e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the quarterly period ended September 30, 2010
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
Commission file number: 001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
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Delaware
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20-0467835 |
(State or other jurisdictions of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway |
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Suite 1200 |
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Plano, TX
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75024 |
(Address of principal executive offices)
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(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)
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):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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.
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Class |
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Outstanding at October 31, 2010 |
Common Stock, $.001 par value
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399,679,295 |
DENBURY RESOURCES INC.
INDEX
2
DENBURY RESOURCES INC.
GLOSSARY AND SELECT ABBREVIATIONS
The following are abbreviations and definitions of certain terms used in this report. The
definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have
been summarized from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
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Bbl
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One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons. |
Bbls/d
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Barrels of oil produced per day. |
Bcf/d
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One billion cubic feet of natural gas or CO2 produced per day. |
BOE
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One barrel of oil equivalent using the ratio of one barrel of crude oil,
condensate, or natural gas liquids to six Mcf of natural gas. |
BOE/d
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BOEs produced per day. |
CO2
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Carbon dioxide. |
Denbury
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Denbury Resources Inc., a publicly traded Delaware corporation, together
with its subsidiaries. |
Encore
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Encore Acquisition Company, together with its subsidiaries. Encore
merged with and into Denbury on March 9, 2010. |
ENP
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Encore Energy Partners LP, a publicly traded Delaware limited
partnership, together with its subsidiaries. |
EOR
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Enhanced oil recovery. |
FASB
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Financial Accounting Standards Board. |
FASC
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FASB Accounting Standards Codification. |
LIBOR
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London Interbank Offered Rate. |
MBOE
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One thousand BOEs. |
Mcf
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One thousand cubic feet of natural gas or CO2. |
Mcf/d
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One thousand cubic feet of natural gas or CO2 produced per day. |
MMBOE
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One million BOEs. |
MMcf/d
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One million cubic feet of natural gas or CO2 per day. |
NYMEX
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New York Mercantile Exchange. |
Proved Developed
Reserves
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Reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. |
Proved Reserves
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The estimated quantities of crude oil, natural gas, and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. |
Proved Undeveloped Reserves
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Reserves that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major expenditure is
required. |
SEC
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The United States Securities and Exchange Commission. |
Tcf
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One trillion cubic feet of natural gas or CO2. |
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)
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September 30, |
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December 31, |
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2010 |
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2009 |
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ASSETS
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Current assets: |
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Cash and cash equivalents |
|
$ |
86,345 |
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$ |
20,591 |
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Accrued production receivable |
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196,708 |
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120,667 |
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Trade and other receivables, net of allowance of $456 and $414, respectively |
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103,314 |
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67,874 |
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Derivatives |
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66,591 |
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309 |
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Deferred taxes |
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6,060 |
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46,321 |
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Total current assets |
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459,018 |
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255,762 |
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Property and equipment: |
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Oil and natural gas properties (using full cost accounting): |
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Proved |
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6,971,308 |
|
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3,595,726 |
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Unevaluated |
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1,198,151 |
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320,356 |
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CO2 properties, equipment, and pipelines |
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1,748,673 |
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1,529,781 |
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Other |
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105,600 |
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82,537 |
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Less accumulated depletion, depreciation, amortization, and impairment |
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(2,121,315 |
) |
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(1,825,528 |
) |
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Net property and equipment |
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7,902,417 |
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3,702,872 |
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Derivatives |
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33,124 |
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506 |
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Goodwill |
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1,230,721 |
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169,517 |
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Other |
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217,923 |
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141,321 |
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Total assets |
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$ |
9,843,203 |
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$ |
4,269,978 |
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LIABILITIES AND EQUITY
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
309,241 |
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$ |
169,874 |
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Oil and natural gas production payable |
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154,972 |
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90,218 |
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Derivatives |
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41,135 |
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124,320 |
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Current maturities of long-term debt |
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7,602 |
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5,308 |
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Other |
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4,070 |
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4,070 |
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Total current liabilities |
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517,020 |
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393,790 |
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Long-term liabilities: |
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Long-term debt, net of current portion |
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2,778,247 |
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1,301,068 |
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Asset retirement obligations, net of current portion |
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92,715 |
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53,251 |
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Deferred taxes |
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1,535,871 |
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515,516 |
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Derivatives |
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26,256 |
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5,239 |
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Other |
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29,176 |
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28,877 |
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Total long-term liabilities |
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4,462,265 |
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1,903,951 |
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Commitments and contingencies (Note 10) |
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Equity: |
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Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding |
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- |
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- |
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Common stock, $.001 par value, 600,000,000 shares authorized; 399,700,260 and
261,929,292 shares issued, respectively |
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400 |
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262 |
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Paid-in capital in excess of par |
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3,029,885 |
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910,540 |
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Retained earnings |
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1,325,778 |
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1,064,419 |
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Accumulated other comprehensive loss |
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(561 |
) |
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(557 |
) |
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Treasury stock, at cost, 162,607 and 156,284 shares, respectively |
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(2,590 |
) |
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(2,427 |
) |
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Total Denbury stockholders equity |
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4,352,912 |
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1,972,237 |
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Noncontrolling interest |
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511,006 |
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- |
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Total equity |
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4,863,918 |
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1,972,237 |
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Total liabilities and equity |
|
$ |
9,843,203 |
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$ |
4,269,978 |
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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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Revenues and other income: |
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|
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Oil, natural gas, and related product sales |
|
$ |
460,785 |
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|
$ |
221,321 |
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$ |
1,279,699 |
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$ |
600,942 |
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CO2 sales and transportation fees |
|
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4,653 |
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|
3,659 |
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13,840 |
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|
9,708 |
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|
Gain on sale of interests in Genesis |
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(3 |
) |
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|
- |
|
|
|
101,537 |
|
|
|
- |
|
|
Interest income and other |
|
|
1,268 |
|
|
|
2,269 |
|
|
|
7,658 |
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|
|
7,750 |
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Total revenues |
|
|
466,703 |
|
|
|
227,249 |
|
|
|
1,402,734 |
|
|
|
618,400 |
|
|
|
|
|
|
|
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|
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Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
131,768 |
|
|
|
83,300 |
|
|
|
355,731 |
|
|
|
241,908 |
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|
Production taxes and marketing expenses |
|
|
35,542 |
|
|
|
10,461 |
|
|
|
92,959 |
|
|
|
30,437 |
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|
CO2 discovery and operating expenses |
|
|
2,488 |
|
|
|
1,047 |
|
|
|
5,537 |
|
|
|
3,442 |
|
|
General and administrative |
|
|
37,115 |
|
|
|
24,038 |
|
|
|
101,016 |
|
|
|
79,828 |
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|
Interest, net of amounts capitalized of $10,917, $20,872,
$56,079, and $48,699, respectively |
|
|
53,331 |
|
|
|
9,859 |
|
|
|
123,230 |
|
|
|
36,960 |
|
|
Depletion, depreciation, and amortization |
|
|
111,602 |
|
|
|
53,525 |
|
|
|
322,683 |
|
|
|
177,145 |
|
|
Derivatives expense (income) |
|
|
31,854 |
|
|
|
3,757 |
|
|
|
(138,045 |
) |
|
|
177,061 |
|
|
Transaction costs and other related to the Encore Merger |
|
|
11,470 |
|
|
|
- |
|
|
|
79,253 |
|
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|
- |
|
|
|
|
|
|
|
|
|
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Total expenses |
|
|
415,170 |
|
|
|
185,987 |
|
|
|
942,364 |
|
|
|
746,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
51,533 |
|
|
|
41,262 |
|
|
|
460,370 |
|
|
|
(128,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
Income tax provision (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
3,704 |
|
|
|
(6,160 |
) |
|
|
11,314 |
|
|
|
18,140 |
|
|
Deferred income taxes |
|
|
16,595 |
|
|
|
20,537 |
|
|
|
167,289 |
|
|
|
(67,869 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income (loss) |
|
|
31,234 |
|
|
|
26,885 |
|
|
|
281,767 |
|
|
|
(78,652 |
) |
|
Less: net income attributable to noncontrolling interest |
|
|
(2,130 |
) |
|
|
- |
|
|
|
(20,408 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Denbury stockholders |
|
$ |
29,104 |
|
|
$ |
26,885 |
|
|
$ |
261,359 |
|
|
$ |
(78,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.07 |
|
|
$ |
0.11 |
|
|
$ |
0.72 |
|
|
$ |
(0.32 |
) |
|
Diluted |
|
$ |
0.07 |
|
|
$ |
0.11 |
|
|
$ |
0.71 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
395,913 |
|
|
|
246,795 |
|
|
|
362,241 |
|
|
|
246,156 |
|
|
Diluted |
|
|
401,093 |
|
|
|
252,189 |
|
|
|
367,434 |
|
|
|
246,156 |
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
2010 |
|
2009 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Consolidated net income (loss) |
|
$ |
281,767 |
|
|
$ |
(78,652 |
) |
Adjustments needed to reconcile consolidated net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
322,683 |
|
|
|
177,145 |
|
Deferred income taxes |
|
|
167,289 |
|
|
|
(67,869 |
) |
Gain on sale of interests in Genesis |
|
|
(101,537 |
) |
|
|
- |
|
Stock-based compensation |
|
|
27,326 |
|
|
|
25,450 |
|
Non-cash fair value derivative adjustments |
|
|
(185,009 |
) |
|
|
323,510 |
|
Founders retirement compensation |
|
|
- |
|
|
|
6,350 |
|
Other |
|
|
14,254 |
|
|
|
2,440 |
|
Changes in operating assets and liabilities, net of effects from acquisitions: |
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
48,453 |
|
|
|
(23,672 |
) |
Trade and other receivables |
|
|
20,548 |
|
|
|
2,609 |
|
Other assets |
|
|
1,106 |
|
|
|
(210 |
) |
Accounts payable and accrued liabilities |
|
|
8,257 |
|
|
|
38,757 |
|
Oil and natural gas production payable |
|
|
10,553 |
|
|
|
205 |
|
Other liabilities |
|
|
(22,915 |
) |
|
|
371 |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
592,775 |
|
|
|
406,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows used for investing activities: |
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures |
|
|
(500,062 |
) |
|
|
(289,815 |
) |
Acquisitions of oil and natural gas properties |
|
|
(24,390 |
) |
|
|
(197,534 |
) |
Cash paid in Encore Merger, net of cash acquired |
|
|
(813,894 |
) |
|
|
- |
|
CO2 capital expenditures, including pipelines |
|
|
(236,485 |
) |
|
|
(543,536 |
) |
Net proceeds from sales of oil and natural gas properties and equipment |
|
|
909,986 |
|
|
|
303,450 |
|
Net proceeds from sale of interests in Genesis |
|
|
162,619 |
|
|
|
- |
|
Other |
|
|
(17,927 |
) |
|
|
(8,955 |
) |
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(520,153 |
) |
|
|
(736,390 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(1,519,000 |
) |
|
|
(606,000 |
) |
Bank borrowings |
|
|
1,229,000 |
|
|
|
551,000 |
|
Senior subordinated notes tendered post Encore Merger |
|
|
(616,637 |
) |
|
|
- |
|
Net proceeds from issuance of senior subordinated debt |
|
|
1,000,000 |
|
|
|
389,827 |
|
Net proceeds from issuance of common stock |
|
|
8,614 |
|
|
|
10,595 |
|
Costs of debt financing |
|
|
(76,232 |
) |
|
|
(10,080 |
) |
ENP distributions to noncontrolling interest |
|
|
(24,513 |
) |
|
|
- |
|
Other |
|
|
(8,100 |
) |
|
|
(766 |
) |
|
|
|
|
|
|
Net cash provided by (used for) financing activities |
|
|
(6,868 |
) |
|
|
334,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
65,754 |
|
|
|
4,620 |
|
Cash and cash equivalents at beginning of period |
|
|
20,591 |
|
|
|
17,069 |
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
86,345 |
|
|
$ |
21,689 |
|
|
|
|
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
6
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury Stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid-In |
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
Common Stock |
|
Capital in |
|
|
|
|
|
Other |
|
Treasury Stock |
|
Denbury |
|
|
|
|
|
|
|
($.001 Par Value) |
|
Excess of |
|
Retained |
|
Comprehensive |
|
(at cost) |
|
Stockholders |
|
Noncontrolling |
|
Total |
|
|
Shares |
|
Amount |
|
Par |
|
Earnings |
|
Loss |
|
Shares |
|
Amount |
|
Equity |
|
Interest |
|
Equity |
|
Balance - December 31, 2009 |
|
|
261,929,292 |
|
|
$ |
262 |
|
|
$ |
910,540 |
|
|
$ |
1,064,419 |
|
|
$ |
(557 |
) |
|
|
156,284 |
|
|
$ |
(2,427 |
) |
|
$ |
1,972,237 |
|
|
$ |
- |
|
|
$ |
1,972,237 |
|
Repurchase of common stock |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
382,238 |
|
|
|
(6,144 |
) |
|
|
(6,144 |
) |
|
|
- |
|
|
|
(6,144 |
) |
Issued pursuant to employee stock
purchase plan |
|
|
- |
|
|
|
- |
|
|
|
(2 |
) |
|
|
- |
|
|
|
- |
|
|
|
(375,915 |
) |
|
|
5,981 |
|
|
|
5,979 |
|
|
|
- |
|
|
|
5,979 |
|
Issued pursuant to employee stock
option plan |
|
|
429,038 |
|
|
|
- |
|
|
|
2,635 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,635 |
|
|
|
- |
|
|
|
2,635 |
|
Issued pursuant to directors
compensation plan |
|
|
12,413 |
|
|
|
- |
|
|
|
196 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
196 |
|
|
|
- |
|
|
|
196 |
|
Issued pursuant to Encore
Merger |
|
|
135,170,505 |
|
|
|
135 |
|
|
|
2,085,546 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,085,681 |
|
|
|
- |
|
|
|
2,085,681 |
|
Restricted stock grants |
|
|
1,979,557 |
|
|
|
2 |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Restricted stock grants - forfeited |
|
|
(267,038 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Performance-based
shares issued |
|
|
446,493 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Stock-based compensation |
|
|
- |
|
|
|
- |
|
|
|
30,815 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
30,815 |
|
|
|
- |
|
|
|
30,815 |
|
Income tax benefit from equity
awards |
|
|
- |
|
|
|
- |
|
|
|
156 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
156 |
|
|
|
- |
|
|
|
156 |
|
ENP revaluation at Encore Merger |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
515,210 |
|
|
|
515,210 |
|
ENP cash distributions to
noncontrolling interest |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(24,512 |
) |
|
|
(24,512 |
) |
Derivative contracts, net |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(4 |
) |
|
|
- |
|
|
|
- |
|
|
|
(4 |
) |
|
|
(100 |
) |
|
|
(104 |
) |
Consolidated net income |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
261,359 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
261,359 |
|
|
|
20,408 |
|
|
|
281,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance - September 30, 2010 |
|
|
399,700,260 |
|
|
$ |
400 |
|
|
$ |
3,029,885 |
|
|
$ |
1,325,778 |
|
|
$ |
(561 |
) |
|
|
162,607 |
|
|
$ |
(2,590 |
) |
|
$ |
4,352,912 |
|
|
$ |
511,006 |
|
|
$ |
4,863,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
7
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Consolidated net income (loss) |
|
$ |
31,234 |
|
|
$ |
26,885 |
|
|
$ |
281,767 |
|
|
$ |
(78,652 |
) |
Other comprehensive income (loss), net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate lock derivative contracts reclassified to income,
net of tax of $11, $11, $32, and $32, respectively |
|
|
17 |
|
|
|
17 |
|
|
|
52 |
|
|
|
52 |
|
Change in deferred hedge loss on interest rate swaps,
net of tax of $14, $0, $32, and $0, respectively |
|
|
(68 |
) |
|
|
- |
|
|
|
(155 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Consolidated comprehensive income (loss) |
|
|
31,183 |
|
|
|
26,902 |
|
|
|
281,664 |
|
|
|
(78,600 |
) |
Less: comprehensive income attributable to noncontrolling interest |
|
|
(2,074 |
) |
|
|
- |
|
|
|
(20,308 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) attributable to Denbury stockholders |
|
$ |
29,109 |
|
|
$ |
26,902 |
|
|
$ |
261,356 |
|
|
$ |
(78,600 |
) |
|
|
|
|
|
|
|
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Description of Business
Organization and Nature of Operations
Denbury is a growing independent oil and natural gas company. Denbury is the largest oil
and natural gas operator in both Mississippi and Montana, owns the largest reserves of
CO2 used for tertiary oil recovery east of the Mississippi River, and holds significant
operating acreage in the Rockies and Gulf Coast regions. Denburys goal is to increase the
value of acquired properties through a combination of exploitation, drilling and proven engineering
extraction practices, with its most significant emphasis relating to tertiary recovery operations.
Encore Merger
On March 9, 2010, Denbury acquired Encore pursuant to an Agreement and Plan of Merger (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 $4.5 billion at that
time, including the assumption of debt and the value of the noncontrolling interest in Encore
Energy Partners LP (ENP). Under the Encore Merger Agreement, Encore was merged with and into
Denbury (the Encore Merger), with Denbury surviving the Encore Merger. The Encore Merger was
consummated on March 9, 2010, following approval by the stockholders of both Denbury and Encore,
closing of a new revolving credit facility as part of the financing for the Encore Merger, and
satisfaction of conditions precedent.
Denbury has consolidated Encores results of operations beginning March 9, 2010, the
acquisition date. See Note 3, Acquisitions and Divestitures, for additional information.
Note 2. Basis of Presentation
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources
Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and
do not include all of the information and footnotes required by accounting principles generally
accepted in the United States for complete financial statements. Unless indicated otherwise or
the context requires, the terms we, our, us, or Denbury, refer to Denbury Resources Inc.
and its subsidiaries. These financial statements and the notes thereto should be read in
conjunction with Denburys Annual Report on Form 10-K for the year ended December 31, 2009.
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 Denburys consolidated financial position
as of September 30, 2010, its consolidated results of operations for the three and nine months
ended September 30, 2010 and 2009, and its consolidated cash flows for the nine months ended
September 30, 2010 and 2009. Certain prior period items have been reclassified to make the
classification consistent with the classification in the most recent quarter.
Revised accounting policy for CO2 properties
During the third quarter 2010, the Company revised its accounting policies for CO2
properties. Previously, the Company accounted for its CO2 properties in a manner
similar to its method of accounting for its oil and natural gas properties, as the process and
activities used by the Company to identify, develop and produce CO2 reserves are
virtually identical to those used to identify, develop and produce its oil and natural gas
reserves. However, because CO2 is not a hydrocarbon, it is excluded from the scope
of FASC Topic 932, Extractive Industries Oil and Gas and, therefore, the Company is precluded
from accounting for its CO2 operations in accordance with FASC
Topic 932.
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Accordingly, commencing July 1, 2010, the Company will expense costs incurred to search for
new CO2 resources. Once proved or probable CO2 reserves are established,
costs incurred to develop that resource will be capitalized. Capitalized costs associated with
drilling activities will be depleted on a units-of-production basis over proved developed CO2 reserves. Other
capitalized
CO2
costs will be depleted on a units-of-production basis over proved and probable CO2
reserves. Leasehold acquisition costs will be capitalized as a tangible asset, subject to
depletion upon identification of proved or probable CO2 reserves, or expensed if no
reserves are identified or the lease is abandoned.
Capitalized CO2 properties and CO2 pipelines will be included as a
reduction of future net revenues in our oil and natural gas ceiling test to the extent these assets
will be used to produce proved oil reserves. The remaining net capitalized CO2
asset cost will be evaluated for impairment by comparing our expected future revenues from
these assets to their net carrying value.
The impact of the revised accounting policy on our historical financial statements is not
material to any individual year, nor is the cumulative impact material to our projected financial
results for the year ended December 31, 2010. The Company has recognized the cumulative impact
of the revised accounting policy as a non-cash net reduction to depletion, depreciation, and
amortization during the three months ended September 30, 2010 resulting in a pretax credit of $9.6
million ($6.0 million after tax), which reflects a reduction to CO2 properties,
equipment and pipelines of $26.1 million offset by a decrease in accumulated depletion,
depreciation and amortization of $35.7 million. The cumulative adjustment did not have an
impact on our cash flows.
We expensed $1.2 million of CO2
discovery costs during the third quarter of 2010.
Noncontrolling Interest
As of September 30, 2010, Denbury owned approximately 46% of ENPs outstanding common
units. Denbury also owns 100% of Encore Energy Partners GP LLC (GP LLC), a Delaware limited
liability company and indirect wholly-owned subsidiary of Denbury, which is ENPs general
partner. Considering the presumption of control of GP LLC in accordance with the
Consolidations topic of the FASC, the financial position, results of operations, and cash flows of
ENP have been consolidated with those of Denbury beginning March 9, 2010, the acquisition date.
As
presented in the accompanying Unaudited Condensed Consolidated Balance Sheets
as of September 30, 2010, the $511 million of Noncontrolling interest represents third-party ownership
interests other than Denburys
in ENP. As presented in the accompanying Unaudited Condensed Consolidated Statements
of Operations for the three months ended
September 30, 2010, Net income attributable to noncontrolling interest of $2.1 million represents ENPs results of operations attributable to
third-party owners other than Denbury, and Net income attributable to noncontrolling interest for the nine months
ended September 30, 2010 of $20.4 million represents ENPs results of operations attributable to
third-party owners from March 9, 2010 through September 30, 2010.
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
September 30, |
In thousands |
|
2010 |
|
2009 |
|
Cash paid for interest, net of amounts capitalized |
|
$ |
114,012 |
|
|
$ |
14,114 |
|
Interest capitalized |
|
|
56,079 |
|
|
|
48,699 |
|
Cash paid (refunded) for income taxes |
|
|
166 |
|
|
|
(4,894 |
) |
Increase (decrease) in liabilities for capital expenditures |
|
|
13,880 |
|
|
|
(54,830 |
) |
Issuance of Denbury common stock in connection
with the Encore Merger |
|
|
2,085,681 |
|
|
|
- |
|
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Net Income (Loss) Per Common Share
Basic net income (loss) per common share is computed by dividing net income (loss) attributable to
Denbury stockholders by the weighted average number of shares of common stock outstanding during
the period. Diluted net income (loss) per common
share is calculated in the
same manner, but also considers the impact of
the potential dilution from stock options, unvested stock appreciation rights (SARs), unvested
restricted stock, and unvested performance equity awards. For the three and nine months ended
September 30, 2010 and 2009, there were no adjustments to net income (loss) attributable to Denbury
stockholders for purposes of calculating diluted net income (loss) per common share. The
following is a reconciliation of the weighted average common shares used in the basic and diluted
net income (loss) per common share calculations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
In thousands |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Basic weighted average common shares |
|
|
395,913 |
|
|
|
246,795 |
|
|
|
362,241 |
|
|
|
246,156 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
3,647 |
|
|
|
4,006 |
|
|
|
3,772 |
|
|
|
- |
|
Performance equity awards |
|
|
292 |
|
|
|
259 |
|
|
|
305 |
|
|
|
- |
|
Restricted stock |
|
|
1,241 |
|
|
|
1,129 |
|
|
|
1,116 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Diluted weighted average common shares |
|
|
401,093 |
|
|
|
252,189 |
|
|
|
367,434 |
|
|
|
246,156 |
|
|
|
|
|
|
|
|
|
|
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Basic weighted average common shares excludes 3.3 million shares and 2.5 million shares at
September 30, 2010 and 2009, respectively, of unvested restricted stock. As these restricted shares
vest, they will be included in the shares outstanding used to calculate basic net income (loss) per
common share, although 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 proceeds equal to the average unrecognized
compensation during the period, adjusted for any estimated future tax consequences recognized
directly in equity. Shares of common stock issued in the Encore Merger were weighted from
March 9, 2010 through September 30, 2010. The dilution impact of these shares on Denburys
earnings per share calculations may increase in future periods depending on the market price of
Denburys common stock during those periods.
The following securities could potentially dilute earnings per share in the future, but were
excluded from the computation of diluted net income (loss) per share as their effect would have
been anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
As of September 30, |
In thousands |
|
2010 |
|
2009 |
|
Stock options and SARs |
|
|
4,357 |
|
|
|
10,813 |
|
Performance equity awards |
|
|
- |
|
|
|
476 |
|
Restricted stock |
|
|
77 |
|
|
|
2,454 |
|
|
|
|
|
|
|
Total |
|
|
4,434 |
|
|
|
13,743 |
|
|
|
|
|
|
CO2 Pipelines
CO2 pipelines are used for transporting CO2 to Denburys tertiary
floods from its CO2 source fields located near Jackson, Mississippi. Denbury is
continuing expansion of its CO2 pipeline infrastructure with several pipelines currently
under construction. At September 30, 2010 and December 31, 2009, Denbury had $106.8 million and
$779.1 million of costs (including capitalized interest), respectively, related to pipeline
construction, primarily the Green Pipeline, in progress, recorded under CO2 properties,
equipment, and pipelines in the accompanying Unaudited Condensed Consolidated Balance Sheets.
The costs of CO2 pipelines under construction were not being depreciated at September
30, 2010 or December 31, 2009. For financial accounting purposes, depreciation commences when
the pipelines are placed into service, and each pipeline is depreciated on a straight-line basis
over its estimated useful life, which ranges from 20 to 50 years. During June 2010, Denbury
placed in service the first phase of the Green Pipeline, a 320-mile CO2 pipeline that
runs from southern Louisiana to near Houston, Texas, at which time it became subject to
depreciation for financial accounting purposes. This first phase runs to Denburys Oyster
Bayou Field in Southeast Texas. Denbury filled this pipeline with CO2 from its
source at Jackson Dome during June and commenced first injection of CO2 at the Oyster
Bayou Field on June 29, 2010. The $106.8 million of costs related to pipeline construction in
progress at September 30, 2010, primarily consist of costs incurred for the remaining portion of
the Green Pipeline to the Hastings Field.
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Goodwill
The following table summarizes the changes in Denburys goodwill for the period indicated:
|
|
|
|
|
|
|
Nine Months Ended |
In thousands |
|
September 30, 2010 |
|
Balance, beginning of period |
|
$ |
169,517 |
|
Adjustment to goodwill related to the acquisition of
interests in the Conroe Field(1) |
|
|
318 |
|
Goodwill related to the Encore Merger(2) |
|
|
1,060,886 |
|
|
|
|
Balance, end of period |
|
$ |
1,230,721 |
|
|
|
|
|
|
|
(1) |
|
Goodwill related to the acquisition of interests in the Conroe Field increased due to the
finalization of reserve estimates, offset by closing adjustments. |
|
(2) |
|
See Note 3, Acquisitions and Divestitures. |
Recently Adopted Accounting Pronouncements
ASU 2010-20. In July 2010, the FASB issued Accounting Standards Update (ASU) No.
2010-20 Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit
lossesASC 310 (ASU 2010-20). ASU 2010-20 enhances disclosures about the credit quality of
financing receivables and the allowance for credit losses, by requiring an entity to provide
disaggregated and class information, credit quality indicators, past due information, and
information about modifications of its financing receivables, and other information. The
disclosures as of the end of a reporting period are effective for interim and annual reporting
periods ending on and after December 15, 2010. The disclosures about activity that occurs during a
reporting period are effective for interim and annual reporting periods beginning on or after
December 15, 2010. Since ASU 2010-20 will only amend disclosure requirements and not current
accounting practice, the ASU will not impact Denburys results of operations or financial position.
Subsequent Events. In February 2010, the FASB issued guidance in the Subsequent Events
topic of the FASC to provide updates including: (1) requiring the company to evaluate subsequent
events through the date in which the financial statements are issued; (2) amending the glossary of
the Subsequent Events topic to include the definition of SEC filer and exclude the definition of
Public entity; and (3) eliminating the requirement to disclose the date through which subsequent
events have been evaluated. This guidance was prospectively effective upon issuance. The
adoption of this guidance did not impact Denburys results of operations or financial condition.
Note 3. Acquisitions and Divestitures
Merger with Encore Acquisition Company
As previously discussed in Note 1, Description of Business, on March 9, 2010, the Encore
Merger was consummated. The Encore Merger was financed through a combination of $1.0 billion
of 8.25% Senior Subordinated Notes due 2020, which Denbury issued on February 10, 2010, a new $1.6
billion revolving credit agreement entered into on March 9, 2010, and the assumption of Encores
remaining outstanding senior subordinated notes. See Note 5, Long-Term Debt, for additional
information.
Encore shareholders received the following consideration for each share of Encore common stock
they owned, depending upon the elections, if any, which they made, and the collar, proration, and
allocation features of the Encore Merger Agreement so that, in the aggregate, 30% of the
consideration for the outstanding shares of Encore common stock would consist of cash, and the
remaining 70% of the consideration would consist of shares of Denbury common stock:
|
|
|
Mixed cash/stock electing (or non-electing) Encore stockholders received $15.00 in cash
and 2.4048 shares of Denbury common stock; |
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
All-cash electing Encore stockholders received $46.48 in cash and 0.2417 shares of
Denbury common stock; and |
|
|
|
All-stock electing Encore stockholders (including those whose Encore restricted stock
bonuses were converted into Denbury restricted stock) received 3.4354 shares of Denbury
common stock. |
All Encore stock options fully vested and their intrinsic value was paid in cash. All
Encore restricted stock vested and each holder had the opportunity to make the same elections as
other holders of Encore common stock as described above, except for shares of Encore restricted
stock granted during 2010 as a bonus pursuant to the 2009 Encore annual incentive program, which
were converted into restricted shares of Denbury common stock.
In the Encore Merger, Denbury issued approximately 135.2 million shares of its common stock
and paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares
issued to Encore stockholders represented approximately 34% of Denburys common stock issued and
outstanding immediately after the Encore Merger. The total fair value of the Denbury common
stock issued to Encore stockholders in the Encore Merger was approximately $2.1 billion based upon
Denburys closing price of $15.43 per share on March 9, 2010.
The Encore Merger met the definition of a business combination under the FASC Business
Combinations topic. As such, Denbury estimated the fair value of Encore as of the acquisition
date, which is the date on which Denbury obtained control of Encore. The acquisition date for
the Encore Merger was March 9, 2010. The FASC Fair Value Measurements and Disclosures topic
defines fair value as the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date (often
referred to as the exit price). The fair value measurement is based on the assumptions of
market participants and not those of the reporting entity. Therefore, entity-specific
intentions should not impact the measurement of fair value unless those assumptions are consistent
with market participant views.
In applying these accounting principles, Denbury estimated the fair value of the Encore assets
acquired less liabilities assumed on the acquisition date to be approximately $2.4 billion.
This measurement resulted in the recognition of goodwill totaling approximately $1.1 billion.
The FASC defines goodwill as an asset representing the future economic benefits arising from other
assets acquired in a business combination that are not individually identified and separately
recognized. For this acquisition, goodwill is the excess of the consideration transferred to
acquire Encore plus the fair value of the noncontrolling interest in ENP, over the acquisition date
estimated fair value of the net assets acquired. Goodwill recorded in the Encore Merger
primarily represents the value of the opportunity to expand Encores CO2 EOR operations
in the Rocky Mountain region, the experience and technical expertise of former Encore employees who
have joined Denbury, and the addition of strategic areas of operations in which Denbury did not
previously have a significant presence.
The fair value of Encore was based on significant inputs not observable in the market, which
FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions
include (1) NYMEX oil and natural gas futures (this input is observable), (2) projections of the
estimated quantities of oil and natural gas reserves, including those classified as proved,
probable, and possible, (3) projections of future rates of production, (4) timing and amount of
future development and operating costs, (5) projected cost of CO2 to a market
participant, (6) projected recovery factors, and (7) risk-adjusted discount rates. The fair
value of the oil and natural gas properties was determined using a risk-adjusted after-tax
discounted cash flow analysis. Denbury applies full cost accounting rules, under which the
acquisition cost of oil and natural gas properties are recognized on a cost center basis (country),
of which Denbury has only one cost center (United States). All of the goodwill was assigned to this
single reporting unit. None of the goodwill is deductible for income tax purposes.
Preliminary Purchase Price Allocation in Encore Merger
The following table is a summary of the consideration issued in the Encore Merger and the fair
value of the assets acquired and liabilities assumed at the acquisition date, as well as the fair
value at the acquisition date of the
noncontrolling interest in ENP:
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
|
|
In thousands |
|
|
|
|
|
|
Consideration and noncontrolling interest: |
|
|
|
|
Fair value of Denbury common stock issued(1) |
|
$ |
2,085,681 |
|
Cash payment to Encore stockholders(2) |
|
|
833,909 |
|
Severance payments |
|
|
32,925 |
|
|
|
|
|
Consideration issued |
|
|
2,952,515 |
|
Fair value of noncontrolling interest of ENP(3) |
|
|
515,210 |
|
|
|
|
|
Consideration and noncontrolling interest of ENP(4) |
|
|
3,467,725 |
|
|
|
|
Add: fair value of liabilities assumed: |
|
|
|
|
Accounts payable and accrued liabilities |
|
|
115,999 |
|
Oil and natural gas production payable |
|
|
54,201 |
|
Current derivatives |
|
|
65,954 |
|
Other current liabilities |
|
|
38,407 |
|
Long-term debt |
|
|
1,375,149 |
|
Asset retirement obligations, net of current portion |
|
|
42,360 |
|
Long-term derivatives |
|
|
35,631 |
|
Long-term deferred taxes |
|
|
871,912 |
|
Other long-term liabilities |
|
|
2,717 |
|
|
|
|
Amount attributable to liabilities assumed |
|
|
2,602,330 |
|
Less: fair value of assets acquired: |
|
|
|
|
Cash and cash equivalents |
|
|
51,850 |
|
Accrued production receivable |
|
|
124,494 |
|
Trade and other receivables |
|
|
46,383 |
|
Current derivatives |
|
|
29,737 |
|
Oil and natural gas properties proved |
|
|
3,340,141 |
|
Oil and natural gas properties unevaluated |
|
|
1,279,000 |
|
CO2 properties, equipment, and pipelines |
|
|
7,254 |
|
Other property, plant, and equipment |
|
|
11,475 |
|
Long-term derivatives |
|
|
35,207 |
|
Other long-term assets |
|
|
83,628 |
|
|
|
|
Amount attributable to assets acquired |
|
|
5,009,169 |
|
|
|
|
|
Goodwill |
|
$ |
1,060,886 |
|
|
|
|
|
|
|
(1) |
|
135.2 million Denbury common shares at $15.43 per share. |
|
(2) |
|
Based on holders of 55.3 million Encore common shares being paid $15.00 per share plus cash payment
to stock option holders of $4.5 million. |
|
(3) |
|
Represents fair value of the noncontrolling interest of ENP. As of March 9, 2010, there were
45.3 million ENP common units outstanding and the closing price was $21.10 per common unit. As
of March 9, 2010, Encore owned approximately 46% of ENPs outstanding common units. |
|
(4) |
|
The sum of the consideration issued, the noncontrolling interest of ENP, and the fair value of
Encores long-term debt assumed totals approximately $4.8 billion, representing the aggregate
purchase price. |
For the three months ended September 30, 2010 and for the period from March 9, 2010 to
September 30, 2010, Denbury recognized $174.3 million and $435.2 million of oil, natural gas and
related product sales, respectively, related to the Encore Merger. For the three months ended
September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, Denbury recognized
$114.1 million and $294.8 million net field operating income (oil, natural gas and related product
sales less lease operating expenses and production taxes and marketing expenses), respectively,
related to the Encore Merger. Transaction and other costs related to the Encore Merger
included in the Companys Unaudited Condensed Consolidated Statements of Operations for the nine
months ended September 30, 2010
include $47.9 million
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
of professional, legal and accounting fees, which have been expensed as
incurred, and $31.4 million of employee-related severance and termination costs, which are accrued
over the employees service period.
2009 Conroe Field Acquisition
In December 2009, Denbury acquired a 91.4% interest in the Conroe Field, a significant
potential tertiary flood north of Houston, Texas, for total consideration of approximately $422.9
million comprised of approximately $254.2 million in cash and 11,620,000 shares of Denbury common
stock. The common stock was valued at $168.7 million based on the closing price of Denburys
stock on December 18, 2009 of $14.52 per share. The effective date of purchase was December 1,
2009. The cash amount paid at closing was $268.5 million, which includes $15.6 million for
amounts in escrow accounts reserved for plugging and abandonment and other adjustments.
Denbury recorded approximately $31.0 million of goodwill related to the acquisition of interests in
the Conroe Field.
Denbury shares issued in a private placement in conjunction with the purchase of interests in
the Conroe Field were subsequently registered for resale with the SEC on February 2, 2010, as
required under a registration rights agreement. The registration rights agreement provides
that the registration statement for the shares remain effective for approximately one year.
2009 Hastings Field Acquisition
During November 2006, Denbury entered into an agreement with a subsidiary of Venoco, Inc.
(Venoco), which gave Denbury an option to purchase Venocos interests in the Hastings Field, a
strategically significant potential tertiary flood candidate located near Houston, Texas.
Denbury exercised the purchase option prior to September 2008, and closed the acquisition during
February 2009. As consideration for the option agreement, during 2006 through 2008, Denbury
made cash payments totaling $50 million, which it recorded as a deposit. The remaining purchase
price of approximately $196 million was paid in cash, and was determined as of January 1, 2009 (the
effective date) with closing on February 2, 2009. The final closing adjustments were completed
during the three months ended September 30, 2009. The final closing price, adjusted for
interim net cash flows between the effective date and closing date of the acquisition (including
minor purchase price adjustments), totaled approximately $246.8 million. Denbury recorded
approximately $138.8 million of goodwill related to the acquisition of interests in the Hastings
Field.
2009 Sale of Barnett Shale Properties
In May 2009, Denbury entered into an agreement to sell 60% of its Barnett Shale natural gas
assets to Talon Oil and Gas LLC (Talon), a privately held company, for $270 million (before
closing adjustments). Denbury closed approximately three-quarters of the sale in June 2009 and
closed the remainder of the sale in July 2009. Net proceeds were approximately $259.8 million
(after closing adjustments, and net of $8.1 million for natural gas swaps transferred in the
sale). The effective date under the agreement was June 1, 2009. Denbury did not record a
gain or loss on the sale in accordance with the full cost method of accounting.
In December 2009, Denbury closed the sale of the remaining 40% of its Barnett Shale natural
gas assets to Talon for $210 million (before closing adjustments). Net proceeds were
approximately $209.9 million (after closing adjustments). The effective date under the
agreement was December 1, 2009. Denbury did not record a gain or loss on the sale in
accordance with the full cost method of accounting. Further, the sale was structured as a
deferred like-kind exchange in conjunction with Denburys acquisition of interests in the Conroe
Field in order to defer most of the tax impacts of the sale.
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
2010 Sale of Interests in Genesis Energy, L.P. (Genesis)
In February 2010, Denbury sold its interest in Genesis Energy, LLC, the general partner of
Genesis, for net proceeds of approximately $84 million, after giving effect to the change of
control provision of the incentive compensation agreement with Genesis management, which was
triggered and under which Denbury paid a total of $14.9 million comprised of deferred compensation
of $1.9 million and change of control redemption of $13.0 million. In February 2010, Denbury
recognized general and administrative expense of $1.1 million associated with the $14.9 million
payment. The remainder of the payment had been previously accrued in Denburys financial
statements as of December 31, 2009. In March 2010, Denbury sold all of its Genesis common
units in a secondary public offering for net proceeds of approximately $79 million. As a
result, Denbury no longer holds any interest in Genesis. Denbury recognized a pre-tax gain of
approximately $101.5 million ($63.0 million after tax) on these dispositions.
2010 Sale of Southern Properties
In May 2010, Denbury sold certain oil and natural gas properties and related assets
acquired in the Encore Merger, primarily located in the Permian Basin in West Texas and
southeastern New Mexico; the Mid-continent area, which includes the Anadarko Basin in Oklahoma,
Texas, and Kansas; and the East Texas Basin (the Southern Assets) to Quantum Resources
Management, LLC for consideration of $883.9 million after closing adjustments and including a prior
$45 million deposit. The effective date of the sale was May 1, 2010. Denbury reduced its
full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale in
accordance with the full cost method of accounting.
2010 Sale of Cleveland Sand Play Properties
In August 2010, Denbury sold certain oil and natural gas properties and related assets
acquired in the Encore Merger, primarily located in the Cleveland Sand Play of western Oklahoma,
for consideration of $32.1 million after closing adjustments. The effective date of the sale
was August 1, 2010. Denbury reduced its full cost pool by the amount of the net proceeds and
did not record a gain or loss on the sale in accordance with the full cost method of accounting.
Pending Sale of Haynesville and East Texas Natural Gas Properties
In October 2010, Denbury entered into an agreement to sell its Haynesville and East Texas
oil and natural gas properties to a private company for consideration of $217.5 million before closing
adjustments. The effective date of the sale will be September 1, 2010, and it is expected to
close by early December of 2010.
Recent Acquisition of Reserves in Rocky Mountain Region at Riley Ridge
In October 2010, Denbury acquired a 42.5% non-operated working interest in the Riley Ridge
Federal Unit located in the LaBarge Field of southwestern Wyoming, a significant natural source of
CO2 as well as natural gas and helium, for consideration of $124.3 million after closing
adjustments. The acquisition also includes approximately 33% of the CO2 rights in
an additional 28,000 acres adjoining the Riley Ridge Unit.
Pro Forma Information
The following unaudited pro forma condensed financial data for the three and nine months ended
September 30, 2010 gives effect to the Encore Merger as if it had occurred on January 1, 2010.
The following unaudited pro forma condensed financial data for the three and nine months ended
September 30, 2009 gives effect to the Encore Merger, the acquisition of interests in the Conroe
Field in December 2009 and the acquisition of interests in the Hastings Field in February 2009 as
if each had occurred on January 1, 2009. The unaudited pro forma condensed consolidated
financial information has been included for comparative purposes only and is not necessarily
indicative of the results that might have occurred had the transactions taken place on the dates
indicated and is not intended to be a projection of future results.
17
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
In thousands, except per share amounts |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma total revenues |
|
$ |
466,703 |
|
|
$ |
425,583 |
|
|
$ |
1,579,184 |
|
|
$ |
1,114,439 |
|
Pro forma net income (loss) attributable to Denbury
stockholders |
|
$ |
29,104 |
|
|
$ |
32,612 |
|
|
$ |
276,527 |
|
|
$ |
(135,954 |
) |
Pro forma net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.07 |
|
|
$ |
0.08 |
|
|
$ |
0.70 |
|
|
$ |
(0.35 |
) |
Diluted |
|
$ |
0.07 |
|
|
$ |
0.08 |
|
|
$ |
0.69 |
|
|
$ |
(0.35 |
) |
Note 4. Asset Retirement Obligations
In general, Denburys future asset retirement obligations relate to future costs associated
with plugging and abandonment of its oil, natural gas, and CO2 wells, removal of
equipment and facilities from leased acreage, and land restoration. The fair value of a
liability for an asset retirement is recorded in the period in which it is incurred, discounted to
its present value using Denburys credit-adjusted risk-free interest rate, and a corresponding
amount capitalized by increasing the carrying amount of the related long-lived asset. The
liability is accreted each period, and the capitalized cost is depreciated over the useful life of
the related asset.
The following table summarizes the changes in Denburys asset retirement obligations for
the period indicated:
|
|
|
|
|
|
|
Nine Months Ended |
In thousands |
|
September 30, 2010 |
|
Balance, beginning of period |
|
$ |
54,338 |
|
Liabilities incurred and assumed during period |
|
|
3,185 |
|
Liabilities assumed in the Encore Merger |
|
|
43,783 |
|
Revisions in estimated retirement obligations |
|
|
2,583 |
|
Liabilities settled during period |
|
|
(4,552 |
) |
Accretion expense |
|
|
4,676 |
|
Sales of properties |
|
|
(7,669 |
) |
|
|
|
|
Balance, end of period |
|
$ |
96,344 |
|
|
|
|
18
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
At September 30, 2010 and December 31, 2009, approximately $3.6 million and $1.1 million,
respectively, of Denburys asset retirement obligations were classified in Accounts payable and
accrued liabilities under current liabilities in the accompanying Unaudited Condensed Consolidated
Balance Sheets. Denbury has escrow accounts that are legally restricted for certain of its asset
retirement obligations. The balances of these escrow accounts were approximately $33.0 million and
$22.8 million at September 30, 2010 and December 31, 2009, respectively, and are included in Other
assets in the accompanying Unaudited Condensed Consolidated Balance Sheets.
Note 5. Long-Term Debt
The following table shows the components of Denburys long-term debt as of the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
In thousands, except percentages |
|
2010 |
|
2009 |
|
Denbury Credit Agreement |
|
$ |
120,000 |
|
|
$ |
- |
|
ENP Credit Agreement |
|
|
240,000 |
|
|
|
- |
|
Senior bank loan (replaced with Denbury Credit Agreement) |
|
|
- |
|
|
|
125,000 |
|
7.5% Senior Subordinated Notes due 2013, net of discount of $486 and $631, respectively |
|
|
224,514 |
|
|
|
224,369 |
|
6.25% Senior Subordinated Notes due 2014, including premium of $12 |
|
|
1,084 |
|
|
|
- |
|
7.5% Senior Subordinated Notes due 2015, including premium of $449 and $513, respectively |
|
|
300,449 |
|
|
|
300,513 |
|
6.0% Senior Subordinated Notes due 2015, including premium of $5 |
|
|
490 |
|
|
|
- |
|
9.5% Senior Subordinated Notes due 2016, including premium of $15,273 |
|
|
240,193 |
|
|
|
- |
|
9.75% Senior Subordinated Notes due 2016, net of discount of $23,210 and $26,424, respectively |
|
|
403,140 |
|
|
|
399,926 |
|
7.25% Senior Subordinated Notes due 2017, including premium of $26 |
|
|
2,276 |
|
|
|
- |
|
8.25% Senior Subordinated Notes due 2020 |
|
|
996,273 |
|
|
|
- |
|
Northeast Jackson Dome pipeline financing |
|
|
168,188 |
|
|
|
170,633 |
|
Free State pipeline financing |
|
|
81,710 |
|
|
|
79,987 |
|
Capital lease obligations |
|
|
7,532 |
|
|
|
5,948 |
|
|
|
|
|
|
Total |
|
|
2,785,849 |
|
|
|
1,306,376 |
|
Less current portion |
|
|
7,602 |
|
|
|
5,308 |
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
2,778,247 |
|
|
$ |
1,301,068 |
|
|
|
|
|
|
19
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
New $1.6 Billion Revolving Credit Agreement
On March 9, 2010, Denbury entered into a new $1.6 billion revolving credit agreement with
JPMorgan Chase Bank, N.A. (JPMorgan), as administrative agent, and 23 other lenders as party
thereto (the Denbury Credit Agreement).
Borrowings under the Denbury Credit
Agreement, coupled with the funds from
Denburys issuance of $1.0 billion of 8.25% Senior Subordinated Notes due 2020, were used to:
|
|
|
fund the cash portion of the consideration issued in the Encore Merger (inclusive of
payments made to stock option holders); |
|
|
|
|
repay amounts outstanding under Denburys then existing $750 million revolving credit
agreement, which had $125 million outstanding as of March 9, 2010; |
|
|
|
|
repay amounts outstanding under Encores then existing revolving credit agreement, which
had $265 million outstanding as of March 9, 2010; |
|
|
|
|
pay Encores severance costs; |
|
|
|
|
pay transaction fees and expenses; and |
|
|
|
|
provide additional liquidity. |
Availability under the Denbury 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 Denbury Credit Agreement provides for a borrowing
base of $1.6 billion, which was reaffirmed on November 1, 2010. The borrowing base represents the amount that can be borrowed based on the
reserves and certain other oil and natural gas assets of Denbury and its restricted subsidiaries,
as confirmed by the banks, while the commitment amount is the amount the banks have committed to
fund pursuant to the terms of the Denbury Credit Agreement. The borrowing base is adjusted at the
banks discretion and is based in part upon external factors over which Denbury has no control. If
the borrowing base were to be less than outstanding borrowings under the Denbury Credit Agreement,
Denbury would be required to repay the deficit over a period of four months. In conjunction with
the sale of the Southern Assets, lending banks performed a redetermination of the borrowing base
under the Denbury Credit Agreement and left the borrowing base unchanged. Denbury incurs a
commitment fee of 0.5% on the unused portion of the credit facility or if less, the borrowing base.
Loans under the Denbury Credit Agreement mature in March 2014.
The Denbury Credit Agreement is secured by substantially all of the proved oil and natural gas
properties of Denburys restricted subsidiaries and by the equity interests of Denburys restricted
subsidiaries. In addition, Denburys obligations under the Denbury Credit Agreement are guaranteed
by its restricted subsidiaries. The restricted subsidiaries include most of the subsidiaries of
the combined company after the Encore Merger, excluding Denburys non-guarantor subsidiaries.
The Denbury Credit Agreement contains several restrictive covenants including, among others:
|
|
|
a prohibition on the payment of dividends to parties other than Denbury and its
restricted subsidiaries; |
|
|
|
a requirement to maintain a current ratio, as determined under the Denbury Credit
Agreement, of not less than 1.0 to 1.0; |
|
|
|
a maximum permitted ratio of debt to adjusted EBITDA (as defined in the Denbury Credit
Agreement) of Denbury and its restricted subsidiaries of not more than 4.5 to 1.0 in 2010
and 4.0 to 1.0 in 2011 and thereafter; and |
|
|
|
a prohibition against incurring debt, subject to permitted exceptions. |
Additionally, there is a limitation on the aggregate amount of forecasted oil and natural gas
production that can be economically hedged with oil or natural gas derivative contracts.
Loans under the Denbury Credit Agreement are subject to varying rates of interest based on
(1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is
a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus
the applicable margin of 2.0% to 3.0% based on the ratio of outstanding borrowings to the borrowing
base, and base rate loans bear interest at the base rate plus the applicable margin of 1.0% to 2.0%
based on the ratio of outstanding borrowings to the borrowing base. The Eurodollar rate for any
interest period (either one, two, three, six, nine, or twelve months, as selected by Denbury) is
the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan,
for deposits in dollars for a similar interest period. The base rate is calculated as the
highest of (1) the annual rate of interest
announced by and JPMorgan as its prime rate, (2) the federal funds effective rate plus 0.5%,
and (3) the Adjusted Eurodollar Rate (as defined in the Denbury Credit Agreement) for a one-month
interest period plus 1.0%.
20
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Encore Energy Partners Operating LLC Credit Agreement
Encore Energy Partners Operating LLC (OLLC), a wholly-owned subsidiary of ENP, is a party to
a five-year credit agreement dated March 7, 2007 (as amended, the ENP Credit Agreement). The ENP
Credit Agreement matures on March 7, 2012. In November 2009, OLLC amended the ENP Credit
Agreement, effective upon the closing of the Encore Merger, to, among other things, permit the
consummation of the Encore Merger despite its being a Change of Control under the ENP Credit
Agreement.
The ENP Credit Agreement provides for revolving credit loans to be made to OLLC from time to
time and letters of credit to be issued from time to time for the account of OLLC or any of its
restricted subsidiaries. The aggregate amount of the commitments of the lenders under the ENP
Credit Agreement is $475 million. Availability under the ENP Credit Agreement is subject to a
borrowing base, which is redetermined semi-annually and upon requested special redeterminations.
As of September 30, 2010, the borrowing base was $375 million and there were $240 million of
outstanding borrowings under the ENP Credit Agreement.
Obligations under the ENP Credit Agreement are secured by a first-priority security interest
in substantially all of OLLCs proved oil and natural gas reserves and in the equity interests of
OLLC and its restricted subsidiaries. In addition, obligations under the ENP Credit Agreement are
guaranteed by ENP and OLLCs restricted subsidiaries. Denbury consolidates the debt of ENP with
that of its own; however, obligations under the ENP Credit Agreement are non-recourse to Denbury
and its restricted subsidiaries.
Issuance of 8.25% Senior Subordinated Notes due 2020
On February 10, 2010, Denbury issued $1.0 billion of 8.25% Senior Subordinated Notes due 2020
(the 2020 Notes), for net proceeds after underwriting discounts and commissions of $980 million.
The 2020 Notes were sold at par. Upon the closing of the Encore Merger, $400 million of the net
proceeds were used to finance a portion of the Encore Merger consideration. Under the indenture
governing the 2020 Notes, to the extent that fewer than $600 million principal amount of Encores
outstanding senior subordinated notes were repurchased in tender offers or change of control
repurchases under the Encore indentures, Denbury was required to redeem an equal amount of the 2020
Notes, plus accrued and unpaid interest. Denbury redeemed $500.5 million principal amount of
Encores outstanding senior subordinated notes in a tender offer, repurchased an additional $95.7
million principal amount of Encores outstanding senior subordinated notes under change of control
provisions, and redeemed $3.7 million principal amount of the 2020 Notes. See Tender Offers and
Consent Solicitations for Encores Senior Subordinated Notes; Supplements to Indentures Governing
Encores Senior Subordinated Notes below.
The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August
15 of each year, beginning August 15, 2010. Denbury may redeem the 2020 Notes in whole or in part
at its option beginning February 15, 2015, at the following redemption prices:
|
|
|
104.125% after February 15, 2015; |
|
|
|
|
102.75% after February 15, 2016; |
|
|
|
|
101.375% after February 15, 2017; and |
|
|
|
|
100% after February 15, 2018. |
Prior to February 15, 2013, Denbury may at its option redeem up to an aggregate of 35% of the
principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain equity
offerings. In addition, at any time prior to February 15, 2015, Denbury may redeem 100% of the
principal amount of the 2020 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 Denburys ability to incur additional debt, pay dividends on its common stock, make investments,
create liens on its assets, engage in transactions with its
affiliates, transfer or sell assets,
consolidate or merge, or sell substantially all of its assets. The 2020 Notes are not subject
to any sinking fund requirements. Certain of Denburys subsidiaries fully and unconditionally
guarantee this debt.
21
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Supplements to Indentures Governing Denburys Senior Subordinated Notes
On March 9, 2010, upon closing of the Encore Merger, Denbury became an obligor, as successor
in interest to Encore, with respect to Encores senior subordinated notes, which are governed by
four indentures covering an aggregate original principal amount of $825 million. In conjunction
with the closing of the Encore Merger, Denbury and its subsidiaries entered into supplemental
indentures to add subsidiary guarantors, as required under the Encore indentures as well as the
indentures governing Denburys senior subordinated notes. The Encore legacy subsidiaries, with
permitted exceptions, became guarantors under the Denbury indentures that were in effect prior to
the Encore Merger and the Denbury legacy subsidiaries, with permitted exceptions, became guarantors
under the Encore indentures with respect to which Denbury succeeded Encore.
Tender Offers and Consent Solicitations for Encores Senior Subordinated Notes; Supplements to
Indentures Governing Encores Senior Subordinated Notes
On February 8, 2010, Denbury commenced a cash tender offer to repurchase $600 million
principal amount of Encores $825 million senior subordinated notes which were governed by three of
Encores four indentures and solicited consents to amend each of those three indentures to
eliminate most of the indenture covenants. Those indentures are the indentures to which Encore was
a party prior to the Encore Merger governing their 6.25% Senior Subordinated Notes due 2014 (the
6.25% Notes), their 6.0% Senior Subordinated Notes due 2015 (the 6.0% Notes), and their 7.25%
Senior Subordinated Notes due 2017 (the 7.25% Notes).
On March 10, 2010, upon expiration of the tender offers and consent solicitations, Denbury
accepted for purchase all notes tendered in the tender offer. The total amount of notes that
Denbury purchased was approximately $500.5 million in principal amount of the $600 million in
original principal amount for which tenders were made, leaving outstanding approximately $99.5
million of the $600 million of notes for which Denbury made tender offers.
The tender of the notes also constituted the delivery of consents of holders of the notes to
eliminate or modify certain provisions contained in each of the three indentures governing the
Encore senior subordinated notes for which tender offers were made. Denbury received sufficient
consents in the solicitations to amend these three Encore indentures effective upon the Encore
Merger. The amendments of the three indentures governing the $600 million of notes subject to the
tender offers eliminated most of the restrictive covenants, including covenants requiring the
filing of SEC reports; restricting certain payments; limiting indebtedness; restricting
distributions from certain restricted subsidiaries, affiliate transactions, and liens; requiring
future subsidiaries to guarantee the applicable notes; requiring the delivery of certificates
concerning compliance with the applicable indenture; certain provisions of covenants relating to
mergers and consolidations; and certain events of default in the indentures. The amendments do not
apply to the 9.50% Senior Subordinated Notes due 2016 (the 9.5% Notes).
On March 12, 2010, Denbury commenced a second tender offer to repurchase, for 101% of the face
amount, the $99.5 million on notes that remained outstanding after completion of the February 8,
2010 tender. The March 12, 2010 tender also included an initial offer to purchase, for 101% of the
face amount, the $225 million of outstanding 9.5% Notes. These change-of-control tenders were
required by each of the Encore indentures. In April 2010, Denbury purchased approximately $95.7
million of these senior subordinated notes, leaving approximately $228.7 million of former Encore
notes outstanding.
Encore Indentures
In addition to the three indentures that govern the Encore senior subordinated notes for which
Denbury made tender offers, as a result of the Encore Merger, Denbury also became successor in
interest to Encore under the Encore indenture with respect to the 9.5% Notes in the original
principal amount of $225 million (the 9.5% Indenture). Interest on the 9.5% Notes is due
semi-annually on May 1 and November 1. The 9.5% Notes mature on May 1, 2016. The material terms
of the 9.5% Indenture include covenants requiring the filing of SEC
reports;
restricting certain payments; limiting indebtedness; restricting distributions from certain
restricted subsidiaries, affiliate transactions, and liens; requiring certain subsidiaries to
deliver guarantees of the notes; requiring the delivery of certificates concerning compliance with
the indenture; and covenants relating to mergers and consolidations.
22
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
All of the Encore indentures, including the 9.5% Indenture, also have covenants limiting the
sale of assets and providing a put right by holders upon change of control, as well as other
certain affirmative and negative covenants.
Note 6. Derivative Instruments and Hedging Activities
Derivative Policy
Denbury applies the provisions of the Derivatives topic of the FASC, which requires each
derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not
been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted
to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending
on the nature of the hedge, the effective portion of changes in fair value can be recognized in
accumulated other comprehensive income or loss within equity until such time as the hedged item is
recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from
the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged
item. In addition, all hedging relationships must be designated, documented, and reassessed
periodically.
Denbury has elected to designate ENPs outstanding interest rate swaps as cash flow hedges.
The effective portion of the mark-to-market gain or loss on these derivative instruments is
recorded in Accumulated other comprehensive loss on the accompanying Unaudited Condensed
Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged
transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is
recognized in earnings and included in Derivatives expense (income) in the accompanying Unaudited
Condensed Consolidated Statements of Operations.
Denbury does not apply hedge accounting treatment to its 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 included in Derivatives expense (income) in the accompanying Unaudited
Condensed Consolidated Statements of Operations.
Oil and Natural Gas Derivative Contracts
From time to time, Denbury enters into various oil and natural gas derivative contracts to
provide an economic hedge of its exposure to commodity price risk associated with anticipated
future oil and natural gas production. Denbury does not hold or issue derivative financial
instruments for trading purposes. These contracts consist of price floors, collars, and fixed
price swaps. Historically, Denbury has hedged up to 80% of its anticipated production for the
following year to provide it with a reasonably certain amount of cash flow to cover most of its
budgeted exploration and development expenditures without incurring significant debt. In October
2010, Denbury entered into costless collar crude oil contracts covering 6,000 Bbls/d during the
second half of 2011 and 12,000 Bbls/d during the first quarter of 2012.
As a result of the anticipated sale of the Haynesville and East Texas assets, upon closing
Denbury expects to terminate a portion of its remaining 2010 and 2011 natural gas hedges during the
fourth quarter of 2010. See Note 13, Subsequent Events, for additional information.
Denbury manages and controls market and counterparty credit risk through established internal
control procedures that are reviewed on an ongoing basis. Denbury attempts to minimize credit risk
exposure to counterparties through formal credit policies, monitoring procedures, and
diversification. All of Denburys and ENPs commodity derivative contracts are with parties that
are lenders under their respective credit agreements. Denbury has included an estimate of
nonperformance risk in the fair value measurement of its commodity derivative contracts as required
by FASC guidance on fair value. At September 30, 2010 and December 31, 2009, the net asset
(liability) of Denburys open commodity derivative contracts of $67.2 million and ($128.7) million,
respectively,
included a reduction of $0.6 million and $0.8 million, respectively, for estimated
nonperformance risk.
23
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 |
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
|
In thousands |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Receipts (payments) on settlement of oil derivative contracts |
|
$ |
(3,590 |
) |
|
$ |
18,527 |
|
|
$ |
(80,969 |
) |
|
$ |
146,365 |
|
Receipts on settlement of natural gas derivative contracts |
|
|
13,626 |
|
|
|
- |
|
|
|
34,005 |
|
|
|
- |
|
Fair value adjustments to derivative contracts income (expense) |
|
|
(42,517 |
) |
|
|
(22,284 |
) |
|
|
183,512 |
|
|
|
(323,426 |
) |
Ineffectiveness on interest rate swaps |
|
|
627 |
|
|
|
- |
|
|
|
1,497 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Derivatives income (expense) |
|
$ |
(31,854 |
) |
|
$ |
(3,757 |
) |
|
$ |
138,045 |
|
|
$ |
(177,061 |
) |
|
|
|
|
|
|
|
|
|
24
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following tables present the fair value of commodity derivative contracts for (1) Denbury
excluding ENP and (2) ENP standalone:
Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments - Excluding
ENP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Prices Per Bbl |
|
Asset (Liability) |
|
|
|
|
Type of |
|
|
|
|
|
Weighted Average Price |
|
September 30, |
|
December 31, |
Year |
|
Months |
|
Contract |
|
Bbls/d |
|
Swap |
|
Floor |
|
Ceiling |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Oil Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
Jan - Mar |
|
Swap |
|
|
30,625 |
|
|
$ |
55.40 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(63,525 |
) |
|
|
|
|
Collar |
|
|
10,000 |
|
|
|
- |
|
|
|
67.45 |
|
|
|
86.38 |
|
|
|
- |
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Mar 2010 |
|
|
40,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
(63,430 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr - June |
|
Collar |
|
|
35,000 |
|
|
|
- |
|
|
|
62.13 |
|
|
|
89.08 |
|
|
|
- |
|
|
|
(24,741 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Apr - June 2010 |
|
|
35,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
(24,741 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July - Sept |
|
Collar |
|
|
35,000 |
|
|
|
- |
|
|
|
62.13 |
|
|
|
89.08 |
|
|
|
- |
|
|
|
(20,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total July - Sept 2010 |
|
|
35,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
(20,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec |
|
Swap |
|
|
5,625 |
|
|
$ |
71.15 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5,142 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
35,000 |
|
|
|
- |
|
|
|
62.13 |
|
|
|
89.08 |
|
|
|
(3,840 |
) |
|
|
(13,320 |
) |
|
|
|
|
Put |
|
|
7,125 |
|
|
|
- |
|
|
|
64.77 |
|
|
|
- |
|
|
|
284 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2010 |
|
|
47,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(8,698 |
) |
|
$ |
(13,320 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Jan - Mar |
|
Swap |
|
|
625 |
|
|
$ |
79.18 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(229 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
43,500 |
|
|
|
- |
|
|
|
70.34 |
|
|
|
100.20 |
|
|
|
2,748 |
|
|
|
177 |
|
|
|
|
|
Put |
|
|
6,625 |
|
|
|
- |
|
|
|
69.53 |
|
|
|
- |
|
|
|
1,300 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Mar 2011 |
|
|
50,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,819 |
|
|
$ |
177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr - June |
|
Swap |
|
|
625 |
|
|
$ |
79.18 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(297 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
43,500 |
|
|
|
- |
|
|
|
70.34 |
|
|
|
100.20 |
|
|
|
1,976 |
|
|
|
(318 |
) |
|
|
|
|
Put |
|
|
6,625 |
|
|
|
- |
|
|
|
69.53 |
|
|
|
- |
|
|
|
2,090 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Apr - June 2011 |
|
|
50,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,769 |
|
|
$ |
(318 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July - Sept |
|
Swap |
|
|
625 |
|
|
$ |
79.18 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(350 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
40,500 |
|
|
|
- |
|
|
|
70.37 |
|
|
|
100.03 |
|
|
|
(703 |
) |
|
|
(1,078 |
) |
|
|
|
|
Put |
|
|
6,625 |
|
|
|
- |
|
|
|
69.53 |
|
|
|
- |
|
|
|
2,680 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total July - Sept 2011 |
|
|
47,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,627 |
|
|
$ |
(1,078 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec |
|
Swap |
|
|
625 |
|
|
$ |
79.18 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(395 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
41,500 |
|
|
|
- |
|
|
|
70.36 |
|
|
|
101.64 |
|
|
|
(1,792 |
) |
|
|
(2,533 |
) |
|
|
|
|
Put |
|
|
6,625 |
|
|
|
- |
|
|
|
69.53 |
|
|
|
- |
|
|
|
3,050 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2011 |
|
|
48,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
863 |
|
|
$ |
(2,533 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
Jan - Mar |
|
Swap |
|
|
625 |
|
|
$ |
81.04 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(312 |
) |
|
$ |
- |
|
|
|
|
|
Collar |
|
|
32,000 |
|
|
|
- |
|
|
|
70.00 |
|
|
|
101.12 |
|
|
|
(3,427 |
) |
|
|
- |
|
|
|
|
|
Put |
|
|
625 |
|
|
|
- |
|
|
|
65.00 |
|
|
|
- |
|
|
|
237 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Mar 2012 |
|
|
33,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3,502 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr - Jun |
|
Swap |
|
|
625 |
|
|
$ |
81.04 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(337 |
) |
|
$ |
- |
|
|
|
|
|
Put |
|
|
625 |
|
|
|
- |
|
|
|
65.00 |
|
|
|
- |
|
|
|
266 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Apr - Jun 2012 |
|
|
1,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(71 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul - Sept |
|
Swap |
|
|
625 |
|
|
$ |
81.04 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(360 |
) |
|
$ |
- |
|
|
|
|
|
Put |
|
|
625 |
|
|
|
- |
|
|
|
65.00 |
|
|
|
- |
|
|
|
277 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total July - Sept 2012 |
|
|
1,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(83 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec |
|
Swap |
|
|
625 |
|
|
$ |
81.04 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(378 |
) |
|
$ |
- |
|
|
|
|
|
Put |
|
|
625 |
|
|
|
- |
|
|
|
65.00 |
|
|
|
- |
|
|
|
301 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2012 |
|
|
1,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(77 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil Contracts - Excluding ENP |
|
$ |
(2,353 |
) |
|
$ |
(126,004 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Prices Per Mcf/d |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Type of |
|
|
|
|
|
|
Weighted Average Price |
|
|
September 30, |
|
|
December 31, |
|
Year |
|
Months |
|
Contract |
|
Mcf/d |
|
Swap |
|
Floor |
|
Ceiling |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
Natural Gas
Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
Jan - Mar |
|
Swap |
|
|
79,000 |
|
|
$ |
5.77 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Mar 2010 |
|
|
79,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr - June |
|
Swap |
|
|
79,000 |
|
|
$ |
5.77 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
397 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Apr - June 2010 |
|
|
79,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
397 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July - Sept |
|
Swap |
|
|
59,000 |
|
|
$ |
5.96 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(294 |
) |
|
|
|
|
|
|
Collar |
|
|
10,000 |
|
|
|
- |
|
|
|
5.13 |
|
|
|
6.25 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total July - Sept 2010 |
|
|
69,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
(294 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec |
|
Swap |
|
|
59,000 |
|
|
$ |
5.96 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
11,054 |
|
|
$ |
(1,954 |
) |
|
|
|
|
|
|
Collar |
|
|
10,000 |
|
|
|
- |
|
|
|
5.13 |
|
|
|
6.25 |
|
|
|
1,191 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2010 |
|
|
69,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
12,245 |
|
|
$ |
(1,954 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Jan - Dec |
|
Swap |
|
|
47,000 |
|
|
$ |
6.36 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
33,567 |
|
|
$ |
(981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Dec 2011 |
|
|
47,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
33,567 |
|
|
$ |
(981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
Jan - Dec |
|
Swap |
|
|
20,000 |
|
|
$ |
6.53 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
11,758 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Dec 2012 |
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
11,758 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Contracts - Excluding ENP
|
|
$ |
57,570 |
|
|
$ |
(2,740 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Commodity Derivative Contracts - Excluding ENP
|
|
$ |
55,217 |
|
|
$ |
(128,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments - ENP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Prices Per Bbl |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Type of |
|
|
|
|
|
|
|
|
|
Average Price |
|
|
|
|
September 30, |
|
|
December 31, |
|
Year |
|
Months |
|
Contract |
|
Bbls/d |
|
Swap |
|
Floor |
|
Ceiling |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Oil
Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
Oct - Dec |
|
Swap |
|
|
1,010 |
|
|
$ |
73.08 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(746 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
1,440 |
|
|
|
- |
|
|
|
69.58 |
|
|
|
82.29 |
|
|
|
(404 |
) |
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
2,200 |
|
|
|
- |
|
|
|
77.78 |
|
|
|
- |
|
|
|
297 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2010 |
|
|
4,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(853 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Jan - Mar |
|
Swap |
|
|
1,010 |
|
|
$ |
76.28 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(631 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
1,440 |
|
|
|
- |
|
|
|
73.06 |
|
|
|
95.41 |
|
|
|
99 |
|
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
2,200 |
|
|
|
- |
|
|
|
74.82 |
|
|
|
- |
|
|
|
711 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Mar 2011 |
|
|
4,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
179 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr - June |
|
Swap |
|
|
1,010 |
|
|
$ |
76.28 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(743 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
1,440 |
|
|
|
- |
|
|
|
73.06 |
|
|
|
95.41 |
|
|
|
32 |
|
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
2,200 |
|
|
|
- |
|
|
|
74.82 |
|
|
|
- |
|
|
|
1,008 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Apr - June 2011 |
|
|
4,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
297 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July - Sept |
|
Swap |
|
|
1,010 |
|
|
$ |
76.28 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(831 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
1,440 |
|
|
|
- |
|
|
|
73.06 |
|
|
|
95.41 |
|
|
|
(70 |
) |
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
2,200 |
|
|
|
- |
|
|
|
74.82 |
|
|
|
- |
|
|
|
1,226 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total July - Sept 2011 |
|
|
4,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
325 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec |
|
Swap |
|
|
1,010 |
|
|
$ |
76.28 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(904 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
1,440 |
|
|
|
- |
|
|
|
73.06 |
|
|
|
95.41 |
|
|
|
(180 |
) |
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
2,200 |
|
|
|
- |
|
|
|
74.82 |
|
|
|
- |
|
|
|
1,367 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2011 |
|
|
4,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
283 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
Jan - Dec |
|
Swap |
|
|
1,510 |
|
|
$ |
77.25 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5,398 |
) |
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
750 |
|
|
|
- |
|
|
|
68.33 |
|
|
|
81.12 |
|
|
|
(2,896 |
) |
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
1,510 |
|
|
|
- |
|
|
|
65.83 |
|
|
|
- |
|
|
|
2,728 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Dec 2012 |
|
|
3,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(5,566 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil Contracts - ENP
|
|
$ |
(5,335 |
) |
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Prices Per MMBtu |
|
|
Asset |
|
|
|
|
|
|
|
Type of |
|
|
|
|
|
|
|
|
|
Average Price |
|
|
|
|
September 30, |
|
|
December 31, |
|
Year |
|
Months |
|
Contract |
|
MMBtu/d |
|
Swap |
|
Floor |
|
Ceiling |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Natural Gas Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
Oct - Dec |
|
Swap |
|
|
6,002 |
|
|
$ |
6.17 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,351 |
|
|
$ |
- |
|
|
|
|
|
|
|
Collar |
|
|
3,800 |
|
|
|
- |
|
|
|
7.20 |
|
|
|
9.58 |
|
|
|
1,147 |
|
|
|
- |
|
|
|
|
|
|
|
Put |
|
|
4,698 |
|
|
|
- |
|
|
|
8.07 |
|
|
|
- |
|
|
|
1,803 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct - Dec 2010 |
|
|
14,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,301 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Jan - Dec |
|
Swap |
|
|
8,502 |
|
|
$ |
6.33 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
6,514 |
|
|
$ |
- |
|
|
|
|
|
|
|
Put |
|
|
3,398 |
|
|
|
- |
|
|
|
6.31 |
|
|
|
- |
|
|
|
2,569 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Dec 2011 |
|
|
11,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
9,083 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
Jan - Dec |
|
Swap |
|
|
6,002 |
|
|
$ |
6.22 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
3,191 |
|
|
$ |
- |
|
|
|
|
|
|
|
Put |
|
|
898 |
|
|
|
- |
|
|
|
6.76 |
|
|
|
- |
|
|
|
697 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Jan - Dec 2012 |
|
|
6,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,888 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Contracts - ENP
|
|
$ |
17,272 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Commodity Derivative Contracts - ENP
|
|
$ |
11,937 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2010, Denbury had $32.4 million of deferred premiums payable, which relate
to various oil and natural gas floor contracts and are payable on a monthly basis from October 2010
to January 2013. These premiums are excluded from the above tables.
Interest Rate Swaps
ENP uses derivative instruments in the form of interest rate swaps which hedge risk related to
interest rate fluctuation, whereby it converts the interest due on certain floating-rate debt under
its revolving credit agreement to a weighted average fixed rate. The following table summarizes
ENPs open interest rate swaps as of September 30, 2010, all of which were entered into with Bank
of America, N.A.:
|
|
|
|
|
|
|
|
|
|
|
|
|
Term |
|
Notional Amount |
|
Fixed Rate |
|
Floating Rate |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
October 2010 - Jan.
2011 |
|
$ |
50,000 |
|
|
|
3.1610 |
% |
|
1-month LIBOR |
October 2010 - Jan.
2011 |
|
|
25,000 |
|
|
|
2.9650 |
% |
|
1-month LIBOR |
October 2010 - Jan.
2011 |
|
|
25,000 |
|
|
|
2.9613 |
% |
|
1-month LIBOR |
October 2010 - Mar.
2012 |
|
|
50,000 |
|
|
|
2.4200 |
% |
|
1-month LIBOR |
28
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Additional Disclosures about Derivative Instruments
At September 30, 2010 and December 31, 2009, Denbury had derivative financial instruments
recorded in the accompanying Unaudited Condensed Consolidated Balance Sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
September 30, |
|
|
December 31, |
|
Type of Contract |
|
Balance Sheet Location |
|
2010 |
|
|
2009 |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative asset: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts |
|
Derivative assets - current |
|
$ |
16,380 |
|
|
$ |
309 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Derivative assets - current |
|
|
50,211 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts |
|
Derivative assets - long-term |
|
|
8,493 |
|
|
|
506 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Derivative assets - long-term |
|
|
24,631 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts |
|
Derivative liabilities - current |
|
|
(15,915 |
) |
|
|
(122,561 |
) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Derivative liabilities - current |
|
|
- |
|
|
|
(1,759 |
) |
|
|
|
|
|
|
|
|
|
|
|
Deferred premiums |
|
Derivative liabilities - current |
|
|
(23,296 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts |
|
Derivative liabilities - long-term |
|
|
(16,646 |
) |
|
|
(4,258 |
) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Derivative liabilities - long-term |
|
|
- |
|
|
|
(981 |
) |
|
|
|
|
|
|
|
|
|
|
|
Deferred premiums |
|
Derivative liabilities - long-term |
|
|
(9,126 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments |
|
|
|
|
34,732 |
|
|
|
(128,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps |
|
Derivative liabilities - current |
|
|
(1,924 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps |
|
Derivative liabilities - long-term |
|
|
(484 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments |
|
|
|
|
(2,408 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
|
|
$ |
32,324 |
|
|
$ |
(128,744 |
) |
|
|
|
|
|
|
|
29
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2010 and 2009, the net effect on income
of derivative instruments not designated as hedges was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss) |
|
Amount of Gain/(Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized in Income |
|
Recognized in Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain/(Loss) |
|
September 30, |
|
September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of Contract |
|
Recognized in Income |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Derivatives not designated as
hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts |
|
Derivatives income (expense) |
|
$ |
(66,040 |
) |
|
$ |
(2,323 |
) |
|
$ |
63,502 |
|
|
$ |
(159,664 |
) |
Natural gas contracts |
|
Derivatives income (expense) |
|
|
33,559 |
|
|
|
(1,434 |
) |
|
|
73,046 |
|
|
|
(17,397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as
hedging instruments |
|
$ |
(32,481 |
) |
|
$ |
(3,757 |
) |
|
$ |
136,548 |
|
|
$ |
(177,061 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7. 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). Denbury utilizes 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. Denbury primarily applies the market approach for recurring fair value measurements
and endeavors to utilize the best available information. Accordingly, Denbury utilizes valuation
techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
Denbury is able to classify fair value balances based on the observability of those inputs. The
FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.
The hierarchy gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable
inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
|
|
|
Level 1 Quoted prices in active markets for identical assets or liabilities as of the
reporting date. During 2009 and the first nine months of 2010, Denbury had no Level 1
recurring measurements. |
|
|
|
|
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. |
|
|
|
|
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.
|
30
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Denbury adjusts the valuations from the valuation model for nonperformance risk, using
managements estimate of the counterpartys credit quality for asset positions and Denburys credit
quality for liability positions. Denbury uses 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 Denburys financial
assets and liabilities that were accounted for at fair value on a recurring basis as of the dates
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 |
|
|
|
|
September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts |
|
$ |
- |
|
|
$ |
48,364 |
|
|
$ |
51,351 |
|
|
$ |
99,715 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts |
|
|
- |
|
|
|
(32,561 |
) |
|
|
- |
|
|
|
(32,561 |
) |
Interest rate swaps |
|
|
- |
|
|
|
(2,408 |
) |
|
|
- |
|
|
|
(2,408 |
) |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
- |
|
|
$ |
13,395 |
|
|
$ |
51,351 |
|
|
$ |
64,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
- |
|
|
$ |
815 |
|
|
$ |
- |
|
|
$ |
815 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts |
|
|
- |
|
|
|
(129,559 |
) |
|
|
- |
|
|
|
(129,559 |
) |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
- |
|
|
$ |
(128,744 |
) |
|
$ |
- |
|
|
$ |
(128,744 |
) |
|
|
|
|
|
|
|
|
|
31
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in the fair value of Denburys Level 3 assets and
liabilities for the nine months ended September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
Using Significant |
In thousands |
|
Unobservable Inputs (Level 3) |
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
- |
|
Included in earnings |
|
|
35,002 |
|
Commodity derivative contracts acquired in Encore Merger |
|
|
38,093 |
|
Receipts on settlement of commodity
derivative contracts |
|
|
(21,744 |
) |
|
|
|
Balance at September 30, 2010 |
|
$ |
51,351 |
|
|
|
|
|
|
|
|
|
The amount of total gains (losses) for the period included
in earnings attributable to the change in unrealized
gains (losses) relating to assets still held at the reporting date |
|
$ |
35,002 |
|
|
|
|
Since Denbury does not use hedge accounting for its commodity derivative contracts, all
gains and losses on its assets and liabilities are included in Derivatives expense (income) in
the accompanying Unaudited Condensed Consolidated Statements of Operations.
32
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth the carrying amount and estimated fair value of financial
instruments as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010 |
|
December 31, 2009 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
In thousands, except percentages |
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
|
$ |
99,715 |
|
|
$ |
99,715 |
|
|
$ |
815 |
|
|
$ |
815 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury Credit Agreement |
|
|
120,000 |
|
|
|
110,605 |
|
|
|
- |
|
|
|
- |
|
ENP Credit Agreement |
|
|
240,000 |
|
|
|
235,819 |
|
|
|
- |
|
|
|
- |
|
Senior bank loan (replaced with Denbury Credit Agreement) |
|
|
- |
|
|
|
- |
|
|
|
125,000 |
|
|
|
122,500 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
224,514 |
|
|
|
228,938 |
|
|
|
224,369 |
|
|
|
226,125 |
|
6.25% Senior Subordinated Notes due 2014 |
|
|
1,084 |
|
|
|
1,072 |
|
|
|
- |
|
|
|
- |
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,449 |
|
|
|
311,250 |
|
|
|
300,513 |
|
|
|
299,250 |
|
6.0% Senior Subordinated Notes due 2015 |
|
|
490 |
|
|
|
485 |
|
|
|
- |
|
|
|
- |
|
9.5% Senior Subordinated Notes due 2016 |
|
|
240,193 |
|
|
|
251,078 |
|
|
|
- |
|
|
|
- |
|
9.75% Senior Subordinated Notes due 2016 |
|
|
403,140 |
|
|
|
478,578 |
|
|
|
399,926 |
|
|
|
455,129 |
|
7.25% Senior Subordinated Notes due 2017 |
|
|
2,276 |
|
|
|
2,250 |
|
|
|
- |
|
|
|
- |
|
8.25% Senior Subordinated Notes due 2020 |
|
|
996,273 |
|
|
|
1,087,233 |
|
|
|
- |
|
|
|
- |
|
Commodity derivative contracts |
|
|
32,561 |
|
|
|
32,561 |
|
|
|
129,559 |
|
|
|
129,559 |
|
Deferred premiums on commodity
derivative contracts |
|
|
32,422 |
|
|
|
32,422 |
|
|
|
- |
|
|
|
- |
|
Interest rate swaps |
|
|
2,408 |
|
|
|
2,408 |
|
|
|
- |
|
|
|
- |
|
The book values of cash and cash equivalents, accrued production receivable, trade and
other receivables, net, and accounts payable and accrued liabilities approximate fair value due to
their short-term nature. The fair values of the senior subordinated notes were
determined using open market quotes. The difference between book value and fair value of the
senior subordinated notes represents the premium or discount on that date. The carrying values of
Denburys and ENPs revolving credit agreements approximate fair value since they are subject to short-term
floating interest rates that approximate the rates available to Denbury and ENP for those periods; however,
the estimated fair value has been adjusted for estimated nonperformance risk of approximately $13.6
million and $2.5 million at September 30, 2010 and December 31, 2009, respectively. The
nonperformance risk was determined utilizing industry credit default swaps. Commodity derivative
contracts and interest rate swaps are stated at fair
value in the accompanying Unaudited Condensed Consolidated Balance Sheets. Deferred premiums on
commodity derivative contracts were recorded at their fair value at the time they were acquired
from Encore, and Denbury accretes that value to the eventual settlement price by recording interest
expense each period.
Note 8. Income Taxes
Denburys effective tax rate has historically been slightly lower than its estimated statutory
rate due to the impact of certain items such as the domestic production activities deduction,
offset in part by certain non-cash stock-based compensation that cannot be deducted for tax
purposes in the same manner as book expense. As a result of the Encore Merger, Denburys statutory
rate increased, which required Denbury to remeasure its deferred tax liabilities resulting in an
additional income tax provision of approximately $10 million. As a result of the sale of the
Southern Assets, Denburys statutory rate decreased, which required Denbury to remeasure its
deferred tax liabilities resulting in an income tax benefit of approximately $3 million. The
combination of these items increased Denburys effective tax rate to 38.8% during the nine months
ended September 30, 2010.
33
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In the second 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
which led us to apply for refunds of certain amounts related thereto on our 2004 and 2006
federal income tax returns. In the course of an IRS audit of those refund claims, the IRS
examination team has questioned the change in accounting method and the ruling received from the
National Office of the IRS in 2008. Together with the IRS examination team, we have submitted a
request to the National Office of the IRS for a Technical Advice Memorandum (TAM) regarding these
issues, which is under consideration by the National Office. Although we have not recorded an
uncertain tax position related to these deductions as we expect to receive those tax refunds, given
the existence of the TAM process related to those refunds, the payment of those tax refunds of
approximately $10.6 million for tax years through 2006 is not free from doubt.
Note 9. Accounts Payable and Accrued Liabilities
The following table summarizes Denburys accounts payable and accrued liabilities as of the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
In thousands |
|
2010 |
|
2009 |
Accounts payable |
|
$ |
32,457 |
|
|
$ |
40,140 |
|
Accrued exploration and development costs |
|
|
122,006 |
|
|
|
40,375 |
|
Accrued compensation |
|
|
30,255 |
|
|
|
35,292 |
|
Accrued lease operating expense |
|
|
32,239 |
|
|
|
14,512 |
|
Accrued interest |
|
|
41,912 |
|
|
|
24,214 |
|
Taxes payable |
|
|
27,017 |
|
|
|
5,358 |
|
Other |
|
|
23,355 |
|
|
|
9,983 |
|
|
|
|
|
|
Total |
|
$ |
309,241 |
|
|
$ |
169,874 |
|
|
|
|
|
|
Note 10. Commitments and Contingencies
In conjunction with the Encore Merger, Denbury acquired certain commitments, including:
remaining outstanding principal and interest on the 6.5% Notes, the 6.0% Notes, the 9.5% Notes, and
the 7.25% Notes previously issued by Encore, derivative contracts, operating leases, and asset
retirement obligations. The Encore Merger is discussed in Note 3, asset retirement obligations are
discussed in Note 4, long-term debt is discussed in Note 5, and derivative contracts are discussed
in Notes 6 and 7. Operating leases assumed from Encore require payments of approximately $1.0
million in the remainder of 2010, $5.4 million in 2011 through 2012, and $1.8 million in 2013.
These amounts include a decrease of approximately $2.4 million during the third quarter of 2010, as
we exercised an early termination option for a portion of the office space leases acquired from
Encore. In addition, Denbury entered into a new lease for its corporate headquarters with a
12-year term that has total minimum monthly payments which aggregate approximately $64.3 million.
We are subject to audits in the various states in which we operate for sales and use taxes and
severance taxes, and from time to time receive assessments for potential taxes that we may owe. We
have received a $14.9 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 plan to appeal this assessment.
We do not believe the outcome of this matter will
have a material adverse impact on the Company.
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 or overall trends in 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.
34
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 11. Condensed Consolidating Financial Information
Denburys subordinated debt is fully and unconditionally guaranteed jointly and severally by
certain of its subsidiaries, except that with respect to Denburys $225 million of 7.5% Senior
Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors.
Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury
Onshore, LLC is a subsidiary guarantor. In the case of the 6.25% Notes, the 6% Notes, the 7.25%
Notes and the 9.5% Notes previously issued by Encore, Denbury is the sole issuer by virtue of the
fact that it is the successor in interest to Encore with respect to all such notes. Each
subsidiary guarantor and the subsidiary co-obligor are wholly-owned, directly or indirectly, by
Denbury Resources Inc.
All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses
between Denbury Resources Inc., Denbury Onshore, LLC, guarantor subsidiaries, and non-guarantor
subsidiaries are shown prior to consolidation with Denbury Resources Inc. and then eliminated to
arrive at consolidated totals per the accompanying Unaudited Condensed Consolidated Financial
Statements.
35
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010 |
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
17,308 |
|
|
$ |
51,865 |
|
|
$ |
6,889 |
|
|
$ |
10,283 |
|
|
$ |
- |
|
|
$ |
86,345 |
|
Other current assets |
|
|
202,293 |
|
|
|
193,107 |
|
|
|
976,622 |
|
|
|
32,999 |
|
|
|
(1,032,348 |
) |
|
|
372,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
219,601 |
|
|
|
244,972 |
|
|
|
983,511 |
|
|
|
43,282 |
|
|
|
(1,032,348 |
) |
|
|
459,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties (using full cost accounting): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
Proved |
|
|
- |
|
|
|
4,054,639 |
|
|
|
2,138,411 |
|
|
|
778,258 |
|
|
|
- |
|
|
|
6,971,308 |
|
Unevaluated |
|
|
- |
|
|
|
229,301 |
|
|
|
847,315 |
|
|
|
121,535 |
|
|
|
- |
|
|
|
1,198,151 |
|
CO2 properties, equipment, and pipelines |
|
|
- |
|
|
|
1,384,634 |
|
|
|
364,039 |
|
|
|
- |
|
|
|
- |
|
|
|
1,748,673 |
|
Other |
|
|
- |
|
|
|
94,810 |
|
|
|
10,300 |
|
|
|
490 |
|
|
|
- |
|
|
|
105,600 |
|
Less accumulated depletion, depreciation,
amortization, and impairment |
|
|
- |
|
|
|
(1,997,565 |
) |
|
|
(97,026 |
) |
|
|
(26,724 |
) |
|
|
- |
|
|
|
(2,121,315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment |
|
|
- |
|
|
|
3,765,819 |
|
|
|
3,263,039 |
|
|
|
873,559 |
|
|
|
- |
|
|
|
7,902,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other assets, net |
|
|
1,925,648 |
|
|
|
231,009 |
|
|
|
99,777 |
|
|
|
14,519 |
|
|
|
(789,185 |
) |
|
|
1,481,768 |
|
Investment in subsidiaries (equity method) |
|
|
4,302,576 |
|
|
|
- |
|
|
|
1,486,627 |
|
|
|
- |
|
|
|
(5,789,203 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
6,447,825 |
|
|
$ |
4,241,800 |
|
|
$ |
5,832,954 |
|
|
$ |
931,360 |
|
|
$ |
(7,610,736 |
) |
|
$ |
9,843,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
31,009 |
|
|
$ |
972,404 |
|
|
$ |
517,409 |
|
|
$ |
28,546 |
|
|
$ |
(1,032,348 |
) |
|
$ |
517,020 |
|
Long-term debt |
|
|
2,063,904 |
|
|
|
1,200,693 |
|
|
|
- |
|
|
|
240,000 |
|
|
|
(726,350 |
) |
|
|
2,778,247 |
|
Deferred taxes |
|
|
- |
|
|
|
621,030 |
|
|
|
976,950 |
|
|
|
726 |
|
|
|
(62,835 |
) |
|
|
1,535,871 |
|
Other liabilities |
|
|
- |
|
|
|
89,249 |
|
|
|
36,019 |
|
|
|
22,879 |
|
|
|
- |
|
|
|
148,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
2,094,913 |
|
|
|
2,883,376 |
|
|
|
1,530,378 |
|
|
|
292,151 |
|
|
|
(1,821,533 |
) |
|
|
4,979,285 |
|
Total equity |
|
|
4,352,912 |
|
|
|
1,358,424 |
|
|
|
4,302,576 |
|
|
|
639,209 |
|
|
|
(5,789,203 |
) |
|
|
4,863,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
6,447,825 |
|
|
$ |
4,241,800 |
|
|
$ |
5,832,954 |
|
|
$ |
931,360 |
|
|
$ |
(7,610,736 |
) |
|
$ |
9,843,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
24 |
|
|
$ |
20,281 |
|
|
$ |
286 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
20,591 |
|
Other current assets |
|
|
637,310 |
|
|
|
233,320 |
|
|
|
20,432 |
|
|
|
- |
|
|
|
(655,891 |
) |
|
|
235,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
637,334 |
|
|
|
253,601 |
|
|
|
20,718 |
|
|
|
- |
|
|
|
(655,891 |
) |
|
|
255,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties (using full cost accounting): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
- |
|
|
|
3,595,726 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,595,726 |
|
Unevaluated |
|
|
- |
|
|
|
320,356 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
320,356 |
|
CO2 properties, equipment, and pipelines |
|
|
- |
|
|
|
1,309,325 |
|
|
|
220,456 |
|
|
|
- |
|
|
|
- |
|
|
|
1,529,781 |
|
Other |
|
|
- |
|
|
|
82,185 |
|
|
|
352 |
|
|
|
- |
|
|
|
- |
|
|
|
82,537 |
|
Less accumulated depletion, depreciation,
amortization and impairment |
|
|
- |
|
|
|
(1,825,282 |
) |
|
|
(246 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,825,528 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment |
|
|
- |
|
|
|
3,482,310 |
|
|
|
220,562 |
|
|
|
- |
|
|
|
- |
|
|
|
3,702,872 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other assets, net |
|
|
746,442 |
|
|
|
225,938 |
|
|
|
6,078 |
|
|
|
- |
|
|
|
(742,131 |
) |
|
|
236,327 |
|
Investment in subsidiaries (equity method) |
|
|
1,303,728 |
|
|
|
23,792 |
|
|
|
1,299,186 |
|
|
|
- |
|
|
|
(2,551,689 |
) |
|
|
75,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,687,504 |
|
|
$ |
3,985,641 |
|
|
$ |
1,546,544 |
|
|
$ |
- |
|
|
$ |
(3,949,711 |
) |
|
$ |
4,269,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
14,827 |
|
|
$ |
795,486 |
|
|
$ |
239,368 |
|
|
$ |
- |
|
|
$ |
(655,891 |
) |
|
$ |
393,790 |
|
Long-term debt |
|
|
700,440 |
|
|
|
1,326,978 |
|
|
|
- |
|
|
|
- |
|
|
|
(726,350 |
) |
|
|
1,301,068 |
|
Deferred taxes |
|
|
- |
|
|
|
527,849 |
|
|
|
3,448 |
|
|
|
- |
|
|
|
(15,781 |
) |
|
|
515,516 |
|
Other liabilities |
|
|
- |
|
|
|
87,367 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
87,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
715,267 |
|
|
|
2,737,680 |
|
|
|
242,816 |
|
|
|
- |
|
|
|
(1,398,022 |
) |
|
|
2,297,741 |
|
Total equity |
|
|
1,972,237 |
|
|
|
1,247,961 |
|
|
|
1,303,728 |
|
|
|
- |
|
|
|
(2,551,689 |
) |
|
|
1,972,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
2,687,504 |
|
|
$ |
3,985,641 |
|
|
$ |
1,546,544 |
|
|
$ |
- |
|
|
$ |
(3,949,711 |
) |
|
$ |
4,269,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2010 |
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas, and related product sales |
|
$ |
- |
|
|
$ |
286,473 |
|
|
$ |
131,469 |
|
|
$ |
42,843 |
|
|
$ |
- |
|
|
$ |
460,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees |
|
|
- |
|
|
|
11,363 |
|
|
|
1,212 |
|
|
|
- |
|
|
|
(7,922 |
) |
|
|
4,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of interests in Genesis |
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
|
16,020 |
|
|
|
(326 |
) |
|
|
2,234 |
|
|
|
(643 |
) |
|
|
(16,017 |
) |
|
|
1,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
16,020 |
|
|
|
297,510 |
|
|
|
134,912 |
|
|
|
42,200 |
|
|
|
(23,939 |
) |
|
|
466,703 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
- |
|
|
|
100,816 |
|
|
|
27,887 |
|
|
|
9,607 |
|
|
|
(6,542 |
) |
|
|
131,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing |
|
|
- |
|
|
|
12,833 |
|
|
|
18,296 |
|
|
|
4,413 |
|
|
|
- |
|
|
|
35,542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating |
|
|
- |
|
|
|
3,250 |
|
|
|
618 |
|
|
|
- |
|
|
|
(1,380 |
) |
|
|
2,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
201 |
|
|
|
30,052 |
|
|
|
4,297 |
|
|
|
2,565 |
|
|
|
- |
|
|
|
37,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized |
|
|
49,180 |
|
|
|
25,621 |
|
|
|
(8,349 |
) |
|
|
2,896 |
|
|
|
(16,017 |
) |
|
|
53,331 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
- |
|
|
|
61,680 |
|
|
|
38,445 |
|
|
|
11,477 |
|
|
|
- |
|
|
|
111,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative income |
|
|
- |
|
|
|
21,001 |
|
|
|
3,900 |
|
|
|
6,953 |
|
|
|
- |
|
|
|
31,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transaction costs related to Encore Merger |
|
|
- |
|
|
|
741 |
|
|
|
10,477 |
|
|
|
252 |
|
|
|
- |
|
|
|
11,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
49,381 |
|
|
|
255,994 |
|
|
|
95,571 |
|
|
|
38,163 |
|
|
|
(23,939 |
) |
|
|
415,170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net earnings of subsidiaries |
|
|
(52,979 |
) |
|
|
- |
|
|
|
6,848 |
|
|
|
- |
|
|
|
46,131 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(86,340 |
) |
|
|
41,516 |
|
|
|
46,189 |
|
|
|
4,037 |
|
|
|
46,131 |
|
|
|
51,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
(13,257 |
) |
|
|
18,628 |
|
|
|
14,848 |
|
|
|
80 |
|
|
|
- |
|
|
|
20,299 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income (loss) |
|
|
(73,083 |
) |
|
|
22,888 |
|
|
|
31,341 |
|
|
|
3,957 |
|
|
|
46,131 |
|
|
|
31,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net Loss (Income) - noncontrolling interest |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,130 |
) |
|
|
- |
|
|
|
(2,130 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Denbury stockholders |
|
$ |
(73,083 |
) |
|
$ |
22,888 |
|
|
$ |
31,341 |
|
|
$ |
1,827 |
|
|
$ |
46,131 |
|
|
$ |
29,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas, and related product sales |
|
$ |
- |
|
|
$ |
221,321 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
221,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees |
|
|
- |
|
|
|
3,659 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
|
16,247 |
|
|
|
647 |
|
|
|
1,622 |
|
|
|
- |
|
|
|
(16,247 |
) |
|
|
2,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
16,247 |
|
|
|
225,627 |
|
|
|
1,622 |
|
|
|
- |
|
|
|
(16,247 |
) |
|
|
227,249 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
- |
|
|
|
83,300 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
83,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing |
|
|
- |
|
|
|
10,461 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating |
|
|
- |
|
|
|
1,047 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
42 |
|
|
|
19,350 |
|
|
|
4,646 |
|
|
|
- |
|
|
|
- |
|
|
|
24,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized |
|
|
17,721 |
|
|
|
10,972 |
|
|
|
(2,587 |
) |
|
|
- |
|
|
|
(16,247 |
) |
|
|
9,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
- |
|
|
|
53,525 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
53,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative expense |
|
|
- |
|
|
|
3,757 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,757 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
17,763 |
|
|
|
182,412 |
|
|
|
2,059 |
|
|
|
- |
|
|
|
(16,247 |
) |
|
|
185,987 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net earnings of subsidiaries |
|
|
28,401 |
|
|
|
- |
|
|
|
28,990 |
|
|
|
- |
|
|
|
(57,391 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
26,885 |
|
|
|
43,215 |
|
|
|
28,553 |
|
|
|
- |
|
|
|
(57,391 |
) |
|
|
41,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision |
|
|
- |
|
|
|
14,225 |
|
|
|
152 |
|
|
|
- |
|
|
|
- |
|
|
|
14,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income |
|
$ |
26,885 |
|
|
$ |
28,990 |
|
|
$ |
28,401 |
|
|
$ |
- |
|
|
$ |
(57,391 |
) |
|
$ |
26,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas, and related product sales |
|
$ |
- |
|
|
$ |
844,516 |
|
|
$ |
335,047 |
|
|
$ |
100,136 |
|
|
$ |
- |
|
|
$ |
1,279,699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees |
|
|
- |
|
|
|
20,550 |
|
|
|
1,212 |
|
|
|
- |
|
|
|
(7,922 |
) |
|
|
13,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of interests in Genesis |
|
|
- |
|
|
|
(227 |
) |
|
|
101,764 |
|
|
|
- |
|
|
|
- |
|
|
|
101,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
|
48,285 |
|
|
|
3,309 |
|
|
|
4,089 |
|
|
|
27 |
|
|
|
(48,052 |
) |
|
|
7,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
48,285 |
|
|
|
868,148 |
|
|
|
442,112 |
|
|
|
100,163 |
|
|
|
(55,974 |
) |
|
|
1,402,734 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
- |
|
|
|
277,175 |
|
|
|
62,231 |
|
|
|
22,867 |
|
|
|
(6,542 |
) |
|
|
355,731 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing |
|
|
- |
|
|
|
37,715 |
|
|
|
44,766 |
|
|
|
10,478 |
|
|
|
- |
|
|
|
92,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating |
|
|
- |
|
|
|
6,299 |
|
|
|
618 |
|
|
|
- |
|
|
|
(1,380 |
) |
|
|
5,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
524 |
|
|
|
80,743 |
|
|
|
12,960 |
|
|
|
6,789 |
|
|
|
- |
|
|
|
101,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized |
|
|
134,803 |
|
|
|
55,635 |
|
|
|
(26,026 |
) |
|
|
6,870 |
|
|
|
(48,052 |
) |
|
|
123,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
- |
|
|
|
198,327 |
|
|
|
96,951 |
|
|
|
27,405 |
|
|
|
- |
|
|
|
322,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative income |
|
|
- |
|
|
|
(92,849 |
) |
|
|
(31,109 |
) |
|
|
(14,087 |
) |
|
|
- |
|
|
|
(138,045 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transaction costs related to Encore Merger |
|
|
- |
|
|
|
46,675 |
|
|
|
31,388 |
|
|
|
1,190 |
|
|
|
- |
|
|
|
79,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
135,327 |
|
|
|
609,720 |
|
|
|
191,779 |
|
|
|
61,512 |
|
|
|
(55,974 |
) |
|
|
942,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net earnings of subsidiaries |
|
|
211,995 |
|
|
|
- |
|
|
|
110,121 |
|
|
|
- |
|
|
|
(322,116 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
124,953 |
|
|
|
258,428 |
|
|
|
360,454 |
|
|
|
38,651 |
|
|
|
(322,116 |
) |
|
|
460,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
(34,218 |
) |
|
|
148,307 |
|
|
|
64,182 |
|
|
|
332 |
|
|
|
- |
|
|
|
178,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income |
|
|
159,171 |
|
|
|
110,121 |
|
|
|
296,272 |
|
|
|
38,319 |
|
|
|
(322,116 |
) |
|
|
281,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net Loss (Income) - noncontrolling interest |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(20,408 |
) |
|
|
- |
|
|
|
(20,408 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Denbury stockholders |
|
$ |
159,171 |
|
|
$ |
110,121 |
|
|
$ |
296,272 |
|
|
$ |
17,911 |
|
|
$ |
(322,116 |
) |
|
$ |
261,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas, and related product sales |
|
$ |
- |
|
|
$ |
600,942 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
600,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees |
|
|
- |
|
|
|
9,708 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
|
42,967 |
|
|
|
2,575 |
|
|
|
5,175 |
|
|
|
- |
|
|
|
(42,967 |
) |
|
|
7,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
42,967 |
|
|
|
613,225 |
|
|
|
5,175 |
|
|
|
- |
|
|
|
(42,967 |
) |
|
|
618,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
- |
|
|
|
241,908 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
241,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing |
|
|
- |
|
|
|
30,437 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
30,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating |
|
|
- |
|
|
|
3,442 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
124 |
|
|
|
67,311 |
|
|
|
12,393 |
|
|
|
- |
|
|
|
- |
|
|
|
79,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized |
|
|
46,692 |
|
|
|
38,295 |
|
|
|
(5,060 |
) |
|
|
- |
|
|
|
(42,967 |
) |
|
|
36,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
- |
|
|
|
177,145 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
177,145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative expense |
|
|
- |
|
|
|
177,061 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
177,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
46,816 |
|
|
|
735,599 |
|
|
|
7,333 |
|
|
|
- |
|
|
|
(42,967 |
) |
|
|
746,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net earnings of subsidiaries |
|
|
(74,803 |
) |
|
|
- |
|
|
|
(72,354 |
) |
|
|
- |
|
|
|
147,157 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
|
(78,652 |
) |
|
|
(122,374 |
) |
|
|
(74,512 |
) |
|
|
- |
|
|
|
147,157 |
|
|
|
(128,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
- |
|
|
|
(50,020 |
) |
|
|
291 |
|
|
|
- |
|
|
|
- |
|
|
|
(49,729 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net loss |
|
$ |
(78,652 |
) |
|
$ |
(72,354 |
) |
|
$ |
(74,803 |
) |
|
$ |
- |
|
|
$ |
147,157 |
|
|
$ |
(78,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
38
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) operating activities |
|
$ |
(72,204 |
) |
|
$ |
610,474 |
|
|
$ |
(445,257 |
) |
|
$ |
66,510 |
|
|
$ |
433,252 |
|
|
$ |
592,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures |
|
|
- |
|
|
|
(315,256 |
) |
|
|
(181,628 |
) |
|
|
(3,178 |
) |
|
|
- |
|
|
|
(500,062 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
|
- |
|
|
|
(24,277 |
) |
|
|
167 |
|
|
|
(280 |
) |
|
|
- |
|
|
|
(24,390 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid in the Encore Merger, net of cash acquired |
|
|
(830,309 |
) |
|
|
- |
|
|
|
3,299 |
|
|
|
13,116 |
|
|
|
- |
|
|
|
(813,894 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 capital expenditures, including pipelines |
|
|
- |
|
|
|
(118,101 |
) |
|
|
(118,384 |
) |
|
|
- |
|
|
|
- |
|
|
|
(236,485 |
) |
Net proceeds from sale of oil and natural gas
properties and equipment |
|
|
- |
|
|
|
(2,675 |
) |
|
|
912,661 |
|
|
|
- |
|
|
|
- |
|
|
|
909,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from sale of interests in Genesis |
|
|
- |
|
|
|
23,537 |
|
|
|
139,082 |
|
|
|
- |
|
|
|
- |
|
|
|
162,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries (equity method) |
|
|
479,540 |
|
|
|
- |
|
|
|
(48,914 |
) |
|
|
- |
|
|
|
(430,626 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
- |
|
|
|
(17,732 |
) |
|
|
(70 |
) |
|
|
(125 |
) |
|
|
- |
|
|
|
(17,927 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) investing activities |
|
|
(350,769 |
) |
|
|
(454,504 |
) |
|
|
706,213 |
|
|
|
9,533 |
|
|
|
(430,626 |
) |
|
|
(520,153 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(879,000 |
) |
|
|
(350,000 |
) |
|
|
(265,000 |
) |
|
|
(25,000 |
) |
|
|
- |
|
|
|
(1,519,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank borrowings |
|
|
999,000 |
|
|
|
225,000 |
|
|
|
- |
|
|
|
5,000 |
|
|
|
- |
|
|
|
1,229,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior subordinated notes tendered post Encore Merger |
|
|
(616,637 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(616,637 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of senior subordinated debt |
|
|
1,000,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,000,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of debt financing |
|
|
(76,232 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(76,232 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
13,126 |
|
|
|
614 |
|
|
|
10,647 |
|
|
|
(45,760 |
) |
|
|
(2,626 |
) |
|
|
(23,999 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) financing activities |
|
|
440,257 |
|
|
|
(124,386 |
) |
|
|
(254,353 |
) |
|
|
(65,760 |
) |
|
|
(2,626 |
) |
|
|
(6,868 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
17,284 |
|
|
|
31,584 |
|
|
|
6,603 |
|
|
|
10,283 |
|
|
|
- |
|
|
|
65,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
24 |
|
|
|
20,281 |
|
|
|
286 |
|
|
|
- |
|
|
|
- |
|
|
|
20,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
17,308 |
|
|
$ |
51,865 |
|
|
$ |
6,889 |
|
|
$ |
10,283 |
|
|
$ |
- |
|
|
$ |
86,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury |
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent and |
|
(Issuer and |
|
Guarantor |
|
Non-Guarantor |
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Co-Obligor) |
|
Co-Obligor) |
|
Subsidiaries |
|
Subsidiaries |
|
Eliminations |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
- |
|
|
$ |
406,192 |
|
|
$ |
242 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
406,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures |
|
|
- |
|
|
|
(289,815 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(289,815 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
|
- |
|
|
|
(197,534 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(197,534 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 capital expenditures, including pipelines |
|
|
- |
|
|
|
(543,536 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(543,536 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from sales of oil and gas properties and equipment |
|
|
- |
|
|
|
303,450 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
303,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries (equity method) |
|
|
(409,293 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
409,293 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
- |
|
|
|
(8,955 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(8,955 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(409,293 |
) |
|
|
(736,390 |
) |
|
|
- |
|
|
|
- |
|
|
|
409,293 |
|
|
|
(736,390 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
- |
|
|
|
(606,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(606,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank borrowings |
|
|
- |
|
|
|
551,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
551,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of senior subordinated debt |
|
|
389,827 |
|
|
|
389,827 |
|
|
|
- |
|
|
|
- |
|
|
|
(389,827 |
) |
|
|
389,827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net equity contributions |
|
|
10,346 |
|
|
|
10,346 |
|
|
|
- |
|
|
|
- |
|
|
|
(10,346 |
) |
|
|
10,346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
9,120 |
|
|
|
(10,597 |
) |
|
|
- |
|
|
|
- |
|
|
|
(9,120 |
) |
|
|
(10,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
409,293 |
|
|
|
334,576 |
|
|
|
- |
|
|
|
- |
|
|
|
(409,293 |
) |
|
|
334,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
- |
|
|
|
4,378 |
|
|
|
242 |
|
|
|
- |
|
|
|
- |
|
|
|
4,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
24 |
|
|
|
16,898 |
|
|
|
147 |
|
|
|
- |
|
|
|
- |
|
|
|
17,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
24 |
|
|
$ |
21,276 |
|
|
$ |
389 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
21,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 12. Encore Energy Partners LP
Administrative Services Agreement
ENP does not have any employees. The employees supporting ENPs operations are employees of
Denbury. Encore Operating, L.P. (Encore Operating), a subsidiary of Denbury, performs
administrative services for ENP, such as accounting, corporate development, finance, land, legal,
and engineering, pursuant to an administrative
services agreement. In addition, Encore Operating provides all personnel, facilities, goods,
and equipment necessary to perform these services which are not otherwise provided for by ENP.
Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement
unless its acts or omissions constitute gross negligence or willful misconduct.
39
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
From March 9, 2010 to March 31, 2010, the administrative fee was $2.02 per BOE of ENPs
production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENPs
production as a result of the COPAS Wage Index Adjustment which occurs every April 1st.
ENP also reimburses Encore Operating for actual third-party expenses incurred on ENPs behalf.
Encore Operating has substantial discretion in determining which third-party expenses to incur on
ENPs behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges
associated with drilling and operating wells that would otherwise be paid by non-operating interest
owners to the operator.
The administrative fee will increase in the following circumstances:
|
|
|
beginning on the first day of April in each year by an amount equal to the product
of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment
for that year; |
|
|
|
if ENP acquires additional assets, Encore Operating may propose an increase in its
administrative fee that covers the provision of services for such additional assets;
however, such proposal must be approved by the board of directors of GP LLC upon the
recommendation of its conflicts committee; and |
|
|
|
otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the
conflicts committee of the board of directors of GP LLC. |
ENP reimburses Denbury for any state, income, franchise, or similar tax incurred by Denbury
resulting from the inclusion of ENP in consolidated tax returns with Denbury as required by
applicable law. The amount of any such reimbursement is limited to the tax that ENP would have
incurred had they not been included in a combined group with Denbury.
Strategic Alternatives for ENP
On September 12, 2010, Denbury and ENP announced that the previously announced consideration
of an asset transaction between Denbury and ENP regarding Elk Basin Field had been terminated. This
process had been initiated in light of the substantial future capital requirements to flood that
field as a possible CO2 tertiary project. No agreement could be reached on the value of
the potential tertiary reserves. Denbury remains focused on its previously announced intent to
sell its interest in ENPs general partner and all or part of the ENP common units that Denbury
owns. There is no assurance of completion of any transaction.
Note 13. Subsequent Events
Acquisition of Reserves in Rocky Mountain region at Riley Ridge
On October 15, 2010, Denbury acquired a 42.5% non-operated working interest in the 9,700 acre
Riley Ridge Federal Unit located in the LaBarge Field of southwestern Wyoming, a significant
natural source of CO2 as well as natural gas and helium, for consideration of $124.3
million after closing adjustments. The acquisition also includes approximately 33% of the
CO2 rights in an additional 28,000 acres adjoining the Riley Ridge Unit.
Sale of Haynesville and East Texas Natural Gas Properties
On October 8, 2010, Denbury entered into an agreement to sell its Haynesville and East Texas
natural gas properties to a private company for consideration of $217.5 million before closing
adjustments. The effective date of the sale will be September 1, 2010, and is expected to close by
early December of 2010.
ENP Distribution
On October 28, 2010, the board of directors of GP LLC declared an ENP cash distribution for
the third quarter of 2010 to unitholders of record as of the close of business on November 8, 2010
of $0.50 per unit or approximately $22.9 million of which $10.7 million is expected to be paid to
GP LLC and its affiliates. The distribution is expected to be paid to unitholders on or about
November 12, 2010.
40
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, 2009, 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 operator 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
Rockies and Gulf Coast regions. Our goal is to increase the value of our acquired properties
through a combination of exploitation, drilling, and proven engineering extraction practices, with
our most significant emphasis relating to tertiary recovery operations.
Third quarter operating highlights. The acquisition of Encore in March 2010
(Encore Merger) has had a significant impact on nearly every aspect of our business, including
oil and natural gas production, revenues and operating expenses, which is more fully discussed
throughout our discussion and analysis of financial condition and results of operations below. We
recognized net income of $29.1 million, or $0.07 per basic common share, during the third quarter
of 2010 as compared to net income of $26.9 million, or $0.11 per basic common share, during the
third quarter of 2009. This increase is primarily attributable to higher production revenues due
to increased volumes attributable to the Encore properties as well as increased tertiary production
offset by higher non-cash fair value derivative expenses, higher interest expense, and Encore
merger-related expenses (principally severance).
During the third quarter of 2010, our oil and natural gas production averaged 77,730
BOE/d compared to 42,659 BOE/d produced during the third quarter of 2009. This 35,071 BOE/d of
additional production is attributable to (1) properties acquired in the Encore Merger, which
contributed average production of 33,605 BOE/d during the quarter, (2) tertiary production
increasing 5,184 Bbls/d between the two quarters, and (3) the December 2009 acquisition of the
Conroe field which contributed average production of 2,745 BOE/d. Offsetting these production
increases was a decrease of 4,948 BOE/d due to the December 2009 sale of our remaining 40% of our
Barnett Shale properties. See Results of Operations Operating Results Production for more
information.
Tertiary oil production averaged 29,531 Bbls/d during the third quarter of 2010, representing
a 21% increase over our average tertiary oil production of 24,347 Bbls/d during the third quarter
of 2009. We had strong production increases during the third quarter of 2010 from several of our
existing tertiary oil fields, including the Tinsley Field, where production increased
2,466 Bbls/d between the comparable periods. See Results of Operations CO2 Operations
for more information.
Oil
prices during the third quarter of 2010 were higher than during the third
quarter of 2009. Our average
oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was
$64.44 per BOE during the third quarter of 2010, as compared to $56.39 per BOE during the third
quarter of 2009, a 14% increase between the two periods. Including the impact of our commodity
derivative contracts, our average oil and natural gas price
per BOE increased to
$65.84 per BOE during the third quarter of 2010, as compared to $61.11 per BOE during the third
quarter of 2009.
Net cash settlements received on our commodity derivative contracts during the third quarter
of 2010 were $10.0 million, compared to $18.5 million of cash settlements received during the third
quarter of 2009. During the third quarter of 2010, we had a non-cash fair value loss on our
commodity derivative contracts of $42.5 million, compared to a non-cash fair value loss of
$22.3 million during the third quarter of 2009. Together these cash settlements and non-cash fair-value losses lowered our pretax income by $28.1 million more during
the third quarter of 2010 than in the third quarter of 2009.
41
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Our lease operating expenses increased 58% ($48.5 million) during the third quarter of 2010 on
an absolute basis, but decreased 13% on a per BOE basis when compared
to levels in the third quarter of 2009. The increase on an absolute basis is
primarily due to the March 2010 Encore Merger and further expansion of our tertiary operations,
partially offset by the effect of our December 2009 sale of our remaining 40% of our Barnett Shale
properties. The decrease on a per BOE basis is primarily due to the
Encore Merger, as the assets acquired have a lower production cost
per BOE than Denburys legacy assets.
General and administrative (G&A) expenses totaled $37.1 million during the third quarter of
2010, compared to $24.0 million during the prior year quarter, principally due to incremental
administrative expense from the ownership of Encore offset by the $3.6 million incentive
compensation expense for management of Genesis incurred in the prior year quarter. During the
quarter, we incurred $11.5 million of transaction costs associated with the Encore Merger,
primarily associated with employee severance. These Encore Merger related fees are included in our
income statement under the caption Transaction costs and other related to the Encore Merger.
Interest expense also increased during the third quarter of 2010, due primarily to our $1.0 billion
issuance of 2020 Notes in February 2010, Encore debt assumed in the Encore Merger, and $10.0
million less interest capitalization.
Merger with Encore Acquisition Company. On March 9, 2010, we acquired Encore pursuant to an
Agreement and Plan of Merger (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 $4.5 billion at that time, including the assumption of debt and the value of the
noncontrolling interest in ENP. Under the Encore Merger Agreement, Encore was merged with and into
Denbury, with Denbury surviving the Encore Merger. The Encore Merger was consummated on March 9,
2010.
In the Encore Merger, we issued approximately 135.2 million shares of our common stock and
paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares issued to
Encore stockholders represented approximately 34% of our common stock issued and outstanding
immediately after the Encore Merger. The total fair value of the Denbury common stock issued to
Encore stockholders pursuant to the Encore Merger was approximately $2.1 billion based upon
Denburys closing price of $15.43 per share on March 9, 2010. See Note 3, Acquisitions and
Divestitures, for additional information.
The Encore Merger was financed through a combination of $1.0 billion of 8.25% Senior
Subordinated Notes due 2020, (the 2020 Notes), which we issued on February 10, 2010, the new $1.6
billion revolving credit agreement (the Credit Agreement) entered into on March 9, 2010, and the
assumption of Encores remaining outstanding senior subordinated notes.
Pursuant to our intent of divesting non-strategic legacy Encore properties, certain oil and
gas properties in the Permian Basin, Mid-continent area, and East Texas Basin (collectively, the
Southern Assets) and the Cleveland Sand Play were sold during the second and third quarters of
2010. In addition, we expect to close on the sale of the Haynesville and East Texas natural gas
properties during the fourth quarter of 2010. See Note 3, Acquisitions and Divestitures, to the
Unaudited Condensed Consolidated Financial Statements for further discussion of these transactions.
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
southwestern Wyoming, together with approximately 33% of the CO2 rights in an additional
28,000 acres adjoining Riley Ridge, for consideration of $124.3 million after closing adjustments.
This acquisition was funded with borrowings on our bank
credit agreement.
We estimate Riley Ridge contains approximately 185 Bcf of natural gas, 6.6 Bcf of helium and
approximately 1.0 Tcf of CO2, net to our interest to be acquired. The additional 28,000
acres is estimated to contain an additional 1.0 Tcf of probable CO2 reserves, net to our
interest. The first production of natural gas and helium from Riley Ridge is expected to occur
in late 2011 after completing construction of the processing facilities to separate the natural gas
and helium. The net development costs to our interest are expected to be approximately $24 million
during 2010 and $32 million in 2011, and are primarily associated with constructing the processing
facilities that will separate the natural gas and helium.
42
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The full well stream at Riley Ridge is expected to contain approximately 65% CO2,
19% natural gas, 10% H2S and 0.6% helium and other gases. Currently, the operator plans
to re-inject the CO2 and H2S, however, we have the right to separate and take
the CO2 and re-inject the H2S. At this time, we are evaluating other
potential CO2 sources in the region, and therefore, we do not have a definitive
development timetable for these CO2 reserves.
Completion of Green Pipeline to Oyster Bayou. On June 29, 2010, Denbury placed the first
phase (approximately 260 miles) of the Green Pipeline, a 320-mile CO2 pipeline that runs
from southern Louisiana to near Houston, Texas, in service. This phase runs to Denburys Oyster
Bayou Field in Southeast Texas while the remaining portion, scheduled for completion in December
2010, will service Denburys Hastings Field west of Galveston Bay. The Green pipeline is designed
to transport both natural and anthropogenic CO2 and will ultimately service other
tertiary operations along the Gulf Coast.
Strategic alternatives for ENP. In September 2010, Denbury and ENP announced that the
previously announced consideration of an asset transaction between Denbury and ENP regarding Elk Basin
Field had been terminated. This process had been initiated in light of the substantial future
capital requirements to flood that field as a possible CO2 tertiary project. No
agreement could be reached on the value of the potential tertiary reserves. Denbury remains
focused on its previously announced intent to sell its interest in ENPs general partner and all or
part of the ENP common units that Denbury owns. There is no assurance
of completion of any transaction.
Capital Resources and Liquidity
We currently estimate our pro forma 2010 capital spending (including Encores $46 million of
capital expenditures between January 1, 2010 and March 9, 2010) will be approximately $1.06
billion, excluding capitalized interest, acquisitions, and divestitures, and net of equipment
leases, and also excluding the expenditures related to the Encore Merger. Our current 2010 capital
budget includes the following:
|
|
|
$413 million allocated for tertiary oil field expenditures; |
|
|
|
|
$193 million to be spent on our CO2 pipelines; |
|
|
|
|
$200 million to drill or participate in drilling or refracing of 55 to 75 wells in the
Bakken area of North Dakota; |
|
|
|
|
$115 million on drilling, completion and other development activities in our other
areas; |
|
|
|
|
$65 million to drill and complete 6 to 8 operated wells and participate in 20 to 25
non-operated wells in the Haynesville and other East Texas fields; and |
|
|
|
|
$74 million to be spent in the Jackson Dome area. |
This estimate also assumes that we fund approximately $50 million of budgeted equipment
purchases with operating leases, which is dependent upon securing acceptable financing. If we do
not enter into a total of $50 million of operating leases during 2010, our net capital expenditures
would increase in an equal amount, and we would anticipate funding those additional capital
expenditures under our Credit Agreement.
Based on oil and natural gas commodity futures prices in early November 2010 and our current
estimated production forecasts, excluding acquisition costs, our pro forma 2010 capital budget (including Encores $46 million of capital
expenditures from January 1, 2010 through March 9, 2010) is $200 million to $300 million greater
than our anticipated cash flow from operations assuming a full year of operations of the combined
companies. This shortfall has been funded to-date with borrowings under our Credit Agreement, and
we have significant borrowing capacity to fund any remaining shortfall in the fourth quarter. The
outstanding borrowings under our Credit Agreement have been substantially reduced already during
the course of the year by repayments made with the cash generated from the sales of our interests
in Genesis and the Southern Assets (see Note 3, Acquisitions and Divestitures, to the Unaudited
Condensed Consolidated Financial Statements).
We preliminarily anticipate that our capital expenditure budget for 2011 will be
in the same range as our 2010 capital budget. Although this amount is currently expected
to be $100 to $200 million higher
than our 2011 forecasted cash flows from operations, we anticipate that our planned sale of our
Haynesville and East Texas assets and any proceeds received from a sale of our interest in ENP (see Overview Strategic
alternatives for ENP above) would offset our capital spending in excess of cash flows in 2010 and
2011.
43
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
As mentioned above, we funded the Riley Ridge acquisition with funds drawn under our Credit
Agreement, and we plan to reduce our outstanding borrowings under our Credit Agreement
(approximately $225.0 million as of November 8, 2010) with the proceeds from the pending sale of
the Haynesville and East Texas natural gas assets (approximately
$217.5 million before closing adjustments). See Note 3, Acquisitions and Divestitures, to
the Unaudited Condensed Consolidated Financial Statements for more
information on these transactions.
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 reduce our anticipated production levels in future years. For 2010, we have
contracted for certain capital expenditures, including construction of the second phase of the
Green Pipeline already in progress and several drilling rigs, and therefore we cannot eliminate all
of our capital commitments without penalties (refer to Off-Balance
Sheet Arrangements Commitments
and Obligations for further information regarding these commitments).
Capital Expenditure Summary. The following table of capital expenditures includes accrued
capital for the nine month periods of 2009 and 2010. Our cash expenditures were $13.9 million
lower in the 2010 period and $54.8 million higher in the 2009 period than the amounts listed below
due to the change in our capital accruals in those periods:
44
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
In thousands |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas exploration and development: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
242,302 |
|
|
$ |
41,150 |
|
|
|
|
|
|
|
|
|
|
Geological, geophysical, and acreage |
|
|
23,381 |
|
|
|
10,713 |
|
|
|
|
|
|
|
|
|
|
Facilities |
|
|
99,797 |
|
|
|
136,556 |
|
|
|
|
|
|
|
|
|
|
Recompletions |
|
|
136,357 |
|
|
|
56,251 |
|
|
|
|
|
|
|
|
|
|
Capitalized interest |
|
|
23,672 |
|
|
|
10,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas exploration and development expenditures |
|
|
525,509 |
|
|
|
255,110 |
|
|
|
|
|
|
|
|
|
|
CO2 capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
143,856 |
|
|
|
456,590 |
|
|
|
|
|
|
|
|
|
|
CO2 producing fields |
|
|
61,509 |
|
|
|
28,562 |
|
|
|
|
|
|
|
|
|
|
Capitalized interest |
|
|
32,407 |
|
|
|
38,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
CO2 capital expenditures |
|
|
237,772 |
|
|
|
523,411 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures without acquisitions |
|
|
763,281 |
|
|
|
778,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas property acquisitions |
|
|
24,390 |
|
|
|
197,534 |
|
|
|
|
|
|
|
|
|
|
Fair value assigned to oil and natural gas properties acquired from Encore |
|
|
5,636,817 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Fair value
assigned to
CO2 assets acquired from Encore |
|
|
7,254 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
6,431,742 |
|
|
$ |
976,055 |
|
|
|
|
|
|
Our capital expenditures for the first nine months of 2010, excluding the Encore Merger, were
funded with $592.8 million of cash flow from operations, along with net proceeds of approximately
$163 million from the sale of our interests
in Genesis, approximately $884 million
from the Southern Assets sale, and $32 million from the Cleveland Sand Play assets sale. See
Overview Merger with Encore Acquisition Company for a discussion of the financing of the Encore
Merger. Our capital expenditures for the first nine months of 2009 were funded with $406.4 million
of cash flow from operations, $259.8 million of net proceeds from the sale of a portion of our
Barnett Shale natural gas assets, and $381.4 million of proceeds from the February 2009 issuance of
the 9.75% Senior Subordinated Notes.
As discussed above in Overview Merger with Encore Acquisition Company, the primary sources
of cash for the Encore Merger were (1) our new $1.6 billion Credit Agreement, which replaced our
previously existing $750 million commitment from banks under our prior revolving credit agreement,
and (2) $1.0 billion of new 2020 Notes. We structured the financing of the Encore Merger to
provide $600 million to $700 million of availability under the new Credit Agreement upon closing
the transaction in order to provide a level of liquidity similar to that available to us prior to
the Encore Merger.
The amounts shown above for the Encore Merger include approximately $2.1 billion of our common
stock issued to Encore stockholders in the Encore Merger, based upon 135.2 million shares valued at
the closing price of $15.43 per share on March 9, 2010, and approximately $1.1 billion of the total
Encore Merger consideration which was assigned to goodwill. See Note 3 to the Unaudited Condensed
Consolidated Financial Statements for additional information regarding the Encore Merger.
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 6 and 7 to the Unaudited Condensed
Consolidated Financial Statements.
45
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
In conjunction with the Encore Merger, we acquired certain of Encores commitments including:
senior subordinated notes, derivative contracts, operating leases, and asset retirement
obligations. The Encore Merger is discussed in Note 3 to the Unaudited Condensed Consolidated
Financial Statements, asset retirement obligations are discussed in Note 4 to the Unaudited
Condensed Consolidated Financial Statements, long-term debt is discussed in Note 5 to the Unaudited
Condensed Consolidated Financial Statements, and derivative contracts are discussed in Notes 6 and
7 to the Unaudited Condensed Consolidated Financial Statements. Operating leases assumed in the
Encore Merger require payments of approximately $1.0 million in the remainder of 2010, $5.4 million
in 2011 through 2012, and $1.8 million in 2013. In addition, we have entered into a new lease for
our corporate headquarters with a 12-year term that has total minimum monthly payments which
aggregate approximately $64.3 million. Please refer to Managements Discussion and Analysis of
Financial Condition and Results of Operations and the section entitled Off-Balance Sheet
Arrangements Commitments and Obligations contained in our Annual Report on Form 10-K for the year
ended December 31, 2009 for further information regarding our commitments and obligations.
Results of Operations
CO2 Operations
Our focus on CO2 operations is becoming an ever-increasing part 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, 2009
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, 2009 for further information regarding these matters.
During 2010, we drilled three additional wells in the Jackson Dome area in order to
increase
CO2 deliverability and proved reserves. Two wells were drilled in the
Gluckstadt Field and the third well was drilled on the DRI Dock prospect. Based on the results of
testing and production associated with these three wells and the recently completed 3D seismic
evaluation of the DRI Dock prospect, our total proven CO2 reserve additions at the
Jackson Dome area during 2010 now total 1.0 Tcf. Additionally, we have acquired a significant
natural source of CO2 in the Rocky Mountain region at Riley Ridge in an acquisition that
closed in October 2010, which has approximately 1.0 Tcf of proved and 1.0 Tcf of probable CO2
reserves, net to our interest. See Acquisition of reserves in Rocky Mountain region at Riley
Ridge above.
During the third quarter of 2010, our CO2 production at Jackson Dome averaged 864
MMcf/d as compared to an average of 629 MMcf/d produced during the third quarter of 2009 and 768
MMcf/d produced during the second quarter of 2010. We used 87% of this production, or 748 MMcf/d,
in our tertiary operations during the third quarter of 2010, and sold the balance to our industrial
customers, or to Genesis pursuant to our volumetric production payments. During June 2010, we
placed in service the first phase (approximately 260 miles) of the Green Pipeline, a 320-mile
CO2 pipeline that runs from southern Louisiana to near Houston, Texas. This first phase
runs to our Oyster Bayou field in Southeast Texas. We filled this pipeline with CO2
from our source at Jackson Dome during June and commenced first injection of CO2 at the
Oyster Bayou field on June 29, 2010. Consequently, our CO2 production at Jackson Dome
was higher this quarter compared to levels in the second quarter of 2010. Refer to 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, 2009 for further discussion on our CO2
delivery obligations.
We spent approximately $0.21 per Mcf in operating expenses to produce our
CO2 during the first nine months of 2010, comprised of $0.20 per Mcf during the
first quarter of 2010, $0.22 per Mcf during the second quarter of 2010, and $0.21 during the third
quarter of 2010. This rate is up significantly from our $0.16 per Mcf cost during the first nine
months of 2009, due primarily to increased CO2 royalty expense as a result of higher oil
prices.
46
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 2009 and the first, second, and third quarters of 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary Oil Field |
|
2009 |
|
|
2009 |
|
|
2009 |
|
|
2009 |
|
|
|
2010 |
|
|
2010 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phase 1: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
3,451 |
|
|
|
3,466 |
|
|
|
3,397 |
|
|
|
3,350 |
|
|
|
|
3,416 |
|
|
|
3,277 |
|
|
|
3,323 |
|
Little Creek area |
|
|
1,619 |
|
|
|
1,560 |
|
|
|
1,356 |
|
|
|
1,479 |
|
|
|
|
1,690 |
|
|
|
1,971 |
|
|
|
1,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mallalieu area |
|
|
4,490 |
|
|
|
4,264 |
|
|
|
3,679 |
|
|
|
4,005 |
|
|
|
|
3,443 |
|
|
|
3,628 |
|
|
|
3,279 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
McComb area |
|
|
2,246 |
|
|
|
2,429 |
|
|
|
2,473 |
|
|
|
2,412 |
|
|
|
|
2,289 |
|
|
|
2,160 |
|
|
|
2,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lockhart Crossing |
|
|
607 |
|
|
|
698 |
|
|
|
882 |
|
|
|
1,025 |
|
|
|
|
1,127 |
|
|
|
1,311 |
|
|
|
1,508 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phase 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eucutta |
|
|
3,813 |
|
|
|
4,145 |
|
|
|
4,068 |
|
|
|
3,912 |
|
|
|
|
3,792 |
|
|
|
3,625 |
|
|
|
3,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heidelberg |
|
|
- |
|
|
|
250 |
|
|
|
829 |
|
|
|
1,506 |
|
|
|
|
1,708 |
|
|
|
1,857 |
|
|
|
2,806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
1,118 |
|
|
|
951 |
|
|
|
720 |
|
|
|
724 |
|
|
|
|
927 |
|
|
|
764 |
|
|
|
606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Soso |
|
|
2,705 |
|
|
|
2,589 |
|
|
|
2,813 |
|
|
|
3,224 |
|
|
|
|
3,213 |
|
|
|
3,207 |
|
|
|
3,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phase 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
2,390 |
|
|
|
3,402 |
|
|
|
3,558 |
|
|
|
3,942 |
|
|
|
|
4,419 |
|
|
|
5,248 |
|
|
|
6,024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phase 4: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cranfield |
|
|
144 |
|
|
|
338 |
|
|
|
572 |
|
|
|
728 |
|
|
|
|
936 |
|
|
|
811 |
|
|
|
855 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phase 5: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delhi |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
63 |
|
|
|
648 |
|
|
|
511 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
|
|
26,307 |
|
|
|
|
27,023 |
|
|
|
28,507 |
|
|
|
29,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary operating expense per Bbl |
|
$ |
20.48 |
|
|
$ |
20.86 |
|
|
$ |
23.14 |
|
|
$ |
22.03 |
|
|
$ |
|
22.67 |
|
|
$ |
21.37 |
|
|
$ |
22.54 |
|
|
|
|
Oil production from our tertiary operations increased to an average of 29,531 Bbls/d
during the third quarter of 2010, a 21% increase over our third quarter of 2009 tertiary production
level of 24,347 Bbls/d, primarily due to production growth in response to continued expansion of
the tertiary floods in our Tinsley, Heidelberg, Delhi, Soso, Cranfield, and Lockhart Crossing
Fields, offset by gradual production declines in our Mallalieu, Eucutta and other fields. Tinsley Field is our top-performing tertiary oil field, and production there is expected to increase
further as we continue to expand the flood. We initiated CO2 injections at Delhi
Field (Phase 5) during November 2009 and saw initial tertiary production response at Delhi
Field late in the first quarter of 2010. During the third quarter, Delhi production averaged 511
Bbls/d, slightly lower than the second quarter of 2010 average due to flowline repairs in the
field; however, we expect this production to increase as we expand this CO2 flood.
Although we commenced injection of CO2 into Oyster Bayou Field near the end of June
2010, we do not anticipate a production response from this field
until late 2011. We have not yet started the construction of our CO2
recycling facilities at Oyster Bayou Field or Hastings Field, both of which are pending
receipt of
regulatory approval.
During the third quarter of 2010, operating costs for our tertiary properties averaged $22.54
per Bbl, slightly lower than the third quarter of 2009 average cost of $23.14 per Bbl. The per barrel decrease quarter-to-quarter was primarily due to lower workover costs, offset in part by higher CO2 costs. On a per
Bbl basis, our cost of
CO2
increased by $0.40 per Bbl, from $4.25 per Bbl during the
third quarter of 2009 to $4.65 per Bbl during the third quarter of 2010. 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 Bbl will again increase.
Operating Results
As summarized in the Overview section above, and discussed in further detail below, our
operating results for the third quarter and first nine months of 2010 were higher than results in
the same periods in 2009. The operating results of Encore and ENP from March 9, 2010 through
September 30, 2010 are included in these results. As we control the general partner of ENP, the
operating results of ENP are consolidated with our results of operations from our legacy
properties, even though we only own approximately 46% of ENPs
common units. The primary factors
impacting our operating results were the acquisition of Encore, higher oil and natural gas
prices, changes in the fair value of our commodity derivative contracts, the gain on the sale of
our interests in Genesis, and changes in production, which are all explained in more detail below.
47
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Certain of our operating results and statistics for the comparative third quarters and first
nine months of 2010 and 2009 are included in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
In thousands, except per share and unit data |
|
2010 |
|
2009 |
|
2010 (1) |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Denbury stockholders |
|
$ |
29,104 |
|
|
$ |
26,885 |
|
|
$ |
261,359 |
|
|
$ |
(78,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share - basic |
|
|
0.07 |
|
|
|
0.11 |
|
|
|
0.72 |
|
|
|
(0.32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share - diluted |
|
|
0.07 |
|
|
|
0.11 |
|
|
|
0.71 |
|
|
|
(0.32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
208,484 |
|
|
|
145,645 |
|
|
|
592,775 |
|
|
|
406,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
64,233 |
|
|
|
34,926 |
|
|
|
58,234 |
|
|
|
36,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mcf/d |
|
|
80,983 |
|
|
|
46,399 |
|
|
|
81,065 |
|
|
|
75,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BOE/d |
|
|
77,730 |
|
|
|
42,659 |
|
|
|
71,745 |
|
|
|
49,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
426,896 |
|
|
$ |
208,128 |
|
|
$ |
1,176,085 |
|
|
$ |
529,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
|
33,889 |
|
|
|
13,193 |
|
|
|
103,614 |
|
|
|
71,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
460,785 |
|
|
$ |
221,321 |
|
|
$ |
1,279,699 |
|
|
$ |
600,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts: (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of commodity derivative contracts |
|
$ |
10,036 |
|
|
$ |
18,527 |
|
|
$ |
(46,964 |
) |
|
$ |
146,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash fair value adjustment income (expense) |
|
|
(42,517 |
) |
|
|
(22,284 |
) |
|
|
183,512 |
|
|
|
(323,426 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (expense) from commodity derivative contracts |
|
$ |
(32,481 |
) |
|
$ |
(3,757 |
) |
|
$ |
136,548 |
|
|
$ |
(177,061 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
131,768 |
|
|
$ |
83,300 |
|
|
$ |
355,731 |
|
|
$ |
241,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing |
|
|
35,542 |
|
|
|
10,461 |
|
|
|
92,959 |
|
|
|
30,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
167,310 |
|
|
$ |
93,761 |
|
|
$ |
448,690 |
|
|
$ |
272,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary
CO2 operating margin: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees |
|
$ |
4,653 |
|
|
$ |
3,659 |
|
|
$ |
13,840 |
|
|
$ |
9,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 discovery and operating expenses |
|
|
(2,488 |
) |
|
|
(1,047 |
) |
|
|
(5,537 |
) |
|
|
(3,442 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
2,165 |
|
|
$ |
2,612 |
|
|
$ |
8,303 |
|
|
$ |
6,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices - including impact of derivative settlements: (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
71.63 |
|
|
$ |
70.54 |
|
|
$ |
68.88 |
|
|
$ |
67.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price per Mcf |
|
|
6.38 |
|
|
|
3.09 |
|
|
|
6.22 |
|
|
|
3.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices - excluding impact of derivative settlements: (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
72.24 |
|
|
$ |
64.77 |
|
|
$ |
73.98 |
|
|
$ |
52.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price per Mcf |
|
|
4.55 |
|
|
|
3.09 |
|
|
|
4.68 |
|
|
|
3.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and expenses per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
64.44 |
|
|
$ |
56.39 |
|
|
$ |
65.34 |
|
|
$ |
44.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas lease operating expenses |
|
$ |
18.43 |
|
|
$ |
21.22 |
|
|
$ |
18.16 |
|
|
$ |
17.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production taxes and marketing expense |
|
|
4.97 |
|
|
|
2.67 |
|
|
|
4.75 |
|
|
|
2.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
23.40 |
|
|
$ |
23.89 |
|
|
$ |
22.91 |
|
|
$ |
20.20 |
|
|
|
|
|
|
|
|
(1) |
|
Includes the results of operations of Encore and ENP from March 9, 2010 through September 30, 2010. |
|
(2) |
|
See Item 3. Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts. |
48
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 2009 and
for the first, second and third quarters of 2010 are shown below, as well as our estimated pro
forma production for the first quarter of 2010 had production from the properties acquired in the
Encore Merger been included with ours for the entire first quarter of 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
First |
|
|
Pro Forma |
|
|
Second |
|
|
Third |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Quarter |
|
|
First Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Area |
|
2009 |
|
|
2009 |
|
|
2009 |
|
|
2009 |
|
|
|
2010 (1) |
|
|
2010 (2) |
|
|
2010 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury
Production excluding ENP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary oil fields |
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
|
|
26,307 |
|
|
|
|
27,023 |
|
|
|
27,023 |
|
|
|
28,507 |
|
|
|
29,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi non-tertiary |
|
|
11,904 |
|
|
|
10,043 |
|
|
|
8,931 |
|
|
|
8,914 |
|
|
|
|
7,829 |
|
|
|
7,829 |
|
|
|
8,967 |
|
|
|
7,965 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
17,063 |
|
|
|
16,088 |
|
|
|
7,579 |
|
|
|
8,035 |
|
|
|
|
5,235 |
|
|
|
5,235 |
|
|
|
5,148 |
|
|
|
4,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
708 |
|
|
|
885 |
|
|
|
699 |
|
|
|
679 |
|
|
|
|
662 |
|
|
|
662 |
|
|
|
775 |
|
|
|
714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama and other |
|
|
1,150 |
|
|
|
1,161 |
|
|
|
1,103 |
|
|
|
1,077 |
|
|
|
|
997 |
|
|
|
997 |
|
|
|
1,078 |
|
|
|
1,091 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cedar Creek Anticline |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
2,537 |
|
|
|
9,830 |
|
|
|
9,967 |
|
|
|
9,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bakken |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
890 |
|
|
|
3,549 |
|
|
|
4,500 |
|
|
|
4,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Haynesville |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
838 |
|
|
|
3,196 |
|
|
|
3,931 |
|
|
|
3,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
1,328 |
|
|
|
5,694 |
|
|
|
2,653 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Rockies |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
1,202 |
|
|
|
4,566 |
|
|
|
4,643 |
|
|
|
4,621 |
|
Mid-Continent |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
2,313 |
|
|
|
8,963 |
|
|
|
5,100 |
|
|
|
2,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Denbury Excluding ENP |
|
|
53,408 |
|
|
|
52,269 |
|
|
|
42,659 |
|
|
|
45,012 |
|
|
|
|
50,854 |
|
|
|
77,544 |
|
|
|
75,269 |
|
|
|
69,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Properties
Sold or to be Sold(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,479 |
) |
|
|
(17,853 |
) |
|
|
(11,684 |
) |
|
|
(5,906 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Production Excluding ENP |
|
|
53,408 |
|
|
|
52,269 |
|
|
|
42,659 |
|
|
|
45,012 |
|
|
|
|
46,375 |
|
|
|
59,691 |
|
|
|
63,585 |
|
|
|
63,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ENP Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cedar Creek Anticline |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
69 |
|
|
|
240 |
|
|
|
267 |
|
|
|
242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bakken |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
3 |
|
|
|
11 |
|
|
|
18 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
852 |
|
|
|
3,411 |
|
|
|
3,268 |
|
|
|
3,169 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Rockies |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
1,227 |
|
|
|
4,845 |
|
|
|
4,816 |
|
|
|
4,797 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
120 |
|
|
|
527 |
|
|
|
473 |
|
|
|
408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ENP |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
2,271 |
|
|
|
9,034 |
|
|
|
8,842 |
|
|
|
8,630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Total |
|
|
53,408 |
|
|
|
52,269 |
|
|
|
42,659 |
|
|
|
45,012 |
|
|
|
|
53,125 |
|
|
|
86,578 |
|
|
|
84,111 |
|
|
|
77,730 |
|
|
|
|
(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.
|
|
(3) |
|
Consists of production associated with the Southern Assets sale, which closed in May 2010; the Cleveland Sand Play sale, which closed in August 2010; and
the proposed Haynesville and East Texas sale, which is expected to close in December 2010.
|
As outlined in the above table, production during the three and nine months ended
September 30, 2010 increased 82% and 45% respectively, over the respective 2009 production levels.
These increases were primarily due to the additional production from the properties acquired in the
Encore Merger, increased production in our tertiary fields, and the Conroe field acquisition which
closed in December 2009. Offsetting these increases are the Barnett Shale dispositions in 2009.
Our adjusted production for the third quarter of 2010, including ENP
but excluding production from the
Cleveland Sand Play disposition as well as the anticipated disposition of the Haynesville and East
Texas natural gas assets, was 71,824 BOE/d.
Our tertiary oil production during the three and nine months ended September 30, 2010
increased 21% and 20%, respectively, over the respective 2009 production levels. The increase in
our tertiary oil production is discussed above under Results of Operations CO2
Operations.
Production in our Mississippi non-tertiary operations decreased 11% and 20% from levels
during the three and nine months ended September 30, 2009, respectively, partially due to the
expected gradual decline in Heidelberg Field due to depletion, and
the development of the
Heidelberg CO2 flood, which resulted in production being shut-in while portions of the
field were converted to tertiary operations. When production commences from these CO2
floods, these volumes will be reported as tertiary production for Heidelberg Field. Another
almost equal factor in the lower production during the three and nine months ended September 30,
2010 was the lack of drilling activity in the Selma Chalk, a natural gas asset characterized by
relatively high initial decline rates.
49
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Our production at Cedar Creek Anticline averaged 10,033 BOE/d during the quarter, comparable
to the production in the second quarter in this area. Production from our Bakken properties
averaged 4,671 BOE/d in the third quarter, an increase of 3% as compared to second quarter 2010
production. The production increases in the Bakken during 2010 are due to on-going drilling and
hydraulic fracturing in this area.
Although we had three rigs operating in the Bakken during the third quarter, our
production growth in the third quarter was impacted by completion problems on a few wells. We anticipate
that we will be able to complete these wells during the fourth quarter, but these completion problems will
cause a delay in our production growth in the fourth quarter and will make it difficult to achieve
our previous production guidance. Before the end of 2010, we
expect to add two drilling rigs in the Bakken, increasing our total expected operated drilling rigs from three to five rigs.
Overall
production decreased from second quarter of 2010 levels due to production
attributable to the Southern Assets sale properties being included during the majority of
the prior quarter. The anticipated sale of the Haynesville and East Texas
properties will further reduce our overall production for the fourth
quarter of 2010.
Our production during the three and nine months ended September 30, 2010 was 83% and 81% oil,
respectively, as compared to 82% and 75% during the three and nine months ended September 30, 2009,
respectively. This increase is due to the sale of our Barnett Shale properties in the second half
of 2009, the acquisition of interests in the Hastings Field in February 2009, the acquisition of
interests in the Conroe Field in December 2009, and the increase in our tertiary operations,
partially offset by the natural gas properties which we acquired in the Encore Merger and sold in
May 2010.
50
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Revenues. Due to the significant increase in oil and natural gas prices
between the first nine months of 2009 and 2010, our oil and natural gas revenues increased sharply
during the three and nine months ended September 30, 2010 as compared to those in the same periods
of 2009. 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 |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2010 vs. 2009 |
|
2010 vs. 2009 |
|
|
|
|
|
|
|
Percentage |
|
|
|
Percentage |
|
|
Increase in |
|
Increase in |
|
Increase in |
|
Increase in |
In thousands |
|
Revenues |
|
Revenues |
|
Revenues |
|
Revenues |
Change in oil and natural gas revenues due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legacy Denbury properties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in commodity prices |
|
$ |
57,516 |
|
|
|
26 |
% |
|
$ |
407,042 |
|
|
|
68 |
% |
Increase in production |
|
|
181,948 |
|
|
|
82 |
% |
|
|
271,715 |
|
|
|
45 |
% |
|
|
|
|
|
|
|
|
|
Total increase in
oil and natural gas
revenues |
|
$ |
239,464 |
|
|
|
108 |
% |
|
$ |
678,757 |
|
|
|
113% |
|
|
|
|
|
|
|
|
|
Excluding any impact of our commodity derivative contracts, our net realized commodity prices
and NYMEX differentials were as follows during the first, second and third quarters and first nine
month periods of 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Three Months Ended |
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
March 31, |
|
June 30, |
|
September 30, |
|
September 30, |
|
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Net Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
76.53 |
|
|
$ |
39.34 |
|
|
$ |
73.99 |
|
|
$ |
54.53 |
|
|
$ |
72.24 |
|
|
$ |
64.77 |
|
|
$ |
73.98 |
|
|
$ |
52.68 |
|
Natural gas price
per Mcf |
|
5.40 |
|
|
|
4.09 |
|
|
|
4.44 |
|
|
|
2.98 |
|
|
|
4.55 |
|
|
|
3.09 |
|
|
|
4.68 |
|
|
|
3.46 |
|
Price per BOE |
|
|
69.21 |
|
|
|
34.97 |
|
|
|
63.76 |
|
|
|
44.48 |
|
|
|
64.44 |
|
|
|
56.39 |
|
|
|
65.34 |
|
|
|
44.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(2.08 |
) |
|
$ |
(3.99 |
) |
|
$ |
(4.13 |
) |
|
$ |
(5.30 |
) |
|
$ |
(3.85 |
) |
|
$ |
(3.47 |
) |
|
$ |
(3.62 |
) |
|
$ |
(4.54 |
) |
Natural gas per Mcf |
|
|
0.37 |
|
|
|
(0.41 |
) |
|
|
0.09 |
|
|
|
(0.82 |
) |
|
|
0.31 |
|
|
|
(0.33 |
) |
|
|
0.14 |
|
|
|
(0.44 |
) |
Our oil NYMEX differential improved during the nine months ended September 30, 2010
as compared to our differential in the comparable period of 2009, primarily due to the 2009 sale
of our Barnett Shale properties, where the NGL price was significantly below NYMEX oil prices,
partially offset by the Rocky Mountain properties we acquired in the Encore Merger which tend to
have higher oil differentials than our historical corporate average.
Our oil NYMEX differential for the third quarter of 2010 was slightly
worse than the comparable period of 2009 due primarily to greater
differentials caused by a pipeline shutdown that temporarily lowered
the oil prices received for our Rockies and Bakken production as we
had to sell to alternative markets. This pipeline has been returned
to service.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during the month, as most of our natural gas is sold on an index price that is set near the
first of each month. While the percentage change in NYMEX natural gas differentials can be quite
large, these differentials are very seldom more than a dollar above or below NYMEX prices.
51
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Commodity Derivative Contracts. The following tables summarize the impact that our commodity
derivative contracts had on our operating results for the three and nine months ended September 30,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative |
|
|
|
|
|
|
|
|
|
Natural Gas Derivative |
In thousands |
|
Oil Derivative Contracts |
|
Contracts |
|
Oil Derivative Contracts |
|
Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash fair value gain (loss) |
|
$ |
(62,450 |
) |
|
$ |
(20,850 |
) |
|
$ |
19,933 |
|
|
$ |
(1,434 |
) |
|
$ |
144,471 |
|
|
$ |
(306,029 |
) |
|
$ |
39,041 |
|
|
$ |
(17,397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlement receipts (payments) |
|
|
(3,590 |
) |
|
|
18,527 |
|
|
|
13,626 |
|
|
|
- |
|
|
|
(80,969 |
) |
|
|
146,365 |
|
|
|
34,005 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(66,040 |
) |
|
$ |
(2,323 |
) |
|
$ |
33,559 |
|
|
$ |
(1,434 |
) |
|
$ |
63,502 |
|
|
$ |
(159,664 |
) |
|
$ |
73,046 |
|
|
$ |
(17,397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 6 and 7 to the
Unaudited Condensed Consolidated Financial Statements for additional information regarding our
commodity derivative contracts.
Production Expenses. Our lease operating expenses increased between the three months ended
September 30, 2010 and 2009 in absolute dollars but decreased on a per BOE basis. Between the nine months
ended September 30, 2010, lease operating expenses increased in both absolute dollars and on a per
BOE basis. The increase in both periods on an absolute basis was primarily a result of:
|
|
|
the completion of the Encore Merger on March 9, 2010; |
|
|
|
our increasing emphasis on tertiary operations and additional tertiary fields moving
into the productive phase (see discussion of those expenses under CO2
Operations); |
|
|
|
increasing personnel and related costs resulting primarily from the Encore Merger; and |
|
|
|
higher electrical costs to operate our properties due primarily to the expansion of our
tertiary operations; |
Offsetting the increase was the sale of our Barnett Shale natural gas properties in the second half
of 2009, which reduced lease operating expense on an absolute basis, but increased it on a per BOE
basis as these properties had a lower per unit operating cost.
Lease operating expense per BOE averaged $18.43 per BOE and $18.16 per BOE for the three and
nine months ended September 30, 2010, respectively, as compared to $21.22 per BOE and $17.94 per
BOE for the same periods in 2009.
The significant difference in the per BOE amounts in the 2009 periods is due primarily to the sale of 60% of our
Barnett Shale properties in the second quarter of 2009. Those properties had much lower operating costs per
BOE than Denburys other properties. The addition of the Encore properties during 2010 have caused our lease
operating costs on a per BOE basis to be lower as Encores properties have lower operating costs per BOE than
Denburys legacy assets. Excluding the impact of the planned Haynesville and East Texas asset sales and the Cleveland Sand Play sale from our third quarter results, our lease operating expenses would have been $19.62
per BOE.
Our tertiary operating costs, which have historically been
higher than our company-wide operating costs, averaged $22.54 per BOE and $22.19 per BOE during the
three and nine months ended September 30, 2010, respectively, as compared to $23.14 per BOE and
$21.53 per BOE for the same periods of 2009. See CO2 Operations for a more detailed
discussion. We expect that our lease operating costs on a per BOE
basis will trend toward our
tertiary operating costs as these operations become a larger percentage of our total operations.
Costs of electricity and utilities to operate our tertiary properties have increased on an absolute
basis primarily due to the expansion of our tertiary operations. We expect our tertiary operating
costs to partially correlate with oil prices, as the price we pay for CO2 is partially
tied to oil prices.
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes, and as such, increased 240% and 205% during the three and nine months ended
September 30, 2010, respectively, as compared to the same periods in 2009. This compares to an
increase in oil and natural gas revenues of 108% and 113% during the three and nine months ended
September 30, 2010, respectively. The addition of properties in other operating areas acquired in
the Encore Merger also affected these costs. Transportation and plant
processing fees increased approximately $5 million and $10 million during the three and nine
months ended September 30, 2010 and 2009, primarily due to the addition of properties in other
operating areas acquired in the Encore Merger.
52
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses
G&A expenses increased on a gross basis and decreased on a per BOE basis between the
respective three and nine months ended September 30, 2010 and 2009 as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
|
In thousands, except per BOE data and employees |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Gross cash G&A expense |
|
$ |
61,532 |
|
|
$ |
36,091 |
|
|
$ |
167,715 |
|
|
$ |
107,565 |
|
Gross stock-based compensation |
|
|
9,832 |
|
|
|
6,101 |
|
|
|
25,985 |
|
|
|
18,600 |
|
Founders compensation award |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,000 |
|
Incentive compensation for Genesis management |
|
|
- |
|
|
|
3,573 |
|
|
|
1,149 |
|
|
|
9,111 |
|
State franchise taxes |
|
|
952 |
|
|
|
1,102 |
|
|
|
2,987 |
|
|
|
3,341 |
|
Operator labor and overhead recovery charges |
|
|
(30,633 |
) |
|
|
(19,333 |
) |
|
|
(81,764 |
) |
|
|
(58,110 |
) |
Capitalized exploration and development costs |
|
|
(4,568 |
) |
|
|
(3,496 |
) |
|
|
(15,056 |
) |
|
|
(10,679 |
) |
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
37,115 |
|
|
$ |
24,038 |
|
|
$ |
101,016 |
|
|
$ |
79,828 |
|
|
|
|
|
|
|
|
|
|
G&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash G&A expense |
|
$ |
3.88 |
|
|
$ |
3.63 |
|
|
$ |
3.83 |
|
|
$ |
3.09 |
|
Net stock-based compensation |
|
|
1.18 |
|
|
|
1.30 |
|
|
|
1.12 |
|
|
|
1.16 |
|
Founders compensation award |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.74 |
|
Incentive compensation for Genesis
management |
|
|
- |
|
|
|
0.91 |
|
|
|
0.06 |
|
|
|
0.68 |
|
State franchise taxes |
|
|
0.13 |
|
|
|
0.28 |
|
|
|
0.15 |
|
|
|
0.25 |
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
5.19 |
|
|
$ |
6.12 |
|
|
$ |
5.16 |
|
|
$ |
5.92 |
|
|
|
|
|
|
|
|
|
|
Employees as of September 30 |
|
|
1,225 |
|
|
|
806 |
|
|
|
1,225 |
|
|
|
806 |
|
|
|
|
|
|
|
|
|
|
Gross cash G&A expenses increased $25.4 million (70.5%) and $60.2 million (56%), respectively,
during the three and nine months ended September 30, 2010, as compared to the same periods of 2009,
primarily due to the Encore Merger and higher compensation and personnel-related costs associated
with an increase in the number of employees and higher wages, which we consider necessary in order
to remain competitive in our industry. During the nine months ended September 30, 2010 we
increased our employee count by 52% primarily as a result of the Encore Merger, resulting in
increased personnel-related costs. During the three and nine months ended September 30, 2010,
stock-based compensation expense increased $3.7 million and $7.4 million, respectively, when
compared to levels in the same periods of 2009, primarily due to the increase in employees and
changes in the mix of compensation awarded to employees including
accruing bonuses at a higher percent.
During the nine months ended September 30, 2010, the increase in personnel-related costs was
partially offset by a $8.0 million decrease in charges relating to incentive compensation awards
for the management of Genesis. The change of control provision of each members compensation
agreement was triggered concurrent with our sale of Genesis in the first quarter of 2010 and the
incentive compensation awards were settled for $14.9 million, with $1.1 million of this being
recognized as expense during February 2010. Additional professional fees, attributable in-part to
fees of $1.7 million paid by the ENP general partner to advisors and others related to the
strategic alternatives process (see Overview Strategic alternatives for ENP), and office
operating expenses attributable to the legacy Encore and new Plano office leases also contributed
to higher G&A expense during the three and nine months ended
September 30, 2010.
The increase in gross G&A expense during the three and nine months ended September 30, 2010,
as compared to those costs in the same period of 2009, 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. Operator labor and overhead recovery
charges also include $2.8 million received from Quantum in payment for our continuing to operate
the Southern Asset properties through July 2010. 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
58% and 41%, respectively, during the three and
nine months ended September 30, 2010, as compared to the same periods in 2009. Capitalized
exploration and development costs also increased between the periods, primarily due to additional
personnel and increased compensation costs.
53
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The net effect of these changes resulted in a 54% increase (a 15% decrease on a per BOE basis)
in G&A expense between the comparable third quarters of 2010 and 2009. For the nine month periods,
G&A expenses increased 27% on a gross basis, but decreased 13% on a per BOE basis, as our increased
production for the nine month period more than offset the increase in expenses.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
|
In thousands, except per BOE data and interest rates |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Cash interest expense |
|
$ |
58,234 |
|
|
$ |
28,694 |
|
|
$ |
164,173 |
|
|
$ |
80,296 |
|
Non-cash interest expense |
|
|
6,014 |
|
|
|
2,037 |
|
|
|
15,136 |
|
|
|
5,363 |
|
Less: capitalized interest |
|
|
(10,917 |
) |
|
|
(20,872 |
) |
|
|
(56,079 |
) |
|
|
(48,699 |
) |
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
53,331 |
|
|
$ |
9,859 |
|
|
$ |
123,230 |
|
|
$ |
36,960 |
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
$ |
1,268 |
|
|
$ |
2,269 |
|
|
$ |
7,658 |
|
|
$ |
7,750 |
|
Net cash interest expense and other income per BOE (1) |
|
$ |
6.57 |
|
|
$ |
1.89 |
|
|
$ |
5.27 |
|
|
$ |
2.21 |
|
Average debt outstanding |
|
$ |
2,751,258 |
|
|
$ |
1,240,827 |
|
|
$ |
2,710,573 |
|
|
$ |
1,246,266 |
|
Average interest rate (2) |
|
|
8.5% |
|
|
|
9.2% |
|
|
|
8.1% |
|
|
|
8.3% |
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest less interest and other income on a per BOE basis. |
|
(2) |
|
Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
Interest expense increased $43.5 million and $86.3 million, respectively, during the
three and nine months ended September 30, 2010, as compared to the same periods in 2009, primarily
due to our February 2010 issuance of the 2020 Notes, debt assumed from Encore in the Encore Merger,
and borrowings under our new $1.6 billion revolving credit agreement, which were used to finance a
portion of the Encore Merger. The increase in interest expense between the comparative nine month
periods was partially offset by an increase of 15% in our interest capitalization relating
primarily to our CO2 pipelines under construction. The first phase of our
Green Pipeline was placed into service on June 29, 2010, and the balance of approximately $815
million (including capitalized interest) was no longer subject to interest capitalization at that
date. A significant amount of our interest capitalized during the first half of 2010 (and to a
lesser extent the second half of 2009) related to the construction of this first phase, and
consequently our capitalized interest for the third quarter of 2010 was 48% and 54% lower compared
to the third
quarter of 2009 and the second quarter of 2010, respectively.
54
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
|
In thousands, except per BOE data |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Depletion, depreciation, and amortization of oil and natural gas
properties |
|
$ |
108,692 |
|
|
$ |
44,935 |
|
|
$ |
295,923 |
|
|
$ |
151,890 |
|
Depletion and depreciation of CO2 assets |
|
|
4,984 |
|
|
|
4,399 |
|
|
|
15,964 |
|
|
|
12,960 |
|
Asset retirement obligations |
|
|
1,877 |
|
|
|
823 |
|
|
|
4,676 |
|
|
|
2,460 |
|
Depreciation of other fixed assets |
|
|
5,668 |
|
|
|
3,368 |
|
|
|
15,739 |
|
|
|
9,835 |
|
Cumulative change due to revision in policy for CO2 properties |
|
|
(9,619 |
) |
|
|
- |
|
|
|
(9,619 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
111,602 |
|
|
$ |
53,525 |
|
|
$ |
322,683 |
|
|
$ |
177,145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
15.46 |
|
|
$ |
11.66 |
|
|
$ |
15.35 |
|
|
$ |
11.44 |
|
CO2 assets and other fixed assets |
|
|
1.49 |
|
|
|
1.98 |
|
|
|
1.62 |
|
|
|
1.69 |
|
Cumulative change due to revision in policy
for CO2 properties |
|
|
(1.34 |
) |
|
|
- |
|
|
|
(0.49 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
15.61 |
|
|
$ |
13.64 |
|
|
$ |
16.48 |
|
|
$ |
13.13 |
|
|
|
|
|
|
|
|
|
|
Depletion of oil and natural gas properties increased on both a per BOE basis and in absolute
dollars during the three and nine months ended September 30, 2010 as compared to the same periods
of 2009, primarily due to the increase in our oil and natural gas property balance and the
associated reserve volumes and production from the Encore Merger, reserve additions in our tertiary
fields and our Bakken properties during the second quarter of 2010, and the acquisition of
interests in the Conroe Field in December 2009.
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. We recognized incremental reserves during the second quarter of 2010
related to our tertiary production at several tertiary fields, the
most significant of which was Delhi Field, where we initiated
CO2 injections during the fourth quarter of 2009, and had first oil production response
to tertiary injections during March 2010.
Our DD&A expense for our other fixed assets increased on an absolute basis during the three
and nine months ended September 30, 2010 as compared to the rate in the comparable periods in 2009.
The increase is primarily a result of the Encore Merger in March 2010 and field office expansion
during 2009. Our DD&A expense for our CO2 assets increased on an absolute basis for the
three and nine months ended September 30, 2010 compared to the prior periods due to increased
CO2 production. On a per BOE basis, DD&A expense for our CO2 assets and
other fixed assets decreased for the three months ended September 30, 2010 compared to the prior
year quarter due to increased oil and natural gas production volumes as a result of the Encore
Merger which closed in March 2010. The first phase of our Green Pipeline was placed into service
on June 29, 2010, and became subject to depreciation. At September 30, 2010, we had $106.8 million
of costs (including capitalized interest) related to CO2 pipelines under
construction, principally related to the remaining portion of the Green Pipeline to Hastings Field,
which were not being depreciated.
During the third quarter of 2010, the Company changed its method of accounting for
CO2 properties and recorded a one-time, non-cash net reduction of $9.6 million ($6.0
million after tax) to depletion, depreciation and amortization expense for the period, which
reflects the cumulative impact of the revised accounting policy on our historical financials. See
Note 2, Basis of Presentation, for additional information regarding the change.
55
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 September 30, 2010. However, if oil and
natural gas prices were to decrease
significantly in subsequent periods, we may be required to record additional 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.
56
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 a total of
$11.5 million and $79.3 million, respectively, of
transaction and other costs during the three and nine
months ended September 30, 2010 associated with the Encore Merger, including $10.7 million and
$31.4 million, respectively, related to severance costs.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
|
In thousands, except per BOE amounts and tax rates |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Current income tax provision (benefit) |
|
$ |
3,704 |
|
|
$ |
(6,160 |
) |
|
$ |
11,314 |
|
|
$ |
18,140 |
|
Deferred income tax provision (benefit) |
|
|
16,595 |
|
|
|
20,537 |
|
|
|
167,289 |
|
|
|
(67,869 |
) |
|
|
|
|
|
|
|
|
|
Total income tax provision (benefit) |
|
$ |
20,299 |
|
|
$ |
14,377 |
|
|
$ |
178,603 |
|
|
$ |
(49,729 |
) |
|
|
|
|
|
|
|
|
|
Average income tax provision (benefit) per BOE |
|
$ |
2.84 |
|
|
$ |
3.66 |
|
|
$ |
9.12 |
|
|
$ |
(3.69 |
) |
Effective tax rate |
|
|
39.4% |
|
|
|
34.9% |
|
|
|
38.8% |
|
|
|
38.7% |
|
Our income taxes are based on an estimated statutory rate of approximately 37.8%. Our
effective tax rate has historically been slightly lower than our estimated statutory rate due to
the impact of certain items such as our domestic production activities deduction, offset in part by
certain non-cash stock-based compensation that cannot be deducted for tax purposes in the same
manner as book expense. As a result of the Encore Merger, our statutory rate increased, which
required us to remeasure our deferred tax liabilities in the first quarter of 2010 resulting in an
additional income tax provision of approximately $10 million. As a result of the sale of the
Southern Assets, our statutory rate decreased, which required us to remeasure our deferred tax
liabilities in the second quarter of 2010 resulting in an income tax benefit of approximately $3
million. The combination of these items increased our effective tax rate to 38.8% during the nine
months ended September 30, 2010, as compared to 38.7% during the nine months ended September 30,
2009.
During the three and nine months ended September 30, 2009, the current income tax expense
(benefit) represented our anticipated alternative minimum cash taxes that we could not offset with
enhanced oil recovery credits. In addition, included in that amount was approximately $23 million
in current taxes associated with our sale of a portion of our Barnett Shale assets. We recognized
a current income tax benefit in the third quarter of 2009 as a result
of a reconciliation of our tax provision to the actual amounts reported
on our tax return. The current income tax expense for the three and nine months ended September 30, 2010
represents state income taxes, primarily related to the sale of the Southern Assets and the sale of
our interests in Genesis. As of
September 30, 2010, we had an estimated $51.4 million of enhanced oil recovery credits, including
$12.9 million related to the Encore Merger, to carry forward that can be utilized to reduce our
current income taxes during 2010 or future years. These enhanced oil recovery credits do not begin
to expire until 2023. 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.
The Encore Merger was treated as a tax-free asset acquisition for tax purposes. Accordingly,
Encores tax basis and tax attributes carried over to us, with the tax attributes being subject to
certain limitations. Upon testing these limitations, it has been determined that the limitations
are not likely to affect our use of Encores tax attributes. The tax attributes that carried over
to us include enhanced oil recovery credits of $12.9 million, alternative minimum tax credits of
$2.3 million, and state net operating losses of $1 million, tax effected.
In the second 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 which led us to apply for refunds of certain amounts related thereto
on our 2004 and 2006 federal income tax returns. In the course of an IRS audit of those claims for
refunds, the IRS examination team has questioned the change in accounting method and the ruling
received from the National Office of the IRS in 2008. Together with the IRS, we have submitted a
request to the National Office of the IRS for a Technical Advice Memorandum (TAM)
regarding these issues, which is under consideration by the National Office. Although we have
not recorded an uncertain tax position related to these deductions as we expect to receive those
tax refunds, given the existence of the TAM process related to those refunds, the payment of those
tax refunds of approximately $10.6 million for tax years through 2006 is not free from doubt.
Although this change to our method of tax accounting is not expected to have a significant impact
on our overall tax rate, it is anticipated that it could defer the amount of cash taxes we might
otherwise pay over the next several years.
57
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 |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
September 30, |
Per BOE data |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Oil and natural gas revenues |
|
$ |
64.44 |
|
|
$ |
56.39 |
|
|
$ |
65.34 |
|
|
$ |
44.55 |
|
Settlement payments (receipts) of commodity derivative contracts |
|
|
1.40 |
|
|
|
4.72 |
|
|
|
(2.40 |
) |
|
|
10.85 |
|
Lease operating expenses |
|
|
(18.43 |
) |
|
|
(21.22 |
) |
|
|
(18.16 |
) |
|
|
(17.94 |
) |
Production taxes and marketing expenses |
|
|
(4.97 |
) |
|
|
(2.67 |
) |
|
|
(4.75 |
) |
|
|
(2.26 |
) |
|
|
|
|
|
|
|
|
|
Production netback |
|
|
42.44 |
|
|
|
37.22 |
|
|
|
40.03 |
|
|
|
35.20 |
|
Non-tertiary CO2 operating margin |
|
|
0.30 |
|
|
|
0.67 |
|
|
|
0.42 |
|
|
|
0.46 |
|
G&A expenses |
|
|
(5.19 |
) |
|
|
(6.12 |
) |
|
|
(5.16 |
) |
|
|
(5.92 |
) |
Transactions
costs and other related to the Encore Merger |
|
|
(1.60 |
) |
|
|
- |
|
|
|
(4.05 |
) |
|
|
- |
|
Net cash interest expense and other income |
|
|
(6.57 |
) |
|
|
(1.89 |
) |
|
|
(5.27 |
) |
|
|
(2.21 |
) |
Current income taxes and other |
|
|
1.37 |
|
|
|
5.03 |
|
|
|
0.92 |
|
|
|
1.26 |
|
Changes in operating assets and liabilities |
|
|
(1.60 |
) |
|
|
2.20 |
|
|
|
3.37 |
|
|
|
1.34 |
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
29.15 |
|
|
|
37.11 |
|
|
|
30.26 |
|
|
|
30.13 |
|
DD&A |
|
|
(15.61 |
) |
|
|
(13.64 |
) |
|
|
(16.48 |
) |
|
|
(13.13 |
) |
Deferred income taxes |
|
|
(2.32 |
) |
|
|
(5.23 |
) |
|
|
(8.54 |
) |
|
|
5.03 |
|
Gain on sale of interests in Genesis |
|
|
- |
|
|
|
- |
|
|
|
5.18 |
|
|
|
- |
|
Non-cash fair value derivative adjustments |
|
|
(5.86 |
) |
|
|
(5.68 |
) |
|
|
9.45 |
|
|
|
(23.98 |
) |
Net income attributable to noncontrolling interest |
|
|
(0.30 |
) |
|
|
- |
|
|
|
(1.04 |
) |
|
|
- |
|
Changes in operating assets and liabilities and other non-cash items |
|
|
(0.99 |
) |
|
|
(5.71 |
) |
|
|
(5.49 |
) |
|
|
(3.88 |
) |
|
|
|
|
|
|
|
|
|
Net income attributable to Denbury stockholders |
|
$ |
4.07 |
|
|
$ |
6.85 |
|
|
$ |
13.34 |
|
|
$ |
(5.83 |
) |
|
|
|
|
|
|
|
|
|
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, 2009.
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.
58
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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; unexpected difficulties
in integrating the operations of Denbury and Encore; 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; 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.
59
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. We had $360
million of bank debt outstanding as of September 30, 2010 (primarily ENP bank debt as outlined
below), $210 million of which is subject to floating interest rates after taking into consideration
interest rate swaps. The carrying value of our bank debt is approximately fair value based on the
fact that it is subject to short-term floating interest rates that approximate the rates available
to us for those periods. We adjusted the estimated fair value measurements of our bank debt at
September 30, 2010, for estimated nonperformance risk of approximately $13.6 million, which was
determined utilizing industry credit default swaps. 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 September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
|
Carrying |
|
|
Fair |
|
|
In thousands, except percentages |
|
2012 |
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2020 |
|
|
Value |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denbury Credit Agreement (weighted average
interest rate of
2.3% at September
30, 2010) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
120,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
120,000 |
|
|
$ |
110,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ENP Credit Agreement (weighted average
interest rate of
2.8% at September
30, 2010) |
|
|
240,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
240,000 |
|
|
|
235,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% Senior Subordinated Notes due 2013 |
|
|
- |
|
|
|
225,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
224,514 |
|
|
|
228,938 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.25% Senior Subordinated Notes due 2014 |
|
|
- |
|
|
|
- |
|
|
|
1,072 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,084 |
|
|
|
1,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.0% Senior Subordinated Notes due 2015 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
485 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
490 |
|
|
|
485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
300,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
300,449 |
|
|
|
311,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.5% Senior Subordinated Notes due 2016 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
224,920 |
|
|
|
- |
|
|
|
- |
|
|
|
240,193 |
|
|
|
251,078 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.75% Senior Subordinated Notes due 2016 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
426,350 |
|
|
|
- |
|
|
|
- |
|
|
|
403,140 |
|
|
|
478,578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.25% Senior Subordinated Notes due 2017 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,250 |
|
|
|
- |
|
|
|
2,276 |
|
|
|
2,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.25% Senior Subordinated Notes due 2020 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
996,273 |
|
|
|
996,273 |
|
|
|
1,087,233 |
|
At this level of floating rate debt, if LIBOR increased by 10%, we would incur an
additional $0.5 million of interest expense per year on our revolving credit facilities, and if
LIBOR decreased by 10%, we would incur $0.5 million less. Additionally, if the discount rates on
our senior notes increased by 10%, we estimate the fair value of our fixed rate debt at September
30, 2010 would increase by approximately $18.5 million, and if the discount rates on our senior
notes decreased by 10%, we estimate the fair value would decrease by approximately $18.5 million.
As of September 30, 2010, the fair market value of ENPs interest rate swaps was a net
liability of approximately $2.4 million. If the Eurodollar rate increased by 10%, we estimate the
liability would remain at approximately $2.4 million, and if the Eurodollar rate decreased by 10%,
we estimate the liability would increase to approximately $2.5 million.
See Note 5 to the Unaudited Condensed Consolidated Financial Statements for details regarding
our long-term debt.
Commodity Derivative Contracts and Commodity Price Sensitivity
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. In early 2009, we began to employ a strategy
to hedge a portion of our production looking out 12 to 15 months from each quarter, 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. However, as
a result of the Encore Merger and the higher debt levels necessary to finance it, we entered into
costless collars in November 2009 and March 2010 to hedge a significant portion of our forecasted
production through 2011. Given the sale of the Southern Assets commencing in May 2010, we returned
to our strategy initiated during early 2009 whereby we hedge a portion of our production for the
next 12 to 15 months, as discussed above. See Notes 6 and 7 to the Unaudited Condensed
Consolidated Financial Statements for additional information regarding our commodity derivative
contracts.
60
DENBURY RESOURCES INC.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided
by external sources and are based on prices that are actively quoted. 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 revolving credit agreement and all of ENPs
commodity derivative contracts are with parties that are lenders under its revolving credit
agreement. We have included an estimate of nonperformance risk in the fair value measurement of
our oil and natural gas derivative contracts. We have measured nonperformance risk based upon
credit default swaps or credit spreads. At September 30, 2010 and December 31, 2009, the net asset
(liability) of our open commodity derivative contracts was reduced by $0.6 million and $0.8
million, respectively, for estimated nonperformance risk.
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 September 30, 2010, our commodity derivative contracts were recorded at their fair value,
which was a net asset of approximately $67.2 million (excluding $32.4 million of deferred premiums
that Denbury is obligated to pay for its derivative contracts, which payments are not subject to
changes in commodity prices), a significant change from the $128.7 million fair value liability
recorded at December 31, 2009. This change is primarily related to the expiration of oil
derivative contracts during the first nine months of 2010 and to the oil and natural gas futures
prices as of September 30, 2010 in relation to the new commodity derivative contracts for 2010
through 2012 that we entered into during the first nine months of 2010.
Based on NYMEX crude oil and natural gas futures prices as of September 30, 2010, 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
|
|
Receipt / (Payment) |
|
Receipt |
|
|
|
|
|
|
|
|
|
Based on: |
|
|
|
|
|
|
|
|
NYMEX futures prices as of September 30, 2010 |
|
$ |
(19,187 |
) |
|
$ |
68,477 |
|
10% increase in prices |
|
|
(38,709 |
) |
|
|
8,185 |
|
10% decrease in prices |
|
|
53,176 |
|
|
|
83,794 |
|
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 September 30, 2010 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.
61
DENBURY RESOURCES INC.
Evaluation of Changes in Internal Control Over Financial Reporting. Under the supervision and
with the participation of our management, including our Chief Executive Officer and our Chief
Financial Officer, we have determined that, during the third quarter of fiscal 2010, 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.
62
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, 2009, updated as follows.
On October 21, 2010, the Presiding Judge in the Israni and Scott class action cases related to
the Encore Merger which are pending in Tarrant County District Court, delayed until December 16,
2010, the October 21st hearing originally set to consider final approval of the Stipulation of Settlement dated
June 22, 2010 settling the Israni and Scott cases, certifying the class and dismissing the case
with prejudice. This delay was ordered to allow time for mailing of a supplemental notice of
pendency and proposed settlement to all former Encore shareholders. The settlement amount agreed
upon with the Israni and Scott plaintiffs is immaterial to us.
On October 11, 2010, the Presiding Judge in the District Court of Dallas County, Texas in
Harbor Police Retirement System vs. Gareth Roberts, et al
denied the defendants motion to dismiss the
plaintiffs compensation claims. On October 20, 2010, the
defendants filed with the Fifth Court of Appeals in Dallas, Texas, a
petition for a writ of mandamus regarding establishment of demand
futility, which motion is pending. Denbury believes that its
directors have a valid defense to the remaining claims against them, and that the allegations in this suit
are without merit. Denbury and its directors intent to defend this litigation vigorously.
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, 2009. 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 third quarter of 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
July 2010 |
|
|
25,444 |
|
|
$ |
15.65 |
|
|
|
- |
|
|
|
- |
|
August 2010 |
|
|
13,352 |
|
|
|
15.55 |
|
|
|
- |
|
|
|
- |
|
September 2010 |
|
|
13,320 |
|
|
|
15.83 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
52,116 |
|
|
|
15.67 |
|
|
|
- |
|
$ |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
These shares were purchased from our employees who delivered shares to us to satisfy their tax
withholding requirements related to the vesting of restricted shares and the exercise of stock
appreciation rights.
Item 6. Exhibits
|
|
|
Exhibit |
|
Description |
10.1*
|
|
Second
Amendment to Credit Agreement, dated as of September 30, 2010, among Denbury Resources Inc.,
as Borrower, the financial institutions listed on Schedule 1.1 thereto, as Banks, JPMorgan
Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication
Agent, and BNP Paribas, The Bank of Nova Scotia, and Credit Suisse Securities (USA) LLC, as
Co-Documentation Agents. |
63
DENBURY RESOURCES INC.
|
|
|
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*
|
|
The following financial statements from our Quarterly Report on Form 10-Q for the quarter
ended September 30, 2010, formatted in XBRL: (1) Unaudited Condensed Consolidated Balance
Sheets, (2) Unaudited Condensed Consolidated Statements of Operations, (3) Unaudited Condensed
Consolidated Statements of Cash Flows, (4) Unaudited Condensed Consolidated Statement of
Changes in Equity, and (5) Unaudited Condensed Consolidated Statements of Comprehensive Operations. |
64
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, Accounting |
Date:
November 9, 2010
65