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 |
For the quarterly period ended March 31, 2007
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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 |
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware
(State or other jurisdictions of
incorporation or organization)
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20-0467835
(I.R.S. Employer
Identification No.) |
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5100 Tennyson Parkway
Suite 1200
Plano, TX
(Address of principal executive offices)
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75024
(Zip code) |
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Registrants telephone number, including area code:
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(972) 673-2000 |
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 is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. (See definition of accelerated filer and large accelerated
filer in Rule 12-b2 of the Exchange Act). (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
12b-2).
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 April 30, 2007 |
Common Stock, $.001 par value
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121,091,494 |
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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March 31, |
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December 31, |
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2007 |
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2006 |
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Assets |
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Current assets |
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Cash and cash equivalents |
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$ |
35,007 |
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$ |
53,873 |
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Accrued production receivable |
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70,783 |
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72,279 |
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Related party receivable Genesis |
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134 |
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119 |
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Trade and other receivables, net of allowance of $333 and $315 |
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33,292 |
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24,260 |
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Deferred tax asset |
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5,570 |
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5,855 |
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Derivative assets |
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26,883 |
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Total current assets |
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144,786 |
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183,269 |
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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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2,340,795 |
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2,226,942 |
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Unevaluated |
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360,665 |
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293,657 |
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CO2 properties and equipment |
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299,061 |
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267,483 |
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Other |
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43,972 |
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43,133 |
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Less accumulated depletion and depreciation |
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(991,685 |
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(951,447 |
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Net property and equipment |
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2,052,808 |
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1,879,768 |
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Investment in Genesis |
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10,543 |
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10,640 |
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Deposits on property under option or contract |
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49,035 |
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49,002 |
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Other assets |
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18,028 |
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17,158 |
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Total assets |
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$ |
2,275,200 |
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$ |
2,139,837 |
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Liabilities and Stockholders Equity |
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Current liabilities |
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Accounts payable and accrued liabilities |
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$ |
132,561 |
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$ |
139,111 |
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Oil and gas production payable |
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53,673 |
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52,244 |
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Derivative liabilities |
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13,279 |
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4,302 |
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Deferred revenue Genesis |
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4,070 |
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4,070 |
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Short-term capital lease obligations |
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686 |
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671 |
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Total current liabilities |
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204,269 |
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200,398 |
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Long-term liabilities |
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Capital lease obligations |
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6,214 |
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6,387 |
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Long-term debt, net of discount |
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603,834 |
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507,786 |
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Asset retirement obligations |
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42,479 |
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39,331 |
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Derivative liabilities |
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6,975 |
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6,834 |
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Deferred revenue Genesis |
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27,887 |
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28,843 |
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Deferred tax liability |
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238,813 |
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235,780 |
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Other |
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11,638 |
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8,419 |
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Total long-term liabilities |
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937,840 |
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833,380 |
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Stockholders equity |
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Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding |
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Common stock, $.001 par value, 250,000,000 shares authorized;
121,275,128 and 120,506,815 shares issued at March 31, 2007 and
December 31, 2006, respectively |
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121 |
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121 |
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Paid-in capital in excess of par |
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626,094 |
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616,046 |
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Retained earnings |
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514,648 |
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498,032 |
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Accumulated other comprehensive loss |
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(513 |
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Treasury stock, at cost, 330,264 and 370,327 shares at March 31, 2007 and
December 31, 2006, respectively |
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(7,259 |
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(8,140 |
) |
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Total stockholders equity |
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1,133,091 |
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1,106,059 |
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Total liabilities and stockholders equity |
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$ |
2,275,200 |
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$ |
2,139,837 |
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(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
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Three Months Ended |
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March 31, |
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2007 |
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2006 |
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Revenues |
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Oil, natural gas and related product sales: |
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Unrelated parties |
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$ |
169,123 |
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$ |
174,094 |
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Related party Genesis |
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11 |
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1,449 |
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CO2 sales and transportation fees |
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3,091 |
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1,988 |
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Interest income and other |
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1,783 |
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1,375 |
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Total revenues |
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174,008 |
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178,906 |
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Expenses |
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Lease operating expenses |
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50,557 |
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36,172 |
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Production taxes and marketing expenses |
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9,103 |
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6,945 |
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Transportation expense Genesis |
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1,101 |
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1,142 |
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CO2 operating expenses |
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703 |
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645 |
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General and administrative |
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11,434 |
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9,867 |
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Interest, net of interest capitalized of $4,033 and $274, respectively |
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6,075 |
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8,254 |
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Depletion, depreciation, and amortization |
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41,027 |
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32,743 |
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Commodity derivative expense |
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26,907 |
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11,630 |
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Total expenses |
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146,907 |
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107,398 |
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Equity in net income of Genesis |
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147 |
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240 |
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Income before income taxes |
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27,248 |
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71,748 |
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Income tax provision |
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Current income taxes |
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1,618 |
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9,786 |
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Deferred income taxes |
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9,014 |
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18,184 |
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Net income |
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$ |
16,616 |
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$ |
43,778 |
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Net income per common share basic |
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$ |
0.14 |
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$ |
0.39 |
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Net income per common share diluted |
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$ |
0.13 |
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$ |
0.37 |
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Weighted average common shares outstanding |
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Basic |
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118,992 |
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113,151 |
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Diluted |
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123,954 |
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119,925 |
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(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
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Three Months Ended |
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March 31, |
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2007 |
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2006 |
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Cash flow from operating activities: |
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Net income |
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$ |
16,616 |
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$ |
43,778 |
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Adjustments needed to reconcile to net cash flow provided by operations: |
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Depreciation, depletion and amortization |
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41,027 |
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32,743 |
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Non-cash derivative adjustments |
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35,158 |
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10,862 |
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Deferred income taxes |
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9,014 |
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18,184 |
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Deferred revenue Genesis |
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(956 |
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(940 |
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Stock-based compensation |
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2,786 |
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2,972 |
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Amortization of debt issue costs and other |
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582 |
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250 |
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Changes in assets and liabilities relating to operations: |
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Accrued production receivable |
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1,480 |
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157 |
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Trade and other receivables |
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(8,979 |
) |
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4,258 |
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Other assets |
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(22 |
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(10,132 |
) |
Accounts payable and accrued liabilities |
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(4,986 |
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(4,741 |
) |
Oil and gas production payable |
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1,429 |
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4,866 |
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Other liabilities |
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|
196 |
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255 |
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Net cash provided by operating activities |
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93,345 |
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102,512 |
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Cash flow used for investing activities: |
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Oil and natural gas expenditures |
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(139,019 |
) |
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(118,599 |
) |
Acquisitions of oil and gas properties |
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(39,137 |
) |
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(252,410 |
) |
Change in accrual for capital expenditures |
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(4,255 |
) |
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10,028 |
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Acquisitions of CO2 assets and CO2 capital expenditures |
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(31,416 |
) |
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(11,024 |
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Net purchases of other assets |
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(897 |
) |
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(1,940 |
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Proceeds from sales of oil and gas properties and equipment |
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5 |
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Deposits on properties under option or contract |
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(33 |
) |
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26,299 |
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Increase in restricted cash |
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(863 |
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(38 |
) |
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Net cash used for investing activities |
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(215,615 |
) |
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(347,684 |
) |
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Cash flow from financing activities: |
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Bank borrowings |
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96,000 |
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100,000 |
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Costs of debt financing |
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(205 |
) |
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(88 |
) |
Payments on capital lease obligations |
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(161 |
) |
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(138 |
) |
Issuance of common stock |
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|
5,210 |
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4,465 |
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Income tax benefit from equity awards |
|
|
2,560 |
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5,835 |
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Purchase of treasury stock |
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(7 |
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Net cash provided by financing activities |
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|
103,404 |
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|
110,067 |
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|
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Net decrease in cash and cash equivalents |
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|
(18,866 |
) |
|
|
(135,105 |
) |
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Cash and cash equivalents at beginning of period |
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53,873 |
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|
165,089 |
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Cash and cash equivalents at end of period |
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$ |
35,007 |
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$ |
29,984 |
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Supplemental disclosure of cash flow information: |
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Cash paid during the period for interest |
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$ |
2,379 |
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$ |
1,125 |
|
Cash paid during the period for income taxes |
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|
1,038 |
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|
6 |
|
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
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Three Months Ended |
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March 31, |
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2007 |
|
|
2006 |
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Net income |
|
$ |
16,616 |
|
|
$ |
43,778 |
|
Other comprehensive loss, net of income tax: |
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Change in fair value of derivative contracts designated as a hedge,
net of tax of $328 |
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(513 |
) |
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Comprehensive income |
|
$ |
16,103 |
|
|
$ |
43,778 |
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|
|
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|
|
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|
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
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, Denbury or Company refer to Denbury Resources
Inc. and its subsidiaries. These financial statements and the notes thereto should be read in
conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006. Any
capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial
Statements have the same meaning given to them in the Form 10-K.
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 fiscal year. In managements opinion, the
accompanying unaudited condensed consolidated financial statements include all adjustments (of a
normal recurring nature) necessary to present fairly the consolidated financial position of Denbury
as of March 31, 2007 and the consolidated results of its operations and cash flows for the three
month periods ended March 31, 2007 and 2006. Certain prior period items have been reclassified to
make the classification consistent with the classification in the most recent quarter.
Net Income Per Common Share
Basic net income per common share is computed by dividing net income by the weighted average
number of shares of common stock outstanding during the period. Diluted net income per common
share is calculated in the same manner but also considers the impact on net income and common
shares for the potential dilution from stock options, stock appreciation rights (SARs),
non-vested restricted stock and any other convertible securities outstanding. For the three month
periods ended March 31, 2007 and 2006, there were no adjustments to net income for purposes of
calculating diluted net income per common share. In April 2006, we issued 3,492,595 shares of
common stock in a public offering. The following is a reconciliation of the weighted average
common shares used in the basic and diluted net income per common share calculations for the three
month periods ended March 31, 2007 and 2006.
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Three Months Ended |
|
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|
March 31, |
|
Share amounts in thousands |
|
2007 |
|
|
2006 |
|
Weighted average common shares basic |
|
|
118,992 |
|
|
|
113,151 |
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
4,338 |
|
|
|
5,880 |
|
Restricted stock |
|
|
624 |
|
|
|
894 |
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
123,954 |
|
|
|
119,925 |
|
|
|
|
|
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|
|
The weighted average common shares basic amount excludes 1,529,078 shares in 2007 and
2,047,576 shares in 2006 of non-vested restricted stock that is subject to future vesting over
time. As these restricted shares vest, they will be included in the shares outstanding used to
calculate basic net income per common share (although all restricted stock is issued and
outstanding upon grant). For purposes of calculating weighted average common shares diluted, the
non-vested 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. The dilution impact of these
shares on our earnings per share calculation may increase in future periods, depending on the
market price of our common stock during those periods.
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three months ended March 31, 2007, common stock options to purchase approximately
193,000 shares of common stock were outstanding but excluded from the diluted net income per common
share calculation, as the exercise prices of the options exceeded the average market price of the
Companys common stock during this period and would be anti-dilutive to the calculation. There
were no anti-dilutive options outstanding for the three months ended March 31, 2006.
Recently Adopted Accounting Pronouncement
Uncertain Tax Positions
In June 2006, the Financial Accounting
Standards Board (FASB) issued Interpretation 48 (FIN
48), Accounting for Uncertainties in Income Taxes an interpretation of FASB Statement No. 109,
Accounting for Income Taxes. This interpretation addresses how tax benefits claimed or expected to
be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the
Company may recognize the tax benefit from an uncertain tax position only if it is more likely than
not that the tax position will be sustained on examination by the taxing authorities, based on the
technical merits of the position. The tax benefits recognized in the financial statements from
such a position should be measured based on the largest benefit that has a greater than fifty
percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes, accounting in interim
periods and required increased disclosures.
We adopted the provisions of FIN 48 as of January 1, 2007. As a result of the implementation,
we determined that approximately $4.0 million of tax benefits previously recognized were considered
uncertain tax positions, as the timing of these deductions may not be sustained upon examination by
taxing authorities. As such, upon adoption of FIN 48, we recorded income taxes payable of $4.3
million (including $0.3 million in estimated interest) which was offset by a corresponding
reduction of the deferred tax liability of $4.1 million for the tax position that we believe will
ultimately be sustained. At January 1, 2007 the total amount of unrecognized tax benefits is $4.5
million, exclusive of interest.
There was no cumulative adjustment made to the opening balance of retained earnings at January
1, 2007. Our uncertain tax positions relate primarily to timing differences and we do not believe
any of such uncertain tax positions will materially impact our effective tax rate in future
periods. The amount of unrecognized tax benefits did not materially change as of March 31, 2007.
We cannot reasonably estimate the potential change in the unrecognized tax benefits that could
occur over the next 12 months.
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in
many state jurisdictions. We are currently under examination by both the Internal Revenue Service
and State authorities. The IRS is examining 2004 while Mississippi is auditing the periods from
1998 through 2000 and from 2001 through 2003. Louisiana is auditing the periods from 2002 through
2004.
We have not paid any significant interest or penalties associated with our income taxes, but
we will classify both interest expense and penalties as part of our income tax expense.
Recently Issued Accounting Pronouncement
Fair Value Option for Financial Assets and Liabilities
In February 2007, the FASB issued FASB
Statement No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities (FAS 159). FAS 159 permits entities to choose
to measure many financial instruments and certain other items at fair value, with the
objective of improving financial reporting by giving entities the opportunity to mitigate
volatility in reported earnings caused by measuring related assets and liabilities differently
without having to apply complex hedge accounting provisions. The provisions of FAS 159 are
effective for us beginning January 1, 2008. We have not yet determined what impact, if any,
this pronouncement will have on our financial position or results of operations.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 2. Acquisitions
2007 Acquisition
On March 30, 2007, Denbury completed the acquisition of the Seabreeze Complex, which is
composed of two significant fields and four smaller fields, in the general area of Houston, Texas.
These fields are currently producing approximately 400 BOE/d and have estimated current
conventional proved reserves of approximately 525 MBOE. Two of these fields are future potential
CO2 tertiary flood candidates. Tertiary flooding at these fields is not expected to
begin until 2010 or 2011, following completion of the proposed CO2 pipeline from
Louisiana to Hastings Field, near Houston, Texas.
The preliminary adjusted purchase price is approximately $41.7 million, after adjusting for
interim net cash flow between the effective date and closing date of the acquisition, and minor
purchase price adjustments. The preliminary purchase price is subject to final adjustment of the
estimated interim net cash flow and potentially other minor adjustments as outlined in the purchase
and sales agreement. The preliminary purchase price was allocated between proved and unevaluated
oil and natural gas properties based on a risk adjusted analysis of the total estimated value of
the proved and probable reserves acquired. Based on this analysis, $5.5 million was assigned to
proved properties and $36.1 million was assigned to unevaluated properties. The unevaluated costs
are currently excluded from the amortization base and will be transferred to the amortization base
as we develop and test the tertiary recovery projects planned in these fields.
We have not presented any pro forma information for the acquired properties as the pro forma
effect was not material to our results of operations for the first quarters of 2007 or 2006.
2006 Acquisition
On January 31, 2006, we completed an acquisition of three producing oil properties that are
future potential CO2 tertiary oil flood candidates: Tinsley Field approximately 40
miles northwest of Jackson, Mississippi; Citronelle Field in Southwest Alabama, and the smaller
South Cypress Creek Field near the Companys Eucutta Field in Eastern Mississippi. The adjusted
purchase price was approximately $250 million (including the $25 million deposited as earnest money
as of December 31, 2005), of which $124 million was assigned to unevaluated properties.
Note 3. Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with
plugging and abandonment of our 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
our 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 our asset retirement obligations for the
three months ended March 31, 2007.
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
|
(in thousands) |
|
Beginning asset retirement obligation, as of 12/31/2006 |
|
$ |
41,107 |
|
Liabilities incurred and assumed during period |
|
|
2,579 |
|
Liabilities settled during period |
|
|
(451 |
) |
Accretion expense |
|
|
730 |
|
|
|
|
|
Ending asset retirement obligation, as of 3/31/2007 |
|
$ |
43,965 |
|
|
|
|
|
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
At March 31, 2007, $1.5 million of our asset retirement obligation was classified in
Accounts payable and accrued liabilities under current liabilities in our Condensed Consolidated
Balance Sheets. Liabilities incurred during the period are primarily for oil and gas properties we
acquired during March 2007. We hold cash and liquid investments in escrow accounts that are
legally restricted for certain of our asset retirement obligations. The balances of these escrow
accounts were $8.5 million at March 31, 2007, and $7.6 million at December 31, 2006 and are
included in Other assets in our Condensed Consolidated Balance Sheets.
Note 4. Notes Payable and Long-term Indebtedness
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
Amounts in thousands |
|
2007 |
|
|
2006 |
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
150,000 |
|
|
$ |
150,000 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(1,166 |
) |
|
|
(1,214 |
) |
Senior bank loan |
|
|
230,000 |
|
|
|
134,000 |
|
Capital lease obligations Genesis |
|
|
5,717 |
|
|
|
5,869 |
|
Capital lease obligations |
|
|
1,183 |
|
|
|
1,189 |
|
|
|
|
|
|
|
|
Total |
|
|
610,734 |
|
|
|
514,844 |
|
Less current obligations |
|
|
686 |
|
|
|
671 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
610,048 |
|
|
$ |
514,173 |
|
|
|
|
|
|
|
|
On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement, the
instrument governing our senior bank loan. The amendments (i) increased the commitment under the
facility to $350 million, (ii) permit an additional $150 million add-on to the existing 7.5% Senior
Subordinated Notes due 2015, (iii) obtained consent for a sale of our existing CO2
pipelines to Genesis Energy, L.P., and (iv) reaffirmed the borrowing base at $500 million.
On April 3, 2007, we issued $150 million of Senior Subordinated Notes as an additional
issuance under the instrument governing the 7.5% Senior Subordinated Notes due 2015. The net
proceeds were used to repay a portion of the outstanding borrowings under our bank credit facility.
See Note 8 Subsequent Event.
Note 5. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate 9.25% interest in Genesis Energy, L.P.
(Genesis), a publicly traded master limited partnership. Genesis primary business activities
include: gathering, marketing and transportation of crude oil and natural gas, and wholesale
marketing of CO2, primarily in Mississippi, Texas, Alabama and Florida.
We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as
we have significant influence over the limited partnership; however, our control is limited under
the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in
Genesis net income for the three months ended March 31, 2007 and 2006 was $0.1 million and $0.2
million, respectively. Denbury received pro-rata distributions from Genesis of $0.2 million during
each of the three months ended March 31, 2007 and 2006. We also received $30,000 in each of these
periods in directors fees for certain officers of Denbury that are board members of Genesis.
There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of
Genesis Energy, Inc.
Oil Sales and Transportation Services
Prior to September 2004, including the period prior to our investment in Genesis, we sold
certain of our oil production to Genesis. Beginning in September 2004, we discontinued most of our
direct sales to Genesis and began to transport our crude oil using Genesis common carrier pipeline
to a sales point where it is sold to third party purchasers. For these transportation services, we
pay Genesis a fee for the use of their pipeline and trucking services. In the first three months
of 2007 and 2006, we expensed $1.1 million and $1.0 million, respectively, for these transportation
services.
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Transportation Leases
In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis
to transport our crude oil from certain of our fields in Southwest Mississippi, and to transport
CO2 from our main CO2 pipeline to
Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital
leases. The pipelines held under these capital leases are classified as property and equipment and
are amortized using the straight-line method over the lease terms. Lease amortization is included
in depreciation expense. The related obligations are recorded as debt. At March 31, 2007 and
December 31, 2006, we had $5.7 million and $5.9 million, respectively, of capital lease obligations
with Genesis recorded as liabilities in our Consolidated Balance Sheets, of which $0.6 million was
current in both periods.
CO2 Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under three separate
volumetric production payment agreements. We have recorded the net proceeds of these volumetric
production payment sales as deferred revenue and recognize such revenue as CO2 is
delivered under the volumetric production payments. At March 31, 2007 and December 31, 2006, $32.0
million and $32.9 million, respectively, was recorded as deferred revenue, of which $4.1 million
was included in current liabilities at both March 31, 2007 and December 31, 2006. We recognized
deferred revenue of $1.0 million and $0.9 million for the three months ended March 31, 2007 and
2006, respectively, for deliveries under these volumetric production payments. We provide Genesis
with certain processing and transportation services in connection with transporting CO2
to their industrial customers for a fee of approximately $0.17 per Mcf of CO2. For
these services, we recognized revenues of $1.1 million and $1.0 million for the three months ended
March 31, 2007 and 2006, respectively.
At March 31, 2007 and December 31, 2006, we had a net receivable from Genesis of $0.1 million
at each period end associated with all of the transactions described above.
Note 6. Derivative Instruments and Hedging Activities
Oil and Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and gas derivative contracts and
therefore the changes in the fair values of these instruments are recognized in income in the
period of change. These fair value changes, along with the cash settlements of expired contracts
are shown under Commodity Derivative Expense in our Condensed Consolidated Statements of
Operations.
The following is a summary of Commodity Derivative Expense included in our Condensed
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(In Thousands) |
|
2007 |
|
|
2006 |
|
(Receipt) payment on settlements of derivative contracts Oil |
|
$ |
(126 |
) |
|
$ |
768 |
|
(Receipt) payment on settlements of derivative contracts Gas |
|
|
(8,125 |
) |
|
|
|
|
Fair value adjustments to derivative contracts |
|
|
35,158 |
|
|
|
10,862 |
|
|
|
|
|
|
|
|
Commodity derivative expense |
|
$ |
26,907 |
|
|
$ |
11,630 |
|
|
|
|
|
|
|
|
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Oil and Natural Gas Commodity Derivative Contracts at March 31, 2007:
Crude Oil Contracts at March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
Fair Value at |
|
|
NYMEX Contract Prices Per Bbl |
|
March 31, 2007 |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
April 2007 - Dec. 2007 |
|
|
2,000 |
|
|
$ |
58.93 |
|
|
$ |
(5,295 |
) |
Jan. 2008 - Dec. 2008 |
|
|
2,000 |
|
|
|
57.34 |
|
|
|
(8,644 |
) |
Natural Gas Contracts at March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
Fair Value at |
|
|
NYMEX Contract Prices Per MMBtu |
|
March 31, 2007 |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
April 2007 - Dec. 2007 |
|
|
20,000 |
|
|
$ |
7.99 |
|
|
$ |
(1,330 |
) |
April 2007 - Dec. 2007 |
|
|
40,000 |
|
|
|
7.96 |
|
|
|
(2,984 |
) |
April 2007 - Dec. 2007 |
|
|
15,000 |
|
|
|
7.95 |
|
|
|
(1,159 |
) |
At March 31, 2007, our oil and natural gas derivative contracts were recorded at their
fair value, which was a net liability of $19.4 million.
Interest Rate Lock Derivative Contracts
In January 2007, we entered into interest rate lock contracts to remove our exposure to
possible interest rate fluctuations related to our commitment to the sale-leaseback financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. The interest
rate lock contracts cover two groups of equipment currently being constructed that we have
committed to finance with Bank of America Leasing & Capital LLC. This equipment has estimated
completion dates during the fourth quarter of 2007 and in mid-year 2008, with total estimated costs
of approximately $15 million and $24 million, respectively. We are applying hedge accounting to
these contracts as provided under SFAS No. 133. For these instruments designated as interest rate
hedges, changes in fair value, to the extent the hedge is effective, are recognized in other
comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing
hedge ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on
the total change in the contracts fair value.
At March 31, 2007, the interest rate lock contracts have a fair value liability of
approximately $842,000 that was recorded in our March 31, 2007 Condensed Consolidating Balance
Sheet. We recorded $513,000 (net of taxes of $328,000) in accumulated other comprehensive loss in
our March 31, 2007 Condensed Consolidating Balance Sheet and the ineffectiveness totaling $1,000
was recognized as expense in our Condensed Consolidating Statement of Operations for the three
months ended March 31, 2007.
Note 7. Condensed Consolidating Financial Information
Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of
Denbury Resources Inc.s subsidiaries other than minor subsidiaries, except that with respect to
our $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.
The results of our equity interest in Genesis are reflected through the equity method by one
of our subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary
co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is
condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and
subsidiary guarantors:
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
March 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
402,474 |
|
|
$ |
140,065 |
|
|
$ |
5,749 |
|
|
$ |
(403,502 |
) |
|
$ |
144,786 |
|
Property and equipment |
|
|
|
|
|
|
2,052,786 |
|
|
|
22 |
|
|
|
|
|
|
|
2,052,808 |
|
Investment in subsidiaries (equity method) |
|
|
725,801 |
|
|
|
|
|
|
|
725,608 |
|
|
|
(1,440,866 |
) |
|
|
10,543 |
|
Other assets |
|
|
155,138 |
|
|
|
65,339 |
|
|
|
154 |
|
|
|
(153,568 |
) |
|
|
67,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,283,413 |
|
|
$ |
2,258,190 |
|
|
$ |
731,533 |
|
|
$ |
(1,997,936 |
) |
|
$ |
2,275,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
322 |
|
|
$ |
601,993 |
|
|
$ |
5,456 |
|
|
$ |
(403,502 |
) |
|
$ |
204,269 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
941,132 |
|
|
|
276 |
|
|
|
(153,568 |
) |
|
|
937,840 |
|
Stockholders equity |
|
|
1,133,091 |
|
|
|
715,065 |
|
|
|
725,801 |
|
|
|
(1,440,866 |
) |
|
|
1,133,091 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,283,413 |
|
|
$ |
2,258,190 |
|
|
$ |
731,533 |
|
|
$ |
(1,997,936 |
) |
|
$ |
2,275,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
392,372 |
|
|
$ |
180,476 |
|
|
$ |
3,662 |
|
|
$ |
(393,241 |
) |
|
$ |
183,269 |
|
Property and equipment |
|
|
|
|
|
|
1,879,742 |
|
|
|
26 |
|
|
|
|
|
|
|
1,879,768 |
|
Investment in subsidiaries (equity method) |
|
|
709,611 |
|
|
|
|
|
|
|
709,020 |
|
|
|
(1,407,991 |
) |
|
|
10,640 |
|
Other assets |
|
|
154,076 |
|
|
|
64,391 |
|
|
|
154 |
|
|
|
(152,461 |
) |
|
|
66,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
590,602 |
|
|
$ |
3,037 |
|
|
$ |
(393,241 |
) |
|
$ |
200,398 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
835,627 |
|
|
|
214 |
|
|
|
(152,461 |
) |
|
|
833,380 |
|
Stockholders equity |
|
|
1,106,059 |
|
|
|
698,380 |
|
|
|
709,611 |
|
|
|
(1,407,991 |
) |
|
|
1,106,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Three Months Ended March 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
2,813 |
|
|
$ |
173,992 |
|
|
$ |
16 |
|
|
$ |
(2,813 |
) |
|
$ |
174,008 |
|
Expenses |
|
|
2,904 |
|
|
|
146,202 |
|
|
|
614 |
|
|
|
(2,813 |
) |
|
|
146,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(91 |
) |
|
|
27,790 |
|
|
|
(598 |
) |
|
|
|
|
|
|
27,101 |
|
Equity in net earnings of subsidiaries |
|
|
16,703 |
|
|
|
|
|
|
|
17,345 |
|
|
|
(33,901 |
) |
|
|
147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
16,612 |
|
|
|
27,790 |
|
|
|
16,747 |
|
|
|
(33,901 |
) |
|
|
27,248 |
|
Income tax provision |
|
|
(4 |
) |
|
|
10,592 |
|
|
|
44 |
|
|
|
|
|
|
|
10,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
16,616 |
|
|
$ |
17,198 |
|
|
$ |
16,703 |
|
|
$ |
(33,901 |
) |
|
$ |
16,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Three Months Ended March 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
2,813 |
|
|
$ |
176,093 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
178,906 |
|
Expenses |
|
|
2,903 |
|
|
|
104,064 |
|
|
|
431 |
|
|
|
|
|
|
|
107,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(90 |
) |
|
|
72,029 |
|
|
|
(431 |
) |
|
|
|
|
|
|
71,508 |
|
Equity in net earnings of subsidiaries |
|
|
43,858 |
|
|
|
|
|
|
|
44,343 |
|
|
|
(87,961 |
) |
|
|
240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
43,768 |
|
|
|
72,029 |
|
|
|
43,912 |
|
|
|
(87,961 |
) |
|
|
71,748 |
|
Income tax provision |
|
|
(10 |
) |
|
|
27,926 |
|
|
|
54 |
|
|
|
|
|
|
|
27,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
43,778 |
|
|
$ |
44,103 |
|
|
$ |
43,858 |
|
|
$ |
(87,961 |
) |
|
$ |
43,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Three Months Ended March 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
33 |
|
|
$ |
93,074 |
|
|
$ |
238 |
|
|
$ |
|
|
|
$ |
93,345 |
|
Cash flow from investing activities |
|
|
(7,770 |
) |
|
|
(215,615 |
) |
|
|
|
|
|
|
7,770 |
|
|
|
(215,615 |
) |
Cash flow from financing activities |
|
|
7,770 |
|
|
|
103,404 |
|
|
|
|
|
|
|
(7,770 |
) |
|
|
103,404 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
33 |
|
|
|
(19,137 |
) |
|
|
238 |
|
|
|
|
|
|
|
(18,866 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
52,225 |
|
|
|
1,647 |
|
|
|
|
|
|
|
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
34 |
|
|
$ |
33,088 |
|
|
$ |
1,885 |
|
|
$ |
|
|
|
$ |
35,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Three Months Ended March 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(4,458 |
) |
|
$ |
106,762 |
|
|
$ |
208 |
|
|
$ |
|
|
|
$ |
102,512 |
|
Cash flow from investing activities |
|
|
|
|
|
|
(347,684 |
) |
|
|
|
|
|
|
|
|
|
|
(347,684 |
) |
Cash flow from financing activities |
|
|
4,458 |
|
|
|
105,609 |
|
|
|
|
|
|
|
|
|
|
|
110,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(135,313 |
) |
|
|
208 |
|
|
|
|
|
|
|
(135,105 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
164,408 |
|
|
|
680 |
|
|
|
|
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
29,095 |
|
|
$ |
888 |
|
|
$ |
|
|
|
$ |
29,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 8. Subsequent Event
On April 3, 2007, we sold $150 million of Senior Subordinated Notes as an additional issuance
under the December 2005 indenture governing our 7.5% Senior Subordinated Notes due 2015. The
notes, which carry a coupon rate of 7.5%, were sold at 100.5% of par, which equates to an effective
yield to maturity of approximately 7.4%. The net proceeds from the sale were approximately $149.2
million, which we used to repay a portion of the outstanding borrowings under our bank
credit facility.
15
DENBURY RESOURCES INC.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
You should read the following in conjunction with our financial statements contained herein
and in our Form 10-K for the year ended December 31, 2006, 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.
We are a growing independent oil and gas company engaged in acquisition, development and
exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas
producer in Mississippi, own the largest carbon dioxide (CO2) reserves east of the
Mississippi River used for tertiary oil recovery, and hold significant operating acreage onshore
Louisiana, Alabama, in the Barnett Shale play near Fort Worth, Texas, and properties in Southeast
Texas. Our goal is to increase the value of acquired properties through a combination of
exploitation, drilling, and proven engineering extraction processes, including secondary and
tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas),
and we have five primary field offices located in Houma, Louisiana; Laurel, Mississippi; McComb,
Mississippi; Brandon, Mississippi; and Cleburne, Texas.
Overview
Operating results. During the first quarter of 2007, we had a record quarterly production
rate that averaged 38,305 BOE/d, an 8% increase over production levels in the first quarter of
2006, with significant increases in our tertiary oil and Barnett shale production, partially offset
by significant production declines in Louisiana. Higher operating costs, a $35.2 million ($21.4
million after tax) mark-to-market pre-tax charge to earnings primarily related to our 2007 natural
gas swaps as a result of higher natural gas price futures at March 31, 2007 than at December 31,
2006, and lower overall commodity prices offset the revenue impact of higher production, causing a
62% decrease in net income between the comparable first quarters. The net result was net income of
$16.6 million during the first quarter of 2007 as compared to $43.8 million of net income during
the first quarter of 2006. Last years first quarter 2006 net income included the effect of
approximately $10.9 million ($6.6 million after tax) of mark-to-market charges related to
derivative contracts in place at that time.
Although we had a large non-cash mark-to-market value charge in the first quarter of 2007 on
our oil and natural gas derivative contracts, we had net cash receipts of $8.3 million on
settlements of our derivative contracts, primarily on our 2007 natural gas swaps, as compared to
total cash payments of $0.8 million during the first quarter of 2006.
All of our expenses, other than interest expense, increased on both an absolute and per BOE
basis during the first quarter of 2007 due to (i) higher overall industry costs, (ii) a higher
percentage of operations related to tertiary operations (which have higher operating costs per
BOE), (iii) the timing impact of the continued expansion of our tertiary operations in which we
expense the cost of our CO2 and other operating costs even though production response to
the injections will lag behind (see CO2 operations for a more thorough discussion), and
(iv) higher compensation expense resulting from additional employees and increased salaries which
we consider necessary in order to remain competitive in the industry. Even though our average debt
level was 19% higher in the first quarter of 2007 as compared to levels in the first quarter of
2006, because of the significant expenditures made during 2006 and 2007 on unevaluated properties,
we capitalized $4.0 million of interest expense in the first quarter of 2007 related to those
unevaluated properties, as compared to $0.3 million of interest capitalized during the first
quarter of 2006, reducing our overall interest expense between the two periods by 26%.
While overall costs were higher in 2007s first quarter than in the prior first quarter
period, the rate of inflation in our industry during 2007 appears to have moderated, and in some
cases, we are beginning to see modest cost reductions. Likewise, although goods and services are
still tight, there were signs of improvement with regard to overall availability, although there
are still supply issues and long lead times for certain items, as for example, compressors used in
our tertiary recycle facilities and construction services for pipelines. It is difficult to
forecast price trends and supply and service availability, which if adverse, can significantly
impact both operating costs and capital expenditures, as well as cause delays in achieving our
anticipated production targets.
Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in
Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We
particularly like this play because of its risk profile, rate of return and lack of
competition in our operating area. Generally, from East Texas to Florida, there are no known
significant natural sources of carbon dioxide except our own, and these large volumes of
16
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CO2 that we own drive the play. Please refer to the section entitled CO2
Operations below and contained in Managements Discussion and Analysis of Financial Condition and
Results of Operations in our 2006 Form 10-K for further information regarding these operations,
their potential, and the ramifications of this focus.
Oil production from our tertiary operations increased to an average of 11,779 BOE/d in the
first quarter of 2007, a 21% increase over the first quarter 2006 tertiary production level of
9,758 BOE/d and a 17% increase over the fourth quarter 2006 production level. Production from our
Phase II operations (Eucutta and Martinville Fields) contributed 959 BOE/d to the increase over the
prior years first quarter production, with the balance from all of our Phase I fields except
Little Creek Field, which is on a gradual decline.
Recent Proposed Acquisition by Genesis Energy. On April 26, 2007, Genesis Energy, L.P.
(Genesis), a master limited partnership of which Denbury is the general partner, announced that
they had entered into an agreement to acquire several energy related businesses from the Davison
family of Ruston, Louisiana at an estimated price of $560 million. These businesses include a
trucking operation for petroleum products and other bulk commodities, terminal storage of refined
petroleum products, a refinery service operation which processes sour gas streams at several
refining operations, and a wholesale petroleum products marketing business. The acquisition is
subject to various customary closing conditions and is expected to close early in the third quarter
of 2007. The acquisition will be funded by a combination of debt from the Genesis bank credit
facility and Genesis common units to be issued to the seller.
We have previously discussed with Genesis that
upon Genesis achieving certain goals, primarily
the acquisition of other economic projects that are not related to Denbury, that we would undertake
to sell certain Denbury assets to Genesis based upon acquisition by Genesis of $1.50 of
non-Denbury-related acquisitions for every $1.00 of sales with Denbury. As a result
of the recently announced Genesis acquisition, we anticipate that
during 2007 we will sell our
two existing significant
CO2
pipelines to Genesis by entering into
sale-leaseback transactions, with a total currently
estimated value of between $200 million and $250 million. This drop-down transaction would be subject
to, among other things, negotiation of specific terms, the approval of the board of directors of
both entities, and the receipt of fairness opinions for both companies, and is expected to occur a
few months following closing of their announced acquisition. We would anticipate a similar
transaction with Genesis for the new CO2 pipeline we are building from
Jackson Dome to
Tinsley and Delhi Fields once that pipeline is completed, forecasted at this time to be in 2008.
If in future periods Genesis is able to complete additional acquisitions of sufficient size with
acceptable economic returns, we would anticipate a similar transaction with Genesis of our proposed
280 to 300 mile CO2 pipeline from Southern Louisiana to Hastings Field,
located near
Houston, Texas, probably in 2010.
Recent Acquisition. On March 31, 2007, we completed an acquisition of six producing oil
fields, two of which are future potential CO2 tertiary oil flood candidates,
collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately
$41.7 million. Tertiary operations are not expected to commence at these fields until 2010 or
2011, following anticipated completion of the 280 to 300 mile CO2 pipeline from
Louisiana to Hastings Field (also near Houston). The acquisition was funded with bank financing
under our existing credit facility. These fields are currently producing approximately 400 BOE/d
net to the acquired interests, and have estimated proved conventional reserves of approximately 525
MBOE. We operate all of these fields and own the majority of the working interests.
April 2007 Debt Issuance. On April 3, 2007, we issued $150 million of 7.5% Senior
Subordinated Notes due 2015 as an additional issuance under our existing December 2005 indenture
governing our December 2005 sale of $150 million of 7.5% Senior Subordinated Notes due 2015. The
notes were issued at 100.5% of par, which equates to an effective yield to maturity of 7.4%. The
net proceeds from the sale were approximately $149.2 million, which we used to repay a portion of
the outstanding borrowings under our bank credit facility.
Capital Resources and Liquidity
Our current 2007 capital budget is $670 million, excluding any acquisitions, and including
approximately $20 million of uncompleted projects carried over from 2006. Approximately 60% of our
2007 budget is expected to be spent on tertiary related operations, approximately 20% in the
Barnett Shale area, and less than 10% on exploration projects, with the balance spent on our
conventional properties in Mississippi or Louisiana. This capital program
17
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
includes an estimated $110 million for a CO2 pipeline from our CO2 source at
Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during 2006. Based on oil and
natural gas commodity futures prices as of the end of April 2007, this budget is $200 million to
$250 million greater than our anticipated cash flow from operations, a much greater shortfall than
we have had in recent years. We plan to fund substantially all of
this shortfall by selling
our two existing significant
CO2
pipelines to Genesis by entering into sale-leaseback transactions (see Overview Recent
Proposed Acquisition by Genesis Energy). Any unfunded portion would be financed with incremental
bank debt. If a transaction with Genesis is not consummated, we would plan to fund the shortfall
with bank debt and could potentially reduce our capital budget later in the year.
As a result of our April 2007 $150 million subordinated debt offering (see Overview Recent
Debt Issuance) which repaid approximately $150 million of bank debt, as of April 30, 2007, we had
$100 million of bank debt outstanding on a $500 million borrowing base, leaving us significant
incremental borrowing capacity, more than we currently plan or desire to use.
We monitor our capital expenditures on a regular basis, adjusting them up or down depending on
commodity prices and the resultant cash flow. Therefore, during the last few years as commodity
prices have increased, we have increased our capital budget throughout the year. As a result of
the recent cost inflation in our industry, many of our recent budget increases have related to
escalating costs rather than additional projects. Even though there are signs that this
inflationary trend is subsiding, if costs do rise or we spend more than our estimated or forecasted
amounts, we will either have to increase our capital budget or consider the elimination of a
portion of our planned projects.
We also continue to pursue additional acquisitions of mature oil fields that we believe have
potential as future tertiary flood candidates. These possible acquisitions are difficult to
forecast and the purchase price can vary widely depending on the levels of existing production and
conventional proved reserves and commodity prices. Any additional acquisitions would be funded, at
least temporarily, with bank or other debt, although if significant, the acquisition would likely
be ultimately funded with more permanent capital such as subordinated debt and/or additional
equity.
Amendment to our bank credit facility. On March 31, 2007, we amended our Sixth Amended and
Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative
agent. The amendment (i) increased the commitment amount that the banks are committed to fund from
$250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized
the $150 million subordinated debt offering (see Overview Recent Debt Issuance), and (iv)
authorized us to enter into a sale-leaseback type transaction for our CO2 pipelines, not
to exceed $300 million, with Genesis, in the type of transaction contemplated and discussed above
(see Overview Recent Proposed Acquisition by Genesis). With regard to our bank credit
facility, the borrowing base represents the amount that can be borrowed from a credit standpoint
based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks
have committed to fund pursuant to the terms of the credit agreement. The banks have the option to
participate in any borrowing request by us in excess of the commitment amount ($350 million), up to
the borrowing base limit ($500 million), although the banks are not obligated to fund any amount in
excess of the commitment amount. At April 30, 2007, we had outstanding $525 million (principal
amount) of 7.5% subordinated notes and $100 million of bank debt.
Sources and Uses of Capital Resources
During the first quarter of 2007, we spent $139.0 million on oil and natural gas exploration
and development expenditures, $31.4 million on CO2 exploration and development
expenditures, and approximately $39.1 million on property acquisitions, for total capital
expenditures of approximately $209.5 million. Our exploration and development expenditures
included approximately $74.2 million incurred for drilling, $7.5 million for geological,
geophysical and acreage expenditures and $57.3 million for facilities and recompletion costs. We
funded these expenditures with $93.3 million of cash flow from operations, $96.0 million of bank
borrowings, $18.9 million of cash and funded the balance with other working capital. Adjusted cash
flow from operations (a non-GAAP measure defined as cash flow from operations before changes in
assets and liabilities as discussed below under Results of Operations-Operating Results) was
$104.2 million for the first quarter of 2007, while cash flow from operations for the same period,
the GAAP measure, was $93.3 million.
18
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
During the first quarter of 2006, we spent $118.6 million on oil and natural gas exploration
and development expenditures, $11.0 million for CO2 exploration and development
expenditures, and approximately $252.4 million on property acquisitions, for total capital
expenditures of approximately $382.0 million. Our exploration and development expenditures
included approximately $56.6 million incurred for drilling, $6.1 million for geological,
geophysical and acreage expenditures and $55.9 million incurred for facilities and recompletion
costs. We funded these expenditures with $102.5 million of cash flow from operations, $100 million
of bank borrowings, a $10.0 million increase in our accrued capital expenditures and funded the
balance with working capital, predominately cash from the December 2005 issuance of $150 million of
subordinated debt. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow
from operations before changes in assets and liabilities as discussed below under Results of
Operations-Operating Results) was $107.8 million for the first quarter of 2006, while cash flow
from operations for the same period, the GAAP measure, was $102.5 million.
Off-Balance Sheet Arrangements
Commitments and Obligations
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 the proved reserve reports. Our derivative contracts are
discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements. Neither the
amounts nor the terms of these commitments or contingent obligations have changed significantly
from the year-end 2006 amounts reflected in our Form 10-K filed in March 2007, except for a
commitment to a new building lease expected to commence in mid-2008 representing future payments of
approximately $20 million over 136 months. Please refer to Managements Discussion and Analysis of
Financial Condition and Results of Operations Off-Balance Sheet Arrangements Commitments and
Obligations contained in our 2006 Form 10-K 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 and other public disclosures. In addition to its long-term effect, this shift in
focus 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 2006 Form 10-K for further
information regarding these matters.
During 2007 we plan to drill additional CO2 source wells to further increase our
production capacity and reserves. We estimate that we are currently capable of producing between
550 MMcf/d and 600 MMcf/d of CO2, and following the anticipated completion of two
additional wells during the second quarter of 2007, we should be capable of producing between 650
MMcf/d and 700 MMcf/d. During the first quarter of 2007 our CO2 production averaged 448
MMCf/d, as compared to an average of approximately 394 MMcf/d during the fourth quarter of 2006.
We used 81% of this production, or 362 MMcf/d, in our tertiary
operations during the first quarter of 2007 and sold the balance to
our industrial customers or to Genesis pursuant to our volumetric production payments.
Oil production from our tertiary operations increased to an average of 11,779 BOE/d in the
first quarter of 2007, a 21% increase over the first quarter 2006 tertiary production level of
9,758 BOE/d, and 17% higher than fourth quarter 2006 tertiary production levels. The table below
shows our tertiary oil production by field for the first quarter of 2007 and all quarters of 2006.
We are beginning to see improved response in our newer floods at Smithdale, Martinville, Eucutta
and Soso Fields, most of which were initiated during 2006. In addition, we continue to see
improved response at most of our other floods except Little Creek Field, which is a mature flood
and is expected to continue to decline over the next several years.
19
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
Tertiary Oil Field |
|
2006 |
|
2006 |
|
2006 |
|
2006 |
|
|
2007 |
|
|
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
547 |
|
|
|
798 |
|
|
|
965 |
|
|
|
1,014 |
|
|
|
|
1,422 |
|
Little Creek & Lazy Creek |
|
|
3,006 |
|
|
|
3,056 |
|
|
|
2,623 |
|
|
|
2,279 |
|
|
|
|
2,117 |
|
Mallalieu (East and West) |
|
|
5,219 |
|
|
|
5,385 |
|
|
|
5,243 |
|
|
|
4,994 |
|
|
|
|
5,470 |
|
McComb & Olive |
|
|
932 |
|
|
|
1,062 |
|
|
|
1,242 |
|
|
|
1,467 |
|
|
|
|
1,497 |
|
Smithdale |
|
|
54 |
|
|
|
74 |
|
|
|
41 |
|
|
|
63 |
|
|
|
|
314 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
320 |
|
Eucutta |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187 |
|
|
|
|
614 |
|
Soso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
11,779 |
|
|
|
|
|
|
|
We spent approximately $0.17 per Mcf to produce our CO2 during the first
quarter of 2007, lower than our 2006 average of $0.19 per Mcf, primarily due to (a) production
increases that more than offset our production cost increases and (b) lower royalty expense due to
lower oil prices in the first quarter of 2007. Due to these same reasons, our estimated total cost
per thousand cubic feet of CO2 during the first quarter of 2007 was approximately $0.25,
after inclusion of depreciation and amortization expense, also down from the 2006 average of $0.28
per Mcf.
For the first quarter of 2007, our operating costs for our tertiary properties averaged $20.27
per BOE, higher than the prior years first quarter average of $15.02 per BOE, but slightly lower
than our fourth quarter 2006 average of $20.58 per BOE. The higher costs are primarily due to
general cost inflation in the industry and the new floods initiated last year, which resulted in
higher CO2 costs, higher fuel and energy costs and higher rental payments on leased
equipment. Because we expense all lease operating costs, including injection costs, associated
with starting a new flood, we expect the lease operating expense per BOE for tertiary operations to
initially be high, until production increases significantly. For example, for the first quarter of
2007, operating costs per BOE for our Phase I properties which are generally more developed than
our Phase II properties, were $17.04 per BOE, as compared to tertiary operating costs of $55.93 per
BOE for Phase II, an area which is just beginning to respond. In comparison, our operating costs
for Mallalieu Field, currently our highest volume tertiary producer, was $10.36 per BOE during the
same period. We expect our operating costs to average between $13 and $15 per BOE over the life of
a tertiary flood, even though our recent average tertiary operating costs have been higher, as we
continue to implement additional floods.
Operating Results
As summarized in the Overview section above and discussed in more detail below, during the
2007 period our record production was more than offset by higher operating expenses, particularly
because of a large mark-to-market charge on our derivative contracts, resulting in lower quarterly
earnings. Because the mark-to-market charge is not a cash item, our cash flow from operations was
down only slightly between the two periods, as lower overall commodity prices and higher operating
expenses offset higher production.
20
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per share amounts |
|
2007 |
|
|
2006 |
|
Net income |
|
$ |
16,616 |
|
|
$ |
43,778 |
|
Net income per common share basic |
|
|
0.14 |
|
|
|
0.39 |
|
Net income per common share diluted |
|
|
0.13 |
|
|
|
0.37 |
|
|
Adjusted cash flow from operations (see below) |
|
$ |
104,227 |
|
|
$ |
107,849 |
|
Net change in assets and liabilities relating to operations |
|
|
(10,882 |
) |
|
|
(5,337 |
) |
|
|
|
|
|
|
|
Cash flow from operations (1) |
|
$ |
93,345 |
|
|
$ |
102,512 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of
Cash Flows. |
Adjusted cash flow from operations is a non-GAAP measure that represents cash flow
provided by operations before changes in assets and liabilities, as calculated from our Unaudited
Condensed Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as
presented in our Unaudited Condensed Consolidated Statements of Cash Flows. In our discussion
herein, we have elected to discuss these two components of cash flow provided by operations
separately.
Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or
incurred from operating activities without regard to the collection or payment of associated
receivables or payables. We believe it is important to consider adjusted cash flow from operations
separately, as we believe it can often be a better way to discuss changes in operating trends in
our business caused by changes in production, prices, operating costs, and related operational
factors, without regard to whether the earned or incurred item was collected or paid during that
year. We also use this measure because the collection of our receivables or payment of our
obligations has not been a significant issue for our business, but merely a timing issue from one
period to the next, with fluctuations generally caused by significant changes in commodity prices
or significant changes in drilling activity.
The net change in assets and liabilities relating to operations is also important as it does
require or provide additional cash for use in our business; however, we prefer to discuss its
effect separately. For instance, as noted above, during the first quarter of both years, we used
cash to fund a net increase in our other working capital items. During the first quarter of 2007,
this was primarily caused by an increase in trade receivables and prepaid expenses as a result of
our higher level of activity. During the first quarter of 2006, this was primarily caused by an
increase in other current assets related to a deposit for post-closing items from the January
acquisition in the first quarter of 2006. These increases were partially offset by changes in
other current assets and liabilities.
21
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Certain of our operating results and statistics for the comparative first quarters of 2007 and
2006 are included in the following table.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
Bbls/d |
|
|
24,054 |
|
|
|
22,211 |
|
Mcf/d |
|
|
85,506 |
|
|
|
79,452 |
|
BOE/d (1) |
|
|
38,305 |
|
|
|
35,454 |
|
Operating revenues (in thousands) |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
118,132 |
|
|
$ |
113,441 |
|
Natural gas sales |
|
|
51,002 |
|
|
|
62,102 |
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
169,134 |
|
|
$ |
175,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative contracts (2) (in thousands) |
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
8,251 |
|
|
$ |
(768 |
) |
Non-cash fair value adjustments |
|
|
(35,158 |
) |
|
|
(10,862 |
) |
|
|
|
|
|
|
|
Total expense from oil and gas derivative contracts |
|
$ |
(26,907 |
) |
|
$ |
(11,630 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (in thousands) |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
50,557 |
|
|
$ |
36,172 |
|
Production
taxes and marketing expenses (3) |
|
|
10,204 |
|
|
|
8,087 |
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
60,761 |
|
|
$ |
44,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin (in thousands) |
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
3,091 |
|
|
$ |
1,988 |
|
CO2 operating expenses |
|
|
(703 |
) |
|
|
(645 |
) |
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
2,388 |
|
|
$ |
1,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
54.63 |
|
|
$ |
56.36 |
|
Gas price per Mcf |
|
|
7.68 |
|
|
|
8.68 |
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
54.57 |
|
|
$ |
56.75 |
|
Gas price per Mcf |
|
|
6.63 |
|
|
|
8.68 |
|
|
|
|
|
|
|
|
|
|
Oil and gas operating revenues and expenses per BOE (1): |
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
49.06 |
|
|
$ |
55.01 |
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
14.66 |
|
|
$ |
11.34 |
|
Oil and gas production taxes and marketing expense |
|
|
2.96 |
|
|
|
2.53 |
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
17.62 |
|
|
$ |
13.87 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas
(BOE). |
|
(2) |
|
See also Market Risk Management below for information concerning the Companys derivative
transactions. |
|
(3) |
|
Includes transportation expenses paid to Genesis of $1.1 million in each period. |
|
(4) |
|
Includes deferred revenue of $1.0 million and $0.9 million for 2007 and 2006, respectively,
associated with volumetric production payments and $1.1 million and $1.0 million, respectively, of
transportation income, both from Genesis. |
22
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Production: Production by area for each of the quarters of 2006 and the first
quarter of 2007 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
Operating Area |
|
2006 |
|
2006 |
|
2006 |
|
2006 |
|
|
2007 |
|
|
|
|
|
|
Mississippi non-CO2 floods |
|
|
12,455 |
|
|
|
12,633 |
|
|
|
13,069 |
|
|
|
12,808 |
|
|
|
|
12,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi CO2 floods |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
11,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
8,349 |
|
|
|
8,623 |
|
|
|
8,221 |
|
|
|
6,572 |
|
|
|
|
5,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
|
3,953 |
|
|
|
4,621 |
|
|
|
4,952 |
|
|
|
5,925 |
|
|
|
|
6,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
|
917 |
|
|
|
1,213 |
|
|
|
1,215 |
|
|
|
1,243 |
|
|
|
|
1,223 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (1) |
|
|
22 |
|
|
|
9 |
|
|
|
(10 |
) |
|
|
43 |
|
|
|
|
(15 |
) |
|
|
|
|
|
|
Total Company |
|
|
35,454 |
|
|
|
37,474 |
|
|
|
37,561 |
|
|
|
36,619 |
|
|
|
|
38,305 |
|
|
|
|
|
|
|
As outlined in the above table, production in the first quarter of 2007 increased 8% over
first quarter of 2006 levels and 5% over fourth quarter 2006 levels. This increase from the first
quarter of 2006 is primarily due to increased production from our tertiary operations and Barnett
Shale, offset in part by decreases in our onshore Louisiana wells. Also, Alabama production in
2006 reflected only two months activity as this production is primarily from Citronelle Field that
we acquired at the end of January 2006. The increase in our tertiary operations is discussed above
under Results of Operations CO2 Operations.
Production in the Mississippi non-CO2 floods area was up slightly from the prior
years first quarter and about the same as the fourth quarter of 2006 level, as our drilling
activity in the Heidelberg area Selma Chalk (natural gas) has helped offset the gradual declines in
oil production.
Our Barnett Shale production increased approximately 77% from the prior year quarters level
due to our successful drilling activity over the last year. During 2006, we drilled 46 horizontal
wells and we drilled 12 wells in the first quarter of 2007. We had four rigs working
in the area during most of the first quarter of 2007, but we have currently reduced our rig count
in this area to three, and will likely make a further reduction to two rigs as our planned drilling
of 35 to 40 new wells is ahead of schedule. We do not anticipate any significant production
increases from the Barnett Shale during the remainder of 2007, and production may decline later
this year as it is unlikely that we will be able to maintain current production levels with only
two rigs.
The decrease in onshore Louisiana production is due primarily to the expected relatively rapid
depletion of wells in this area. Also, since 2005 we have focused less of our spending in this
area and therefore drilled fewer wells than we have historically. During the first quarter of
2007, we reached total depth on the second well in our Gumbo Prospect, the State Lease 18380 #2.
Our analysis of this well indicated that minimal reserves were found and we decided to sidetrack
this well. We expect to know the result of this well sometime during the second quarter of 2007.
Oil and Natural Gas Revenues: Oil and natural gas revenues for the first quarter of 2007
decreased $6.4 million, or 4%, from revenues in the first quarter of 2006, as lower commodity
prices offset higher production. The decrease in overall commodity prices in the first quarter of
2007 decreased revenues by $20.5 million, or 12%, when comparing the two first quarters of 2006 and
2007, while the increase in production in the first quarter of 2007 increased oil and natural gas
revenues by $14.1 million, or 8%, as compared to the prior years first quarter. Our realized
natural gas prices (excluding hedges) for the first quarter of 2007 averaged $6.63 per Mcf, a 24%
decrease from the average of $8.68 per Mcf realized during the first quarter of 2006, and our
realized oil prices (excluding hedges) for the first quarter of 2007 averaged $54.57 per Bbl, a 4%
decrease from the $56.75 per Bbl average realized in the first quarter of 2006. On a
combined BOE basis, our realized commodity prices were 11% lower in the first quarter of 2007 than
in the first quarter of 2006.
23
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The differentials between our net realized oil prices (excluding commodity derivative
contracts) and NYMEX prices improved in the first quarter of 2007 as compared to the differentials
in both the first quarter of 2006 and fourth quarter of 2006 differentials. Our average oil price
NYMEX differential for the first quarter of 2007 was approximately $3.73 per Bbl as compared to
$6.71 per Bbl during the first quarter of 2006 and $5.92 per Bbl during the fourth quarter of 2006.
This improvement in the NYMEX differential in the first quarter of 2007 was related to higher
prices received for both our light sweet barrels and our sour barrels primarily as a result of
NYMEX (WTI) prices being depressed due to lack of available storage capacity in the mid-continent
area, an oversupply of crude from Canada, capacity/transportation issues in moving crude oil out of
the Cushing, Oklahoma area and unanticipated refinery outages.
Our average natural gas differential relative to NYMEX moved in an unfavorable direction as
compared to the differential in the first quarter of 2006, but improved slightly from fourth
quarter of 2006 differentials. Our average natural gas differential for the first quarter of 2007
was a negative variance of approximately $0.51 per Mcf, as compared to a positive variance of $0.78
per Mcf during the first quarter of 2006 and a negative variance of $0.64 per Mcf during the fourth
quarter of 2006. The positive variance in the first quarter of 2006 was primarily due to the
significant weakening of natural gas prices during that quarter and conversely, the negative
variance in the first quarter of 2007 is primarily due to a strengthening of natural gas prices
during that quarter. Since most of our natural gas is sold on an index price that is set near the
first of each month, the variance will decrease if NYMEX natural gas prices consistently decrease
during the quarter and vice versa.
Oil and Natural Gas Derivative Contracts: We received proceeds of $8.3 million on settlements
of our oil and natural gas derivative contracts during the first quarter of 2007, as compared to
cash payments of $0.8 million we made during the first quarter of 2006. The 2007 receipts
primarily related to the 75 MMcf/d of natural gas swaps for calendar 2007 that we entered into in
December 2006. Due to rising natural gas prices during the period, the market value of those same
natural gas swaps declined substantially during the period, resulting in a $32.4 million
mark-to-market value adjustment at March 31, 2007. Our total mark-to-market expense was $35.2
million during the first quarter of 2007, as compared to an expense of $10.9 million in the first
quarter of 2006. Because we do not utilize hedge accounting for our commodity derivative
contracts, the adjustments in the fair value of these contracts is recognized currently in our
income statement. See Market Risk Management for additional information regarding our derivative
activities and Note 6 to the Condensed Consolidated Financial Statements.
Production Expenses: Our lease operating expenses increased between the comparable first
quarters on both a per BOE basis and in absolute dollars, primarily as a result of (i) our
increasing emphasis on tertiary operations (see discussion of those expenses under CO2
Operations above), (ii) higher overall industry costs, (iii) increased personnel and related
costs, (iv) higher fuel and energy costs to operate our properties, (v) increasing lease payments
for certain of our tertiary operating facilities, and (vi) higher workover costs.
During the first quarter of 2007, operating costs averaged $14.66 per BOE, up from $11.34 per
BOE in the first quarter of 2006, and up slightly from $13.99 per BOE in the fourth quarter of
2006. Operating expenses on our tertiary operations increased from $13.2 million in the first
quarter of 2006 to $21.5 million during the first quarter of 2007, as a result of our increased
tertiary activity level. Tertiary operating expenses were particularly impacted by higher power
and energy costs, expenses on floods from which there was minimal production response to date, and
payments on leased facilities and equipment (see CO2 Operations above). Our emphasis
on tertiary operations is expected to continue, which may further increase our cost per BOE as
tertiary production becomes a more significant portion of our total production and operations.
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes and therefore were higher in the first quarter of 2007 than in the comparable
quarter of 2006. Transportation and plant processing fees were about $1.5 million higher in the
first quarter of 2007 than in the first quarter of 2006.
24
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General and Administrative Expenses
General and administrative (G&A) expenses increased 16% between the respective first
quarters as set forth below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in Thousands Except Per BOE and Employee Data |
|
2007 |
|
|
2006 |
|
Gross G&A expense |
|
$ |
26,770 |
|
|
$ |
21,340 |
|
State franchise taxes |
|
|
718 |
|
|
|
412 |
|
Operator labor and overhead recovery charges |
|
|
(13,806 |
) |
|
|
(9,909 |
) |
Capitalized exploration and development costs |
|
|
(2,248 |
) |
|
|
(1,976 |
) |
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
11,434 |
|
|
$ |
9,867 |
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.32 |
|
|
$ |
3.09 |
|
Employees as of March 31 |
|
|
629 |
|
|
|
507 |
|
|
|
|
|
|
|
|
Gross G&A expenses increased $5.4 million, or 25%, between the first quarters of 2006 and
2007. Approximately $4.3 million of the increase in gross G&A expenses is related to increases in
personnel related costs, due primarily to the increase in employees and increase in wages resulting
from the 5% mid-year pay increase for all employees in mid-2006 and year end pay increases which
averaged 4.4%. During 2006, we increased our employee count by 30% and we further increased our
employee count by approximately 6% during the first quarter of 2007. Stock compensation expense
reflected in gross G&A expenses was approximately $3.1 million for the first quarter of 2007 and
$3.5 million for the first quarter of 2006.
The increase in gross G&A was offset in part by an increase in operator labor and overhead
recovery charges in the first quarter of 2007. Our well operating agreements allow us, as
operator, to charge labor to a well and to charge a specified overhead rate during the drilling
phase and also to charge a monthly fixed overhead rate for each producing well. As a result of
additional operated wells from acquisitions, additional tertiary operations, drilling activity
during the past year and increased compensation expense, the amount we recovered as operator labor
and overhead charges increased by 39% between the first quarters of 2006 and 2007. Capitalized
exploration and development costs also increased between the comparable periods in 2006 and 2007,
primarily as a result of increased compensation costs.
The net effect was a 16% increase in net G&A expense between the respective first quarters.
On a per BOE basis, G&A costs increased 7% in the first quarter of 2007 as compared to levels of
those costs in the first quarter of 2006, a lower percentage increase than the increase in gross
costs as a result of the higher production levels.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE data |
|
2007 |
|
|
2006 |
|
Cash interest expense |
|
$ |
9,839 |
|
|
$ |
8,268 |
|
Non-cash interest expense |
|
|
269 |
|
|
|
260 |
|
Less: Capitalized interest |
|
|
(4,033 |
) |
|
|
(274 |
) |
|
|
|
|
|
|
|
Interest expense |
|
$ |
6,075 |
|
|
$ |
8,254 |
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
1,783 |
|
|
$ |
1,375 |
|
Average net cash interest expense per BOE (1) |
|
$ |
1.18 |
|
|
$ |
2.07 |
|
Average debt outstanding |
|
$ |
530,586 |
|
|
$ |
446,953 |
|
Average interest rate (2) |
|
|
7.4 |
% |
|
|
7.4 |
% |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest and other income on a BOE basis.
|
|
(2) |
|
Includes commitment fees but excludes amortization of discount and debt issue costs. |
25
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest expense decreased $2.2 million, or 26%, comparing the first quarters of 2006 and 2007.
This decrease is primarily due to higher capitalized interest of approximately $3.8 million in the
first quarter of 2007, due primarily to interest capitalized on our significant unevaluated
properties, most of which were acquired in 2006. The increase in capitalized interest is partially
offset by a 19% increase in our average debt level between the two quarters.
Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE data |
|
2007 |
|
|
2006 |
|
Depletion and depreciation of oil and natural
gas properties |
|
$ |
35,966 |
|
|
$ |
29,317 |
|
Depletion and depreciation of CO2 assets |
|
|
2,680 |
|
|
|
1,789 |
|
Asset retirement obligations |
|
|
730 |
|
|
|
571 |
|
Depreciation of other fixed assets |
|
|
1,651 |
|
|
|
1,066 |
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
41,027 |
|
|
$ |
32,743 |
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
10.64 |
|
|
$ |
9.37 |
|
CO2 assets and other fixed assets |
|
|
1.26 |
|
|
|
0.89 |
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
11.90 |
|
|
$ |
10.26 |
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization (DD&A) rate on a per BOE basis increased
3% over the fourth quarter of 2006 DD&A rate of $11.60 per BOE, and increased 16% between the
respective first quarters, primarily due to capital spending and increased costs. We allocated
approximately $36.1 million of the $41.7 million preliminary adjusted purchase price of the
Seabreeze acquisition to unevaluated properties to reflect the significant potential probable
reserves that we considered to be as part of the acquisition. As a result, the acquisition did not
materially affect our overall DD&A rate, as the amount included in our full cost pool was at a cost
per BOE relatively consistent with our overall DD&A rate. We did not book any incremental oil
reserves related to our tertiary operations during the first quarter of 2007, which historically
have had a lower finding and development cost than our overall company average. Although we have
seen some production response at Soso and Martinville Fields during the first quarter of 2007,
based on the limited response thus far, we considered it premature to book any significant reserves
to these fields. We expect that we may be able to book reserves associated with these fields in
the second quarter. We continually evaluate the performance of our other tertiary projects, and if
performance indicates that we are reasonably certain of recovering additional reserves from these
floods, we recognize those incremental reserves in that quarter. Since we adjust our DD&A rate
each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our
DD&A rate could change significantly in the future.
Our DD&A rate for our CO2 and other general corporate fixed assets increased in the
first quarter of 2007 as compared to the rate in the comparable quarter in 2006 as a result of the
additional cost incurred drilling CO2 wells during the past year, putting the Free State
CO2 pipeline into service late in the first quarter of 2006, and higher associated
future development costs, partially offset by an increase in CO2 reserves from 4.6 Tcf
as of December 31, 2005, to 5.5 Tcf as of December 31, 2006 (100% working interest basis before
amounts attributable to Genesis volumetric production payments).
26
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2007 |
|
|
2006 |
|
Current income tax expense |
|
$ |
1,618 |
|
|
$ |
9,786 |
|
Deferred income tax provision |
|
|
9,014 |
|
|
|
18,184 |
|
|
|
|
|
|
|
|
Total income tax provision |
|
$ |
10,632 |
|
|
$ |
27,970 |
|
|
|
|
|
|
|
|
Average income tax expense per BOE |
|
$ |
3.08 |
|
|
$ |
8.77 |
|
Effective tax rate |
|
|
39.0 |
% |
|
|
39.0 |
% |
|
|
|
|
|
|
|
Our income tax provision for the first quarter of 2007 and 2006 was based on an estimated
statutory tax rate of 39%. In both periods, the current income tax expense represents our
anticipated alternative minimum cash taxes that we cannot offset with enhanced oil recovery
credits. As of December 31, 2006, we had an estimated $41.9 million of enhanced oil recovery
credits to carry forward that we can utilize to reduce our current income taxes during 2007. We
have not earned any additional credits since 2005 due to the high oil prices, which completely
phased out our ability to earn any additional credits.
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 |
|
|
|
March 31, |
|
Per BOE data |
|
2007 |
|
|
2006 |
|
Oil and natural gas revenues |
|
$ |
49.06 |
|
|
$ |
55.01 |
|
Gain (loss) on settlements of derivative contracts |
|
|
2.39 |
|
|
|
(0.24 |
) |
Lease operating expenses |
|
|
(14.66 |
) |
|
|
(11.34 |
) |
Production taxes and marketing expenses |
|
|
(2.96 |
) |
|
|
(2.53 |
) |
|
|
|
|
|
|
|
Production netback |
|
|
33.83 |
|
|
|
40.90 |
|
Non-tertiary CO2 operating margin |
|
|
0.69 |
|
|
|
0.42 |
|
General and administrative expenses |
|
|
(3.32 |
) |
|
|
(3.09 |
) |
Net cash interest expense |
|
|
(1.18 |
) |
|
|
(2.07 |
) |
Current income taxes and other |
|
|
0.22 |
|
|
|
(2.36 |
) |
Changes in assets and liabilities relating to operations |
|
|
(3.16 |
) |
|
|
(1.67 |
) |
|
|
|
|
|
|
|
Cash flow from operations |
|
|
27.08 |
|
|
|
32.13 |
|
DD&A |
|
|
(11.90 |
) |
|
|
(10.26 |
) |
Deferred income taxes |
|
|
(2.61 |
) |
|
|
(5.70 |
) |
Non-cash derivative adjustments |
|
|
(10.20 |
) |
|
|
(3.40 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
2.45 |
|
|
|
0.95 |
|
|
|
|
|
|
|
|
Net income |
|
$ |
4.82 |
|
|
$ |
13.72 |
|
|
|
|
|
|
|
|
Market Risk Management
Debt
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. The following
table presents the carrying and fair values of our debt, along with average interest rates. We had
$230 million of bank debt outstanding as of March 31, 2007 and $134 million at December 31, 2006.
Approximately $150 million of the bank debt as of March 31, 2007
27
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
was repaid with proceeds from subordinated debt issued on
April 3, 2007 under the December 2005 indenture governing our already outstanding subordinated debt
due 2015 (see Overview April 2007 Debt Issuance). The fair value of the subordinated debt is
based on quoted market prices. None of our debt has any triggers or covenants regarding our debt
ratings with rating agencies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
Amounts in thousands |
|
2007 - 2011 |
|
Value |
|
Value |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (matures September 2011)
(The weighted average interest rate at March 31, 2007 was 6.3%) |
|
$ |
230,000 |
|
|
$ |
230,000 |
|
|
$ |
230,000 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013, net of discount
(The interest rate on the subordinated debt is a fixed rate of 7.5%) |
|
|
|
|
|
|
223,834 |
|
|
|
226,688 |
|
7.5% subordinated debt, due 2015
(The interest rate on the subordinated debt is a fixed rate of 7.5%) |
|
|
|
|
|
|
150,000 |
|
|
|
151,320 |
|
Oil and Gas Derivative Contracts
From time to time, we enter into various oil and 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.
Historically, we hedged up to 75% of our anticipated production each year to provide us with a
reasonably certain amount of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. Since 2005 and beyond, we have entered into fewer
derivative contracts, primarily because of our strong financial position resulting from our lower
levels of debt relative to our cash flow from operations. We did make an exception in late 2006
when we swapped 80% to 90% of our forecasted 2007 natural gas production at a weighted average
price of $7.96 per Mcf. We did this to protect our 2007 projected cash flow, primarily because we
currently plan to spend $200 million to $250 million more than we expect to generate in cash flow
from operations (see Capital Resources and Liquidity) and we did not want to be exposed to the
risk of lower natural gas prices.
When we make a significant acquisition, we generally attempt to hedge a large percentage, up
to 100%, of the forecasted proved production for the subsequent one to three years following the
acquisition in order to help provide us with a minimum return on our investment. As of March 31,
2007, we had derivative contracts in place related to our $250 million acquisition that closed on
January 31, 2006, on which we entered into contracts to cover 100% of the first three years
estimated proved producing production at the time we signed the purchase and sale agreement. While
these derivative contracts related to the acquisition represent approximately 7% of our estimated
2007 production, they are intended to help protect our acquisition economics related to the first
three years of production from the proved producing reserves that we acquired. These swaps cover
2,000 Bbls/d for 2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34
per Bbl.
At March 31, 2007, our derivative contracts were recorded at their fair value, which was a net
liability of approximately $19.4 million, a decrease of approximately $35.1 million from the $15.7
million fair value asset recorded as of December 31, 2006. This change is the result of a decrease
in the fair market value of our hedges due to an increase in oil and natural gas commodity futures
prices between December 31, 2006 and March 31, 2007.
Based on NYMEX crude oil futures prices at March 31, 2007, we would expect to make future cash
payments of $14.6 million on our oil commodity hedges. If oil futures prices were to decline by
10%, the amount we would expect to pay under our oil commodity hedges would decrease to $5.7
million, and if futures prices were to increase by 10%
we would expect to pay $23.5 million. Based on NYMEX natural gas futures prices at March 31, 2007,
we would expect to make future cash payments of $5.4 million on our natural gas commodity hedges.
If natural gas futures prices
were to decline by 10%, we would expect to receive future cash
payments of $11.6 million and if future prices were to increase by 10% we would expect to pay $22.4
million.
28
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Rate Lock Contracts
In January 2007, we entered into interest rate lock contracts to remove our exposure to
possible interest rate fluctuations related to our commitment to the sale-leaseback financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. The interest
rate lock contracts cover equipment currently being constructed that we have committed to finance
with Bank of America Leasing & Capital LLC. This equipment has two estimated completion dates, one
during the fourth quarter of 2007 and one during mid-year 2008, with a total estimated cost of
approximately $15 million and $24 million, respectively. We are applying hedge accounting to these
contracts as provided under SFAS No. 133.
At March 31, 2007, the interest rate locks were recorded at their fair value, which was a
liability of approximately $0.8 million. If the 5-year Semi-Annual Swap Rate were to increase or
decrease 50-basis points, we would expect the fair value liability to change by approximately $0.9
million, with the increase in rates being a benefit to us and a decrease in rates being a liability
to us.
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to property, plant and
equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations,
income taxes and hedging activities, and 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, 2006.
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, drilling activity or methods, acquisition plans and
proposals and dispositions, development activities, cost savings, production rates and volumes or
forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values,
potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon
current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding costs, rates of return, estimated costs,
future capital expenditures and overall economics and other variables surrounding our tertiary
operations and future plans. Such forward-looking statements generally are accompanied by words
such as plan, estimate, expect, predict, anticipate, projected, should, assume,
believe, target or other words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon managements current plans, expectations, estimates and
assumptions and is subject to a number of risks and uncertainties that could significantly affect
current plans, anticipated actions, the timing of such actions and the Companys 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 or on behalf of the Company. Among the factors that could cause actual results to differ
materially are: fluctuations of the prices received or demand for the Companys oil and natural
gas, inaccurate cost estimates, fluctuations in the prices of goods and services, the uncertainty
of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for
capital or its availability, general economic conditions, competition and government regulations,
unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and
production activities or which are otherwise discussed in this annual report, including, without
limitation, the portions referenced above, and the uncertainties set forth from time to time in the
Companys other public reports, filings and public statements.
29
DENBURY RESOURCES INC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by Item 3 is set forth under Market Risk Management in Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Item 4. Controls and Procedures
We maintain disclosure controls and procedures and internal controls designed to ensure that
information required to be disclosed in our filings under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods specified in the Securities
and Exchange Commissions rules and forms. Our chief executive officer and chief financial officer
have evaluated our disclosure controls and procedures as of the end of the period covered by this
quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are
effective in ensuring that material information required to be disclosed in this quarterly report
is accumulated and communicated to them and our management to allow timely decisions regarding
required disclosure.
There have been no significant changes in internal controls over financial reporting during
the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are
reasonably likely to materially affect, Denburys internal controls over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
Information with respect to this item has been incorporated by reference from our Form 10-K
for the year ended December 31, 2006. There have been no material developments in such legal
proceedings since the filing of such Form 10-K.
Item 1A. Risk Factors
Information with respect to risk factors has been incorporated by reference from Item 1.A. of
our Form 10-K for the year ended December 31, 2006. 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
None
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
30
DENBURY RESOURCES INC.
Item 6. Exhibits
|
|
|
Exhibits: |
|
|
10*
|
|
First Amendment to 6th Amended and Restated Credit Agreement among
Denbury Onshore, LLC, as Borrower, Denbury Resources Inc., as Parent Guarantor,
JPMorgan Chase Bank, N.A. as Administrative Agent, and certain other financial
institutions effective as of March 31, 2007. |
|
|
|
10(a)*
|
|
Amendment for Increased Commitment from $250 million to $350 million to Sixth Amended
and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan
Chase Bank, N.A., as Administrative Agent, and certain other financial institutions
dated as of March 31, 2007. |
|
|
|
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
31
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.
(Registrant)
|
|
|
By: |
/s/ Phil Rykhoek
|
|
|
|
Phil Rykhoek |
|
|
|
Sr. Vice President and Chief Financial Officer |
|
|
|
|
|
|
By: |
/s/ Mark C. Allen
|
|
|
|
Mark C. Allen |
|
|
|
Vice President and Chief Accounting Officer |
|
|
Date: May 4, 2007
32