transportation issues, but are showing signs of greater stability as infrastructure and takeaway capacity improve in the region.

Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be quite large, the absolute impact of these changes on our results has historically been minor, as natural gas sales represented only approximately 2% of our oil and natural gas revenues during the three months ended March 31, 2015.


- 26 -


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

Commodity Derivative Contracts

The following tables summarize the impact our oil and natural gas derivative contracts had on our operating results for the three months ended March 31, 2015 and 2014:
 
 
Three Months Ended March 31,
 
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
In thousands
 
Crude Oil
Derivative Contracts
 
Natural Gas
Derivative Contracts
 
Total Commodity
Derivative Contracts
Receipt (payment) on settlements of commodity derivatives
 
$
147,716

 
$
(26,559
)
 
$
749

 
$
(610
)
 
$
148,465

 
$
(27,169
)
Noncash fair value adjustments on commodity derivatives (1)
 
(65,122
)
 
(48,854
)
 
(267
)
 
(646
)
 
(65,389
)
 
(49,500
)
Total income (expense)
 
$
82,594

 
$
(75,413
)
 
$
482

 
$
(1,256
)
 
$
83,076

 
$
(76,669
)

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

For the remainder of 2015, we have commodity derivative contracts consisting of a combination of enhanced swaps, collars, and three-way collars covering a total of 58,000 Bbls/d for the second and third quarters of 2015 and 38,000 Bbls/d for the fourth quarter of 2015. Roughly half of these 2015 derivative contracts are collars and three-way collars, so the variability in potential cash flows from these types of hedges exposes us to more downside price risk than our enhanced swaps. These 2015 collars and three-way collars, which include both NYMEX and LLS hedges, have a weighted average floor of approximately $82 per Bbl (approximately $81 per Bbl and $87 per Bbl for NYMEX and LLS hedges, respectively) and a weighted average ceiling price of approximately $97 per Bbl (approximately $95 per Bbl and $101 per Bbl for NYMEX and LLS hedges, respectively). Our three-way collars and enhanced swaps all include sold puts that have a weighted average price of approximately $67 per Bbl. The sold puts for our three-way collars and enhanced swaps limit the benefit that our hedges provide us to the extent that oil prices remain below the price of our sold puts.

Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our oil and natural gas derivative contracts.  Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations. The details of our outstanding commodity derivative contracts at March 31, 2015, are included in Note 4, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements. Also, see Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion on our commodity derivative contracts.


- 27 -


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

Production Expenses

Lease Operating Expense
 
 
Three Months Ended
 
 
March 31,
In thousands, except per-BOE data
 
2015
 
2014
Lease operating expense
 
 
 
 
Tertiary
 
$
85,459

 
$
97,698

Non-tertiary
 
55,625

 
72,681

Total lease operating expense
 
$
141,084

 
$
170,379

 
 
 
 
 
Lease operating expense per BOE
 
 

 
 

Tertiary
 
$
22.70

 
$
27.21

Non-tertiary
 
19.00

 
23.87

Total lease operating expense per BOE
 
21.08

 
25.68


We have seen many of our lease operating costs decline as a result of our cost reduction efforts throughout 2014 and early 2015, as well as general market decreases in the prices of many of the components of these costs. Total lease operating expenses decreased $29.3 million (17%) on an absolute-dollar basis or $4.60 (18%) on a per-BOE basis during the three months ended March 31, 2015 compared to 2014 levels. When comparing the first quarter of 2015 to the fourth quarter of 2014, lease operating expenses, excluding Delhi Field remediation costs, decreased $14.9 million (10%) on an absolute-dollar basis or $1.56 (7%) on a per-BOE basis. The year-over-year and sequential quarter declines were due to cost decreases in most categories of lease operating expenses, the most significant of which including (1) a decrease in workover costs, (2) lower power cost and usage, (3) lower CO2 expense resulting from a decrease in Gulf Coast region CO2 injection volumes and a decrease in the cost of CO2 during both comparative periods, which correlates with oil prices, and (4) lower third-party contractor and vendor expenses such as contract labor and chemical costs.

Tertiary lease operating expenses decreased $12.2 million (13%) on an absolute-dollar basis or $4.51 (17%) on a per-barrel basis during the first quarter of 2015 compared to the first quarter of 2014. When comparing the first quarter of 2015 to the fourth quarter of 2014, tertiary lease operating expenses, excluding Delhi Field remediation costs, decreased $7.4 million (8%) or $1.40 (6%) on a per-barrel basis. The year-over-year and sequential quarter declines were primarily due to (1) lower workover costs, (2) lower power costs due to lower rates and usage, (3) lower CO2 expense resulting from a decrease in Gulf Coast region CO2 injection volumes and a decrease in the cost of CO2 during both comparative periods, which correlates with oil prices, and (4) lower third-party contractor and vendor expenses such as contract labor and chemical costs. Although there was a sequential-quarter increase in company-wide CO2 utilization due to increased injection volumes at our newest tertiary flood at Bell Creek Field in the Rocky Mountain region, CO2 utilization in the Gulf Coast region decreased 1% sequentially and 7% when compared to prior year as a result of improved efficiency and utilization of CO2 for those fields. The reduction in CO2 utilization is in part due to our innovation and improvement initiatives, under which we are doing a bottom-up review of each of our fields. In addition, our operating costs on a per-barrel basis have improved from the first quarter of 2014, as our expense at Bell Creek Field has decreased on a per-BOE basis when comparing the first quarter of 2015 to the same period in 2014, due primarily to continued production increases. For any specific field, we expect our tertiary lease operating expense per barrel to be high initially, as we experienced in 2013 and 2014 with our Bell Creek flood, and then decrease as production increases, ultimately leveling off until production begins to decline in the later life of the field, when operating expense per barrel will again increase.

Currently, our CO2 expense comprises approximately one-fourth of our typical tertiary lease operating expenses, and for the CO2 reserves we already own, consists of CO2 production expenses, and for the CO2 reserves we do not own, consists of our purchase of CO2 from royalty and working interest owners and industrial sources. During the three months ended March 31, 2015 and 2014, approximately 63% and 65%, respectively, of the CO2 utilized in our CO2 floods consisted of CO2 owned and produced by us. The price we pay others for CO2 varies by source and is generally indexed to oil prices. When combining the production

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

cost of the CO2 we own with what we pay third parties for CO2, our average cost of CO2 during the first quarter of 2015 was approximately $0.29 per Mcf, including taxes paid on CO2 production but excluding depletion and depreciation of capital. This rate during the first quarter of 2015 was lower than the $0.32 per Mcf comparable measure during the fourth quarter of 2014 and $0.35 per Mcf during the first quarter of 2014, primarily driven by reductions in commodity costs due to the significant decline in oil prices. Including the cost of depreciation and amortization of capital expended at our CO2 source fields and industrial sources, but excluding depreciation of our CO2 pipelines, our cost of CO2 was $0.39 per Mcf and $0.46 per Mcf during the first quarters of 2015 and 2014, respectively.

Non-tertiary lease operating expenses decreased $17.1 million (23%) on an absolute-dollar basis and $4.87 (20%) on a per-BOE basis between the three months ended March 31, 2015 and 2014, and decreased $7.5 million (12%) on an absolute-dollar basis and $1.79 (9%) on a per-BOE basis between the fourth quarter of 2014 and the first quarter of 2015. The year-over-year and sequential quarter decreases were primarily due to lower workover costs, repairs and maintenance costs, and other third-party costs for contract labor and consulting services during the first quarter of 2015.

Marketing and Plant Operating Expenses

Marketing and plant operating expenses primarily consist of amounts incurred relating to the marketing, processing, and transportation of oil and natural gas production, as well as expenses related to our Riley Ridge gas processing facility. Marketing and plant operating expenses decreased $5.1 million (30%) between the three months ended March 31, 2015 and 2014, primarily due to reductions in marketing, compression, and plant processing fees, as well as reductions related to the Riley Ridge gas processing facility, which is currently shut-in.

Taxes Other Than Income

Taxes other than income includes ad valorem, production and franchise taxes. Taxes other than income decreased $19.3 million during the three months ended March 31, 2015, compared to the same period in 2014. The levels of taxes other than income during most periods are generally aligned with fluctuations in oil and natural gas revenues. The decrease in 2015 is also attributable to severance tax reductions at Hastings Field and Oyster Bayou Field, which reduced severance taxes by approximately $1 million in the first quarter of 2015 related to state-approved enhanced oil recovery project exemptions that were approved in the second half of 2014 and reduce severance taxes for those fields for approximately the next seven years.

General and Administrative Expenses ("G&A")
 
 
Three Months Ended
 
 
March 31,
In thousands, except per-BOE data and employees
 
2015
 
2014
Gross cash compensation and administrative costs
 
$
95,280

 
$
91,997

Gross stock-based compensation
 
11,059

 
11,226

Operator labor and overhead recovery charges
 
(42,128
)
 
(43,140
)
Capitalized exploration and development costs
 
(17,931
)
 
(16,390
)
Net G&A expense
 
$
46,280

 
$
43,693

 
 
 
 
 
G&A per BOE:
 
 

 
 

Net administrative costs
 
$
5.89

 
$
5.46

Net stock-based compensation
 
1.03

 
1.13

Net G&A expense
 
$
6.92

 
$
6.59

 
 
 
 
 
Employees as of March 31
 
1,496

 
1,498



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

Gross cash compensation and administrative costs on an absolute-dollar basis increased $3.3 million (4%) primarily due to higher employee-related insurance costs and professional service fees between the three months ended March 31, 2015 and 2014. Net G&A expense increased $2.6 million (6%) on an absolute-dollar basis and $0.33 (5%) on a per-BOE basis over the same period, primarily based on the changes noted in gross cash compensation and administrative costs, as total operator labor and overhead recovery charges and capitalized exploration and developments costs remained relatively unchanged on a combined basis.

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well.  In addition, salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities.  Capitalized exploration and development costs increased 9% between the three months ended March 31, 2015 and 2014, primarily due to increased compensation costs subject to capitalization.

Interest and Financing Expenses
 
 
Three Months Ended
 
 
March 31,
In thousands, except per-BOE data and interest rates
 
2015
 
2014
Cash interest expense
 
$
46,287

 
$
51,071

Noncash interest expense
 
2,221

 
3,519

Less: capitalized interest
 
(8,409
)
 
(5,756
)
Interest expense, net
 
$
40,099

 
$
48,834

Interest expense, net per BOE
 
$
5.99

 
$
7.36

Average debt outstanding
 
$
3,615,918

 
$
3,521,495