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, 2008
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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
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20-0467835 |
(State or other jurisdictions of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway |
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Suite 1200 |
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Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip code) |
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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,
a non-accelerated filer, or a smaller reporting company.
See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o
(Do not check if a smaller reporting company) |
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Smaller reporting company 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, 2008 |
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Common Stock, $.001 par value |
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245,992,681 |
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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March 31, |
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December 31, |
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2008 |
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2007 |
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Assets
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Current assets |
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Cash and cash
equivalents |
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$ |
74,039 |
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$ |
60,107 |
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Accrued production
receivable |
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142,318 |
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136,284 |
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Trade and other receivables, net of allowance
of $384 and $369 |
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35,354 |
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28,977 |
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Derivative assets |
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2,283 |
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Deferred tax assets |
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32,583 |
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12,708 |
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Total current assets |
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284,294 |
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240,359 |
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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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2,735,996 |
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2,682,932 |
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Unevaluated |
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418,129 |
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366,518 |
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CO2 properties and equipment |
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479,138 |
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436,591 |
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Other |
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55,997 |
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50,116 |
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Less accumulated depletion and depreciation |
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(1,193,075 |
) |
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(1,143,282 |
) |
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Net property and equipment |
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2,496,185 |
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2,392,875 |
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Deposits on properties
under option or contract |
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49,112 |
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49,097 |
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Other assets |
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94,687 |
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88,746 |
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Total assets |
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$ |
2,924,278 |
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$ |
2,771,077 |
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Liability and
Stockholders Equity
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Current liabilities |
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Accounts payable and
accrued liabilities |
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$ |
144,623 |
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$ |
147,580 |
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Oil and gas
production payable |
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101,784 |
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84,150 |
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Derivative liabilities |
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64,657 |
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28,096 |
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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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980 |
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737 |
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Total current
liabilities |
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316,114 |
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264,633 |
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Long-term liabilities |
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Capital lease
obligations |
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5,248 |
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5,665 |
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Long-term debt, net
of discount or
premium |
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635,692 |
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674,665 |
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Asset retirement
obligations |
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40,153 |
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38,954 |
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Deferred revenue
Genesis |
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23,380 |
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24,424 |
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Deferred tax liability |
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398,894 |
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347,370 |
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Other |
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12,789 |
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10,988 |
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Total
long-term
liabilities |
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1,116,156 |
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1,102,066 |
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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, $.001 par value, 600,000,000
shares authorized;
246,491,237 and 245,386,951 shares issued
at March 31, 2008 and
December 31,
2007,
respectively |
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246 |
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245 |
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Paid-in capital in
excess of par |
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677,180 |
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662,698 |
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Retained earnings |
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824,181 |
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751,179 |
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Accumulated other
comprehensive loss |
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(2,053 |
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(1,591 |
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Treasury stock, at cost, 589,311 and 637,795
shares at March 31, 2008 and
December 31,
2007,
respectively |
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(7,546 |
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(8,153 |
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Total
stockholders
equity |
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1,492,008 |
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1,404,378 |
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Total
liabilities
and
stockholders
equity |
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$ |
2,924,278 |
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$ |
2,771,077 |
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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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2008 |
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2007 |
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Revenues |
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Oil, natural gas and related product sales |
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$ |
313,197 |
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$ |
169,134 |
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CO2 sales and transportation fees |
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2,851 |
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3,091 |
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Interest income and other |
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1,287 |
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1,930 |
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Total revenues |
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317,335 |
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174,155 |
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Expenses |
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Lease operating expenses |
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66,001 |
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50,557 |
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Production taxes and marketing expenses |
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15,186 |
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9,103 |
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Transportation expense Genesis |
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1,550 |
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1,101 |
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CO2 operating expenses |
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1,143 |
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703 |
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General and administrative |
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16,005 |
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11,434 |
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Interest, net of interest capitalized of
$7,266 and $4,033, respectively |
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4,941 |
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6,075 |
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Depletion, depreciation and amortization |
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49,839 |
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41,027 |
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Commodity derivative expense |
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46,781 |
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26,907 |
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Total expenses |
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201,446 |
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146,907 |
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Income before income taxes |
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115,889 |
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27,248 |
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Income tax provision |
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Current income taxes |
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21,236 |
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1,618 |
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Deferred income taxes |
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21,651 |
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9,014 |
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Net income |
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$ |
73,002 |
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$ |
16,616 |
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Net income per common share basic |
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$ |
0.30 |
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$ |
0.07 |
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Net income per common share diluted |
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$ |
0.29 |
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$ |
0.07 |
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Weighted average common shares outstanding |
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Basic |
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242,757 |
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237,984 |
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Diluted |
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252,109 |
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247,907 |
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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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2008 |
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2007 |
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Cash flow from operating activities: |
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Net income |
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$ |
73,002 |
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$ |
16,616 |
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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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49,839 |
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41,027 |
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Deferred income taxes |
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21,651 |
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9,014 |
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Deferred revenue Genesis |
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(1,044 |
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(956 |
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Stock-based compensation |
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3,886 |
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2,786 |
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Non-cash fair value derivative adjustments |
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39,128 |
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35,158 |
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Amortization of debt issue costs and other |
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281 |
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582 |
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Changes in assets and liabilities relating to operations: |
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Accrued production receivable |
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(6,034 |
) |
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1,480 |
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Trade and other receivables |
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(8,359 |
) |
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(8,979 |
) |
Other assets |
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(838 |
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(22 |
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Accounts payable and accrued liabilities |
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16,486 |
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(4,986 |
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Oil and gas production payable |
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17,634 |
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1,429 |
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Other liabilities |
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625 |
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196 |
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Net cash provided by operating activities |
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206,257 |
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93,345 |
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Cash flow used for investing activities: |
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Oil and natural gas capital expenditures |
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(156,302 |
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(139,019 |
) |
Acquisitions of oil and gas properties |
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(402 |
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(39,137 |
) |
Change in accrual for capital expenditures |
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(9,609 |
) |
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(4,255 |
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Distributions from Genesis |
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1,250 |
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Acquisitions
of CO2 assets and CO2 capital expenditures |
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(42,526 |
) |
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(31,416 |
) |
Net purchases of other assets |
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(10,279 |
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(897 |
) |
Deposits on properties under option or contract |
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(33 |
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Increase in restricted cash |
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(45 |
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(863 |
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Net proceeds from sales of properties and equipment |
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54,225 |
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5 |
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Net cash used for investing activities |
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(163,688 |
) |
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(215,615 |
) |
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Cash flow from financing activities: |
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Bank repayments |
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(91,000 |
) |
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Bank borrowings |
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52,000 |
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96,000 |
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Payments on capital lease obligations |
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(178 |
) |
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(161 |
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Income tax benefit from equity awards |
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5,414 |
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|
2,560 |
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Issuance of common stock |
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5,154 |
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5,210 |
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Purchase of treasury stock |
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(27 |
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Costs of debt financing |
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(205 |
) |
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Net cash provided by (used for) financing activities |
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(28,637 |
) |
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103,404 |
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Net increase (decrease) in cash and cash equivalents |
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13,932 |
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(18,866 |
) |
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Cash and cash equivalents at beginning of period |
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60,107 |
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|
53,873 |
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Cash and cash equivalents at end of period |
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$ |
74,039 |
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$ |
35,007 |
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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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$ |
2,050 |
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$ |
2,379 |
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Cash paid during the period for income taxes |
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|
2,630 |
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|
1,038 |
|
Interest capitalized |
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|
7,266 |
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|
4,033 |
|
(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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2008 |
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|
2007 |
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Net income |
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$ |
73,002 |
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$ |
16,616 |
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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
($252) and ($328) |
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(480 |
) |
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(513 |
) |
Net loss reclassified into income, net of taxes of $11 |
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18 |
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Comprehensive income |
|
$ |
72,540 |
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$ |
16,103 |
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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, 2007. 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, 2008 and the consolidated results of its operations and cash flows for the three
month periods ended March 31, 2008 and 2007. Certain prior period items have been reclassified to
make the classification consistent with the classification in the most recent quarter.
Stock Split
On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our
Restated
Certificate of Incorporation to increase the number of shares of our authorized common stock from
250,000,000 shares to 600,000,00 shares and to split our common stock on a 2-for-1 basis.
Stockholders of record on December 5, 2007, received one additional share of Denbury common stock
for each share of common stock held at that time. Information pertaining to shares and earnings per
share has been retroactively adjusted in the accompanying financial statements and related notes
thereto to reflect the stock split.
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, 2008 and 2007, there were no adjustments to net income for purposes of calculating
diluted net income per common share. The following is a reconciliation of the weighted average
common shares used in the basic and diluted net income per common share calculations for the three
month periods ended March 31, 2008 and 2007.
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Three Months Ended |
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March 31, |
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2008 |
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|
2007 |
|
Share amounts in thousands |
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Weighted average common shares basic |
|
|
242,757 |
|
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|
237,984 |
|
Potentially dilutive securities: |
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|
Stock options and SARs |
|
|
7,995 |
|
|
|
8,675 |
|
Restricted stock |
|
|
1,357 |
|
|
|
1,248 |
|
|
|
|
|
|
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|
Weighted average common shares diluted |
|
|
252,109 |
|
|
|
247,907 |
|
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|
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|
The weighted average common shares basic amount excludes 2,671,868 shares in 2008 and
3,058,156 shares in 2007 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
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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.
For the three months ended March 31, 2008 and 2007, stock options and SARs to purchase
approximately 693,000 and 386,000 shares of common stock, respectively, were outstanding but
excluded from the diluted net income per common share calculation, as their exercise prices
exceeded the average market price of the Companys common stock during this period and would be
anti-dilutive to the calculation.
Recently Adopted Accounting Pronouncement
Fair Value Measurements
During the first quarter of 2008, we adopted Statement of Financial Accounting Standards
(SFAS) No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a
framework for measuring fair value in accordance with United States generally accepted accounting
principles, and expands disclosures about fair value measurements. SFAS No. 157 does not require
any new fair value measurements, but provides guidance on how to measure fair value by providing a
fair value hierarchy used to classify the source of the information. On February 12, 2008, the FASB
issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all nonfinancial
assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in
the financial statements on a recurring basis (at least annually). This FSP partially defers the
effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim
periods within those fiscal years for items within the scope of this FSP. This deferral of SFAS No.
157 applies to our asset retirement obligation (ARO), which uses fair value measures at the date
incurred to determine our liability. However, we do not expect the adoption of SFAS No. 157 to
significantly change the methodology we use to estimate the initial fair value of our ARO, because
the guidance in SFAS No. 157 is consistent with the fair value guidance in SFAS No. 143,
Accounting for Asset Retirement Obligations which we apply to determine our ARO.
As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants at the
measurement date (exit price). The Company utilizes market data or assumptions that market
participants would use in pricing the asset or liability, including assumptions about risk and the
risks inherent in the inputs to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. We primarily apply the market approach for
recurring fair value measurements and endeavor to utilize the best available information.
Accordingly, we utilize valuation techniques that maximize the use of observable inputs and
minimizes the use of unobservable inputs. We are able to classify fair value balances based on the
observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the
inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy
defined by SFAS No. 157 are as follows:
Level 1 Quoted prices in active markets for identical assets or liabilities as of the
reporting date. During the first quarter of 2008 we had no level 1 recurring measurements.
Level 2 Pricing inputs are other than quoted prices in active markets included in level 1,
which are either directly or indirectly observable as of the reported date. Level 2 includes those
financial instruments that are valued using models or other valuation methodologies. These models
are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices
for the underlying instruments, as well as other relevant economic measures. Substantially all of
these assumptions are observable in the marketplace throughout the full term of the instrument, can
be derived from observable data or are supported by observable levels at which transactions are
executed in the marketplace. Instruments in this category include non-exchange-traded oil and
natural gas derivatives such as over-the-counter swaps.
Level 3 Pricing inputs include significant inputs that are generally less observable from
objective sources. These inputs may be used with internally developed methodologies that result in
managements best estimate of fair value. During the first quarter of 2008 we had no level 3
recurring measurements.
The following table sets forth by level within the fair value hierarchy our financial assets
and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2008 Using |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
Amounts in thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Derivative Contracts |
|
$ |
|
|
|
$ |
62,064 |
|
|
$ |
|
|
|
$ |
62,064 |
|
Interest Rate Lock Contracts |
|
|
|
|
|
|
2,593 |
|
|
|
|
|
|
|
2,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
64,657 |
|
|
$ |
|
|
|
$ |
64,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recently Issued Accounting Pronouncement
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activitiesan amendment of SFAS No. 133. SFAS No. 161 requires entities that utilize
derivative instruments to provide qualitative disclosures about their objectives and strategies for
using such instruments, as well as any details of credit-risk-related contingent features contained
within derivatives. SFAS No. 161 also requires entities to disclose additional information about
the amounts and location of derivatives located within the financial statements, how the provisions
of SFAS No. 133 have been applied, and the impact that hedges have on an entitys financial
position, financial performance, and cash flows. SFAS No. 161 is effective for us beginning January
1, 2009. We have not yet determined what impact, if any, this pronouncement will have on our
disclosures about derivatives.
Note 2. Divestiture
In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a
privately held company for approximately $180 million (before closing adjustments), plus we
retained a net profits interest in one well. In late December 2007, we closed on approximately 70%
of that sale with net proceeds of approximately $108.6 million (including estimated final purchase
price adjustments). We closed on the remaining portion of the sale in February 2008 and received
net proceeds of approximately $48.9 million related to this portion of the asset sale. The
agreement has an effective date of August 1, 2007, and consequently operating net revenue after
August 1, net of capital expenditures, along with any other minor closing items were adjustments
to the purchase price. The potential net profits interest relates
to a well in the South Chauvin field and is only earned if operating income from that well exceeds
certain levels, which we believe could potentially increase the ultimate value we receive by up to
10%. The operating results of these sold properties are included in our financial statements
through the applicable closing dates of the sold properties. We did not record any gain or loss on
the sale in accordance with the full cost method of accounting.
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.
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in our asset retirement obligations for the three
months ended March 31, 2008.
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
Amounts in thousands |
|
2008 |
|
Beginning asset retirement obligation |
|
$ |
41,258 |
|
Liabilities incurred and assumed during period |
|
|
466 |
|
Revisions in estimated cash flows |
|
|
76 |
|
Liabilities settled during period |
|
|
(292 |
) |
Accretion expense |
|
|
762 |
|
Sales |
|
|
(75 |
) |
|
|
|
|
Ending asset retirement obligation |
|
$ |
42,195 |
|
|
|
|
|
At March 31, 2008, $2.1 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 three months ended March 31, 2008 are primarily for oil and
natural gas wells drilled during the period. 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 $9.5 million at March 31, 2008 and December 31, 2007 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 |
|
2008 |
|
|
2007 |
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
300,000 |
|
|
$ |
300,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
664 |
|
|
|
685 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(972 |
) |
|
|
(1,020 |
) |
Senior bank loan |
|
|
111,000 |
|
|
|
150,000 |
|
Capital lease obligations Genesis |
|
|
5,071 |
|
|
|
5,238 |
|
Capital lease obligations |
|
|
1,157 |
|
|
|
1,164 |
|
|
|
|
|
|
|
|
Total |
|
|
641,920 |
|
|
|
681,067 |
|
Less current obligations |
|
|
980 |
|
|
|
737 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
640,940 |
|
|
$ |
680,330 |
|
|
|
|
|
|
|
|
Effective April 1, 2008, we amended our Sixth Amended and Restated Credit Agreement, the
instrument governing our senior bank loan, which increased our borrowing base from $500 million to
$1.0 billion. 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 ($1.0 billion), although
the banks are not obligated to fund any amount in excess of the commitment amount.
Note 5. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denburys subsidiary, Genesis Energy, Inc. is the general partner and owns an aggregate 9.25%
interest in Genesis Energy, L.P. (Genesis), a publicly traded master limited partnership.
Genesis business is focused on the mid stream segment of the oil and gas industry in the Gulf
Coast area of the United States, and its activities include gathering,
marketing and transportation of crude oil and natural gas, refinery services, wholesale
marketing of
CO2, and supply and logistic services.
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
We account 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 investment in
Genesis is included in Other assets in our Condensed Consolidated Balance Sheets. Denbury
received cash distributions from Genesis of $1.3 million and $0.3 million during the three months
ended March 31, 2008 and 2007, respectively. We also received $30,000 in each of these periods as
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
We utilize Genesis trucking services and common carrier pipeline to transport certain of our
crude oil production to sales points where it is sold to third party purchasers. In the first
three months of 2008 and 2007, we expensed $1.5 million and $1.1 million, respectively, for these
transportation services.
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, 2008 and
December 31, 2007, we had $5.1 million and $5.2 million, respectively, of capital lease
obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheets.
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, 2008 and December 31, 2007, $27.4
million and $28.5 million, respectively, was recorded as deferred revenue, of which $4.1 million
was included in current liabilities at both March 31, 2008 and December 31, 2007. We recognized
deferred revenue of $1.0 million for each of the three months ended March 31, 2008 and 2007, 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 $0.18 per Mcf of CO2. For these services, we
recognized revenues of $1.3 million and $1.1 million for the three
months ended March 31, 2008 and 2007, respectively.
Note 6. Derivative Instruments and Hedging Activities
Oil and Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts
and therefore the changes in the fair values of these instruments are recognized in income in the
period of change. These fair value changes, along with the cash settlements of expired contracts
are shown under 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, |
|
Amounts in thousands |
|
2008 |
|
|
2007 |
|
Receipt (payment) on settlements of derivative contracts
Oil |
|
$ |
(7,392 |
) |
|
$ |
126 |
|
Receipt (payment) on settlements of derivative contracts
Gas |
|
|
(656 |
) |
|
|
8,125 |
|
Fair value adjustments to derivative contracts expense |
|
|
(38,733 |
) |
|
|
(35,158 |
) |
|
|
|
|
|
|
|
Commodity derivative expense |
|
$ |
(46,781 |
) |
|
$ |
(26,907 |
) |
|
|
|
|
|
|
|
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Oil and Natural
Gas Commodity Derivative Contracts at March 31, 2008:
Crude Oil Contracts
at March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
NYMEX Contract Prices Per Bbl |
|
|
Fair Value Liability |
|
|
|
|
|
|
|
|
|
|
|
at March 31, 2008 |
|
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
|
(In Thousands) |
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 Dec. 2008 |
|
|
2,000 |
|
|
$ |
57.34 |
|
|
$ |
(22,976 |
) |
|
Natural Gas Contracts at March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
NYMEX Contract Prices Per MMBtu |
|
Fair Value Liability |
|
|
|
|
|
|
|
|
|
|
at March 31, 2008 |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 Dec. 2008
|
|
|
20,000 |
|
|
$ |
7.89 |
|
|
$ |
(13,157 |
) |
April 2008 Dec. 2008
|
|
|
20,000 |
|
|
|
7.91 |
|
|
|
(13,047 |
) |
April 2008 Dec. 2008
|
|
|
20,000 |
|
|
|
7.94 |
|
|
|
(12,884 |
) |
At March 31, 2008, our oil and natural gas derivative contracts were recorded at their fair
value, which was a net liability of $62.1 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. 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,
2008, the interest rate lock contracts have a fair value liability of
approximately $2.6 million that was recorded in our March 31,
2008 Condensed Consolidating Balance
Sheet. At March 31, 2008, $2.1 million (net of taxes of $1.3 million) is
included in Accumulated
other comprehensive loss in our Condensed Consolidating Balance Sheet associated with these
accounting hedges and approximately $0.4 million was expensed in the first quarter of 2008 for
ineffectiveness or hedges that no longer qualified for hedge accounting.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
455,850 |
|
|
$ |
277,903 |
|
|
$ |
10,597 |
|
|
$ |
(460,056 |
) |
|
$ |
284,294 |
|
Property and equipment |
|
|
|
|
|
|
2,496,176 |
|
|
|
9 |
|
|
|
|
|
|
|
2,496,185 |
|
Investment in subsidiaries (equity method) |
|
|
1,034,633 |
|
|
|
|
|
|
|
979,138 |
|
|
|
(2,013,771 |
) |
|
|
|
|
Other assets |
|
|
303,105 |
|
|
|
85,463 |
|
|
|
56,036 |
|
|
|
(300,805 |
) |
|
|
143,799 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,793,588 |
|
|
$ |
2,859,542 |
|
|
$ |
1,045,780 |
|
|
$ |
(2,774,632 |
) |
|
$ |
2,924,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
765,059 |
|
|
$ |
11,111 |
|
|
$ |
(460,056 |
) |
|
$ |
316,114 |
|
Long-term liabilities |
|
|
301,580 |
|
|
|
1,115,345 |
|
|
|
36 |
|
|
|
(300,805 |
) |
|
|
1,116,156 |
|
Stockholders equity |
|
|
1,492,008 |
|
|
|
979,138 |
|
|
|
1,034,633 |
|
|
|
(2,013,771 |
) |
|
|
1,492,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,793,588 |
|
|
$ |
2,859,542 |
|
|
$ |
1,045,780 |
|
|
$ |
(2,774,632 |
) |
|
$ |
2,924,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
430,518 |
|
|
$ |
237,273 |
|
|
$ |
7,263 |
|
|
$ |
(434,695 |
) |
|
$ |
240,359 |
|
Property and equipment |
|
|
|
|
|
|
2,392,865 |
|
|
|
10 |
|
|
|
|
|
|
|
2,392,875 |
|
Investment in subsidiaries (equity method) |
|
|
961,990 |
|
|
|
|
|
|
|
905,796 |
|
|
|
(1,867,786 |
) |
|
|
|
|
Other assets |
|
|
312,556 |
|
|
|
78,230 |
|
|
|
57,226 |
|
|
|
(310,169 |
) |
|
|
137,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,705,064 |
|
|
$ |
2,708,368 |
|
|
$ |
970,295 |
|
|
$ |
(2,612,650 |
) |
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
691,062 |
|
|
$ |
8,266 |
|
|
$ |
(434,695 |
) |
|
$ |
264,633 |
|
Long-term liabilities |
|
|
300,686 |
|
|
|
1,111,510 |
|
|
|
39 |
|
|
|
(310,169 |
) |
|
|
1,102,066 |
|
Stockholders equity |
|
|
1,404,378 |
|
|
|
905,796 |
|
|
|
961,990 |
|
|
|
(1,867,786 |
) |
|
|
1,404,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,705,064 |
|
|
$ |
2,708,368 |
|
|
$ |
970,295 |
|
|
$ |
(2,612,650 |
) |
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
5,625 |
|
|
$ |
311,619 |
|
|
$ |
5,716 |
|
|
$ |
(5,625 |
) |
|
$ |
317,335 |
|
Expenses |
|
|
5,745 |
|
|
|
194,897 |
|
|
|
6,429 |
|
|
|
(5,625 |
) |
|
|
201,446 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the
following: |
|
|
(120 |
) |
|
|
116,722 |
|
|
|
(713 |
) |
|
|
|
|
|
|
115,889 |
|
Equity in net
earnings of
subsidiaries |
|
|
73,104 |
|
|
|
|
|
|
|
73,805 |
|
|
|
(146,909 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before
income taxes |
|
|
72,984 |
|
|
|
116,722 |
|
|
|
73,092 |
|
|
|
(146,909 |
) |
|
|
115,889 |
|
Income tax
provision (benefit) |
|
|
(18 |
) |
|
|
42,917 |
|
|
|
(12 |
) |
|
|
|
|
|
|
42,887 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
73,002 |
|
|
$ |
73,805 |
|
|
$ |
73,104 |
|
|
$ |
(146,909 |
) |
|
$ |
73,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
2,813 |
|
|
$ |
173,992 |
|
|
$ |
163 |
|
|
$ |
(2,813 |
) |
|
$ |
174,155 |
|
Expenses |
|
|
2,904 |
|
|
|
146,202 |
|
|
|
614 |
|
|
|
(2,813 |
) |
|
|
146,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the
following: |
|
|
(91 |
) |
|
|
27,790 |
|
|
|
(451 |
) |
|
|
|
|
|
|
27,248 |
|
Equity in net
earnings of
subsidiaries |
|
|
16,703 |
|
|
|
|
|
|
|
17,198 |
|
|
|
(33,901 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before
income taxes |
|
|
16,612 |
|
|
|
27,790 |
|
|
|
16,747 |
|
|
|
(33,901 |
) |
|
|
27,248 |
|
Income tax
provision (benefit) |
|
|
(4 |
) |
|
|
10,592 |
|
|
|
44 |
|
|
|
|
|
|
|
10,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
16,616 |
|
|
$ |
17,198 |
|
|
$ |
16,703 |
|
|
$ |
(33,901 |
) |
|
$ |
16,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from
operations |
|
$ |
(10 |
) |
|
$ |
205,010 |
|
|
$ |
1,257 |
|
|
$ |
|
|
|
$ |
206,257 |
|
Cash flow from
investing
activities |
|
|
(10,541 |
) |
|
|
(163,688 |
) |
|
|
|
|
|
|
10,541 |
|
|
|
(163,688 |
) |
Cash flow from
financing
activities |
|
|
10,541 |
|
|
|
(28,637 |
) |
|
|
|
|
|
|
(10,541 |
) |
|
|
(28,637 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase
(decrease) in cash |
|
|
(10 |
) |
|
|
12,685 |
|
|
|
1,257 |
|
|
|
|
|
|
|
13,932 |
|
Cash, beginning of
period |
|
|
34 |
|
|
|
58,343 |
|
|
|
1,730 |
|
|
|
|
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
71,028 |
|
|
$ |
2,987 |
|
|
$ |
|
|
|
$ |
74,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007, 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, in 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 four primary field offices located in Laurel, Mississippi; McComb, Mississippi;
Brandon, Mississippi; and Cleburne, Texas.
Overview
Operating results. During the first quarter of 2008 our production averaged 44,900 BOE/d,
approximately the same as fourth quarter 2007 production after adjusting for the sale of our
Louisiana natural gas properties in December 2007 and February 2008, and a 17% increase over
production levels in the first quarter of 2007 (a 33% increase after adjusting for the Louisiana
natural gas properties sale). Commodity prices continued to increase during the first quarter of 2008, resulting in a 56%
increase in our average per BOE price received over prices received in the first quarter
of 2007 and a 12% increase over fourth quarter of 2007 average per BOE price received. As a result of the
higher prices, we recognized a $38.7 million non-cash fair value charge in the first quarter of
2008 on our oil and natural gas derivative contracts, and in addition, made cash payments of $8.0
million on our derivative contract settlements in the first quarter of 2008, primarily related to
our 2008 oil swaps. This compares to a $35.2 million non-cash fair value charge in the first
quarter of 2007 and net cash receipts of $8.3 million during that same period.
All of our expenses, other than interest expense, increased on both an absolute and per BOE
basis during the first quarter of 2008 due to (i) higher overall industry costs, (ii) a higher
percentage of operations related to tertiary operations (which have higher operating costs per
BOE), and (iii) higher compensation expense resulting from additional employees and increased
salaries, which we consider necessary in order to remain competitive in the industry. In addition,
the sale of our Louisiana natural gas properties, which had lower operating costs per BOE,
increased our operating cost per BOE by over $1.00, based on 2007 average costs. Even though our
average debt level was 25% higher in the first quarter of 2008 as compared to levels in the first
quarter of 2007, because of the significant expenditures made during 2007 and 2008 on unevaluated
properties, we capitalized $7.3 million of interest expense in the first quarter of 2008 related to
those unevaluated properties, as compared to $4.0 million of interest capitalized during the first
quarter of 2007, reducing our overall interest expense between the two periods by 19%. The net
result was net income of $73.0 million during the first quarter of 2008 as compared to $16.6
million of net income during the first quarter of 2007.
While overall costs were higher in 2008s first quarter than in the prior first quarter
period, the rate of inflation in our industry during 2007 appears to have moderated for some goods
and services, but is increasing rapidly for other goods, an example being steel prices. Likewise,
the availability of goods and
services is mixed, with improvements in some areas such as rig availability, but still 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
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 2007
Form 10-K for further information regarding these operations, their potential, and the
ramifications of this focus.
16
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil production from our tertiary operations averaged 17,156 BOE/d in the first quarter of 2008, a
46% increase over our first quarter 2007 tertiary production average of 11,779 BOE/d. This increase
resulted from production increases during 2007 in almost every tertiary field except Little Creek
Field as more completely described in our 2007 Form 10-K. However, tertiary oil production was
slightly lower than our fourth quarter 2007 tertiary production level of 17,428 BOE/d as a result
of various operational issues and delays, coupled with normal and expected fluctuations in the
forecasted production growth curve.
Sale of Louisiana Natural Gas Assets. We completed the remaining 30% of the sale of our
Louisiana natural gas assets in February with additional proceeds received at that time of
approximately $48.9 million, the prior 70% of which closed in December 2007. Production
attributable to the sold properties averaged 302 BOE/d (approximately 81% natural gas) during the
first quarter of 2008, representing the production prior to the closing date for the portion of the
sale that closed in February. Production attributable to the sold properties averaged approximately
30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of
our total fourth quarter production and approximately 4% of our total proved reserve quantities as
of December 31, 2006.
Genesis Transactions. The Company continues to work toward closing its contemplated
transactions with Genesis involving the Companys NEJD and Free
State CO2 Pipelines,
including a long-term transportation service arrangement for the Free State line and a 20-year
financing lease for the NEJD system. In these transactions, Denbury expects to receive from Genesis
$225 million in cash and $25 million of Genesis common limited partnership units at the average
closing price of the units over the thirty days prior to closing. The Company anticipates
capitalizing these transactions for accounting purposes and currently projects that it will
initially pay Genesis approximately $30 million per annum under the financing lease and
transportation services agreement (a lesser pro-rated amount for 2008), with future payments for
the NEJD pipeline payments fixed at $20.7 million per year during the term of the financing lease,
and the payments
relating to the Free State Pipeline dependant on the volumes of CO2 transported therein.
While the business terms of the
transactions have been substantially completed, closing remains subject to finalization of legal
issues primarily with Genesis lenders, and completion and delivery of closing documentation.
Capital Resources and Liquidity
Our current 2008 capital exploration and development budget is approximately $900 million,
excluding any potential acquisitions. The current 2008 program includes an estimated $245 million
to acquire pipe and right-of-ways for our proposed CO2 pipeline from Louisiana to Texas
(the Green Pipeline) and another $80 million for the segment of the Delta CO2 Pipeline
from Tinsley to Delhi Fields. We expect to spend an additional $450 million constructing the Green
Pipeline during 2009, making our current anticipated total cost for that line approximately $700
million. Currently, over 50% of the remaining portion of our 2008 budget is expected to be spent
on other tertiary related operations, over 25% in the Barnett Shale area, and the balance in other
areas.
Last fall when we set our initial 2008 capital budget, our capital budget was forecasted to be
significantly in excess of our projected cash flow from operations. However, with the significant
increases in commodity prices since that time and based on oil and natural gas commodity prices as
of late April 2008, we currently project that our 2008 cash flow should be sufficient to fund most,
if not all, of our current 2008 capital budget. We are still working to close the anticipated
pipeline transactions with Genesis (see Overview Genesis Transactions), which if consummated,
will provide us with $225 million of additional long-term financing and it is possible that we
could generate additional funds through
supplemental transactions with Genesis late in 2008 relating to our Delta CO2 Pipeline,
or portions thereof. These
potential incremental funds from Genesis would provide us with a significant cushion should
commodity prices significantly decrease from current levels during the remainder of the year. Even
if these Genesis transactions are not consummated, we have significant availability under our bank
credit facility which we could use to fund our expenditures if needed. We could also consider
reducing our capital budget if necessary.
As part of our semi-annual bank review, our bank borrowing base was increased as of April 1,
2008 from $500 million to $1.0 billion as a result of our continued growth, along with the higher
commodity prices. 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 ($1.0 billion), although
the banks are not
17
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
obligated to fund any amount in excess of the commitment amount. At April 30, 2008, we had
outstanding $525 million (principal amount) of 7.5% subordinated notes and $131 million of bank
debt.
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.
Sources and Uses of Capital Resources
|
|
|
|
|
|
|
|
|
Capital Expenditure Summary |
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands |
|
2008 |
|
|
2007 |
|
Oil and gas exploration and development |
|
|
|
|
|
|
|
|
Drilling |
|
$ |
67,291 |
|
|
$ |
74,153 |
|
Geological, geophysical and acreage |
|
|
4,942 |
|
|
|
7,540 |
|
Facilities |
|
|
44,342 |
|
|
|
25,710 |
|
Recompletions |
|
|
33,744 |
|
|
|
27,583 |
|
Capitalized interest |
|
|
5,983 |
|
|
|
4,033 |
|
|
|
|
|
|
|
|
Total oil and gas exploration and development expenditures |
|
|
156,302 |
|
|
|
139,019 |
|
Oil and gas property acquisitions |
|
|
402 |
|
|
|
39,137 |
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
156,704 |
|
|
|
178,156 |
|
CO2 capital expenditures, including capitalized interest |
|
|
42,526 |
|
|
|
31,416 |
|
|
|
|
|
|
|
|
Total |
|
$ |
199,230 |
|
|
$ |
209,572 |
|
|
|
|
|
|
|
|
Our
first quarter 2008 capital expenditures were essentially funded with $206.3 million of cash
flow from operations, as the $48.9 million of proceeds from the second closing on our Louisiana
property sale was used to reduce bank debt by $39.0 million during the first quarter, with the
balance of funds from the property sale primarily used to fund other net assets. Our first quarter
2007 capital expenditures were funded with $93.3 million of cash flow from operations, $96.0
million of bank borrowings, $18.9 million of cash and the balance funded with other working
capital.
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
which are recorded at fair value in our balance sheets, 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 2007 amounts reflected in
our Form 10-K filed in February 2008. Please refer to Managements Discussion and Analysis of
Financial Condition and Results of Operations Off-Balance Sheet Arrangements Commitments and
Obligations contained in our 2007 Form 10-K for further information regarding our commitments and
obligations.
18
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 2007 Form 10-K for further information regarding these matters.
During 2008 we plan to drill five additional CO2 source wells to further increase
our production capacity and
reserves. We estimate that we are currently capable of producing between 850 MMcf/d and 950
MMcf/d of
CO2. During
the first quarter of 2008 our CO2 production averaged
554 MMcf/d, as compared to an
average of approximately 448 MMcf/d during the first quarter of 2007. We used 86% of this
production, or 476 MMcf/d, in our tertiary operations during the first quarter of 2008, and sold
the balance to our industrial customers or to Genesis pursuant to our volumetric production
payments.
Oil production from our tertiary operations averaged of 17,156 BOE/d in the first quarter of
2008, a 46% increase over our first quarter 2007 tertiary production level of 11,779 BOE/d. This
increase resulted from production increases during 2007 in almost every tertiary field except
Little Creek Field as more completely described in our 2007 Form 10-K. However, tertiary oil
production was slightly lower than our fourth quarter 2007 tertiary production level of 17,428
BOE/d as a result of various operational issues and delays, coupled with normal and expected
fluctuations in the forecasted production growth curve.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
First |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Quarter |
|
Tertiary Oil Field |
|
2007 |
|
|
2007 |
|
|
2007 |
|
|
2007 |
|
|
|
2008 |
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
1,422 |
|
|
|
1,794 |
|
|
|
2,452 |
|
|
|
2,507 |
|
|
|
|
2,638 |
|
Little Creek area |
|
|
2,117 |
|
|
|
1,974 |
|
|
|
2,011 |
|
|
|
1,957 |
|
|
|
|
1,807 |
|
Mallalieu area |
|
|
5,470 |
|
|
|
5,802 |
|
|
|
5,823 |
|
|
|
6,304 |
|
|
|
|
6,099 |
|
McComb area |
|
|
1,811 |
|
|
|
1,884 |
|
|
|
1,853 |
|
|
|
2,096 |
|
|
|
|
1,632 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
320 |
|
|
|
521 |
|
|
|
1,101 |
|
|
|
883 |
|
|
|
|
793 |
|
Eucutta |
|
|
614 |
|
|
|
1,338 |
|
|
|
2,035 |
|
|
|
2,572 |
|
|
|
|
2,699 |
|
Soso |
|
|
25 |
|
|
|
370 |
|
|
|
826 |
|
|
|
1,109 |
|
|
|
|
1,488 |
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
11,779 |
|
|
|
13,683 |
|
|
|
16,101 |
|
|
|
17,428 |
|
|
|
|
17,156 |
|
|
|
|
|
|
|
|
|
|
We
spent approximately $0.22 per Mcf to produce our CO2 during the first quarter of
2008, higher than our 2007
average of $0.17 per Mcf, primarily due to higher operating costs and increased royalty expense due
to higher oil prices in
the first quarter of 2008. Due to these same reasons, our estimated total cost per thousand
cubic feet of
CO2 during the
first quarter of 2008 was approximately $0.30, after inclusion of depreciation and amortization
expense, also up from the 2007 average of $0.25 per Mcf.
During the first quarter of 2008, our operating costs for our tertiary properties averaged
$20.81 per BOE, higher than the prior years first quarter average of $20.27 per BOE, and our
fourth quarter 2007 average of $19.90 per BOE. The
higher costs are primarily due to general cost inflation in the industry and higher CO2
costs, higher fuel and energy costs
and higher rental payments on leased equipment, partially offset by the change in accounting
discussed in the below paragraph. We do 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 2008,
operating costs per BOE for our Phase I properties, which are generally more developed than our
Phase II properties, were $19.85 per BOE, as compared to tertiary operating costs of $23.18 per BOE
for Phase II, an area which is just beginning to respond. In comparison, our operating costs for
19
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Mallalieu Field, currently our highest volume tertiary producer, was $12.68 per BOE during the same
period. We expect our operating costs to average between $15 and $20 per BOE over the life of a
tertiary flood, even though our recent average tertiary operating costs have been higher because
several floods are not yet mature.
Prior to January 1, 2008, we expensed currently all costs associated with injecting
CO2 that we use in our tertiary
recovery operations, even though some of these costs were incurred prior to any tertiary related
oil production. Commencing January 1, 2008, we began capitalizing, as a development cost, injection
costs in fields that are in their
development stage, which means we have not yet seen incremental oil production due to the
CO2 injections (i.e. a
production response). These capitalized development costs are included in our unevaluated property
costs within our full cost pool if there are not already proved tertiary reserves in that field.
After we see a production response to the CO2 injections (i.e. the production stage),
injection costs will be expensed as incurred, and any previously deferred unevaluated development
costs will become subject to depletion upon recognition of proved tertiary reserves. Since we are
continuing to initiate new tertiary floods, this means that we are now capitalizing certain costs
that we would have expensed historically. Had we continued with the prior accounting methodology
of expensing all tertiary injectant costs, we would have expensed an additional $2.9 million or
$1.84 per BOE (tertiary properties only), as there were significant injectant costs during the
period in new tertiary floods without tertiary related oil production, primarily in the two new
tertiary floods at Tinsley and Lockhart Crossing Fields. During the first quarter of 2007, the
accounting methodology was not material, as only $116,000 would have been capitalized under the new
accounting procedure.
Operating Results
As summarized in the Overview section above and discussed in more detail below, higher
commodity prices and higher production in the 2008 period more than offset higher expenses,
resulting in significantly higher quarterly earnings.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
Amounts in
thousands, except per share amounts |
|
2008 |
|
2007 |
Net income |
|
$ |
73,002 |
|
|
$ |
16,616 |
|
Net income per common share basic |
|
|
0.30 |
|
|
|
0.07 |
|
Net income per common share diluted |
|
|
0.29 |
|
|
|
0.07 |
|
Cash flow from operations |
|
|
206,257 |
|
|
|
93,345 |
|
|
20
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 2008 and
2007 are included in the following table.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
Bbls/d |
|
|
30,164 |
|
|
|
24,054 |
|
Mcf/d |
|
|
88,419 |
|
|
|
85,506 |
|
BOE/d (1) |
|
|
44,900 |
|
|
|
38,305 |
|
|
|
|
|
|
|
|
|
|
Operating revenues (in thousands) |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
250,441 |
|
|
$ |
118,132 |
|
Natural gas sales |
|
|
62,756 |
|
|
|
51,002 |
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
313,197 |
|
|
$ |
169,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative contracts (2) (in thousands) |
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
(8,048 |
) |
|
$ |
8,251 |
|
Non-cash fair
value adjustment expense |
|
|
(38,733 |
) |
|
|
(35,158 |
) |
|
|
|
|
|
|
|
Total expense from oil and gas derivative contracts |
|
$ |
(46,781 |
) |
|
$ |
(26,907 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (in thousands) |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
66,001 |
|
|
$ |
50,557 |
|
Production taxes and marketing expenses (3) |
|
|
16,736 |
|
|
|
10,204 |
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
82,737 |
|
|
$ |
60,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary
CO2 operating margin (in thousands) |
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
2,851 |
|
|
$ |
3,091 |
|
CO2 operating expenses |
|
|
(1,143 |
) |
|
|
(703 |
) |
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
1,708 |
|
|
$ |
2,388 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
88.55 |
|
|
$ |
54.63 |
|
Gas price per Mcf |
|
|
7.72 |
|
|
|
7.68 |
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
91.24 |
|
|
$ |
54.57 |
|
Gas price per Mcf |
|
|
7.80 |
|
|
|
6.63 |
|
|
|
|
|
|
|
|
|
|
Oil and gas operating revenues and expenses per BOE (1) |
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
76.65 |
|
|
$ |
49.06 |
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
16.15 |
|
|
$ |
14.66 |
|
Oil and gas production taxes and marketing expenses |
|
|
4.10 |
|
|
|
2.96 |
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
20.25 |
|
|
$ |
17.62 |
|
|
|
|
|
|
|
|
|
|
|
(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 expense Genesis. |
|
(4) |
|
Includes deferred revenue of $1.0 million for both periods associated with volumetric
production payments and $1.3 million and $1.1 million for 2008 and 2007, respectively, of
transportation income, both from Genesis. |
21
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Average daily production by area for each of the quarters of 2007 and the
first quarter of 2008 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
Operating Area |
|
2007 |
|
2007 |
|
2007 |
|
2007 |
|
|
2008 |
|
|
|
|
|
|
Mississippi CO2 floods |
|
|
11,779 |
|
|
|
13,683 |
|
|
|
16,101 |
|
|
|
17,428 |
|
|
|
|
17,156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi non CO2 floods |
|
|
12,738 |
|
|
|
12,525 |
|
|
|
12,131 |
|
|
|
12,530 |
|
|
|
|
12,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
6,989 |
|
|
|
9,048 |
|
|
|
10,695 |
|
|
|
13,488 |
|
|
|
|
13,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
5,591 |
|
|
|
5,391 |
|
|
|
5,546 |
|
|
|
5,638 |
|
|
|
|
905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama and other |
|
|
1,208 |
|
|
|
1,269 |
|
|
|
1,247 |
|
|
|
1,287 |
|
|
|
|
1,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
38,305 |
|
|
|
41,916 |
|
|
|
45,720 |
|
|
|
50,371 |
|
|
|
|
44,900 |
|
|
|
|
|
|
|
As outlined in the above table, production in the first quarter of 2008 increased 17% over
first quarter of 2007 levels but decreased 11% over fourth quarter 2007 levels primarily due to the
sale of our onshore Louisiana natural gas properties, of which approximately 70% closed in late
December 2007 and approximately 30% in February 2008. The sold Louisiana properties contributed
production of 5,097 BOE/d to our fourth quarter of 2007 production and 302 BOE/d to our first
quarter of 2008 production, representing the production from those sold properties prior to their
closing dates in December 2007 and February 2008. The sale accounts for almost all of the
production fluctuations in the onshore Louisiana area above.
Excluding the Louisiana property sale, the production increase from the first quarter of 2007
is primarily due to increased production from our tertiary operations and from the Barnett Shale,
offset in part by decreases in our Mississippi-non CO2 floods. The increase in our
tertiary operations is discussed above under Results of
Operations CO2 Operations.
Production in the Mississippi non-CO2 floods area decreased from the prior years
first quarter as this area is generally on a gradual decline due to normal depletion; however, 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 84% from the prior years first quarter
level due to our successful drilling activity. During 2006 and 2007, we drilled between 45 and 50
wells each year and we plan to do the same in 2008. Since these wells are characterized by high
depletion rates, particularly in their first year of production, we anticipate that our production
there during 2008 will be relatively flat to that in the fourth quarter of 2007 production levels
at this drilling pace. This trend is evident in that the Barnet Shale production was almost the
same in the first quarter of 2008 (12,801 BOE/d) as it was during the fourth quarter of 2007
(12,729 BOE/d), although both are significantly higher than a year ago. The Texas property
acquisition we made late in the first quarter of 2007 contributed approximately 721 BOE/d to the
first quarter 2008 production.
Oil and Natural Gas Revenues: Oil and natural gas revenues for the first quarter of 2008
increased $144.1 million, or 85%, from revenues in the first quarter of 2007, due to higher
commodity prices and higher production. The increase in overall commodity prices in the first
quarter of 2008 increased revenues by $112.8 million, or 67%, when compared to revenues in the
first quarter of 2007, while the increase in production in the first quarter of 2008 increased oil
and natural gas revenues by $31.3 million, or 18%, as compared to the prior years first quarter.
Our realized natural gas prices (excluding derivative contracts) for the first quarter of 2008
averaged $7.80 per Mcf, an 18% increase from the average of $6.63 per Mcf realized during the first
quarter of 2007, and our realized oil prices (excluding derivative contracts) for the first quarter of 2008
averaged $91.24 per Bbl, a 67% increase from the $54.57 per Bbl average realized in the first
quarter of 2007.
22
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
On a combined per BOE basis, our realized commodity prices were 56% higher in the first quarter of
2008 than in the first quarter of 2007.
Excluding any impact of our hedging activities, our net realized commodity prices and NYMEX
differentials were as follows during the first three months of 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2008 |
|
2007 |
Net Realized Prices: |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
91.24 |
|
|
$ |
54.57 |
|
Gas price per Mcf |
|
|
7.80 |
|
|
|
6.63 |
|
Price per BOE |
|
|
76.65 |
|
|
|
49.06 |
|
|
|
|
|
|
|
|
|
|
NYMEX Differentials: |
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(6.50 |
) |
|
$ |
(3.73 |
) |
Natural Gas per Mcf |
|
|
(0.90 |
) |
|
|
(0.51 |
) |
Our oil NYMEX differential during the first three quarters of 2007 was the lowest in our
corporate history. The improved NYMEX differential during 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. This trend reversed itself by the
fourth quarter of 2007, with average NYMEX oil differentials during that quarter of $(7.27) per
Bbl, higher than our historical averages due to the significant increase in liquids extracted from
our natural gas production in the Barnett Shale, which is recorded as oil production, but sells at
a significant discount to NYMEX. The differentials for the first quarter of 2008 improved slightly
over fourth quarter of 2007 levels due to normal market fluctuations and minor improvements in
certain oil contracts and slightly less Barnett Shale liquid production.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during a month, as most of our natural gas is sold on an index price that is set near the
first of the month. The sale of our Louisiana natural gas properties also contributed to a higher
or worse differential during the first quarter of 2008, as we typically received higher than NYMEX
prices for the natural gas produced from these sold properties.
Oil and Natural Gas Derivative Contracts: We made cash payments of $8.0 million on settlements
of our oil and natural gas derivative contracts during the first quarter of 2008, as compared to
net cash receipts of $8.3 million during the first quarter of 2007, a negative differential of
$16.3 million. The payments made in the first quarter of 2008 primarily related to the 2,000 Bbl/d
oil swaps for 2008 entered into when we made a large acquisition in January 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.
Our total mark-to-market expense was $38.7 million during the first quarter of 2008, slightly
higher than the $35.2 million charge in the first quarter of 2007. Both of the non-cash charges
primarily relate to natural gas swaps for that calendar year entered into the year before, and the
resultant decline in value for those swaps as a result of an increase in natural gas prices during
both first quarters. 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, 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, and (v) increasing lease payments for
certain equipment in our tertiary operating facilities.
23
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
During the first quarter of 2008, operating costs averaged $16.15 per BOE, up from $14.66 per
BOE in the first quarter of 2007, and up from $13.78 per BOE in the fourth quarter of 2007. A
significant portion of the increase in per BOE expenses in the first quarter of 2008 resulted from
the sale of our Louisiana natural gas properties. If the sold properties were excluded from the
first quarter of 2007 results, our operating costs during that period would have been approximately
$1.41 per BOE higher than reported, or $16.07 per BOE, much more in line with the first quarter of
2008 operating costs per BOE.
Effective January 1, 2008, we changed the way we account for certain tertiary costs (see
Results of Operations CO2 Operations above). Had we continued with the prior
accounting methodology of expensing all tertiary injectant costs, we would have expensed an
additional $2.9 million, or approximately $0.70 per BOE, as there were significant injectant costs,
primarily at two new tertiary floods at Tinsley and Lockhart Crossing Fields which had not yet
shown a production response to the CO2 injections.
Operating expenses on our tertiary operations increased from $21.5 million in the first
quarter of 2007 to $32.5 million during the first quarter of 2008, as a result of our increased
tertiary activity level. Tertiary operating expenses were particularly impacted by higher power
and energy costs, higher costs for CO2 and payments on leased equipment (see
CO2 Operations above). We expect this increase in tertiary operating costs to
continue and to 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 2008 than in the comparable
quarter of 2007. Transportation and plant processing fees were about $1.7 million higher in the
first quarter of 2008 than in the first quarter of 2007, largely associated with the incremental
production and incremental plant processing fees related to our Barnett Shale production.
General and Administrative Expenses
General and administrative (G&A) expenses increased 40% between the respective first
quarters as set forth below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE data and employees |
|
2008 |
|
|
2007 |
|
Gross G&A expense |
|
$ |
34,165 |
|
|
$ |
26,770 |
|
State franchise taxes |
|
|
828 |
|
|
|
718 |
|
Operator labor and overhead recovery charges |
|
|
(15,953 |
) |
|
|
(13,806 |
) |
Capitalized exploration and development costs |
|
|
(3,035 |
) |
|
|
(2,248 |
) |
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
16,005 |
|
|
$ |
11,434 |
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.92 |
|
|
$ |
3.32 |
|
Employees as of March 31 |
|
|
701 |
|
|
|
629 |
|
|
|
|
|
|
|
|
Gross G&A expenses increased $7.4 million, or 28%, between the first quarters of 2007 and
2008. Approximately $7.0 million of the increase in gross G&A expenses is related to increases in
compensation and personnel related costs, due primarily to the increase in employees and salary
increases, which we consider necessary in order to remain competitive in our industry. During
2007, we increased our employee count by 15% and we further increased our employee count by
approximately 2% during the first quarter of 2008. Stock compensation expense reflected in gross
G&A expenses was approximately $4.5 million for the first quarter of 2008 and $3.1 million for the
first quarter of 2007.
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 2008. 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 16% between the first quarters of 2007 and 2008. Capitalized
exploration and development costs also increased between the comparable periods in 2007 and 2008,
primarily due to additional personnel and increased compensation costs.
24
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The net effect was a 40% increase in net G&A expense between the respective first quarters.
On a per BOE basis, G&A costs increased 18% in the first quarter of 2008 as compared to levels of
those costs in the first quarter of 2007, 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 |
|
2008 |
|
|
2007 |
|
Cash interest expense |
|
$ |
11,800 |
|
|
$ |
9,839 |
|
Non-cash interest expense |
|
|
407 |
|
|
|
269 |
|
Less: Capitalized interest |
|
|
(7,266 |
) |
|
|
(4,033 |
) |
|
|
|
|
|
|
|
Interest expense |
|
$ |
4,941 |
|
|
$ |
6,075 |
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
1,287 |
|
|
$ |
1,930 |
|
Average net cash interest expense per BOE (1) |
|
$ |
0.84 |
|
|
$ |
1.18 |
|
Average debt outstanding |
|
$ |
661,809 |
|
|
$ |
530,586 |
|
Average interest rate (2) |
|
|
7.1 |
% |
|
|
7.4 |
% |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest and other income on a BOE basis. |
|
(2) |
|
Includes commitment fees but excludes amortization of premium, discount and debt issue costs. |
Interest expense decreased $1.1 million, or 19%, comparing the first quarters of 2007 and
2008, primarily as a result of a $3.2 million increase in capitalized interest between the first
quarter of 2007 and 2008. Our interest capitalization increased because of our growing balance of
unevaluated property expenditures related to our CO2 tertiary floods without proved
reserves, the largest of which is Tinsley Field, and the construction of our new CO2
pipelines. The increase in capitalized interest was partially offset by a 25% 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 |
|
2008 |
|
|
2007 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
44,190 |
|
|
$ |
35,966 |
|
Depletion and depreciation of CO2 assets |
|
|
3,022 |
|
|
|
2,680 |
|
Asset retirement obligations |
|
|
762 |
|
|
|
730 |
|
Depreciation of other fixed assets |
|
|
1,865 |
|
|
|
1,651 |
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
49,839 |
|
|
$ |
41,027 |
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.00 |
|
|
$ |
10.64 |
|
CO2 assets and other fixed assets |
|
|
1.20 |
|
|
|
1.26 |
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
12.20 |
|
|
$ |
11.90 |
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization (DD&A) rate on a per BOE basis increased 1%
over the fourth quarter of 2007 DD&A rate of $12.05 per BOE, and increased 3% between the
respective first quarters, primarily due to capital spending and increased costs and the lack of
any significant incremental proved tertiary reserves to date in 2008. During 2007, we initiated
floods at Lockhart Crossing (Phase I), Tinsley (Phase III) and Cranfield (Phase IV), but through
March 31, 2008 had not seen a production response, nor had we booked any proved tertiary reserves
at these fields. We anticipate recording significant additional proved tertiary reserves by the
end of 2008. 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
25
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 decreased in the
first quarter of 2008 as compared to the rate in the comparable quarter in 2007, primarily as a
result of the capitalization of approximately $759,000 of DD&A costs associated with the
CO2 that was injected into new floods, primarily Tinsley and Lockhart Crossing Fields,
and DD&A associated with the CO2 pipelines for those fields if the pipeline was
exclusive to that field. Commencing January 1, 2008, we began capitalizing costs incurred to
inject CO2 into fields that were in the development stage and had not yet shown a
production response to the CO2 (see Results of Operations CO2
Operations).
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2008 |
|
|
2007 |
|
Current income tax expense |
|
$ |
21,236 |
|
|
$ |
1,618 |
|
Deferred income tax provision |
|
|
21,651 |
|
|
|
9,014 |
|
|
|
|
|
|
|
|
Total income tax provision |
|
$ |
42,887 |
|
|
$ |
10,632 |
|
|
|
|
|
|
|
|
Average income tax expense per BOE |
|
$ |
10.50 |
|
|
$ |
3.08 |
|
Effective tax rate |
|
|
37.0 |
% |
|
|
39.0 |
% |
|
|
|
|
|
|
|
In the fourth quarter of 2007, we lowered our estimated statutory income tax rate to 38% from
39% as result of our sale of our Louisiana natural gas assets. During the first quarter of 2008,
our effective rate was further reduced primarily as a result of higher section 199 deductions
because of our higher pretax income. The current tax portion of our income tax expense increased
in the first quarter of 2008 as compared to the first quarter of 2007 as a result of the higher
pretax income resulting from higher commodity prices and the lack of any taxable deductions on most
of our 2008 CO2 pipeline expenditures (a significant portion of our 2008 capital
spending) as they will not be placed into service during the current year. In the first quarter of
2007, 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, 2007, we had an estimated
$37 million of enhanced oil recovery credits to carry forward that we can utilize to reduce our
current income taxes during 2008. 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.
26
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Per BOE data |
|
2008 |
|
|
2007 |
|
Oil and natural gas revenues |
|
$ |
76.65 |
|
|
$ |
49.06 |
|
Gain (loss) on settlements of derivative contracts |
|
|
(1.97 |
) |
|
|
2.39 |
|
Lease operating expenses |
|
|
(16.15 |
) |
|
|
(14.66 |
) |
Production taxes and marketing expenses |
|
|
(4.10 |
) |
|
|
(2.96 |
) |
|
|
|
|
|
|
|
Production netback |
|
|
54.43 |
|
|
|
33.83 |
|
Non-tertiary CO2 operating margin |
|
|
0.42 |
|
|
|
0.69 |
|
General and administrative expenses |
|
|
(3.92 |
) |
|
|
(3.32 |
) |
Net cash interest expense |
|
|
(0.84 |
) |
|
|
(1.18 |
) |
Current income taxes and other |
|
|
(4.39 |
) |
|
|
0.22 |
|
Changes in assets and liabilities relating to operations |
|
|
4.78 |
|
|
|
(3.16 |
) |
|
|
|
|
|
|
|
Cash flow from operations |
|
|
50.48 |
|
|
|
27.08 |
|
DD&A |
|
|
(12.20 |
) |
|
|
(11.90 |
) |
Deferred income taxes |
|
|
(5.30 |
) |
|
|
(2.61 |
) |
Non-cash commodity derivative adjustments |
|
|
(9.48 |
) |
|
|
(10.20 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
(5.63 |
) |
|
|
2.45 |
|
|
|
|
|
|
|
|
Net income |
|
$ |
17.87 |
|
|
$ |
4.82 |
|
|
|
|
|
|
|
|
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. We had $111
million of bank debt outstanding as of March 31, 2008 and $150 million at December 31, 2007. 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. The following table
presents the carrying and fair values of our debt as of March 31, 2008, along with average interest
rates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
Amounts in thousands |
|
2011 |
|
2013 |
|
2015 |
|
Value |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted average interest rate of 4.1% at
March 31, 2008) |
|
$ |
111,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
111,000 |
|
|
$ |
111,000 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated
debt due 2013 (fixed rate of 7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
224,028 |
|
|
|
230,063 |
|
7.5% subordinated debt due 2015 (fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
300,664 |
|
|
|
306,750 |
|
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, 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 enter into natural gas derivative contracts
in late 2006 when we swapped 80% to 90% of our forecasted 2007 natural gas
27
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
production at a weighted average price of $7.96 per Mcf, and in September 2007 we swapped 70% to
80% of our remaining forecasted 2008 natural gas production after the sale of our Louisiana natural
gas properties at a weighted average price of $7.91 per Mcf. We did this to protect our 2008
projected cash flow, primarily because we initially planned to spend $200 million to $250 million
more than we expected to generate in cash flow from operations and we did not want to be exposed to
the risk of potentially lower natural gas prices. As a result of the higher oil prices, we
currently anticipate that our cash flow will exceed our current capital budget (see Capital
Resources and Liquidity).
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,
2008, 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 oil production at the time we signed the purchase and sale agreement.
While these derivative contracts related to the acquisition represent less than 10% of our
estimated 2008 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 2008 at a price of $57.34 per Bbl.
At March 31, 2008, our derivative contracts were recorded at fair value, which was a liability
of approximately $62.1 million, an increase in liability of approximately $38.8 million from the
$23.3 million fair value liability recorded as of December 31, 2007. This change is the result of
an increase in oil and natural gas commodity futures prices between December 31, 2007 and March 31,
2008.
Based on NYMEX crude oil futures prices at March 31, 2008, we would expect to make future cash
payments of $23.3 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 $17.8
million, and if futures prices were to increase by 10% we would expect to pay $28.8 million. Based
on NYMEX natural gas futures prices at March 31, 2008, we would expect to make future cash payments
of $39.3 million on our natural gas commodity hedges. If natural gas futures prices were to
decline by 10%, we would expect to make future cash payments of $22.3 million and if futures prices
were to increase by 10% we would expect to pay $56.3 million.
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, 2007.
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
28
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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.
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, 2007. 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, 2007. 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.
29
DENBURY RESOURCES INC.
Item 6. Exhibits
Exhibits:
|
|
|
10(a)*
|
|
Amendment for Increased Borrowing Base from $500 million to $1.0 billion 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 28, 2008. |
|
|
|
10(b)*
|
|
2008 Form of restricted stock award to certain officers that cliff vests on March 31,
2011 pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
10(c)*
|
|
2008 Form of restricted stock award without change of control vesting to certain
officers that cliff vests on March 31, 2011 pursuant to 2004 Omnibus Stock and
Incentive Plan for Denbury Resources Inc. |
|
|
|
10(d)*
|
|
2008 Form of performance share awards to certain officers pursuant to 2004 Omnibus
Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
10(e)*
|
|
2008 Form of performance share awards without change of control vesting to certain
officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
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31(a)*
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Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31(b)*
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Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32*
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Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
30
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.
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DENBURY RESOURCES INC.
(Registrant)
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By: |
/s/ Phil Rykhoek
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Phil Rykhoek |
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Sr. Vice President and Chief Financial Officer |
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By: |
/s/ Mark C. Allen
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Mark C. Allen |
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Vice President and Chief Accounting Officer |
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Date: May 6, 2008
31