DENBURY INC - Quarter Report: 2011 June (Form 10-Q)
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
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 June 30, 2011
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 jurisdictions of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
5320 Legacy Drive Plano, TX |
75024 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code: (972) 673-2000
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
(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 (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
Class | Outstanding at August 1, 2011 | |
Common Stock, $.001 par value | 402,350,295 |
DENBURY RESOURCES INC.
INDEX
2
Table of Contents
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)
(In thousands, except par value and share data)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
ASSETS |
||||||||
Current assets |
||||||||
Cash and cash equivalents |
$ | 121,792 | $ | 381,869 | ||||
Accrued production receivable |
255,034 | 223,584 | ||||||
Trade and other receivables, net of allowance of $486 and $456, respectively |
153,018 | 114,149 | ||||||
Short-term investments |
88,220 | 93,020 | ||||||
Derivative assets |
19,322 | 24,242 | ||||||
Deferred tax assets |
22,097 | 27,454 | ||||||
Total current assets |
659,483 | 864,318 | ||||||
Property and equipment |
||||||||
Oil and natural gas properties (using full cost accounting) |
||||||||
Proved |
6,508,928 | 6,042,442 | ||||||
Unevaluated |
952,452 | 870,130 | ||||||
CO2 and other non-hydrocarbon gases properties |
572,957 | 523,423 | ||||||
Pipelines and plants |
1,445,214 | 1,378,239 | ||||||
Other property and equipment |
138,671 | 120,641 | ||||||
Less accumulated depletion, depreciation, amortization, and impairment |
(2,403,741 | ) | (2,197,517 | ) | ||||
Net property and equipment |
7,214,481 | 6,737,358 | ||||||
Derivative assets |
17,609 | 12,919 | ||||||
Goodwill |
1,232,418 | 1,232,418 | ||||||
Other assets |
215,432 | 218,050 | ||||||
Total assets |
$ | 9,339,423 | $ | 9,065,063 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities |
||||||||
Accounts payable and accrued liabilities |
$ | 333,953 | $ | 345,998 | ||||
Oil and gas production payable |
172,837 | 143,145 | ||||||
Derivative liabilities |
81,627 | 78,184 | ||||||
Current maturities of long-term debt |
8,622 | 7,948 | ||||||
Other liabilities |
4,070 | 4,070 | ||||||
Total current liabilities |
601,109 | 579,345 | ||||||
Long-term liabilities |
||||||||
Long-term debt, net of current portion |
2,288,112 | 2,416,208 | ||||||
Asset retirement obligations |
86,109 | 81,290 | ||||||
Derivative liabilities |
3,378 | 29,687 | ||||||
Deferred taxes |
1,687,839 | 1,547,992 | ||||||
Other liabilities |
24,562 | 29,834 | ||||||
Total long-term liabilities |
4,090,000 | 4,105,011 | ||||||
Commitments and contingencies (Note 7) |
||||||||
Stockholders equity |
||||||||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding |
| | ||||||
Common stock, $.001 par value, 600,000,000 shares authorized; 402,508,885 and
400,291,033 shares issued, respectively |
403 | 400 | ||||||
Paid-in capital in excess of par |
3,074,335 | 3,045,937 | ||||||
Retained earnings |
1,581,198 | 1,336,142 | ||||||
Accumulated other comprehensive loss |
(3,429 | ) | (488 | ) | ||||
Treasury stock, at cost, 193,177 and 78,524 shares, respectively |
(4,193 | ) | (1,284 | ) | ||||
Total stockholders equity |
4,648,314 | 4,380,707 | ||||||
Total liabilities and stockholders equity |
$ | 9,339,423 | $ | 9,065,063 | ||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
3
Table of Contents
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(In thousands, except per share data)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues and other income |
||||||||||||||||
Oil, natural gas, and related product sales |
$ | 591,099 | $ | 488,028 | $ | 1,097,291 | $ | 818,914 | ||||||||
CO2 sales and transportation fees |
5,343 | 4,690 | 10,267 | 9,187 | ||||||||||||
Gain on sale of interests in Genesis |
| (28 | ) | | 101,540 | |||||||||||
Interest income and other income |
4,955 | 4,520 | 8,004 | 6,390 | ||||||||||||
Total revenues and other income |
601,397 | 497,210 | 1,115,562 | 936,031 | ||||||||||||
Expenses |
||||||||||||||||
Lease operating expenses |
129,932 | 127,743 | 257,029 | 223,963 | ||||||||||||
Production taxes and marketing expenses |
39,688 | 38,100 | 72,439 | 57,417 | ||||||||||||
CO2 discovery and operating expenses |
1,869 | 1,681 | 4,023 | 3,049 | ||||||||||||
General and administrative |
30,900 | 31,192 | 74,746 | 63,901 | ||||||||||||
Interest, net of amounts capitalized of $13,194, $23,850,
$24,151 and $45,162, respectively |
42,249 | 43,483 | 91,026 | 69,899 | ||||||||||||
Depletion, depreciation, and amortization |
103,495 | 129,209 | 197,089 | 211,081 | ||||||||||||
Derivatives income |
(172,904 | ) | (128,674 | ) | (2,154 | ) | (169,899 | ) | ||||||||
Loss on early extinguishment of debt |
348 | | 16,131 | | ||||||||||||
Transaction and other costs related to the Encore Merger |
2,018 | 22,784 | 4,377 | 67,783 | ||||||||||||
Total expenses |
177,595 | 265,518 | 714,706 | 527,194 | ||||||||||||
Income before income taxes |
423,802 | 231,692 | 400,856 | 408,837 | ||||||||||||
Income tax provision |
||||||||||||||||
Current income taxes |
12,028 | 6,941 | 11,180 | 7,610 | ||||||||||||
Deferred income taxes |
152,528 | 74,422 | 144,620 | 150,694 | ||||||||||||
Consolidated net income |
259,246 | 150,329 | 245,056 | 250,533 | ||||||||||||
Less: net income attributable to noncontrolling interest |
| (14,962 | ) | | (18,278 | ) | ||||||||||
Net income attributable to Denbury stockholders |
$ | 259,246 | $ | 135,367 | $ | 245,056 | $ | 232,255 | ||||||||
Net income per common share |
||||||||||||||||
Basic |
$ | 0.65 | $ | 0.34 | $ | 0.62 | $ | 0.67 | ||||||||
Diluted |
$ | 0.64 | $ | 0.34 | $ | 0.61 | $ | 0.66 | ||||||||
Weighted average common shares outstanding |
||||||||||||||||
Basic |
398,631 | 395,548 | 398,032 | 345,126 | ||||||||||||
Diluted |
403,919 | 400,867 | 403,703 | 350,326 |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
4
Table of Contents
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(In thousands)
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities |
||||||||
Consolidated net income |
$ | 245,056 | $ | 250,533 | ||||
Adjustments needed to reconcile to net cash provided by operating activities |
||||||||
Depletion, depreciation, and amortization |
197,089 | 211,081 | ||||||
Deferred income taxes |
144,620 | 150,694 | ||||||
Gain on sale of interests in Genesis |
| (101,540 | ) | |||||
Stock-based compensation |
18,132 | 17,130 | ||||||
Non-cash fair value derivative adjustments |
(11,508 | ) | (226,899 | ) | ||||
Loss on early extinguishment of debt |
16,131 | | ||||||
Other, net |
5,755 | 5,871 | ||||||
Changes in operating assets and liabilities |
||||||||
Accrued production receivable |
(35,068 | ) | 52,075 | |||||
Trade and other receivables |
(28,258 | ) | 10,058 | |||||
Other assets |
(2,920 | ) | (3,134 | ) | ||||
Accounts payable and accrued liabilities |
(48,471 | ) | 12,066 | |||||
Oil and natural gas production payable |
30,135 | 11,236 | ||||||
Other liabilities |
(7,340 | ) | (4,880 | ) | ||||
Net cash provided by operating activities |
523,353 | 384,291 | ||||||
Cash flows used for investing activities |
||||||||
Oil and natural gas capital expenditures |
(471,601 | ) | (317,173 | ) | ||||
Acquisitions of oil and natural gas properties |
(32,482 | ) | (24,243 | ) | ||||
Cash paid in Encore Merger, net of cash acquired |
| (801,489 | ) | |||||
CO2 and other non-hydrocarbon gases capital expenditures |
(31,731 | ) | (44,274 | ) | ||||
Pipelines and plants capital expenditures |
(98,669 | ) | (108,177 | ) | ||||
Net proceeds from sales of oil and natural gas properties and equipment |
| 881,344 | ||||||
Net proceeds from sale of interests in Genesis |
| 162,622 | ||||||
Other |
1,643 | (7,224 | ) | |||||
Net cash used for investing activities |
(632,840 | ) | (258,614 | ) | ||||
Cash flows from financing activities |
||||||||
Bank repayments |
(130,000 | ) | (1,514,000 | ) | ||||
Bank borrowings |
130,000 | 1,149,000 | ||||||
Repayment of senior subordinated notes |
(525,000 | ) | (609,424 | ) | ||||
Premium paid on repayment of senior subordinated notes |
(13,137 | ) | (7,214 | ) | ||||
Net proceeds from issuance of senior subordinated notes |
400,000 | 1,000,000 | ||||||
Net proceeds from issuance of common stock |
9,203 | 5,540 | ||||||
Costs of debt financing |
(13,274 | ) | (76,232 | ) | ||||
ENP distributions to noncontrolling interest |
| (12,209 | ) | |||||
Other |
(8,382 | ) | (14,255 | ) | ||||
Net cash used for financing activities |
(150,590 | ) | (78,794 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
(260,077 | ) | 46,883 | |||||
Cash and cash equivalents at beginning of period |
381,869 | 20,591 | ||||||
Cash and cash equivalents at end of period |
$ | 121,792 | $ | 67,474 | ||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
5
Table of Contents
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
(In thousands)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Consolidated net income |
$ | 259,246 | $ | 150,329 | $ | 245,056 | $ | 250,533 | ||||||||
Other comprehensive income, net of income tax |
||||||||||||||||
Net unrealized loss on available-for-sale securities,
net of tax of $(4,375) and $(1,824), respectively |
(7,139 | ) | | (2,976 | ) | | ||||||||||
Interest rate lock derivative contracts reclassified to income,
net of tax of $10, $10, $21, and $21, respectively |
18 | 17 | 35 | 34 | ||||||||||||
Change in deferred hedge loss on interest rate swaps, net of tax of $8 and $18,
respectively |
| (60 | ) | | (87 | ) | ||||||||||
Consolidated comprehensive income |
252,125 | 150,286 | 242,115 | 250,480 | ||||||||||||
Less: comprehensive income attributable to noncontrolling interest |
| (14,950 | ) | | (18,235 | ) | ||||||||||
Comprehensive income attributable to Denbury stockholders |
$ | 252,125 | $ | 135,336 | $ | 242,115 | $ | 232,245 | ||||||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
6
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
We are a growing independent oil and natural gas company. We are the largest oil and natural
gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for
tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the
Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties
through a combination of exploitation, drilling and proven engineering extraction practices, with
our most significant emphasis on our CO2 tertiary 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 (U.S. GAAP) 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, 2010. Unless
indicated otherwise or the context requires, the terms we, our, us, 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 managements 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
June 30, 2011, our consolidated results of operations for the three and six months ended June 30,
2011 and 2010, and our consolidated cash flows for the six months ended June 30, 2011 and 2010.
Certain prior period items have been reclassified to make the classification consistent with the
classification in the most recent quarter.
Noncontrolling Interest
From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners
LP (ENP) outstanding common units and 100% of Encore Energy Partners GP LLC (GP LLC), which was
ENPs general partner. Considering the presumption of control of GP LLC in accordance with the
Consolidation topic of the Financial Accounting Standards Board Codification (FASC), the results
of operations and cash flows of ENP were consolidated with those of Denbury for this period. On
December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not
consolidate ENP in our Unaudited Condensed Consolidated Balance Sheets as of December 31, 2010 and
June 30, 2011, nor do our Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011
or our
Unaudited Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2011 include ENPs results of operations or cash flows.
As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and
six months ended June 30, 2010, Net income attributable to noncontrolling interest of $15.0
million and $18.3 million, respectively, represents ENPs results of operations attributable to
third-party ENP limited partner interest owners, other than Denbury, for the portion of that period
for which we consolidated ENP.
Net Income Per Common Share
Basic net income per common share is computed by dividing net income attributable to our
stockholders by the weighted average number of shares of common stock outstanding during the
period. Diluted net income per common share is calculated in the same manner, but also considers
the impact of the potential dilution from stock options, stock appreciation rights (SARs),
unvested restricted stock, and unvested performance equity awards. For the three and six months
ended June 30, 2011 and 2010, there were no adjustments to net income attributable to our
stockholders for purposes of calculating diluted net income per common share. The following is a
reconciliation of the weighted average common shares used in the basic and diluted net income per
common share calculations for the periods indicated:
7
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Basic weighted average common shares |
398,631 | 395,548 | 398,032 | 345,126 | ||||||||||||
Potentially dilutive securities: |
||||||||||||||||
Stock options and SARs |
3,946 | 3,980 | 4,251 | 3,835 | ||||||||||||
Performance equity awards |
23 | 146 | 12 | 312 | ||||||||||||
Restricted stock |
1,319 | 1,193 | 1,408 | 1,053 | ||||||||||||
Diluted weighted average common shares |
403,919 | 400,867 | 403,703 | 350,326 | ||||||||||||
Basic weighted average common shares excludes 3.4 million and 3.6 million shares for the three
and six months ended ended June 30, 2011, respectively, and 3.5 million and 3.3 million shares for
the three and six months ended June 30, 2010, respectively, of unvested restricted stock. As these
restricted shares vest or become retirement eligible, they will be included in the shares
outstanding used to calculate basic net income per common share, although all restricted stock is
issued and outstanding upon grant. For purposes of calculating diluted weighted average common
shares, unvested restricted stock is included in the computation using the treasury stock method,
with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted
for 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 per share as their effect would have been
anti-dilutive:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Stock options and SARs |
2,412 | 4,223 | 2,297 | 4,785 | ||||||||||||
Restricted stock |
24 | 35 | 15 | 413 |
Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any
unrealized gains or losses included in accumulated other comprehensive income. At June 30, 2011 and
December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural
Resources LLC (Vanguard) common units obtained as partial consideration for the sale of our
interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this
investment is $93.0 million. We received distributions of $1.7 million and $3.5 million on the
Vanguard common units we own for the three and six months ended June 30, 2011, respectively, which
distributions are included in Interest income and other income on our Unaudited Condensed
Consolidated Statements of Operations. The unrealized loss on our short-term investment of $7.1
million (net of a tax benefit of $4.4 million) and
$3.0 million (net of a tax benefit of $1.8 million) for the three
and six months ended June 30, 2011, respectively, is included in our Unaudited Condensed
Consolidated Statements of Comprehensive Operations.
Recently Issued Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRSs, (ASU 2011-04). ASU 2011-04 amends the FASC Fair Value
Measurements topic by providing a consistent definition and measurement of fair value, as well as
similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards.
ASU 2011-04 changes certain fair value measurement principles, clarifies the application of
existing fair value measurements and expands the fair value disclosure requirements, particularly
for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning
January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our
consolidated financial statements, but may require additional disclosures.
8
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (ASU
2011-05). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous
statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will
be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend
presentation requirements, it will not have a material effect on our consolidated financial
statements.
9
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 2. Acquisitions and Divestitures
2010 Merger with Encore Acquisition Company
On March 9, 2010, we acquired Encore Acquisition Company (Encore) pursuant to the Encore
Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided
for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date,
including the assumption of debt and the value of the noncontrolling interest in ENP (the Encore
Merger). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury
surviving the Encore Merger.
For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30,
2010, we recognized $200.6 million and $260.9 million, respectively, of oil, natural gas sales and
related product sales related to the Encore Merger. For the three months ended June 30, 2010 and
for the period from March 9, 2010 to June 30, 2010, we recognized $137.8 million and $180.7
million, respectively, of net field operating income (oil, natural gas and related product sales
less lease operating expenses, production taxes and marketing expenses) related to the Encore
Merger. We recognized a total of $2.0 million and $22.8 million of transaction and other costs
related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and
severance costs) for the three months ended June 30, 2011 and 2010, respectively, and $4.4 million
and $67.8 million of such costs for the six months ended June 30, 2011 and 2010, respectively.
2010 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge
In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal
Unit (Riley Ridge), located in the LaBarge Field of southwestern Wyoming, for $132.3 million
after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and
CO2 resources. The purchase included a working interest in a gas plant, which is
currently under construction, which will separate the helium and natural gas from the commingled
gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in
an additional 28,000 acres adjoining the Riley Ridge Unit.
This acquisition meets the definition of a business under the FASC Business Combinations
topic. The following table presents a summary of the preliminary fair value of these Riley Ridge
assets acquired and liabilities assumed:
In thousands | ||||
Oil and natural gas properties |
$ | 19,646 | ||
CO2
and other non-hydrocarbon gases properties |
10,907 | |||
Pipelines and
plants |
72,070 | |||
Prepaid construction and drilling costs |
9,346 | |||
Other assets |
19,300 | |||
Asset retirement obligations |
(472 | ) | ||
Goodwill |
1,460 | |||
Total |
$ | 132,257 | ||
On August 1, 2011, we acquired the remaining working interest in Riley Ridge and an additional
interest in the adjoining acreage and became the operator of both projects; see Note 8, Subsequent
Event, for more information.
Pro Forma Information
Had the Encore Merger and October 2010 Riley Ridge acquisition both occurred on January 1,
2010, our combined pro forma revenues and net income for the three and six months ended June 30,
2010, would have been as follows:
10
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Pro Forma Results | ||||||||
Three Months Ended | Six Months Ended | |||||||
In thousands, except per share amounts | June 30, 2010 | June 30, 2010 | ||||||
Pro forma total revenues |
$ | 497,210 | $ | 1,112,481 | ||||
Pro forma net income attributable to Denbury stockholders |
135,494 | 247,423 | ||||||
Pro forma net income per common share: |
||||||||
Basic |
$ | 0.34 | $ | 0.63 | ||||
Diluted |
0.34 | 0.62 |
2010 Sale of Interests in Genesis
In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis
Energy, L.P. (Genesis), for net proceeds of approximately $84 million. In March 2010, we sold
all of our Genesis common units in a secondary public offering for net proceeds of approximately
$79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax)
on these dispositions.
2010 Sale of Southern Assets
In May 2010, we sold certain non-strategic legacy Encore properties primarily located in the
Permian Basin, the Mid-continent area and the East Texas Basin (the Southern Assets) to Quantum
Resources Management, LLC for consideration of $892.1 million after closing adjustments. We did
not record a gain or loss on the sale in accordance with the full cost method of accounting.
Note 3. Long-Term Debt
The following table shows the components of our long-term debt:
June 30, | December 31, | |||||||
In thousands | 2011 | 2010 | ||||||
Bank Credit Agreement |
$ | | $ | | ||||
71/2% Senior Subordinated Notes due 2013, including discount of $437 |
| 224,563 | ||||||
71/2% Senior Subordinated Notes due 2015, including premium of $427 |
| 300,427 | ||||||
91/2% Senior Subordinated Notes due 2016, including premium of $13,222 and $14,589,
respectively |
238,142 | 239,509 | ||||||
93/4% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139,
respectively |
406,354 | 404,211 | ||||||
81/4% Senior Subordinated Notes due 2020 |
996,273 | 996,273 | ||||||
6⅜% Senior Subordinated Notes due 2021 |
400,000 | | ||||||
Other Subordinated Notes, including premium of $37 and $41, respectively |
3,842 | 3,848 | ||||||
NEJD financing |
165,550 | 167,331 | ||||||
Free State financing |
80,953 | 81,188 | ||||||
Capital lease obligations |
5,620 | 6,806 | ||||||
Total |
2,296,734 | 2,424,156 | ||||||
Less current obligations |
(8,622 | ) | (7,948 | ) | ||||
Long-term debt and capital lease obligations |
$ | 2,288,112 | $ | 2,416,208 | ||||
The parent company, Denbury Resources Inc. (DRI), is the sole issuer of all of our
outstanding senior subordinated notes. DRI has no independent assets or operations. All of our
100% owned subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee our
senior subordinated debt jointly and severally.
Bank Credit Agreement
In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase
Bank, N.A., as administrative agent, and other lenders as party thereto (the Bank Credit
Agreement). Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to
May 1 and November 1 and upon requested special redeterminations. The borrowing base is adjusted
at the banks discretion and is based in part upon external factors over which we have no control.
If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement,
we would be required to repay the deficit over a period of four months.
11
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the
Amendment). The Amendment reconfirms our current borrowing base of $1.6 billion, extends the
maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on
outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of
debt to adjusted EBITDA. Under the Amendment, the margin on outstanding Eurodollar loans bears
interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable
margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to
the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank
Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the
ratio of outstanding borrowings to the borrowing base. The Amendment also prescribes a commitment
fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the
borrowing base, and adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and
its subsidiaries from 4.0x to 4.25x.
6⅜% Senior Subordinated Notes due 2021
In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (2021
Notes). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of
$393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see
Redemption of our 2013 and 2015 Notes below).
The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15
of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our
option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August
15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on
or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an
aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds
of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100%
of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a
make-whole premium and accrued and unpaid interest. The indenture contains certain restrictions
on our ability to incur additional debt, pay dividends on our common stock, make investments,
create liens on our assets, engage in transactions with our affiliates, transfer or sell assets,
consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to
any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and
unconditionally guarantee this debt jointly and severally.
Redemption of our 2013 and 2015 Notes
On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal
amount of our 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration
of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the
2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of
par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding
2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding
2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $0.3 million and $16.1 million
loss during the three and six months ended June 30, 2011 associated with the debt repurchases,
which is included in our Unaudited Condensed Consolidated Statements of Operations under the
caption Loss on early extinguishment of debt.
Note 4. Derivative Instruments and Hedging Activities
Oil and Natural Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts,
and 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 cash settlements of expired contracts are shown under Derivatives expense
(income) in our Unaudited Condensed Consolidated Statements of Operations.
12
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 consisted of price floors, collars and fixed price swaps. The
production that we hedge has varied from year to year depending on our levels of debt and financial
strength and expectation of future commodity prices. We currently employ a strategy to hedge a
portion of our forecasted production for a period generally ranging from approximately 12 to
18 months in advance, as we believe it is important to protect our future cash flow to provide a
level of assurance for our capital spending in those future periods in light of current worldwide
economic uncertainties and commodity price volatility.
We manage and control market and counterparty credit risk through established internal control
procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to
counterparties through formal credit policies, monitoring procedures, and diversification. All of
our commodity derivative contracts are with parties that are lenders under our Bank Credit
Agreement.
The following is a summary of Derivatives expense (income) included in the accompanying
Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Oil |
||||||||||||||||
Payment on settlements of derivative contracts |
$ | 16,972 | $ | 13,829 | $ | 22,000 | $ | 77,379 | ||||||||
Fair value adjustments to derivative contracts expense (income) |
(187,194 | ) | (145,099 | ) | (20,130 | ) | (206,920 | ) | ||||||||
Total derivative expense (income) oil |
(170,222 | ) | (131,270 | ) | 1,870 | (129,541 | ) | |||||||||
Natural Gas |
||||||||||||||||
Receipt on settlements of derivative contracts |
(6,030 | ) | (16,630 | ) | (12,646 | ) | (20,379 | ) | ||||||||
Fair value adjustments to derivative contracts expense (income) |
3,348 | 19,909 | 8,622 | (19,109 | ) | |||||||||||
Total derivative expense (income) natural gas |
(2,682 | ) | 3,279 | (4,024 | ) | (39,488 | ) | |||||||||
Ineffectiveness on interest rate swaps |
| (683 | ) | | (870 | ) | ||||||||||
Derivative income |
$ | (172,904 | ) | $ | (128,674 | ) | $ | (2,154 | ) | $ | (169,899 | ) | ||||
13
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Commodity Derivative Contracts Not Classified as Hedging Instruments
The following tables present outstanding commodity derivative contracts with respect to future
production as of June 30, 2011:
NYMEX Contract Prices Per Bbl | ||||||||||||||||||||||||
Type of | Weighted Average Price | |||||||||||||||||||||||
Year | Months | Contract | Bbls/d | Swap | Floor | Ceiling | ||||||||||||||||||
Oil Contracts |
||||||||||||||||||||||||
2011 |
July - Sept | Swap | 625 | 79.18 | | | ||||||||||||||||||
Collar | 42,500 | | 70.35 | 100.09 | ||||||||||||||||||||
Put | 6,625 | | 69.53 | | ||||||||||||||||||||
Total July - Sept 2011 | 49,750 | |||||||||||||||||||||||
Oct - Dec | Swap | 625 | 79.18 | | | |||||||||||||||||||
Collar | 45,500 | | 70.33 | 101.74 | ||||||||||||||||||||
Put | 6,625 | | 69.53 | | ||||||||||||||||||||
Total Oct - Dec 2011 | 52,750 | |||||||||||||||||||||||
2012 |
Jan - Mar | Swap | 625 | 81.04 | | | ||||||||||||||||||
Collar | 52,000 | | 70.00 | 106.86 | ||||||||||||||||||||
Put | 625 | | 65.00 | | ||||||||||||||||||||
Total Jan - Mar 2012 | 53,250 | |||||||||||||||||||||||
Apr-June | Swap | 625 | 81.04 | | | |||||||||||||||||||
Collar | 53,000 | | 70.00 | 119.44 | ||||||||||||||||||||
Put | 625 | | 65.00 | | ||||||||||||||||||||
Total Apr - June 2012 | 54,250 | |||||||||||||||||||||||
July-Sept | Swap | 625 | 81.04 | | | |||||||||||||||||||
Collar | 53,000 | | 80.00 | 128.57 | ||||||||||||||||||||
Put | 625 | | 65.00 | | ||||||||||||||||||||
Total July - Sept 2012 | 54,250 | |||||||||||||||||||||||
Oct - Dec | Swap | 625 | 81.04 | | | |||||||||||||||||||
Collar | 53,000 | | 80.00 | 128.57 | ||||||||||||||||||||
Put | 625 | | 65.00 | | ||||||||||||||||||||
Total Oct - Dec 2012 | 54,250 | |||||||||||||||||||||||
14
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Type of | Weighted Average Swap | |||||||||||||||
Year | Months | Contract | MMBtu/d | Price per MMBtu | ||||||||||||
Natural Gas Contracts |
||||||||||||||||
2011 |
July - Sept | Swap | 33,500 | $ | 6.27 | |||||||||||
Total July-Sept 2011 | 33,500 | |||||||||||||||
Oct - Dec | Swap | 33,500 | 6.27 | |||||||||||||
Total Oct - Dec 2011 | 33,500 | |||||||||||||||
2012 |
Jan - Dec | Swap | 20,000 | 6.53 | ||||||||||||
Total Jan - Dec 2012 | 20,000 | |||||||||||||||
Additional Disclosures about Derivative Instruments
At June 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in
our Unaudited Condensed Consolidated Balance Sheets as follows:
Estimated Fair Value | ||||||||||||
Asset (Liability) | ||||||||||||
June 30, | December 31, | |||||||||||
Type of Contract | Balance Sheet Location | 2011 | 2010 | |||||||||
(In thousands) | ||||||||||||
Derivatives not designated as hedging instruments |
||||||||||||
Derivative asset |
||||||||||||
Oil contracts |
Derivative assets current | $ | 1,462 | $ | 3,050 | |||||||
Natural gas contracts |
Derivative assets current | 17,860 | 21,192 | |||||||||
Oil contracts |
Derivative assets long-term | 11,281 | 1,301 | |||||||||
Natural gas contracts |
Derivative assets long-term | 6,328 | 11,618 | |||||||||
Derivative liability |
||||||||||||
Oil contracts |
Derivative liabilities current | (67,196 | ) | (55,256 | ) | |||||||
Deferred premiums |
Derivative liabilities current | (14,431 | ) | (22,928 | ) | |||||||
Oil contracts |
Derivative liabilities long-term | (2,228 | ) | (25,906 | ) | |||||||
Deferred premiums |
Derivative liabilities long-term | (1,150 | ) | (3,781 | ) | |||||||
Total derivatives
not designated as
hedging instruments |
$ | (48,074 | ) | $ | (70,710 | ) | ||||||
Note 5. Fair Value Measurements
Fair Value Hierarchy
Fair value is 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 (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 market 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:
15
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. | ||
| Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, 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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. | ||
| Level 3 Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in managements best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel). |
We adjust the valuations for nonperformance risk, using our estimate of the counterpartys
credit quality for asset positions and Denburys 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: | ||||||||||||||||
Significant | ||||||||||||||||
Quoted Prices | Other | Significant | ||||||||||||||
in Active | Observable | Unobservable | ||||||||||||||
Markets | Inputs | Inputs | ||||||||||||||
In thousands | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
June 30, 2011 |
||||||||||||||||
Assets |
||||||||||||||||
Short-term investments |
$ | 88,220 | $ | | $ | | $ | 88,220 | ||||||||
Oil and natural gas derivative contracts |
| 30,293 | 6,638 | 36,931 | ||||||||||||
Liabilities |
||||||||||||||||
Oil and natural gas derivative contracts |
| (69,424 | ) | | (69,424 | ) | ||||||||||
Total |
$ | 88,220 | $ | (39,131 | ) | $ | 6,638 | $ | 55,727 | |||||||
December 31, 2010 |
||||||||||||||||
Assets |
||||||||||||||||
Short-term investments |
$ | 93,020 | $ | | $ | | $ | 93,020 | ||||||||
Oil and natural gas derivative contracts |
| 20,683 | 16,478 | 37,161 | ||||||||||||
Liabilities |
||||||||||||||||
Oil and natural gas derivative contracts |
| (81,162 | ) | | (81,162 | ) | ||||||||||
Total |
$ | 93,020 | $ | (60,479 | ) | $ | 16,478 | $ | 49,019 | |||||||
16
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in the fair value of our Level 3 assets for the
three and six months ended June 30, 2011 and 2010:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Balance, beginning of period |
$ | 15,346 | $ | 50,518 | $ | 16,478 | $ | | ||||||||
Unrealized gains/(losses) on commodity derivative
contracts included in earnings |
(7,386 | ) | 126 | (7,076 | ) | 14,899 | ||||||||||
Commodity derivative contracts acquired from Encore |
| | | 38,093 | ||||||||||||
Receipts on settlement of commodity derivative contracts |
(1,322 | ) | (10,361 | ) | (2,764 | ) | (12,709 | ) | ||||||||
Balance, end of period |
6,638 | 40,283 | $ | 6,638 | $ | 40,283 | ||||||||||
Since we do not use hedge accounting for our commodity derivative contracts, any gains
and losses on our assets and liabilities are included in Derivatives income in the accompanying
Unaudited Condensed Consolidated Statements of Operations.
17
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth the fair value of financial instruments that are not recorded
at fair value in our Unaudited Condensed Consolidated Financial Statements:
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying | Estimated | Carrying | Estimated | |||||||||||||
In thousands | Amount | Fair Value | Amount | Fair Value | ||||||||||||
71/2% Senior Subordinated Notes due 2013 |
$ | | $ | | $ | 224,563 | $ | 228,375 | ||||||||
71/2% Senior Subordinated Notes due 2015 |
| | 300,427 | 310,500 | ||||||||||||
91/2% Senior Subordinated Notes due 2016 |
238,142 | 249,942 | 239,509 | 249,661 | ||||||||||||
93/4% Senior Subordinated Notes due 2016 |
406,354 | 476,446 | 404,211 | 475,380 | ||||||||||||
81/4% Senior Subordinated Notes due 2020 |
996,273 | 1,085,938 | 996,273 | 1,080,956 | ||||||||||||
6⅜% Senior Subordinated Notes due 2021 |
400,000 | 400,000 | | |
The fair values of our senior subordinated notes are based on quoted market prices. We have
other financial instruments consisting primarily of cash, cash equivalents and short-term
receivables and payables that approximate fair value due to the nature of the instrument and the
relatively short maturities.
Note 6. Supplemental Information
Accounts Payable and Accrued Liabilities
The following table summarizes our accounts payable and accrued liabilities as of the periods
indicated:
June 30, | December 31, | |||||||
In thousands | 2011 | 2010 | ||||||
Accounts payable |
$ | 72,830 | $ | 47,660 | ||||
Accrued exploration and development costs |
96,910 | 101,758 | ||||||
Accrued compensation |
26,760 | 39,757 | ||||||
Accrued lease operating expense |
25,100 | 23,557 | ||||||
Accrued interest |
61,166 | 57,077 | ||||||
Taxes payable |
16,537 | 34,371 | ||||||
Other |
34,650 | 41,818 | ||||||
Total |
$ | 333,953 | $ | 345,998 | ||||
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
Six Months Ended | ||||||||
June 30, | ||||||||
In thousands | 2011 | 2010 | ||||||
Cash paid for interest, expensed |
$ | 72,774 | $ | 43,296 | ||||
Cash paid for interest, capitalized |
24,151 | 45,162 | ||||||
Cash paid for income taxes |
31,072 | 11,920 | ||||||
Cash received for income tax refunds |
20,841 | 13,093 | ||||||
Increase in liabilities for capital expenditures |
25,141 | 46,170 | ||||||
Issuance of Denbury common stock in connection with the Encore Merger |
| 2,085,681 |
18
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 7. Commitments and Contingencies
In March 2011, we entered into three long-term supply contracts to purchase CO2
from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three
contracts are in addition to the previously disclosed long-term supply contracts Denbury currently
has in place in the Gulf Coast, Rocky Mountain and Midwest regions. Under the three new contracts,
Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLCs
Medicine Bow Fuel and Power LLC (MBFP) project in Medicine Bow, Wyoming, purchase 70% of the
CO2 captured from Mississippi Power Companys Kemper County Integrated Gasification
Combined Cycle (IGCC) project in Mississippi, and purchase 100% of the CO2 captured by
Air Products LLC (Air Products) at a third-party refinery in Port Arthur, Texas. These new
contracts each have an initial term of 15 to 16 years and include options to extend the term. We
estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our
enhanced oil recovery operations, although under certain circumstances, we may be obligated to
purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to
begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in 2015,
115 MMcf/d of CO2 from the IGCC project by 2014, and 50 MMcf/d of CO2 from
Air Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased
under these three contracts would be approximately $110 million per year (assuming purchases of 460
MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of
CO2 will fluctuate based on the changes in the price of oil.
As is the case with all of our long-term supply contracts to purchase CO2, the
three agreements entered into in March are subject to various contingencies. The IGCC and Air
Products plants are currently being constructed and MBFP is in the initial stages of construction
but its completion is still contingent upon securing debt financing and equity commitments and
receipt of all necessary consents and approvals.
In the third quarter of 2008, we obtained approval from the National Office of the Internal
Revenue Service (IRS) to change our method of tax accounting for certain assets used in our
tertiary oilfield recovery operations. As a result of the approved change in method of tax
accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs
for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax
years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently
exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we
received a Technical Advice Memorandum (TAM) issued by the IRS National Office disapproving our
method of accounting and revoking its consent to our change, on a prospective basis only,
commencing January 1, 2011. As a result of the prospective nature of the IRSs determination, there
should be no change in our position with respect to the deductibility of these costs for 2007,
2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending
and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to
assess the outcome of any such review, nor how that outcome may affect the other years covered by
the TAM.
We are subject to audits for sales and use taxes and severance taxes in the various states in
which we operate, and from time to time receive assessments for potential taxes that we may owe.
We have received a $15.0 million assessment from the Mississippi taxing authority for use tax,
penalties and interest covering the 2004-2007 period. We believe this assessment is significantly
in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome
of this matter will have a material adverse effect on our financial position or results of
operations.
We are involved in various lawsuits, claims and other regulatory proceedings incidental to our
businesses. While we currently believe that the ultimate outcome of these proceedings, individually
and in the aggregate, will not have a material adverse effect on our financial position, results of
operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling
were to occur, there exists the possibility of a material adverse impact on our net income in the
period in which the ruling occurs. We provide accruals for litigation and claims if we determine
that a loss is probable and the amount can be reasonably estimated.
Note 8. Subsequent Event
On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge and a
working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of
the transaction, we became the operator of both projects. The purchase price was approximately
$191 million, including a $15 million contingent payment to be paid at the time the propertys gas
processing facility is operational and meets specific performance conditions, plus customary
closing adjustments including payment for capital expenditures incurred between the effective date
of the purchase (April 1, 2011) and closing. We expect the gas processing facility to be
operational during the fourth quarter of 2011.
19
Table of Contents
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The acquisition of Riley Ridge meets the definition of a business under the FASC Business
Combinations topic. We will account for our acquisition of Riley Ridge under the acquisition
method of accounting, which will result in the allocation of the purchase price to the assets
acquired and liabilities assumed based on their estimated fair values at the date of acquisition,
with the excess purchase price, if any, being recognized as goodwill. We have not yet completed our
initial calculation necessary to make this allocation.
20
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis should be read in conjunction with our consolidated
financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for
the year ended December 31, 2010, along with Managements Discussion and Analysis of Financial
Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in
the following discussion have the same meaning given to them in the Form 10-K. Our discussion and
analysis includes forward-looking information that involves risks and uncertainties and should be
read in conjunction with Risk Factors under Item 1A of this report, along with Forward-Looking
Information at the end of this section for information about the risks and uncertainties that could
cause our actual results to be materially different than our forward-looking statements.
Overview
We are a growing independent oil and natural gas company. We are the largest oil and natural
gas producer in both Mississippi and Montana, own the largest CO2 reserves used for
tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the
Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties
through a combination of exploitation, drilling and proven engineering extraction practices, with
the most significant emphasis on our CO2 tertiary recovery operations.
The acquisition of Encore Acquisition Company (the Encore Merger) on March 9, 2010, has had
a significant impact on nearly every aspect of our business, including oil and natural gas
production, revenues and operating expenses. Accordingly, the Encore Merger impacts the
comparability of our financial results for the first six months of 2010 to those in the first six
months of 2011, which is more fully detailed throughout the following discussion and analysis. Our
financial results for the first six months of 2010 include the results of operations of Encore from
the date of the acquisition on March 9, 2010 through June 30, 2010. Additionally, starting in May
2010 and throughout the remainder of that year, we disposed of non-strategic Encore properties and
our ownership interests in Encore Energy Partners LP (ENP).
Second Quarter Operating Highlights. We recognized net income of $259.2 million, or
$0.65 per basic common share, during the second quarter of 2011 as compared to net income of $135.4
million, or $0.34 per basic common share, during the second quarter of 2010. This increase between
the two periods is primarily attributable to:
| A $103.1 million ($63.9 million after tax), or 21%, increase in revenue, made up of $214.4 million of additional revenue from higher realized commodity prices in the 2011 second quarter, partially offset by a decrease of $111.3 million of revenue primarily attributable to the absence in the most recent quarter of production from properties sold starting in May 2010; | ||
| A $58.6 million increase in the non-cash fair value adjustment in the mark-to-market valuation of our commodities derivatives, principally attributable to oil futures (non-cash income of $183.8 million in the second quarter of 2011 compared to $125.2 million of such non-cash income in the second quarter of 2010); and | ||
| $22.8 million of transaction and other costs related to the Encore Merger incurred in the 2010 period ($14.1 million after tax), which costs were negligible in the most recent quarter. |
During the second quarter of 2011, our oil and natural gas production, which was 92% oil,
averaged 64,919 BOE/d compared to 84,111 BOE/d produced during the second quarter of 2010. This
drop in production is primarily attributable to the sale of non-strategic legacy Encore assets and
our interests in ENP (which together had production of 20,526 BOE/d in last years second quarter),
which were sold starting in May 2010, partially offset by increases in our quarterly tertiary and
Bakken production. Our tertiary oil production averaged 30,771 Bbls/d during the second quarter of
2011, up 8% over the 28,507 Bbls/d during the second quarter a year earlier. Tertiary oil
production was essentially flat sequentially (down 0.2%, or 54 Bbls/d) for the second quarter. Our
Bakken oil production averaged 7,626 BOE/d during the second quarter of 2011, up 69% over
production of 4,500 BOE/d during the second quarter of 2010 and sequentially up 33% from levels in the first quarter of
2011. See Results of Operations CO2 Operations and Results of Operations
Operating Results Production for more information.
21
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil prices during the second quarter of 2011 were considerably higher than prices during the
second quarter of 2010. Our average oil and natural gas price received per BOE, excluding the
impact of commodity derivative contracts, was $100.06 per BOE during the second quarter of 2011,
compared to $63.76 per BOE during the second quarter of 2010, a 57% increase between the two
periods. Including the impact of cash settlements on our commodity derivative contracts, our
average oil and natural gas price per BOE was $98.21 per BOE during the second quarter of 2011
compared to $64.13 per BOE during the second quarter of 2010, a 53% increase. During the second
quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West
Texas Intermediate (WTI) prices) improved significantly from a negative $4.13 per Bbl in the
second quarter of 2010 to a positive $3.72 per Bbl in the second quarter of 2011, primarily due to
the favorable price differential for crude oil sold under Louisiana Light Sweet (LLS) index
pricing. See Results of Operations Operating Results Oil and Natural Gas Revenues below for
more information.
August 2011 Acquisition of Remaining Working Interest in Riley Ridge. On August 1, 2011, we
acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (Riley Ridge) and a
working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of
the transaction, we became the operator of both projects. The purchase price was approximately
$191 million, which includes a $15 million contingent payment to be paid at the time the propertys
gas processing facility is operational and meets specific performance conditions, plus customary
closing adjustments, including payments for capital expenditures incurred between the effective
date of the purchase (April 1, 2011) and closing. We currently expect the gas processing facility
to be operational with the first production of natural gas and helium from Riley Ridge during the
fourth quarter of 2011. The CO2 will be re-injected into the reservoir until we have
completed an additional separation facility and a CO2 pipeline to the field, which is
expected to be completed in four or five years.
Combining this acquisition with the interest in Riley Ridge that we acquired in October 2010, we estimate that our total
ownership at Riley Ridge currently contains estimated proved reserves of 435 Bcf of natural gas, 15.5 Bcf of helium and 2.4
Tcf of CO2. The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural
gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO2, net to our interest.
The first production of natural gas and helium from Riley Ridge is expected to begin late in the fourth quarter of 2011,
with initial production of CO2 expected in four to five years following construction of both additional facilities to
separate the CO2 from the remaining gas stream, and a CO2 pipeline to the field.
Addition of Proved Oil and Natural Gas Reserves. We added 30.9 MMBOE of estimated proved
reserves during the first six months. These reserve additions include 28.1 MMBOE of estimated
proved reserves at our Bakken properties, and minor revisions to our other properties. These
additions do not include estimated proved reserves of approximately 250 Bcf of natural gas (41.7
MMBOE) associated with the Riley Ridge acquisitions completed in August discussed above.
March 2011 CO2 Purchase Contracts. In March 2011, we entered into three long-term
supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and
Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term
supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest
regions. We will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLCs
Medicine Bow Fuel and Power LLC (MBFP) project in Medicine Bow, Wyoming, 70% of the
CO2 captured from Mississippi Power Companys Kemper County Integrated Gasification
Combined Cycle (IGCC) project in Mississippi, and 100% of the CO2 captured by Air
Products LLC (Air Products) at a third-party refinery in Port Arthur, Texas. These three
contracts each have an initial term of 15 to 16 years and include options to extend the term. We
estimate these three sources will supply approximately 365 MMcf/d of CO2 for our
enhanced oil recovery operations, although under certain circumstances, we may be obligated to
purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to
begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d
of CO2 from the IGCC project in 2014, and 50 MMcf/d of CO2 from Air Products
in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these
three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d),
plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of
CO2 will fluctuate based on the changes in the price of oil.
As is the case with all of our long-term supply contracts to purchase CO2, the
three agreements entered into in March are subject to various contingencies.
Construction on the IGCC and MBFP plants is in the initial stages and additional construction under the MBFP agreement is contingent upon securing debt
financing and equity commitments and receipt of all necessary consents and approvals. The Air
Products agreement is also contingent upon third party approvals for the necessary utilities and
infrastructure.
22
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
February 2011 Debt Refinancing. In February 2011, we issued, at par, $400 million of 6⅜%
Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to
partially fund the repurchase of $525 million in principal amount of our outstanding 2013 Notes and
2015 Notes in cash tender offers to purchase $225 million principal amount of our 2013 Notes and
$300 million principal amount of our 2015 Notes. In the first quarter of 2011, we accepted for
purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in
principal of the 2015 Notes at 104.125% of par. We redeemed the remaining outstanding 2015 Notes
at 103.75% of par during the first quarter of 2011 and all of the remaining outstanding 2013 Notes
at par on April 1, 2011. During the three and six months ended June 30, 2011, we recognized $0.3
million and $16.1 million, respectively, of loss associated with the debt repurchases, included in
our income statements under the caption Loss on early extinguishment of debt.
Capital Resources and Liquidity
In June 2011, when we signed the agreement to acquire the remaining interest in Riley Ridge,
which closed in August 2011, our Board of Directors approved a $50 million increase in our 2011
capital spending budget for development of the Riley Ridge plant, increasing our projected 2011 oil
and gas capital investments to $1.35 billion, excluding capitalized interest, tertiary start-up
costs, acquisitions and divestitures, and net of equipment leases. Our current 2011 capital budget
includes the following:
| $450 million allocated for tertiary oil field expenditures; | ||
| $350 million in the Bakken area of North Dakota; | ||
| $250 million to be spent on our CO2 pipelines; | ||
| $200 million to be spent on CO2 sources in the Jackson Dome and Riley Ridge areas; and | ||
| $100 million on drilling, completion and other development activities in our other areas. |
Based on oil and natural gas commodity futures prices in early August 2011 and our current
production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized
interest and tertiary start-up costs, is $150 million to $250 million greater than our anticipated
cash flow from operations. These expenditures will be funded with our excess cash on hand or, if
necessary, borrowings under our $1.6 billion Bank Credit Agreement under which at August 4, 2011,
we had drawn $125 million, all of which was used as part of the funding of our August 1, 2011 Riley
Ridge acquisition discussed above. Another potential source of funds would be proceeds if we
should sell the units in Vanguard Natural Resources LLP units acquired in the sale of ENP, which
have ranged in value between approximately $80 million and $100 million during the second quarter
of 2011.
We continually monitor our capital spending and anticipated cash flows and believe that we can
adjust our capital spending up or down depending on cash flows; however, any such reduction in
capital spending could impact the timing of our future production. There are potential limitations
on the amount of capital spending we can eliminate without penalties (refer to Managements
Discussion and Analysis Capital Resources and Liquidity Off-Balance Sheet Arrangements
Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010,
and see CO2 Purchase Contracts above and Off-Balance Sheet Arrangements below for
further information regarding additional commitments entered into during 2011). In addition to the
potential flexibility in our capital spending plans, we have approximately $1.4 billion of unused
liquidity under our bank credit line and have significant oil price floors through the end of 2012
(see Note 4 to the Unaudited Condensed Consolidated Financial Statements), which together should
provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if
oil prices were to decrease significantly.
Our capital spending estimate also assumes that we fund approximately $60 million of budgeted
equipment purchases with operating leases, the amount of which is dependent upon securing
acceptable financing. Through August 1, 2011, we have funded approximately $27 million of these
budgeted equipment purchases with operating leases. Our net capital expenditures would increase by
the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under
our Bank Credit Agreement.
23
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
In May 2011, we entered into our Fifth Amendment to the Bank Credit Agreement, reconfirming
our current borrowing base of $1.6 billion, extending the maturity from March 2014 to May 2016,
reducing certain margins and letter of credit fees, and adjusting the maximum permitted ratio of
debt to adjusted EBITDA. See further discussion in Note 3 to the Unaudited Condensed Consolidated
Financial Statements.
Capital Expenditure Summary. The following table of capital expenditures includes accrued
capital for the six month periods of 2011 and 2010:
Six Months Ended | ||||||||
June 30, | ||||||||
In thousands | 2011 | 2010 | ||||||
Oil and natural gas exploration and development: |
||||||||
Drilling |
$ | 244,466 | $ | 155,503 | ||||
Geological, geophysical, and acreage |
14,339 | 15,121 | ||||||
Facilities |
123,742 | 73,712 | ||||||
Recompletions |
104,878 | 91,534 | ||||||
Capitalized interest |
18,652 | 13,681 | ||||||
Total oil and natural gas exploration and development expenditures
|
506,077 | 349,551 | ||||||
CO2 and other non-hydrocarbon gases capital expenditures: |
||||||||
Drilling |
28,768 | 27,113 | ||||||
Geological, geophysical, and acreage |
10,195 | 4,299 | ||||||
Facilities |
13,737 | 12,245 | ||||||
Total CO2 and other non-hydrocarbon gases capital expenditures |
52,700 | 43,657 | ||||||
Pipelines and plants capital expenditures: |
||||||||
Pipelines and plants |
61,292 | 92,500 | ||||||
Capitalized interest |
5,499 | 31,481 | ||||||
Total pipelines and plants capital expenditures |
66,791 | 123,981 | ||||||
Total capital expenditures excluding acquisitions |
625,568 | 517,189 | ||||||
Oil and natural gas property acquisitions |
32,482 | 24,243 | ||||||
Consideration for the Encore Merger(1) |
| 2,952,515 | ||||||
Total |
$ | 658,050 | $ | 3,493,947 | ||||
(1) | Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued. |
Our capital expenditures for the first six months of 2011 were funded with $523.4 million of
cash flow from operations and the remainder with cash on hand at the beginning of the period. Our
capital expenditures for the first six months of 2010, excluding the Encore Merger, were funded
with $384.3 million of cash flow from operations along with proceeds from the sale of our interests
in Genesis and the Southern Assets.
Off-Balance Sheet Arrangements. Our obligations that are not currently recorded on our
balance sheet consist of our operating leases and various obligations for development and
exploratory expenditures arising from purchase agreements, our capital expenditure program, or
other transactions common to our industry. In addition, in order to recover our proved undeveloped
reserves, we must also fund the associated future development costs as forecasted in our proved
reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets,
are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.
In April 2011, we entered into three long-term drilling contracts. Our total commitment under
these contracts is approximately $93 million, with $9 million expected to be paid during the
remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.
24
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
In May 2011, we entered into an agreement with Elk Petroleum to acquire a 65% working interest
in Grieve Field, a planned CO2 enhanced oil recovery project located in Wyoming.
Denbury will invest the first $28.5 million of capital and operating costs in Phase 1. In Phase 2
of the project, Denbury may fund, at Elks option, Elks 35% share of the next $34.3 million of
capital and operating costs, with Denbury recouping its Phase 2 expenditures (plus interest) out of
Elks 35% working interest share of production from the project. In connection with that
agreement, we were assigned a CO2 purchase and CO2 transportation contract to
purchase CO2 reserves from Exxon Mobil Corporations La Barge facility and transport the
CO2 to Grieve Field beginning in March of 2012. Our annual commitment under the
CO2 purchase and transportation contracts is approximately $16 million annually for 2
years and approximately $25 million annually for the remaining 8 years (assuming a $100 per barrel
NYMEX oil price).
Our commitments and obligations consist of those detailed as of December 31, 2010 in our 2010
Form 10-K under Managements Discussion and Analysis of Financial Condition and Results of
Operations - Off-Balance Sheet Arrangements Commitments and Obligations, plus the long-term
drilling contracts described above, the Grieve Field obligations detailed above, and the three
CO2 purchase contracts entered into during the first quarter of 2011, which
CO2 purchase contracts are subject to numerous contingencies, as discussed under
Overview CO2 Purchase Contracts above.
Results of Operations
CO2 Operations
Our focus on CO2 operations is the primary strategy of our business and
operations. We believe that there are significant additional oil reserves and production that can
be obtained through the use of CO2, and we have outlined certain of this
potential in our Annual Report on Form 10-K for the year ended December 31, 2010 and other public
disclosures. In addition to its long-term effect, our focus on these types of operations impacts
certain trends in our current and near-term operating results. Please refer to Managements
Discussion and Analysis of Financial Condition and Results of Operations and the section entitled
CO2 Operations contained in our Annual Report on Form 10-K for the year ended
December 31, 2010 for further information regarding these matters.
During the second quarter of 2011, our CO2 production at Jackson Dome averaged 992
MMcf/d compared to an average of 768 MMcf/d produced during the second quarter of 2010 and 1,021
MMcf/d produced during the first quarter of 2011. We used 91% of this production, or 903 MMcf/d,
in our tertiary operations during the second quarter of 2011, and sold the balance to our
industrial customers, or to Genesis pursuant to our volumetric production payments. Refer to
Managements Discussion and Analysis of Financial Condition and Results of Operations Capital
Resources and Liquidity Off-Balance Sheet Arrangements Commitments and Obligations in our
Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our
CO2 delivery obligations. We recognized a negative proven CO2 reserve
revision during the second quarter of approximately 239 Bcf at our Jackson Dome Dri-Dock prospect.
This revision was a result of the second well in this formation not being a productive well and
analysis of the reprocessed seismic data, which showed incremental faulting in the Dri-Dock
reservoir. Even with this downward revision, we still anticipate that we have sufficient CO2
reserves to develop our current Gulf Coast enhanced oil recovery program and we are
continuing to drill additional wells to increase our productive capability and to test the
significant probable and possible reserves at Jackson Dome. At December 31, 2010, our proven
CO2 reserves at Jackson Dome were approximately 7.1 Tcf.
We spent approximately $0.27 per Mcf in operating expenses to produce our CO2
during the first six months of 2011, comprised of $0.25 per Mcf during the first quarter of 2011
and $0.28 per Mcf during the second quarter of 2011. This rate is up significantly from our $0.22
per Mcf cost during the second quarter of 2010, due primarily to increased CO2 royalty
expense as a result of higher oil prices (to which CO2 royalties are tied).
25
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The following table summarizes our tertiary oil production and tertiary lease operating
expense per Bbl for each quarter in 2010 and the first and second quarters of 2011:
Average Daily Production (Bbls/d) | ||||||||||||||||||||||||
First | Second | Third | Fourth | First | Second | |||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||
Tertiary Oil Field | 2010 | 2010 | 2010 | 2010 | 2011 | 2011 | ||||||||||||||||||
Phase 1: |
||||||||||||||||||||||||
Brookhaven |
3,416 | 3,277 | 3,323 | 3,699 | 3,664 | 3,213 | ||||||||||||||||||
McComb area |
2,289 | 2,160 | 2,484 | 2,433 | 2,161 | 1,983 | ||||||||||||||||||
Mallalieu area |
3,443 | 3,628 | 3,279 | 3,164 | 2,925 | 2,646 | ||||||||||||||||||
Other |
2,817 | 3,282 | 3,343 | 3,361 | 3,290 | 3,196 | ||||||||||||||||||
Phase 2: |
||||||||||||||||||||||||
Heidelberg |
1,708 | 1,857 | 2,806 | 3,422 | 3,374 | 3,548 | ||||||||||||||||||
Eucutta |
3,792 | 3,625 | 3,284 | 3,286 | 3,247 | 3,114 | ||||||||||||||||||
Soso |
3,213 | 3,207 | 3,016 | 2,828 | 2,582 | 2,317 | ||||||||||||||||||
Martinville |
927 | 764 | 606 | 586 | 500 | 416 | ||||||||||||||||||
Phase 3: |
||||||||||||||||||||||||
Tinsley |
4,419 | 5,248 | 6,024 | 6,614 | 6,567 | 6,990 | ||||||||||||||||||
Phase 4: |
||||||||||||||||||||||||
Cranfield |
936 | 811 | 855 | 1,043 | 991 | 1,085 | ||||||||||||||||||
Phase 5: |
||||||||||||||||||||||||
Delhi |
63 | 648 | 511 | 703 | 1,524 | 2,263 | ||||||||||||||||||
Total tertiary oil production |
27,023 | 28,507 | 29,531 | 31,139 | 30,825 | 30,771 | ||||||||||||||||||
Tertiary operating expense per Bbl |
$ | 22.67 | $ | 21.37 | $ | 22.54 | $ | 22.26 | $ | 25.40 | $ | 23.35 | ||||||||||||
Oil production from our tertiary operations increased to an average of 30,771 Bbls/d
during the second quarter of 2011, an 8% increase over our second quarter of 2010 tertiary
production level of 28,507 Bbls/d, primarily due to production growth in response to continued
expansion of the tertiary floods in the Tinsley, Heidelberg and Delhi Fields. Offsetting these
production gains were declines in our more mature Phase 1 and Phase 2 fields (excluding
Heidelberg).
The production growth rate at a tertiary flood varies from quarter to quarter as a tertiary
fields production may increase rapidly when wells respond to the CO2, plateau
temporarily, and then resume its growth as additional areas of the field are developed. During a
tertiary flood life cycle, facility capacity is increased from time to time, which occasionally
requires temporary shutdowns during installation, thereby causing temporary declines in production.
We also find it difficult to precisely predict when any given well will respond to the injected
CO2 as the CO2 seldom travels through the rock consistently due to
heterogeneity in the oil-bearing formations. We find all these fluctuations to be normal, and
generally expect oil production at a tertiary field to increase over time until the entire field is
developed, albeit sometimes in inconsistent patterns. These types of fluctuations were most
noticeable at Tinsley and Heidelberg Fields in the first quarter of 2011, two of our fields which
have exhibited strong production growth in recent periods. These fields resumed their growth
during the second quarter of 2011 and these temporary fluctuations have not changed our overall
outlook for these fields.
We initiated CO2 injections at Oyster Bayou and Hastings Fields during June 2010
and December 2010, respectively. We currently anticipate tertiary production responses at Hastings
Field in late 2011, assuming our CO2 recycle facilities at this field are completed on
schedule. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012,
also dependant on the completion of CO2 recycle facilities.
During the second quarter of 2011, operating costs for our tertiary properties averaged
$23.35 per Bbl, down 8% from our first quarter 2011 average of $25.40 per Bbl, due primarily to
lower workover expenses between the respective periods, but 9% higher than our second quarter 2010
average cost of $21.37 per Bbl, due primarily to higher utility and CO2 costs.
CO2 costs increased due to a 37% increase in injection volumes, primarily related to the
ramping up of tertiary activity at our Heidelberg, Tinsley and Delhi fields, and a 27% increase in the cost
of CO2 (which is variable and partially tied to oil prices). On a per Bbl basis, our
cost of CO2 increased from $5.05 per Bbl
during the second quarter of 2010 to $5.62 per Bbl during the second quarter of 2011 but
remained relatively consistent with the $5.58 per Bbl level of these costs during the first quarter
of 2011. Second quarter of 2011 workover expenses of $2.53 per Bbl also increased from second
quarter of 2010 workover expenses of $1.62 per Bbl but decreased from first quarter of 2011
levels of $3.75 per Bbl as we completed planned mechanical integrity test repairs at Brookhaven
Field and completed other workovers at Soso and Eucutta during the first quarter of 2011. For any
specific field, we expect our tertiary lease operating expense per Bbl to be high initially and
then decrease as production increases, ultimately leveling off until production begins to decline
in the latter life of the field, when lease operating expense per barrel will again increase.
26
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Operating Results
Certain of our operating results and statistics for the comparative second quarters and first
six months of 2011 and 2010 are included in the following table:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands, except per share and unit data | 2011 | 2010(1) | 2011 | 2010(1) | ||||||||||||
Operating results: |
||||||||||||||||
Net income attributable to Denbury stockholders |
$ | 259,246 | $ | 135,367 | $ | 245,056 | $ | 232,255 | ||||||||
Net income per common share basic |
0.65 | 0.34 | 0.62 | 0.67 | ||||||||||||
Net income per common share diluted |
0.64 | 0.34 | 0.61 | 0.66 | ||||||||||||
Cash flow from operations |
398,521 | 271,123 | 523,353 | 384,291 | ||||||||||||
Average daily production volumes: |
||||||||||||||||
Bbls/d |
59,538 | 65,942 | 59,002 | 55,185 | ||||||||||||
Mcf/d |
32,283 | 109,014 | 31,579 | 81,108 | ||||||||||||
BOE/d |
64,919 | 84,111 | 64,265 | 68,703 | ||||||||||||
Operating revenues: |
||||||||||||||||
Oil sales |
$ | 575,928 | $ | 443,984 | $ | 1,068,766 | $ | 749,188 | ||||||||
Natural gas sales |
15,171 | 44,044 | 28,525 | 69,726 | ||||||||||||
Total oil and natural gas sales |
$ | 591,099 | $ | 488,028 | $ | 1,097,291 | $ | 818,914 | ||||||||
Commodity derivative contracts: (2) |
||||||||||||||||
Net cash receipts (payments) on settlement of commodity derivative contracts |
$ | (10,942 | ) | $ | 2,801 | $ | (9,354 | ) | $ | (57,000 | ) | |||||
Non-cash fair value adjustment income |
183,846 | 125,190 | 11,508 | 226,029 | ||||||||||||
Total income from commodity derivative contracts |
$ | 172,904 | $ | 127,991 | $ | 2,154 | $ | 169,029 | ||||||||
Operating expenses: |
||||||||||||||||
Lease operating |
$ | 129,932 | $ | 127,743 | $ | 257,029 | $ | 223,963 | ||||||||
Production taxes and marketing |
39,688 | 38,100 | 72,439 | 57,417 | ||||||||||||
Total production expenses |
$ | 169,620 | $ | 165,843 | $ | 329,468 | $ | 281,380 | ||||||||
Unit prices including impact of derivative settlements: (2) |
||||||||||||||||
Oil price per Bbl |
$ | 103.17 | $ | 71.68 | $ | 98.02 | $ | 67.26 | ||||||||
Natural gas price per Mcf |
7.22 | 6.12 | 7.20 | 6.14 | ||||||||||||
Unit prices excluding impact of derivative settlements: (2) |
||||||||||||||||
Oil price per Bbl |
$ | 106.30 | $ | 73.99 | $ | 100.08 | $ | 75.00 | ||||||||
Natural gas price per Mcf |
5.16 | 4.44 | 4.99 | 4.75 | ||||||||||||
Oil and natural gas operating revenues and expenses per BOE: |
||||||||||||||||
Oil and natural gas revenues |
$ | 100.06 | $ | 63.76 | $ | 94.33 | $ | 65.85 | ||||||||
Oil and natural gas lease operating expenses |
$ | 21.99 | $ | 16.69 | $ | 22.10 | $ | 18.01 | ||||||||
Oil and natural gas production taxes and marketing expense |
6.72 | 4.98 | 6.23 | 4.62 | ||||||||||||
Total oil and natural gas production expenses |
$ | 28.71 | $ | 21.67 | $ | 28.33 | $ | 22.63 | ||||||||
(1) | Includes the results of operations of Encore properties and ENP from March 9, 2010 through the end of the period. | |
(2) | See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts. |
27
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production. Average daily production by area for each of the four quarters of 2010 and for
the first and second quarters of 2011 are shown below:
Average Daily Production (BOE/d) | ||||||||||||||||||||||||||||
First | Pro Forma | Second | Third | Fourth | First | Second | ||||||||||||||||||||||
Quarter | First Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||||||
Operating Area | 2010(1) | 2010(2) | 2010 | 2010 | 2010 | 2011 | 2011 | |||||||||||||||||||||
Gulf Coast Region: |
||||||||||||||||||||||||||||
Tertiary oil fields |
27,023 | 27,023 | 28,507 | 29,531 | 31,139 | 30,825 | 30,771 | |||||||||||||||||||||
Non-tertiary fields: |
||||||||||||||||||||||||||||
Mississippi |
7,829 | 7,829 | 8,967 | 7,965 | 7,293 | 7,586 | 7,333 | |||||||||||||||||||||
Texas |
5,235 | 5,235 | 5,148 | 4,824 | 4,564 | 4,371 | 4,202 | |||||||||||||||||||||
Louisiana |
662 | 662 | 775 | 714 | 687 | 767 | 659 | |||||||||||||||||||||
Alabama and other |
997 | 997 | 1,078 | 1,091 | 1,026 | 1,026 | 1,084 | |||||||||||||||||||||
Total Gulf Coast Region |
41,746 | 41,746 | 44,475 | 44,125 | 44,709 | 44,575 | 44,049 | |||||||||||||||||||||
Rocky Mountain Region: |
||||||||||||||||||||||||||||
Cedar Creek Anticline |
2,537 | 9,830 | 9,967 | 9,791 | 9,328 | 9,163 | 8,925 | |||||||||||||||||||||
Bakken |
890 | 3,549 | 4,500 | 4,657 | 5,193 | 5,728 | 7,626 | |||||||||||||||||||||
Bell Creek |
252 | 966 | 997 | 994 | 957 | 890 | 936 | |||||||||||||||||||||
Paradox |
173 | 675 | 702 | 738 | 716 | 635 | 690 | |||||||||||||||||||||
Other |
777 | 2,925 | 2,944 | 2,889 | 2,809 | 2,613 | 2,693 | |||||||||||||||||||||
Total Rocky Mountain Region |
4,629 | 17,945 | 19,110 | 19,069 | 19,003 | 19,029 | 20,870 | |||||||||||||||||||||
Total Continuing Production |
46,375 | 59,691 | 63,585 | 63,194 | 63,712 | 63,604 | 64,919 | |||||||||||||||||||||
Disposed Properties: |
||||||||||||||||||||||||||||
Legacy Encore properties |
4,479 | 17,853 | 11,684 | 5,906 | 4,156 | | | |||||||||||||||||||||
ENP |
2,271 | 9,034 | 8,842 | 8,630 | 8,567 | | | |||||||||||||||||||||
Total Production |
53,125 | 86,578 | 84,111 | 77,730 | 76,435 | 63,604 | 64,919 | |||||||||||||||||||||
(1) | Includes production of Encore and ENP from March 9, 2010 through March 31, 2010. | |
(2) | Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010. |
Continuing production during the three months ended June 30, 2011 increased 1,334 BOE/d
over the comparable 2010 production levels, and continuing production when including Encores
pre-merger production increased from 61,649 BOE/d during the first half of 2010 to 64,265 BOE/d
during the first half of 2011. These increases were primarily due to production increases from the
Bakken and our tertiary oil fields (see a discussion of our tertiary operations in CO2
Operations above), offset by normal declines in most of our other non-tertiary properties.
Additionally, our production from the Cedar Creek Anticline generally declines in periods of
increasing prices due to a net profits interest associated with this production. Total production
decreased 23% between the second quarters of 2010 and 2011 due to the sale of non-strategic legacy
Encore properties during May 2010 through December 2010, as well as the sale of our interests in
ENP in December 2010. On a year-to-date basis, total production decreased 6% between the first six
months of 2010 and 2011 due primarily to the sale of the non-strategic Encore assets during 2010.
Production from our Bakken properties averaged 7,626 BOE/d in the second quarter of 2011, a
69% increase from second quarter 2010 levels and an increase of over 33% compared to first quarter
2011 production levels. The production increases in the Bakken are due to a gradual acceleration
of our drilling activities in the area, as we have increased our operated drilling rigs from two,
at the time of the Encore acquisition in March 2010, to five operated rigs currently. We
anticipate adding a sixth rig late in the third quarter or early fourth quarter of 2011 to test our
acreage in the Almond area, and a seventh rig by the end of 2011. During the first six months of
2011, we drilled and completed 16 operated wells in the Bakken. Our Bakken production for the first six
months of 2011 was negatively impacted by severe winter weather and flooding which caused delays in
well completions and curtailments in oil production.
28
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Our production during both the three and six months ended June 30, 2011 was 92% oil, as
compared to 78% and 80%, during the three and six months ended June 30, 2010, respectively. This
increase is due to the sales of the non-strategic Encore properties and ENP properties in 2010,
which had a higher percentage of natural gas production, and increases in our tertiary and Bakken
production, which are primarily oil.
Oil and Natural Gas Revenues. Although our production for the three and six months ended June
30, 2011 declined from comparable 2010 levels due to the asset sales discussed above (partially
offset during the six-month period by lower production in 2010 prior to the Encore Merger which
closed in March 2010), our oil and natural gas revenues increased significantly in the current
periods due to higher oil prices. These changes in oil and natural gas revenues, excluding any
impact of our commodity derivative contracts, are reflected in the following table:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 vs. 2010 | 2011 vs. 2010 | |||||||||||||||
Percentage | Percentage | |||||||||||||||
Increase | Increase | Increase | ||||||||||||||
(Decrease) in | (Decrease) in | Increase (Decrease) | (Decrease) in | |||||||||||||
In thousands | Revenues | Revenues | in Revenues | Revenues | ||||||||||||
Change in oil and natural gas revenues due to: |
||||||||||||||||
Increase in commodity prices |
$ | 214,398 | 44 | % | $ | 331,259 | 40 | % | ||||||||
Decrease in production |
(111,327 | ) | (23 | %) | (52,882 | ) | (6 | %) | ||||||||
Total increase in
oil and natural gas
revenues |
$ | 103,071 | 21 | % | $ | 278,377 | 34 | % | ||||||||
Excluding any impact of our commodity derivative contracts, our net realized commodity prices
and NYMEX differentials were as follows during the first and second quarters and first six month
periods of 2011 and 2010:
Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||||
March 31, | June 30, | June 30, | ||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||
Net Realized Prices: |
||||||||||||||||||||||||
Oil price per Bbl |
$ | 93.67 | $ | 76.53 | $ | 106.30 | $ | 73.99 | $ | 100.08 | $ | 75.00 | ||||||||||||
Natural gas price per Mcf |
4.81 | 5.40 | 5.16 | 4.44 | 4.99 | 4.75 | ||||||||||||||||||
Price per BOE |
88.42 | 69.21 | 100.06 | 63.76 | 94.33 | 65.85 | ||||||||||||||||||
NYMEX Differentials: |
||||||||||||||||||||||||
Oil per Bbl |
$ | (0.59 | ) | $ | (2.08 | ) | $ | 3.72 | $ | (4.13 | ) | $ | 1.64 | $ | (3.36 | ) | ||||||||
Natural gas per Mcf |
0.61 | 0.37 | 0.78 | 0.09 | 0.70 | 0.06 |
During the second quarter of 2011, our oil price differentials improved significantly,
primarily due to the favorable price differential for crude oil sold under LLS index pricing.
Company-wide oil price differentials in the second quarter of 2011 were $3.72 per Bbl above NYMEX,
as compared to an average negative differential of $4.13 per Bbl below NYMEX in the second quarter
of 2010 and an average negative differential of $0.59 per Bbl during the first quarter of 2011.
Our oil price differential in the second quarter of 2010 reflected production from the
non-strategic Encore properties sold in 2010, which typically received lower oil prices than our
legacy production. During the latter part of the first quarter, the LLS index price
increased significantly more than NYMEX prices, causing the LLS differential to increase
significantly, and it remained high throughout the second quarter. For the second quarter of 2011,
this LLS differential averaged a positive $15.32 per barrel on a trade-month basis, as compared to
a $9.28 positive differential in the first quarter of 2011 and a more typical $3.21 positive
differential in
29
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
the second quarter of 2010. It is uncertain how long this LLS differential will remain at this
level, Because our derivative contracts are based on NYMEX prices, they do not impact the
differential we receive. We currently sell approximately (a) 40% of our crude oil based on the LLS
index price, although due to contract provisions we may not realize the full differential; (b)
approximately 40% based on WTI prices; and (c) approximately 20% based on various other indexes,
most of which also improved relative to WTI, but to a lesser degree.
Commodity Derivative Contracts. The following tables summarize the impact our commodity
derivative contracts had on our operating results for the three and six months ended June 30, 2011
and 2010:
Three Months Ended June 30, | ||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||
Oil | Natural Gas | |||||||||||||||||||||||
In thousands | Derivative Contracts | Derivative Contracts | Total Commodity Derivative Contracts | |||||||||||||||||||||
Non-cash fair value gain (loss) |
$ | 187,194 | $ | 145,099 | $ | (3,348 | ) | $ | (19,909 | ) | $ | 183,846 | $ | 125,190 | ||||||||||
Cash settlement receipts (payments) |
(16,972 | ) | (13,829 | ) | 6,030 | 16,630 | (10,942 | ) | 2,801 | |||||||||||||||
Total |
$ | 170,222 | $ | 131,270 | $ | 2,682 | $ | (3,279 | ) | $ | 172,904 | $ | 127,991 | |||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||
Oil | Natural Gas | |||||||||||||||||||||||
In thousands | Derivative Contracts | Derivative Contracts | Total Commodity Derivative Contracts | |||||||||||||||||||||
Non-cash fair value gain (loss) |
$ | 20,130 | 206,920 | (8,622 | ) | 19,109 | $ | 11,508 | $ | 226,029 | ||||||||||||||
Cash settlement receipts (payments) |
(22,000 | ) | (77,379 | ) | 12,646 | 20,379 | (9,354 | ) | (57,000 | ) | ||||||||||||||
Total |
$ | (1,870 | ) | $ | 129,541 | $ | 4,024 | $ | 39,488 | $ | 2,154 | $ | 169,029 | |||||||||||
Changes in commodity prices and the expiration of contracts cause fluctuations in the
estimated fair value of our commodity derivative contracts. Because we do not utilize hedge
accounting for our commodity derivative contracts, the changes in fair value of these contracts, as
outlined above, are recognized currently in the income statement. See Notes 4 and 5 to the
Unaudited Condensed Consolidated Financial Statements for additional information regarding our
commodity derivative contracts.
Production Expenses. Our lease operating expenses increased 2% during the three months ended
June 30, 2011 compared to the same period in 2010 primarily as a result of the increased
CO2 injections as we continued to ramp up tertiary activities at Tinsley, Heidelberg and
Delhi fields during 2010 and 2011, the cost of CO2 (which are variable and partially
tied to oil prices) and workover expenses on our tertiary operations (see discussion of those
expenses under CO2 Operations), offset by the sale of the non-strategic legacy Encore
and ENP properties during 2010.
The 15% increase in lease operating expense during the six months ended June 30, 2011 compared
to 2010 was further impacted by the inclusion in the 2011 period of a full six months of lease
operating expense related to properties acquired in the Encore Merger on March 9, 2010.
Lease operating expense per BOE averaged $21.99 per BOE and $22.10 per BOE for the three and
six months ended June 30, 2011, compared to $16.69 per BOE and $18.01 per BOE for the same periods
in 2010. These increases from the respective prior periods are attributable to the sale of the
non-strategic Encore and ENP properties from May 2010 through December 2010, which generally had a
lower operating cost per BOE than Denburys legacy properties. However, second quarter 2011 lease
operating expenses per BOE decreased from $22.20 per BOE in the first quarter of 2011. Our
tertiary operating costs, which have historically been higher than our company-wide operating
costs, averaged $23.35 per BOE and $24.37 per BOE during the three and six months
ended June 30, 2011, compared to $21.37 per BOE and $22.00 per BOE for the same periods in
2010. See CO2 Operations for a more detailed discussion.
30
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Generally, production taxes change in relation to oil and natural gas revenues, and marketing
expenses change in relation to production volumes. The 21% increase in oil and natural gas
revenues between the second quarters of 2010 and 2011 contributed to severance taxes increasing
from $28.7 to $33.4 million, respectively. Likewise, the 34% increase in oil and natural gas
revenues between the first six months of 2010 and 2011 contributed to severance taxes increasing
from $43.6 million to $60.9 million, respectively. These severance tax increases in both
comparative periods were partially offset by lower marketing expenses primarily attributable to
lower production volumes in 2011.
General and Administrative Expenses (G&A)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands, except per BOE data and employees | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Gross cash G&A expense |
$ | 60,137 | $ | 57,909 | $ | 127,834 | $ | 106,183 | ||||||||
Gross stock-based compensation |
9,687 | 7,363 | 21,024 | 17,302 | ||||||||||||
State franchise taxes |
1,668 | 965 | 2,827 | 2,035 | ||||||||||||
Operator labor and overhead recovery charges |
(31,423 | ) | (29,086 | ) | (61,139 | ) | (51,131 | ) | ||||||||
Capitalized exploration and development costs |
(9,169 | ) | (5,959 | ) | (15,800 | ) | (10,488 | ) | ||||||||
Net G&A expense |
$ | 30,900 | $ | 31,192 | $ | 74,746 | $ | 63,901 | ||||||||
G&A per BOE: |
||||||||||||||||
Net cash G&A expense |
$ | 3.73 | $ | 3.15 | $ | 4.78 | $ | 3.81 | ||||||||
Net stock-based compensation |
1.22 | 0.79 | 1.41 | 1.17 | ||||||||||||
State franchise taxes |
0.28 | 0.13 | 0.24 | 0.16 | ||||||||||||
Net G&A expense |
$ | 5.23 | $ | 4.07 | $ | 6.43 | $ | 5.14 | ||||||||
Employees as of June 30 |
1,283 | 1,304 | 1,283 | 1,304 | ||||||||||||
Gross cash G&A expenses increased $2.2 million (4%) and $21.7 million (20%) during the three
and six months ended June 30, 2011, respectively, as compared to the same periods of 2010. The
increase between the comparative second quarters is reflective of higher salary costs which we
consider necessary in order to remain competitive in our industry. The year-to-date comparative
increase is primarily impacted by increased expense resulting from the Encore Merger as the 2010
period includes the effect of the Encore Merger beginning on the acquisition date, March 9, 2010.
The number of employees at June 30, 2011, compared to June 30, 2010, decreased slightly, by 2%,
primarily due to the departure of Encore transition employees who did not accept permanent
positions with Denbury and who completed their transition period. However, prior to the Encore
Merger, our headcount was 856 employees.
Additional expense attributable to the legacy Encore office leases and the new Denbury
headquarters lease, together with related moving costs, contributed to the higher cash G&A expense
during the first six months of 2011. Additionally, stock-based compensation expense increased $2.3
million for the second quarter 2011 when compared to levels in the same period of 2010, due
primarily to higher compensation levels.
Gross cash G&A expenses decreased $7.6 million, or 11% from levels in the first quarter of
2011, due primarily to lower compensation and employee-related costs and lower professional fees in
the current quarter. The first quarter of 2011 included higher payroll tax burdens and 401(k) matching contribution associated with bonus payouts, the true-up of long-term incentive compensation estimates, incremental costs
associated with relocating our headquarters and higher professional fees associated with year-end
work.
The increase in gross G&A expense during the three and six months ended June 30, 2011, as
compared to those costs in the same periods of 2010, was offset in part by an increase in operator
overhead recovery charges. 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. As a result of additional operated wells from
acquisitions, additional tertiary operations, drilling activity during the past year, and increased
compensation expense, the amount we recovered as operator labor and overhead charges increased by
8% and 20% during the three and six months ended June 30, 2011, as compared to the same periods in 2010. Capitalized exploration and development costs also increased between the periods, primarily due to
increased compensation costs subject to capitalization.
31
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The net effect of these changes resulted in a 1% decrease (a 29% increase on a per BOE basis)
in G&A expense between the comparable second quarters of 2011 and 2010. Lower production in the
most recent quarter attributable to the 2010 sale of properties was the primary factor relating to
the higher cost per BOE, as any cost savings as a result of the property sales were offset by other
expenses, including compensation increases effective at the beginning of 2011 and incremental
expense attributable to the legacy Encore office leases and the new Denbury headquarters noted
above.
Interest and Financing Expenses
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands, except per BOE data and interest rates | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Cash interest |
$ | 50,509 | $ | 60,966 | $ | 104,715 | $ | 105,940 | ||||||||
Non-cash interest |
4,934 | 6,367 | 10,462 | 9,121 | ||||||||||||
Less: capitalized interest |
(13,194 | ) | (23,850 | ) | (24,151 | ) | (45,162 | ) | ||||||||
Interest expense, net |
$ | 42,249 | $ | 43,483 | $ | 91,026 | $ | 69,899 | ||||||||
Interest income and other |
$ | 4,955 | $ | 4,520 | $ | 8,004 | $ | 6,390 | ||||||||
Net cash interest expense and other income per BOE (1) |
$ | 5.54 | $ | 4.43 | $ | 6.31 | $ | 4.53 | ||||||||
Average debt outstanding |
$ | 2,305,104 | $ | 3,152,564 | $ | 2,409,284 | $ | 2,689,894 | ||||||||
Average interest rate (2) |
8.8 | % | 7.7 | % | 8.7 | % | 7.9 | % |
(1) | Cash interest expense less capitalized interest less interest income and other income on a per BOE basis. | |
(2) | Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
Cash interest expense decreased $10.5 million during the three month period ending June
30, 2011, as compared to the same period in 2010, primarily due to a decrease in our average debt
outstanding. Our debt level increased in early 2010 as a result of the Encore Merger and decreased
throughout 2010 and in early 2011 as we repaid debt with proceeds from the sale of non-strategic
legacy Encore assets and our ENP ownership interest. Year-to-date cash interest expense remained
relatively consistent with that incurred in the same period in 2010. The decrease in cash interest
expense during both the three and six month comparative periods was offset by lower capitalized
interest relating primarily to the Green Pipeline, which was completed and placed into service at
the end of June 2010.
32
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands, except per BOE data | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Depletion, depreciation, and amortization (DD&A) of oil and natural gas properties |
$ | 91,961 | $ | 116,034 | $ | 174,047 | $ | 187,231 | ||||||||
Depletion and depreciation of CO2 assets |
4,588 | 5,680 | 9,178 | 10,980 | ||||||||||||
Asset retirement obligations |
1,696 | 1,692 | 3,259 | 2,799 | ||||||||||||
Depreciation of other fixed assets |
5,250 | 5,803 | 10,605 | 10,071 | ||||||||||||
Total DD&A |
$ | 103,495 | $ | 129,209 | $ | 197,089 | $ | 211,081 | ||||||||
DD&A per BOE: |
||||||||||||||||
Oil and natural gas properties |
$ | 15.85 | $ | 15.38 | $ | 15.24 | $ | 15.28 | ||||||||
CO2 assets and other fixed assets |
1.67 | 1.50 | 1.70 | 1.69 | ||||||||||||
Total DD&A cost per BOE |
$ | 17.52 | $ | 16.88 | $ | 16.94 | $ | 16.97 | ||||||||
Depletion of oil and natural gas properties decreased on an absolute dollars basis during the
three and six months ended June 30, 2011 as compared to the same periods of 2010, primarily due to
the sale of non-strategic legacy Encore assets and our ownership interests in ENP during 2010.
Depletion of oil and gas properties increased on a per BOE basis during the second quarter of 2011
compared to 2010, primarily due to higher finding and development costs per barrel associated with
the incremental Bakken capital program and upward revisions in estimated future development costs.
We continually evaluate the performance of our tertiary projects, and if performance indicates
that we are reasonably certain of recovering additional reserves from these floods, we recognize
those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter based on
any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change
significantly in the future.
Our DD&A expense for our CO2 assets decreased on an absolute basis for the three
and six months ended June 30, 2011 compared to the same periods in 2010 due to proved
CO2 reserve increases at Jackson Dome and Riley Ridge at the end of 2010. On a
per BOE basis, DD&A expense for our CO2 assets and other fixed assets increased for the
three months ended June 30, 2011 compared to those in the prior-year quarter due to decreased oil
and natural gas production volumes as a result of the sale of non-strategic Encore properties and
our interests in ENP during 2010.
Under full cost accounting rules, we are required each quarter to perform a ceiling test
calculation. We did not have a ceiling test write-down at June 30, 2011. However, if oil and
natural gas prices were to decrease significantly in subsequent periods, we may be required to
record write-downs under the full cost pool ceiling test in the future. The possibility and amount
of any future write-down is difficult to predict, and will depend upon oil and natural gas prices,
the incremental proved reserves that may be added each period, revisions to previous reserve
estimates and future capital expenditures, and additional capital spent.
Encore Transaction and Other Costs
FASC Business Combinations topic requires that all transaction-related costs (advisory, legal,
accounting, due diligence, integration, etc.) be expensed as incurred. We recognized transaction
and other costs of $2.0 million and $4.4 million for the three and six months ended June 30, 2011,
respectively, associated with the Encore Merger, including $1.8 million and $3.6 million, respectively, related to severance costs.
Transaction and other costs of $22.8 million and $67.8 million for the three and six months ended
June 30, 2010, respectively, included $19.5 million and $20.7 million, respectively, of severance
costs, and were significantly higher than 2011 levels. We anticipate that these severance costs
will decline in the remainder of 2011 as the integration winds down and fewer former Encore
transition employees remain.
33
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
In thousands, except per BOE amounts and tax rates | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Current income tax provision |
$ | 12,028 | $ | 6,941 | $ | 11,180 | $ | 7,610 | ||||||||
Deferred income tax provision |
152,528 | 74,422 | 144,620 | 150,694 | ||||||||||||
Total income tax provision |
$ | 164,556 | $ | 81,363 | $ | 155,800 | $ | 158,304 | ||||||||
Average income tax provision per BOE |
$ | 27.85 | $ | 10.63 | $ | 13.39 | $ | 12.73 | ||||||||
Effective tax rate |
38.8 | % | 35.1 | % | 38.9 | % | 38.7 | % |
Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective
tax rate for the second quarter of 2011 was slightly higher compared to our statutory rate,
primarily due to nondeductible expenses. Our effective tax rate for the second quarter of 2010 was
lower due to the remeasurement of our deferred tax liabilities as a result of the May 2010 sale of
certain legacy Encore properties in the Permian Basin, Mid-continent area and East Texas Basin (the
Southern Assets), which resulted in an income tax benefit of approximately $3 million recorded in
the second quarter of 2010. The nondeductible expenses in 2011 and the income tax benefit recorded
in 2010 resulted in a slight increase in the effective tax rate, to 38.9%, during the six months
ended June 30, 2011, as compared to 38.7% in the six months ended June 30, 2010. The current
income tax expense represents our state income taxes during the three and six months ended June 30,
2011 and 2010.
As of June 30, 2011, we had an estimated $39.8 million of enhanced oil recovery credits to
carry forward related to our tertiary operations, and $34.5 million of alternative minimum tax
credits that can be utilized to reduce our current income taxes during 2011 or future years. The
enhanced oil recovery credits do not begin to expire until 2024. Since the ability to earn
additional enhanced oil recovery credits is based upon the level of oil prices, we would not
currently expect to earn additional enhanced oil recovery credits unless oil prices were to
significantly deteriorate.
In the third quarter of 2008, we obtained approval from the National Office of the Internal
Revenue Service (IRS) to change our method of tax accounting for certain assets used in our
tertiary oilfield recovery operations. As a result of the approved change in method of tax
accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs
for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax
years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently
exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we
received a Technical Advice Memorandum (TAM) issued by the IRS National Office disapproving our
method of accounting and revoking its consent to our change, on a prospective basis only,
commencing January 1, 2011. Henceforth, beginning with the 2011 tax year, we are returning to
capitalizing and depreciating the costs of these assets for tax purposes. As a result of the
prospective nature of the IRSs determination, there should be no change in our position with
respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims
of $10.6 million for tax years through 2006 are pending and are pending review by the Joint
Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review,
nor how that outcome may affect the other years covered by the TAM.
The Presidents 2012 budget, as well as certain Congressional legislative initiatives, have
proposed repealing many tax incentives for the oil and gas industry. Those items that would have
the most significant impact on us would include the loss of the domestic manufacturing deduction,
the repeal of the immediate expensing of intangible drilling costs and tertiary injectant costs,
and the elimination of the percentage depletion allowance. It is uncertain whether these or similar
tax law changes will be enacted, and if so what the effective date of any such changes might be,
although the current proposals would not take effect until 2012. If some or all of these proposals
were enacted and included us, they would likely increase the amount of cash taxes that we pay in
future periods, and, accordingly, could impact our forecasted capital expenditure budget.
34
Table of Contents
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Per BOE Data
The following table summarizes our cash flow, DD&A, and results of operations on a per BOE
basis for the comparative periods. Each of the individual components is discussed above.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Per BOE data | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Oil and natural gas revenues |
$ | 100.06 | $ | 63.76 | $ | 94.33 | $ | 65.85 | ||||||||
Gain (loss) on settlements of derivative contracts |
(1.85 | ) | 0.37 | (0.80 | ) | (4.58 | ) | |||||||||
Lease operating expenses |
(21.99 | ) | (16.69 | ) | (22.10 | ) | (18.01 | ) | ||||||||
Production taxes and marketing expenses |
(6.72 | ) | (4.98 | ) | (6.23 | ) | (4.62 | ) | ||||||||
Production netback |
69.50 | 42.46 | 65.20 | 38.64 | ||||||||||||
Non-tertiary CO2 operating margin |
0.59 | 0.39 | 0.53 | 0.49 | ||||||||||||
General and administrative expenses |
(5.23 | ) | (4.07 | ) | (6.43 | ) | (5.14 | ) | ||||||||
Transactions and other costs related to the Encore Merger |
(0.34 | ) | (2.98 | ) | (0.38 | ) | (5.45 | ) | ||||||||
Net cash interest expense and other income |
(5.54 | ) | (4.43 | ) | (6.31 | ) | (4.53 | ) | ||||||||
Current income taxes and other |
(0.74 | ) | 0.10 | 0.28 | 0.66 | |||||||||||
Changes in assets and liabilities relating to operations |
9.22 | 3.95 | (7.90 | ) | 6.23 | |||||||||||
Cash flow from operations |
67.46 | 35.42 | 44.99 | 30.90 | ||||||||||||
DD&A |
(17.52 | ) | (16.88 | ) | (16.94 | ) | (16.97 | ) | ||||||||
Deferred income taxes |
(25.82 | ) | (9.72 | ) | (12.43 | ) | (12.12 | ) | ||||||||
Gain on sale of interests in Genesis |
| | | 8.17 | ||||||||||||
Loss on early extinguishment of debt |
(0.06 | ) | | (1.39 | ) | | ||||||||||
Non-cash fair value derivative adjustments |
31.12 | 16.45 | 0.99 | 18.25 | ||||||||||||
Net income attributable to noncontrolling interest |
| 1.95 | | 1.47 | ||||||||||||
Changes in assets and liabilities and other non-cash items |
(11.30 | ) | (9.53 | ) | 5.85 | (11.02 | ) | |||||||||
Net income attributable to Denbury stockholders |
$ | 43.88 | $ | 17.69 | $ | 21.07 | $ | 18.68 | ||||||||
Critical Accounting Policies
For additional discussion of our critical accounting policies, which remain unchanged, see
Managements Discussion and Analysis of Financial Condition and Results of Operations in our Annual
Report on Form 10-K for the year ended December 31, 2010.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q that are not historical facts,
including, but not limited to, statements found in this Managements Discussion and Analysis of
Financial Condition and Results of Operations, are forward-looking statements, as that term is
defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may concern, among
other things, forecasted capital expenditures, dates of pipeline construction commencement and
completion, drilling activity or methods, acquisition plans and proposals and dispositions,
development activities, timing of CO2 injections in tertiary flooding projects, cost
savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve
quantities and values, CO2 reserves, potential reserves from tertiary operations,
hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas
prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters,
mark-to-market values, competition, long-term forecasts of production, finding costs, rates of
return, estimated costs, or changes in costs, future capital expenditures and overall economics and
other variables surrounding our operations and future plans. Such forward-looking statements
generally are accompanied by words such as plan, estimate, expect, predict, anticipate,
projected, should, assume, believe, target, or other words that convey the uncertainty of
future events or outcomes. Such forward-looking information is based upon managements current
plans, expectations, estimates, and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated actions, the timing of
such actions and our financial condition and results of operations. As a consequence, actual
results may differ materially from expectations, estimates or assumptions expressed in or implied
by any forward-looking statements made by us or on our behalf. Among the factors that could cause
actual results to differ materially are: fluctuations of the prices received or demand for our oil
and natural gas;
effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates;
availability of and fluctuations in the prices of goods and services; the uncertainty of drilling
results and reserve estimates; operating hazards; disruption of operations and damages from
hurricanes or tropical storms; acquisition risks; requirements for capital or its availability;
conditions in the financial and credit markets; changes in interest rates; general economic
conditions; competition and government regulations; and unexpected delays, as well as the risks and
uncertainties inherent in oil and natural gas drilling and production activities or which are
otherwise discussed in this quarterly report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in our other public reports,
filings and public statements.
35
Table of Contents
DENBURY RESOURCES INC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Long-Term Debt and Interest Rate Sensitivity
We finance some of our acquisitions and other expenditures with fixed and variable-rate debt.
These debt agreements expose us to market risk related to changes in interest rates. None of our
existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The
fair value of the subordinated debt is based on quoted market prices. The following table presents
the carrying and fair values of our debt, along with average interest rates at June 30, 2011:
Carrying | Fair | |||||||||||||||||||||||||||||||
In thousands, except percentages | 2014 | 2015 | 2016 | 2017 | 2020 | 2021 | Value | Value | ||||||||||||||||||||||||
Variable rate debt: |
||||||||||||||||||||||||||||||||
Bank Credit Agreement |
$ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | | ||||||||||||||||
Fixed rate debt: |
||||||||||||||||||||||||||||||||
9.5% Senior
Subordinated Notes due
2016 |
| | 224,920 | | | | 238,142 | 249,942 | ||||||||||||||||||||||||
9.75% Senior
Subordinated Notes due
2016 |
| | 426,350 | | | | 406,354 | 476,446 | ||||||||||||||||||||||||
8.25% Senior
Subordinated Notes due
2020 |
| | | | 996,273 | | 996,273 | 1,085,938 | ||||||||||||||||||||||||
6.375% Senior
Subordinated Notes due
2021 |
| | | | | 400,000 | 400,000 | 400,000 | ||||||||||||||||||||||||
Other Subordinated Notes |
1,072 | 485 | | 2,250 | | | 3,843 | 3,807 |
Commodity Derivative Contracts and Commodity Price Sensitivity
From time to time, we enter into 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 consisted of price floors, collars and fixed price swaps. The
production that we hedge has varied from year to year depending on our levels of debt and financial
strength and expectation of future commodity prices. We currently employ a strategy to hedge a
portion of our forecasted production for a period generally ranging from approximately 12 to 18
months in advance (although we will hedge farther in advance if deemed prudent), as we believe it
is important to protect our future cash flow for a short period of time in order to give us time to
adjust to commodity price fluctuations, particularly since many of our expenditures have long lead
times. See Note 4, Derivative Instruments and Hedging Activities, to the Consolidated Financial
Statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided
by external sources. We manage and control market and counterparty credit risk through established
internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit
risk exposure to counterparties through formal credit policies, monitoring procedures, and
diversification. All of our commodity derivative contracts are with parties that are lenders under
our bank credit agreement. We have included an estimate of nonperformance risk in the fair value
measurement of our oil and natural gas derivative contracts, which we have measured for
nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting to our commodity derivative
contracts. This means that any changes in the fair value of these derivative contracts will be
charged to earnings on a quarterly basis instead of charging the effective portion to other
comprehensive income and the ineffective portion to earnings.
At June 30, 2011, our commodity derivative contracts were recorded at their fair value, which
was a net liability of approximately $32.5 million (excluding $15.6 million of deferred premiums
that Denbury is obligated to pay for its derivative contracts, which payments are not subject to
changes in commodity prices), which is less than the $44.0 million fair value liability recorded at
December 31, 2010. This change is primarily related to changes in oil futures prices between
December 31, 2010 and June 30, 2011.
36
Table of Contents
DENBURY RESOURCES INC.
Based on NYMEX crude oil and natural gas futures prices as of June 30, 2011, and assuming both
a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil
and natural gas derivative contracts as seen in the following table:
Crude Oil | Natural Gas | |||||||
Derivative | Derivative | |||||||
Contracts | Contracts | |||||||
In thousands | (Payment) | Receipt | ||||||
Based on: |
||||||||
NYMEX futures prices as of June 30, 2011 |
$ | (9,390 | ) | $ | 24,508 | |||
10% increase in prices |
(81,222 | ) | 18,312 | |||||
10% decrease in prices |
(2,952 | ) | 30,703 |
Equity Price Sensitivity
Our investment in Vanguard common units is considered an investment in available-for-sale
securities, which is recorded at fair value with any unrealized gains or losses included in
accumulated other comprehensive income. This investment is thus subject to equity price
sensitivity, as fair value is determined by quoted market prices. We estimate that a hypothetical
10% increase or decrease in quoted market prices for Vanguard common units would result in a $8.8
million unrealized gain or loss, respectively, as of June 30, 2011.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this
report, an evaluation of the effectiveness of the design and operation of the Companys disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under
the supervision and with the participation of the Companys management, including our Chief
Executive Officer and our Chief Financial Officer. Based on that evaluation, the Companys Chief
Executive Officer and our Chief Financial Officer concluded that the Companys disclosure controls
and procedures were effective as of June 30, 2011, to ensure: that information required to be
disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods specified in the SECs rules
and forms; and that information that is required to be disclosed under the Exchange Act is
accumulated and communicated to the Companys management, including our Chief Executive Officer and
our Chief Financial Officer, as appropriate to allow timely decisions regarding required
disclosure.
Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and
with the participation of our management, including our Chief Executive Officer and our Chief
Financial Officer, we have determined that, during the second quarter of fiscal 2011, there were no
changes in our internal control over financial reporting that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
37
Table of Contents
DENBURY RESOURCES INC.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Information with respect to this item is incorporated by reference from our Annual Report on
Form 10-K for the year ended December 31, 2010.
Item 1A. Risk Factors
Information with respect to the risk factors has been incorporated by reference from Item 1A
of our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no
material changes to the risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes purchases of our common stock during the second quarter of
2011, consisting entirely of delivery by our employees of shares to us to satisfy their tax
withholding requirements related to the vesting of restricted shares and the exercise of stock
appreciation rights:
Total Number of | Approximate Dollar | |||||||||||||||
Total | Shares Purchased | Value of Shares | ||||||||||||||
Number of | Average | as Part of Publicly | that May Yet Be | |||||||||||||
Shares | Price Paid | Announced Plans or | Purchased Under the | |||||||||||||
Month | Purchased | per Share | Programs | Plans or Programs | ||||||||||||
April 2011 |
17,272 | $ | 23.97 | | $ | | ||||||||||
May 2011 |
9,466 | 21.28 | | | ||||||||||||
June 2011 |
14,479 | 19.95 | | | ||||||||||||
Total |
41,217 | 21.94 | | $ | | |||||||||||
Item 6. Exhibits
Exhibit | Description | |
3.1 | Amended and Restated Bylaws of Denbury Resources Inc. effective as of June 17, 2011
(incorporated by reference as Exhibit 3.1 of our Form 8-K filed on June 21, 2011). |
|
4.1 | Fifth Amendment to Credit Agreement dated as of March 9, 2010, dated as of May 19, 2011,
among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent,
and the financial institutions party thereto (incorporated by reference as Exhibit 99.1 of our
Form 8-K filed on May 20, 2011). |
|
31.1* | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002. |
|
31.2* | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002. |
|
32* | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
|
101* | Interactive Data Files. |
* | Filed herewith. |
38
Table of Contents
DENBURY RESOURCES INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DENBURY RESOURCES INC. |
||||
By: | /s/ Mark C. Allen | |||
Mark C. Allen | ||||
Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary | ||||
By: | /s/ Alan Rhoades | |||
Alan Rhoades | ||||
Vice President and Chief Accounting Officer | ||||
Date: August 8, 2011
39