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 September 30, 2007
or
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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 |
For the transition period from to
Commission File Number: 001-16295
ENCORE ACQUISITION COMPANY
(Exact name of registrant as specified in its charter)
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Delaware
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75-2759650 |
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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777 Main Street, Suite 1400, Fort Worth, Texas
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76102 |
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(Address of principal executive offices)
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(Zip Code) |
(817) 877-9955
(Registrants telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
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Number of shares of common stock, $0.01 par value, outstanding as of October 31, 2007 |
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54,238,182 |
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ENCORE ACQUISITION COMPANY
INDEX
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Certain information included in this Quarterly Report on Form 10-Q (the Report) and other
materials filed with the Securities and Exchange Commission (SEC), or in other written or oral
statements made or to be made by us, other than statements of historical fact, are forward-looking
statements as defined by the safe harbor provisions of the Private Securities Litigation Reform Act
of 1995. These forward-looking statements give our current expectations or forecasts of future
events. You can identify our forward-looking statements by the fact that they do not relate
strictly to historical or current facts. These statements may include words such as may, will,
could, anticipate, estimate, expect, project, intend, plan, believe, should,
predict, potential, pursue, target, continue, and other words and terms of similar
meaning. Our actual results may differ significantly from the results discussed in the
forward-looking statements. Such statements involve risks and uncertainties, including, but not
limited to, the matters discussed in Item 1A. Risk Factors in our Annual Report on Form 10-K for
the year ended December 31, 2006 and in our other filings with the SEC. If one or more of these
risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual
outcomes may vary materially from those indicated. You should not place undue reliance on
forward-looking statements. Each forward-looking statement speaks only as of the date of the
particular statement. We undertake no responsibility to update forward-looking statements for
changes related to these or any other factors that may occur subsequent to this filing for any
reason.
i
ENCORE ACQUISITION COMPANY
GLOSSARY OF CERTAIN TERMS
The following are abbreviations and definitions of certain terms used in this Report. The
definitions of proved developed reserves and proved reserves have been abbreviated from the
applicable definitions contained in Rule 4-10(a)(2-3) of Regulation S-X.
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Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil
or other liquid hydrocarbons. |
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Bbl/D. One Bbl per day. |
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BOE. One barrel of oil equivalent, calculated by converting natural gas to oil
equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. |
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BOE/D. One BOE per day. |
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Council of Petroleum Accountants Societies, or COPAS. A professional organization of
oil and gas accountants that maintains consistency in accounting procedures and
interpretations, including the procedures that are part of most joint operating agreements.
These procedures establish a drilling rate and an overhead rate to reimburse the operator
of a well for overhead costs, such as accounting and engineering. |
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EAC. Encore Acquisition Company, a Delaware corporation, together with its
subsidiaries. |
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ENP. Encore Energy Partners LP, a publicly traded Delaware limited partnership,
together with its subsidiaries. |
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Gross Wells. The total number of wells in which we own a working interest. |
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High-Pressure Air Injection (HPAI). HPAI involves utilizing compressors to force air
under high pressure into previously produced oil and natural gas formations in order to
displace remaining resident hydrocarbons and force them under pressure to a common lifting
point for production. |
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LIBOR. London Interbank Offered Rate. |
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MBbls. One thousand Bbls. |
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MBOE. One thousand BOE. |
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Mcf. One thousand cubic feet of natural gas. |
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Mcf/D. One Mcf per day. |
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Net Wells. Gross wells multiplied by the percentage of the working interest owned by
us. |
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NGLs. Natural gas liquids. |
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NYMEX. New York Mercantile Exchange. |
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Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. |
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Proved Reserves. The estimated quantities of oil, natural gas, and NGLs that geological
and engineering data demonstrate with reasonable certainty are recoverable in future years
from known reservoirs under existing economic and operating conditions. |
ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
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September 30, |
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December 31, |
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2007 |
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2006 |
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(unaudited) |
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ASSETS |
Current assets: |
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Cash and cash equivalents |
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$ |
8,467 |
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$ |
763 |
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Accounts receivable |
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105,871 |
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81,470 |
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Inventory |
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19,149 |
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18,170 |
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Derivatives |
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13,533 |
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17,349 |
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Deferred taxes |
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18,851 |
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24,978 |
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Prepaid
expenses and other |
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6,769 |
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2,988 |
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Total current assets |
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172,640 |
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145,718 |
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Properties and equipment, at cost successful efforts method: |
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Proved properties, including wells and related equipment |
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2,740,805 |
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2,033,914 |
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Unproved properties |
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56,427 |
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47,548 |
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Accumulated depletion, depreciation, and amortization |
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(442,393 |
) |
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(364,780 |
) |
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2,354,839 |
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1,716,682 |
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Other property and equipment |
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20,539 |
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18,231 |
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Accumulated depreciation |
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(10,041 |
) |
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(7,791 |
) |
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10,498 |
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10,440 |
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Goodwill |
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60,606 |
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60,606 |
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Derivatives |
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25,020 |
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40,715 |
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Long-term receivables |
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47,031 |
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19,642 |
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Other |
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29,166 |
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13,097 |
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Total assets |
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$ |
2,699,800 |
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$ |
2,006,900 |
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current liabilities: |
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Accounts payable |
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$ |
32,913 |
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$ |
18,204 |
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Accrued liabilities: |
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Lease operations expense |
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12,265 |
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8,582 |
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Development capital |
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34,911 |
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44,492 |
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Interest |
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13,365 |
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11,273 |
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Production, ad valorem, and severance taxes |
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23,434 |
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10,915 |
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Oil purchases |
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705 |
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11,191 |
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Derivatives |
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44,002 |
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60,448 |
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Other |
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23,980 |
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21,358 |
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Total current liabilities |
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185,575 |
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186,463 |
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Derivatives |
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27,915 |
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38,688 |
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Future abandonment cost |
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28,177 |
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19,205 |
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Deferred taxes |
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294,971 |
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282,825 |
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Long-term debt |
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1,139,099 |
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661,696 |
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Other |
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1,326 |
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1,158 |
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Total liabilities |
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1,677,063 |
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1,190,035 |
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Commitments and contingencies (see Note 14) |
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Minority interest in consolidated partnership |
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181,412 |
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Stockholders equity: |
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Preferred stock, $.01 par value, 5,000,000 shares authorized,
none issued and outstanding |
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Common stock, $.01 par value, 144,000,000 shares authorized,
53,217,560 and 53,028,866 issued and outstanding, respectively |
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533 |
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531 |
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Additional paid-in capital |
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458,989 |
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457,201 |
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Treasury stock, at cost, none and 17,809 shares, respectively |
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(457 |
) |
Retained earnings |
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391,980 |
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394,917 |
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Accumulated other comprehensive loss |
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(10,177 |
) |
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(35,327 |
) |
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Total stockholders equity |
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841,325 |
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816,865 |
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Total liabilities and stockholders equity |
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$ |
2,699,800 |
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$ |
2,006,900 |
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The accompanying notes are an integral part of these consolidated financial statements.
1
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
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Three months ended |
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Nine months ended |
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September 30, |
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September 30, |
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2007 |
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2006 |
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2007 |
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2006 |
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Revenues: |
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Oil |
|
$ |
159,295 |
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$ |
99,516 |
|
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$ |
377,514 |
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$ |
268,066 |
|
Natural gas |
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|
32,439 |
|
|
|
32,177 |
|
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|
110,548 |
|
|
|
109,050 |
|
Marketing |
|
|
3,282 |
|
|
|
46,004 |
|
|
|
27,139 |
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106,036 |
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Total revenues |
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|
195,016 |
|
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|
177,697 |
|
|
|
515,201 |
|
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|
483,152 |
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Expenses: |
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Production: |
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Lease operations |
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37,114 |
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|
24,478 |
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|
|
105,186 |
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|
70,332 |
|
Production, ad valorem, and severance taxes |
|
|
20,003 |
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|
13,560 |
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|
|
51,750 |
|
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|
38,382 |
|
Depletion, depreciation, and amortization |
|
|
49,026 |
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|
|
27,471 |
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|
|
136,372 |
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|
|
82,479 |
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Exploration |
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8,920 |
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|
12,322 |
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|
|
23,856 |
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|
18,347 |
|
General and administrative |
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|
12,668 |
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|
6,250 |
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|
26,216 |
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|
18,199 |
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Marketing |
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|
4,089 |
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|
48,001 |
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|
27,607 |
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|
|
105,661 |
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Derivative fair value loss (gain) |
|
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15,786 |
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(33,363 |
) |
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68,166 |
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(20,263 |
) |
Other operating |
|
|
6,351 |
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|
976 |
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13,667 |
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3,573 |
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Total expenses |
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153,957 |
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|
99,695 |
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452,820 |
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|
316,710 |
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Operating income |
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41,059 |
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78,002 |
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62,381 |
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166,442 |
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Other income (expenses): |
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Interest |
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(23,933 |
) |
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(11,261 |
) |
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(68,040 |
) |
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(33,766 |
) |
Other |
|
|
857 |
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|
|
463 |
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|
|
1,889 |
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|
1,012 |
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Total other income (expenses) |
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(23,076 |
) |
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(10,798 |
) |
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(66,151 |
) |
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(32,754 |
) |
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Income (loss) before income taxes and minority interest |
|
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17,983 |
|
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|
67,204 |
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(3,770 |
) |
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|
133,688 |
|
Income tax provision |
|
|
(8,986 |
) |
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|
(25,069 |
) |
|
|
(1,490 |
) |
|
|
(51,382 |
) |
Minority interest in loss of consolidated partnership |
|
|
2,988 |
|
|
|
|
|
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|
2,988 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net income (loss) |
|
$ |
11,985 |
|
|
$ |
42,135 |
|
|
$ |
(2,272 |
) |
|
$ |
82,306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Net income (loss) per common share: |
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|
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|
|
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|
|
|
|
|
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|
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|
Basic |
|
$ |
0.23 |
|
|
$ |
0.80 |
|
|
$ |
(0.04 |
) |
|
$ |
1.60 |
|
Diluted |
|
$ |
0.22 |
|
|
$ |
0.78 |
|
|
$ |
(0.04 |
) |
|
$ |
1.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
53,198 |
|
|
|
52,968 |
|
|
|
53,140 |
|
|
|
51,481 |
|
Diluted |
|
|
54,179 |
|
|
|
53,776 |
|
|
|
53,140 |
|
|
|
52,375 |
|
The accompanying notes are an integral part of these consolidated financial statements.
2
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
(in thousands)
(unaudited)
|
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Issued |
|
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Accumulated |
|
|
|
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|
Shares of |
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|
Additional |
|
|
Shares of |
|
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|
|
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Other |
|
|
Total |
|
|
|
Common |
|
|
Common |
|
|
Paid-in |
|
|
Treasury |
|
|
Treasury |
|
|
Retained |
|
|
Comprehensive |
|
|
Stockholders |
|
|
|
Stock |
|
|
Stock |
|
|
Capital |
|
|
Stock |
|
|
Stock |
|
|
Earnings |
|
|
Loss |
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006 |
|
|
53,047 |
|
|
$ |
531 |
|
|
$ |
457,201 |
|
|
|
(18 |
) |
|
$ |
(457 |
) |
|
$ |
394,917 |
|
|
$ |
(35,327 |
) |
|
$ |
816,865 |
|
Exercise of stock options and vesting
of restricted stock |
|
|
210 |
|
|
|
2 |
|
|
|
1,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,599 |
|
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21 |
) |
|
|
(546 |
) |
|
|
|
|
|
|
|
|
|
|
(546 |
) |
Cancellation of treasury stock |
|
|
(39 |
) |
|
|
|
|
|
|
(338 |
) |
|
|
39 |
|
|
|
1,003 |
|
|
|
(665 |
) |
|
|
|
|
|
|
|
|
Non-cash stock-based compensation |
|
|
|
|
|
|
|
|
|
|
11,513 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,513 |
|
EACs share of ENPs offering costs |
|
|
|
|
|
|
|
|
|
|
(10,984 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,984 |
) |
Components of comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,272 |
) |
|
|
|
|
|
|
(2,272 |
) |
Amortization of deferred hedge losses, net of
tax of $15,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,150 |
|
|
|
25,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2007 |
|
|
53,218 |
|
|
$ |
533 |
|
|
$ |
458,989 |
|
|
|
|
|
|
$ |
|
|
|
$ |
391,980 |
|
|
$ |
(10,177 |
) |
|
$ |
841,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,272 |
) |
|
$ |
82,306 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
136,372 |
|
|
|
82,479 |
|
Non-cash exploration expense |
|
|
22,511 |
|
|
|
12,542 |
|
Deferred taxes |
|
|
1,374 |
|
|
|
48,673 |
|
Non-cash stock-based compensation expense |
|
|
12,790 |
|
|
|
6,797 |
|
Non-cash derivative |
|
|
87,108 |
|
|
|
(13,013 |
) |
Loss on disposition of assets |
|
|
5,918 |
|
|
|
395 |
|
Minority interest in loss of consolidated partnership |
|
|
(2,988 |
) |
|
|
|
|
Other |
|
|
6,055 |
|
|
|
5,644 |
|
Changes in operating assets and liabilities, net of effects from acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(31,064 |
) |
|
|
11,579 |
|
Current derivatives |
|
|
(15,303 |
) |
|
|
(1,221 |
) |
Other current assets |
|
|
(1,858 |
) |
|
|
(3,472 |
) |
Long-term derivatives |
|
|
(22,301 |
) |
|
|
(29,097 |
) |
Other assets |
|
|
(4,428 |
) |
|
|
(4 |
) |
Accounts payable |
|
|
4,416 |
|
|
|
(2,047 |
) |
Other current liabilities |
|
|
17,810 |
|
|
|
19,188 |
|
Other noncurrent liabilities |
|
|
(496 |
) |
|
|
13,633 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
213,644 |
|
|
|
234,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from disposition of assets |
|
|
291,339 |
|
|
|
666 |
|
Purchases of other property and equipment |
|
|
(2,443 |
) |
|
|
(3,450 |
) |
Acquisition of oil and natural gas properties |
|
|
(839,945 |
) |
|
|
(22,809 |
) |
Development of oil and natural gas properties |
|
|
(259,457 |
) |
|
|
(241,502 |
) |
Net advances to working interest partners |
|
|
(22,644 |
) |
|
|
(8,667 |
) |
Other |
|
|
|
|
|
|
(1,509 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(833,150 |
) |
|
|
(277,271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs |
|
|
|
|
|
|
127,101 |
|
Proceeds from issuance of ENP common units, net of issuance costs |
|
|
171,220 |
|
|
|
|
|
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases |
|
|
1,053 |
|
|
|
3,151 |
|
Proceeds from long-term debt, net of issuance costs |
|
|
1,269,291 |
|
|
|
164,853 |
|
Payments on long-term debt |
|
|
(805,428 |
) |
|
|
(245,000 |
) |
Change in cash overdrafts |
|
|
10,293 |
|
|
|
(8,331 |
) |
Payment of deferred hedge premiums |
|
|
(19,219 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
627,210 |
|
|
|
41,774 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
7,704 |
|
|
|
(1,115 |
) |
Cash and cash equivalents, beginning of period |
|
|
763 |
|
|
|
1,654 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
8,467 |
|
|
$ |
539 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
4
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. About Encore
EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore
fields in the United States. Since 1998, EAC has acquired producing properties with proven
reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring,
reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques.
EACs properties and oil and natural gas reserves are located in four core areas: the Cedar
Creek Anticline (CCA) in the Williston Basin of Montana and North Dakota; the Permian Basin of
West Texas and southeastern New Mexico; the Rockies, which includes non-CCA assets in the
Williston, Big Horn, and Powder River Basins of Wyoming, Montana, and North Dakota, and the Paradox
Basin of southeastern Utah; and the Mid-Continent area, which includes the Arkoma and Anadarko
Basins of Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Barnett Shale of
northern Texas.
Note 2. Basis of Presentation
EACs consolidated financial statements include the accounts of wholly owned and
majority-owned subsidiaries. All material intercompany balances and transactions have been
eliminated in consolidation.
In February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas
properties and to acquire, own, and operate related assets. In September 2007, ENP completed its
initial public offering (IPO) of 9,000,000 common units, representing a 37.4 percent limited
partner interest, at a price to the public of $21.00 per unit. On September 30, 2007, EAC owned
approximately 61 percent of ENPs common units, as well as all of the interests of ENPs general
partner, which is a wholly owned subsidiary of EAC. Considering the presumption of control of the
general partner in accordance with Emerging Issues Task Force Issue No. 04-5, Determining Whether
a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar
Entity When the Limited Partners Have Certain Rights, the financial position, results of
operations, and cash flows of ENP are consolidated within EACs operations. EAC elected not to
recognize a gain on ENPs IPO as permitted by Staff Accounting Bulletin Topic 5H, Accounting for
Sales of Stock by a Subsidiary. See Note 16. ENP for additional discussion.
In the opinion of management, the accompanying unaudited consolidated financial statements of
EAC include all adjustments necessary to present fairly, in all material respects, its financial
position as of September 30, 2007, results of operations for the three and nine months ended
September 30, 2007 and 2006, and cash flows for the nine months ended September 30, 2007 and 2006.
All adjustments are of a normal recurring nature. These interim results are not necessarily
indicative of results for an entire year.
Certain amounts and disclosures have been condensed or omitted from these consolidated
financial statements pursuant to the rules and regulations of the SEC. Therefore, these
consolidated financial statements should be read in conjunction with the consolidated financial
statements and related notes thereto included in EACs 2006 Annual Report on Form 10-K.
Variable Interest Entity
On April 11, 2007, EAC completed the purchase of certain oil and natural gas properties and
related assets in the Williston Basin of Montana and North Dakota from certain subsidiaries of
Anadarko Petroleum Corporation (Anadarko). Prior to closing, EAC assigned all of its rights and
duties under the purchase and sale agreement to Encore Operating, L.P., a Texas limited partnership
and indirect wholly owned guarantor subsidiary of EAC (Encore Operating), which further assigned
all of its rights and duties under the purchase and sale agreement to Encore Exchange, LLC, a
Delaware limited liability company unaffiliated with EAC or Encore Operating (Encore Exchange).
The Williston Basin acquisition was structured to qualify as the first step of a reverse
like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S.
Revenue Procedure 2000-37. The Williston Basin assets were acquired by Encore Exchange as an
exchange accommodation titleholder. Encore Exchange held the assets pursuant to a qualified
exchange accommodation agreement until the second step of the like-kind exchange was completed.
During the period the assets were held by Encore Exchange, Encore Operating operated the Williston
Basin assets pursuant to a management agreement with Encore Exchange. The second step of the
like-kind exchange was completed in July 2007 upon the completion of the disposition of certain of
EACs Mid-Continent properties and the Williston Basin assets were transferred to EAC. See Note
3. Acquisitions and Dispositions for additional discussion of the Mid-Continent disposition.
In connection with the like-kind exchange described above, EAC (through Encore Operating)
loaned an amount equal to the
5
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
purchase price to Encore Exchange. Based on the provisions of
Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 46(R), Consolidation of Variable Interest Entities, EAC determined that Encore
Exchange was a variable interest entity for which EAC was the primary beneficiary. During the
third quarter of 2007, the like-kind exchange was completed, and Encore Exchange was dissolved.
Minority Interest
As presented in the accompanying Consolidated Balance Sheets, Minority interest in
consolidated partnership as of September 30, 2007 of $181.4 million represents third-party
ownership interests in ENP. For financial reporting purposes, the assets and liabilities of ENP
are consolidated with those of EAC, with any third-party ownership interests in such amounts being
presented as minority interest.
As presented in the accompanying Consolidated Statements of Operations, Minority interest in
loss of consolidated partnership for the three and nine months ended September 30, 2007 of $3.0
million represents the net loss of ENP attributable to third-party owners.
Reclassifications
Certain amounts in prior periods have been reclassified to conform to the current period
presentation. In particular, certain amounts on the accompanying Consolidated Statements of Cash
Flows have been either combined or classified in more detail.
New Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS
157)
In September 2006, the FASB issued SFAS 157. SFAS 157 standardizes the definition of fair
value, establishes a framework for measuring fair value in generally accepted accounting principles
and expands disclosures related to the use of fair value measures in financial statements. SFAS
157 applies whenever other standards require (or permit) assets or liabilities to be measured at
fair value but does not expand the use of fair value measurements. SFAS 157 is prospectively
effective for financial statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. EAC does not expect the adoption of SFAS 157 to have a
material impact on its results of operations or financial condition.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities including an
amendment of FASB Statement No. 115 (SFAS 159)
In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many
financial instruments and certain other assets and liabilities at fair value on an
instrument-by-instrument basis. SFAS 159 allows entities to measure eligible items at fair value
at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159
is effective as of the beginning of an entitys first fiscal year that begins after November 15,
2007. EAC does not expect the adoption of SFAS 159 to have a material impact on its results of
operations or financial condition.
FASB Staff Position (FSP) on FIN 39-1, Amendment of FASB Interpretation No. 39 (FSP FIN 39-1)
In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FIN No. 39, Offsetting of
Amounts Related to Certain Contracts (FIN 39), to permit a reporting entity that is party to a
master netting arrangement to offset the fair value amounts recognized for the right to reclaim
cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have been offset under the same master
netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years
beginning after November 15, 2007. EAC does not expect the adoption of FSP FIN 39-1 to have a
material impact on its results of operations or financial condition.
Note 3. Acquisitions and Dispositions
Acquisitions
On January 23, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries
of Anadarko to acquire oil
6
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
and natural gas properties and related assets in the Williston Basin of
Montana and North Dakota. The closing of the Williston Basin acquisition occurred on April 11,
2007 after which time the operations have been included with those of EAC.
The total purchase price for the Williston Basin assets was approximately $392.0 million,
including estimated transaction costs of approximately $1.3 million. Based on currently available
information, the calculation of the total purchase price and the estimated allocation to the fair
value of the Williston Basin assets acquired and liabilities assumed from Anadarko are as follows
as of September 30, 2007 (in thousands):
|
|
|
|
|
Calculation of total purchase price: |
|
|
|
|
Cash paid to Anadarko |
|
$ |
390,728 |
|
Estimated transaction costs |
|
|
1,298 |
|
|
|
|
|
Total purchase price |
|
$ |
392,026 |
|
|
|
|
|
|
|
|
|
|
Allocation of purchase price to the fair value of net
assets acquired: |
|
|
|
|
Proved properties, including wells and related equipment |
|
$ |
383,741 |
|
Unproved properties |
|
|
16,134 |
|
Accounts receivable |
|
|
2,910 |
|
Inventory |
|
|
743 |
|
|
|
|
|
Total assets acquired |
|
|
403,528 |
|
|
|
|
|
Current liabilities |
|
|
(7,996 |
) |
Future abandonment cost |
|
|
(3,506 |
) |
|
|
|
|
Total liabilities assumed |
|
|
(11,502 |
) |
|
|
|
|
Fair value of net assets acquired |
|
$ |
392,026 |
|
|
|
|
|
On January 16, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries
of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of
Wyoming and Montana, which included oil and natural gas properties and related assets in or near
the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas
properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing,
EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin
assets to Encore Energy Partners Operating LLC (OLLC), a Delaware limited liability company and
wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement
relating to the Gooseberry assets to Encore Operating. The closing of the Big Horn Basin
acquisition occurred on March 7, 2007 after which time the operations have been included with those
of EAC.
The total purchase price for the Big Horn Basin assets was approximately $393.2 million,
including estimated transaction costs of approximately $1.3 million. The calculation of the total
purchase price and the estimated allocation to the fair value of the Big Horn Basin assets acquired
and liabilities assumed from Anadarko are as follows as of September 30, 2007 (in thousands):
|
|
|
|
|
Calculation of total purchase price: |
|
|
|
|
Cash paid to Anadarko |
|
$ |
391,943 |
|
Estimated transaction costs |
|
|
1,288 |
|
|
|
|
|
Total purchase price |
|
$ |
393,231 |
|
|
|
|
|
|
|
|
|
|
Allocation of purchase price to the fair value of net
assets acquired: |
|
|
|
|
Proved properties, including wells and related equipment |
|
$ |
395,598 |
|
Intangibles |
|
|
4,225 |
|
Accounts receivable |
|
|
1,673 |
|
|
|
|
|
Total assets acquired |
|
|
401,496 |
|
|
|
|
|
Current liabilities |
|
|
(1,292 |
) |
Future abandonment cost |
|
|
(6,973 |
) |
|
|
|
|
Total liabilities assumed |
|
|
(8,265 |
) |
|
|
|
|
Fair value of net assets acquired |
|
$ |
393,231 |
|
|
|
|
|
The properties and equipment amount in the Big Horn Basin purchase price allocation includes
the fair value of proved leasehold costs, lease and well equipment (including flue gas reinjection
facilities used to maintain reservoir pressure by
7
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
compressing and reinjecting the gas produced),
and an oil pipeline and natural gas pipeline used primarily to transport production from the
acquired fields. NGLs are produced as a byproduct of the flue gas tertiary recovery project and
are sold at market prices. The revenues generated by these hydrocarbon liquids are included in
Oil revenues in the accompanying Consolidated Statements of Operations. Third-party revenues and
expenses related to the pipelines are included in Marketing revenues and Marketing expenses,
respectively, in the accompanying Consolidated Statements of Operations.
EAC and ENP financed the acquisitions of the Big Horn Basin and Williston Basin assets through
borrowings under revolving credit facilities. As of December 31, 2006, estimated total proved
reserves associated with the Big Horn Basin and Williston Basin acquisitions were 38,934 MBOE, 92
percent of which were oil and 90 percent of which were proved developed.
See Note 8. Debt for additional discussion of EACs and ENPs revolving credit facilities.
See Note 13. Financial Statements of Subsidiary Guarantors for a discussion of EACs guarantor
and non-guarantor subsidiaries.
Dispositions
On June 29, 2007, EAC completed the sale of certain oil and natural gas properties in the
Mid-Continent. In July 2007, additional Mid-Continent properties that were subject to preferential
rights were sold. The total net proceeds were approximately $289.7 million, including estimated
transactions costs of approximately $3.5 million, and EAC recorded a loss on sale of approximately
$5.8 million, which is included in Other operating expense in the accompanying Consolidated
Statements of Operations. The disposed properties included certain properties in the Anadarko and
Arkoma fields of Oklahoma. EAC retained a material oil and natural gas interest in other
properties in the Anadarko and Arkoma fields and remains active in those areas.
Proceeds from the Mid-Continent disposition were used to reduce outstanding borrowings under
EACs revolving credit facility. As of December 31, 2006, estimated total proved reserves
associated with the Mid-Continent disposition were 17,416 MBOE, 92 percent of which were natural
gas and 75 percent of which were proved developed.
Pro Forma
The following unaudited pro forma condensed financial data for the three and nine months ended
September 30, 2007 and 2006 was derived from the historical financial statements of EAC and from
the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset
acquisitions and the Mid-Continent disposition as if they had occurred on January 1, 2006. The
unaudited pro forma condensed financial information has been included for comparative purposes only
and is not necessarily indicative of the results that might have occurred had the Big Horn Basin
and Williston Basin acquisitions and the Mid-Continent disposition taken place as of the dates
indicated and are not intended to be a projection of future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma total revenues |
|
$ |
195,016 |
|
|
$ |
219,653 |
|
|
$ |
522,778 |
|
|
$ |
595,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
14,171 |
|
|
$ |
46,257 |
|
|
$ |
4,879 |
|
|
$ |
86,590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.27 |
|
|
$ |
0.87 |
|
|
$ |
0.09 |
|
|
$ |
1.68 |
|
Diluted |
|
$ |
0.26 |
|
|
$ |
0.86 |
|
|
$ |
0.09 |
|
|
$ |
1.65 |
|
Note 4. Inventory
Inventory is comprised principally of materials and supplies and oil in pipelines, which are
stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease
which resides unsold in pipelines is carried at an amount equal to its operating costs to produce.
Oil in pipelines purchased from third parties is carried at average purchase price. EACs
inventory consisted of the following as of the dates indicated:
8
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
Materials and supplies |
|
$ |
13,018 |
|
|
$ |
11,784 |
|
Oil in pipelines |
|
|
6,131 |
|
|
|
6,386 |
|
|
|
|
|
|
|
|
Total inventory |
|
$ |
19,149 |
|
|
$ |
18,170 |
|
|
|
|
|
|
|
|
Note 5. Proved Properties
Amounts shown in the accompanying Consolidated Balance Sheets as Proved properties include
leasehold costs and wells and related equipment, both completed and in process, and consisted of
the following as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
Proved leasehold costs |
|
$ |
1,325,112 |
|
|
$ |
796,932 |
|
Wells and related equipment Completed |
|
|
1,373,207 |
|
|
|
1,200,938 |
|
Wells and related equipment In process |
|
|
42,486 |
|
|
|
36,044 |
|
|
|
|
|
|
|
|
Total proved properties |
|
$ |
2,740,805 |
|
|
$ |
2,033,914 |
|
|
|
|
|
|
|
|
Note 6. Derivative Financial Instruments
EAC had $48.6 million of deferred premiums payable recorded at September 30, 2007, of which
$21.7 million is considered long-term and recorded in Derivatives in the non-current liabilities
section of the accompanying Consolidated Balance Sheet and $26.9 million is considered current and
recorded in Derivatives in the current liabilities section of the accompanying Consolidated
Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable
on a monthly basis from October 2007 to January 2010. EAC recorded these amounts at their net
present value at the time the contract was entered into and accretes that value up to the eventual
settlement price by recording interest expense each period.
Commodity Contracts Mark-to-Market Accounting: Previously designated as hedges
Prior to July 2006, EAC used hedge accounting for certain of its derivative contracts, whereby
the effective portion of changes in the fair value of the contract was deferred, until the hedged
production occurred, in accumulated other comprehensive loss (AOCL) included in stockholders
equity in the accompanying Consolidated Balance Sheets rather than recognized currently in
earnings. In the third quarter of 2006, EAC elected to discontinue hedge accounting prospectively
for all remaining commodity derivatives which were previously accounted for as hedges. While this
change has no effect on cash flows, results of operations are affected by mark-to-market gains and
losses, which fluctuate with the changes in oil and natural gas prices. The deferred loss in AOCL
at the time of dedesignation is being amortized to oil and natural gas revenues over the original
term of the contracts. The amortization of these amounts is included in oil and natural gas
revenues with the revenues from the hedged production. All mark-to-market gains and losses from
July 2006 forward are recognized in earnings through Derivative fair value loss (gain) in the
accompanying Consolidated Statements of Operations rather than deferring such amounts in AOCL.
9
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
The following tables summarize EACs open commodity derivative instruments as of September 30,
2007:
Oil Derivative Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset |
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
(Liability) |
|
|
|
Floor |
|
|
Floor |
|
|
|
Short Floor |
|
|
Short Floor |
|
|
|
Cap |
|
|
Cap |
|
|
|
Swap |
|
|
Swap |
|
|
|
Fair Market |
|
Period |
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Value |
|
|
|
(Bbl) |
|
|
(per Bbl) |
|
|
|
(Bbl) |
|
|
(per Bbl) |
|
|
|
(Bbl) |
|
|
(per Bbl) |
|
|
|
(Bbl) |
|
|
(per Bbl) |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct. Dec. 2007 |
|
|
14,500 |
|
|
$ |
56.72 |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
3,000 |
|
|
$ |
36.75 |
|
|
|
$ |
(11,847 |
) |
Jan. June 2008 |
|
|
18,500 |
|
|
|
62.84 |
|
|
|
|
(4,000 |
) |
|
|
50.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
|
58.59 |
|
|
|
|
256 |
|
July Dec. 2008 |
|
|
14,500 |
|
|
|
63.62 |
|
|
|
|
(4,000 |
) |
|
|
50.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,395 |
|
Jan. Dec. 2009 |
|
|
8,750 |
|
|
|
67.63 |
|
|
|
|
(5,000 |
) |
|
|
50.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
|
68.70 |
|
|
|
|
11,381 |
|
Jan. Dec. 2010 |
|
|
2,000 |
|
|
|
65.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
|
77.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
Daily |
|
|
Average |
|
|
|
Asset |
|
|
|
Floor |
|
|
Floor |
|
|
|
Short Floor |
|
|
Short Floor |
|
|
|
Cap |
|
|
Cap |
|
|
|
Swap |
|
|
Swap |
|
|
|
Fair Market |
|
Period |
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Volume |
|
|
Price |
|
|
|
Value |
|
|
|
(Mcf) |
|
|
(per Mcf) |
|
|
|
(Mcf) |
|
|
(per Mcf) |
|
|
|
(Mcf) |
|
|
(per Mcf) |
|
|
|
(Mcf) |
|
|
(per Mcf) |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct. Dec. 2007 |
|
|
36,500 |
|
|
$ |
6.85 |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
2,000 |
|
|
$ |
9.85 |
|
|
|
|
10,000 |
|
|
$ |
4.99 |
|
|
|
$ |
1,562 |
|
Jan. Dec. 2008 |
|
|
24,000 |
|
|
|
6.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
|
9.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
5,019 |
|
Jan. Dec. 2009 |
|
|
4,000 |
|
|
|
7.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
|
9.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,573 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts Mark-to-Market Accounting: Floor Spreads
In order to partially finance the cost of premiums on certain purchased floors, EAC may sell
floors with a strike price below the strike price of the purchased floor. Together the two floors,
known as a floor spread or put spread, have a lower premium cost than a traditional floor contract
but provide price protection only down to the strike price of the short floor. EAC has entered
into floor spreads with a $70 per Bbl purchased floor and a $50 per Bbl short floor for 4,000
Bbls/D in 2008 and 5,000 Bbls/D in 2009. As with EACs other derivative contracts, these are
marked-to-market each quarter through Derivative fair value loss (gain) in the accompanying
Consolidated Statements of Operations. In the above table, the purchased floor component of these
floor spreads has been included with EACs other floor contracts and the short floor component is
shown separately as negative volumes.
Commodity Contracts Current Period Impact
EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $13.4
million and $14.4 million during the three months ended September 30, 2007 and 2006, respectively,
and $40.2 million and $45.7 million during the nine months ended September 30, 2007 and 2006,
respectively, related to commodity derivative contracts which were previously designated as hedges.
EAC also recognized derivative fair value gains and losses related to (i) changes in the market
value since the date of dedesignation of derivative contracts which were previously designated as
hedges, (ii) changes in the market value of certain other commodity derivatives that were never
designated as hedges, (iii) settlements on derivative contracts not designated as hedges, and (iv)
ineffectiveness of derivative contracts designated as hedges prior to July 2006. The following
table summarizes the components of derivative fair value loss (gain) for the three and nine months ended
September 30, 2007 and 2006:
10
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ineffectiveness on designated cash flow hedges |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,748 |
|
Mark-to-market loss (gain) on commodity contracts |
|
|
9,686 |
|
|
|
(37,729 |
) |
|
|
56,122 |
|
|
|
(30,639 |
) |
Premium amortization |
|
|
10,462 |
|
|
|
3,449 |
|
|
|
28,151 |
|
|
|
9,820 |
|
Settlements on commodity contracts |
|
|
(4,362 |
) |
|
|
917 |
|
|
|
(16,107 |
) |
|
|
(1,192 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain) |
|
$ |
15,786 |
|
|
$ |
(33,363 |
) |
|
$ |
68,166 |
|
|
$ |
(20,263 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts Future Period Impact
At September 30, 2007 and December 31, 2006, AOCL consisted entirely of deferred losses on
commodity derivatives which were previously designated as hedges of $10.2 million and $35.3
million, respectively.
EAC expects to reclassify the remaining $16.3 million of deferred losses associated with its
dedesignated commodity contracts from AOCL to oil and natural gas revenues by June 30, 2008. EAC
also expects to reclassify the remaining $6.1 million of net deferred tax assets from AOCL to
income tax benefit by June 30, 2008.
Note 7. Asset Retirement Obligations
EACs primary asset retirement obligations relate to future plugging and abandonment expenses
on oil and natural gas properties and related facilities disposal. EAC does not include a market
risk premium in its risk estimates because a reliable estimate cannot be determined. As of
September 30, 2007, EAC had $6.0 million held in an escrow account from which funds are released
only for reimbursement of plugging and abandonment expenses on its Bell Creek property. This
amount is included in Other assets in the accompanying Consolidated Balance Sheets. The
following table summarizes the changes in EACs future abandonment liability, the long-term portion
of which is recorded in Future abandonment cost on the accompanying Consolidated Balance Sheets,
for the nine months ended September 30, 2007 (in thousands):
|
|
|
|
|
Future abandonment liability at January 1, 2007 |
|
$ |
19,841 |
|
Wells drilled |
|
|
89 |
|
Accretion of discount |
|
|
867 |
|
Plugging and abandonment costs incurred |
|
|
(497 |
) |
Revision of estimates |
|
|
(604 |
) |
Disposition of properties |
|
|
(959 |
) |
Acquisition of properties |
|
|
10,745 |
|
|
|
|
|
Future abandonment liability at September 30, 2007 |
|
$ |
29,482 |
|
|
|
|
|
Note 8. Debt
EACs long-term debt consisted of the following as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Revolving credit facilities |
|
$ |
545,000 |
|
|
$ |
68,000 |
|
6 1/4% Senior Subordinated Notes due due April 15, 2014 |
|
|
150,000 |
|
|
|
150,000 |
|
6% Senior Subordinated Notes due July 15, 2015, net of unamortized
discount of $4,555 and $4,892, respectively |
|
|
295,445 |
|
|
|
295,108 |
|
7 1/4% Senior Subordinated Notes due December 1, 2017, net of
unamortized discount of $1,346 and $1,412, respectively |
|
|
148,654 |
|
|
|
148,588 |
|
|
|
|
|
|
|
|
Total |
|
$ |
1,139,099 |
|
|
$ |
661,696 |
|
|
|
|
|
|
|
|
11
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
Revolving Credit Facilities
Encore Acquisition Company Senior Secured Credit Agreement
On March 7, 2007, EAC entered into a five-year amended and restated credit agreement (the EAC
Credit Agreement) with a bank syndicate comprised of Bank of America, N.A. and other lenders,
which amended and restated EACs Amended and Restated Credit Agreement dated as of August 19, 2004.
The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to
time and letters of credit to be issued from time to time for the account of EAC or any of its
restricted subsidiaries. The aggregate amount of the commitments of the lenders under the EAC
Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a
borrowing base, which is redetermined semi-annually and upon requested special redeterminations.
Upon the contribution of certain assets in the Permian Basin to ENP at the closing of its IPO in
September 2007, the borrowing base was reduced to $870 million. See Note 16. ENP for additional
discussion.
The EAC Credit Agreement matures on March 7, 2012. EACs obligations under the EAC Credit
Agreement are secured by a first-priority security interest in EACs and its restricted
subsidiaries proved oil and natural gas reserves and in the equity interests of EACs restricted
subsidiaries. In addition, EACs obligations under the EAC Credit Agreement are guaranteed by its
restricted subsidiaries.
Loans under the EAC Credit Agreement are subject to varying rates of interest based on (i) the
total amount outstanding in relation to the borrowing base and (ii) whether the loan is a
Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus
the applicable margin indicated in the following table, and base rate loans bear interest at the
base rate plus the applicable margin indicated in the following table:
|
|
|
|
|
|
|
|
|
|
|
Applicable Margin for |
|
Applicable Margin for |
Ratio of Total Outstanding Borrowings to Borrowing Base |
|
Eurodollar Loans |
|
Base Rate Loans |
Less than .50 to 1 |
|
|
1.000 |
% |
|
|
0.000 |
% |
Greater than or equal to .50 to 1 but less than .75
to 1 |
|
|
1.250 |
% |
|
|
0.000 |
% |
Greater than or equal to .75 to 1 but less than .90
to 1 |
|
|
1.500 |
% |
|
|
0.250 |
% |
Greater than or equal to .90 to 1 |
|
|
1.750 |
% |
|
|
0.500 |
% |
The Eurodollar rate for any interest period (either one, two, three, or six months, as
selected by EAC) is the rate per year equal to LIBOR, as published by Reuters or another source
designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The
base rate is calculated as the higher of (i) the annual rate of interest announced by Bank of
America, N.A. as its prime rate and (ii) the federal funds effective rate plus 0.5 percent.
As of September 30, 2007, the aggregate principal amount of loans outstanding under the EAC
Credit Agreement was $478.5 million and the aggregate face amount of outstanding letters of credit
was $20 million, all of which related to EACs joint development agreement with ExxonMobil
Corporation (ExxonMobil). See Note 14. Commitments and Contingencies for additional discussion
of this agreement. Any outstanding letters of credit reduce the availability under the EAC Credit
Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without
penalty.
The EAC Credit Agreement contains covenants that include, among others:
|
|
|
a prohibition against incurring debt, subject to permitted exceptions; |
|
|
|
|
a prohibition against paying dividends or making distributions, purchasing or redeeming
capital stock, or prepaying indebtedness, subject to permitted exceptions; |
|
|
|
|
a restriction on creating liens on EACs and its restricted subsidiaries assets,
subject to permitted exceptions; |
|
|
|
|
restrictions on merging and selling assets outside the ordinary course of business; |
|
|
|
|
restrictions on use of proceeds, investments, transactions with affiliates, or change of
principal business; |
|
|
|
|
a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not
exceeding 75 percent of anticipated production from proved producing reserves; |
|
|
|
|
a requirement that EAC maintain a ratio of consolidated current assets to consolidated current
liabilities of not less than 1.0 to 1.0; and
|
12
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
|
|
|
a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the EAC Credit
Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less
than 2.5 to 1.0. |
The EAC Credit Agreement contains customary events of default. If an event of default occurs and is
continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare
all amounts outstanding under the EAC Credit Agreement to be immediately due and payable. EAC was in
compliance with all of the debt covenants under the EAC Credit Agreement as of September 30, 2007.
EAC incurs a commitment fee on the unused portion of the EAC Credit Agreement determined based on the
ratio of amounts outstanding under the EAC Credit Agreement to the borrowing base in effect on such date.
The following table summarizes the calculation of the commitment fee under the EAC Credit Agreement:
|
|
|
|
|
|
|
Commitment |
Ratio of Total Outstanding Borrowings to Borrowing Base |
|
Fee Percentage |
Less than .50 to 1 |
|
|
0.250 |
% |
Greater than or equal to .50 to 1 but less than
..75 to 1 |
|
|
0.300 |
% |
Greater than or equal to .75 to 1 but less than
..90 to 1 |
|
|
0.375 |
% |
Greater than or equal to .90 to 1 |
|
|
0.375 |
% |
Encore Energy Partners Operating LLC Credit Agreement
OLLC is a party to a five-year credit agreement dated March 7, 2007 (the OLLC Credit Agreement) with a
bank syndicate comprised of Bank of America, N.A. and other lenders. On August 22, 2007, OLLC entered into
the First Amendment to the OLLC Credit Agreement, which revised certain financial covenants. The OLLC Credit
Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to
be issued from time to time for the account of OLLC or any of its restricted subsidiaries.
The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million.
Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined
semi-annually and upon requested special redeterminations. As a result of the contribution of certain assets
in the Permian Basin from EAC to OLLC at the closing of ENPs IPO in September 2007, the borrowing base was
increased to $145 million.
The OLLC Credit Agreement matures on March 7, 2012. OLLCs obligations under the OLLC Credit Agreement
are secured by a first-priority security interest in OLLCs and its restricted subsidiaries proved oil and
natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition,
OLLCs obligations under the OLLC Credit Agreement are guaranteed by its direct parent, ENP, and OLLCs
restricted subsidiaries. EAC consolidates the debt of ENP with that of its own; however, obligations under
the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
Loans under the OLLC Credit Agreement are subject to varying rates of interest based on the same
provisions as the EAC Credit Agreement.
As of September 30, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit
Agreement was $66.5 million and there were no outstanding letters of credit. Any outstanding letters of
credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement
may be repaid from time to time without penalty.
The OLLC Credit Agreement contains covenants that include, among others:
|
|
|
a prohibition against incurring debt, subject to permitted exceptions; |
|
|
|
|
a prohibition against paying dividends or making distributions prior to the IPO Effective Date (as
defined in the OLLC Credit Agreement), purchasing or redeeming capital stock, or prepaying
indebtedness, subject to permitted exceptions; |
|
|
|
|
a restriction on creating liens on the assets of ENP, OLLC and its restricted subsidiaries, subject
to permitted exceptions; |
|
|
|
|
restrictions on merging and selling assets outside the ordinary course of business; |
|
|
|
|
restrictions on use of proceeds, investments, transactions with affiliates, or change of principal
business; |
13
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
|
|
|
a provision limiting oil and natural gas hedging transactions (other than puts) to a
volume not exceeding 75 percent of anticipated production from proved producing reserves; |
|
|
|
|
a requirement that OLLC maintain a ratio of consolidated current assets to consolidated
current liabilities of not less than 1.0 to 1.0; |
|
|
|
|
a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC
Credit Agreement) to the sum of consolidated net interest expense plus letter of credit
fees of not less than 1.5 to 1.0; |
|
|
|
|
a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC
Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and |
|
|
|
|
a requirement that OLLC maintain a ratio of consolidated funded debt (excluding certain
related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit
Agreement) of not more than 3.5 to 1.0. |
The OLLC Credit Agreement contains customary events of default. If an event of default occurs
and is continuing, lenders with a majority of the aggregate commitments may require Bank of
America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately
due and payable. At September 30, 2007, OLLC was in compliance with all of the debt covenants
under the OLLC Credit Agreement, as amended.
OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined
based on the same provisions as the EAC Credit Agreement.
Note 9. Income Taxes
The components of the income tax provision were as follows for the nine months ended September
30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Federal: |
|
|
|
|
|
|
|
|
Current |
|
$ |
(116 |
) |
|
$ |
(1,361 |
) |
Deferred |
|
|
(679 |
) |
|
|
(45,405 |
) |
|
|
|
|
|
|
|
Total federal |
|
|
(795 |
) |
|
|
(46,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State, net of federal benefit/expense: |
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
(1,348 |
) |
Deferred |
|
|
(695 |
) |
|
|
(3,268 |
) |
|
|
|
|
|
|
|
Total state |
|
|
(695 |
) |
|
|
(4,616 |
) |
|
|
|
|
|
|
|
Income tax provision |
|
$ |
(1,490 |
) |
|
$ |
(51,382 |
) |
|
|
|
|
|
|
|
The following table reconciles income tax provision with income tax at the Federal statutory
rate for the nine months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Income (loss) before income taxes |
|
$ |
(782 |
) |
|
$ |
133,688 |
|
|
|
|
|
|
|
|
Tax at statutory rate |
|
$ |
274 |
|
|
$ |
(46,791 |
) |
State income taxes, net of federal
benefit/expense |
|
|
19 |
|
|
|
(3,118 |
) |
Enactment of the Texas margin tax |
|
|
|
|
|
|
(1,389 |
) |
Change in estimated future tax rate |
|
|
(597 |
) |
|
|
|
|
ENP minority interest in deferred compensation |
|
|
(1,238 |
) |
|
|
|
|
Permanent and other |
|
|
52 |
|
|
|
(84 |
) |
|
|
|
|
|
|
|
Income tax provision |
|
$ |
(1,490 |
) |
|
$ |
(51,382 |
) |
|
|
|
|
|
|
|
On January 1, 2007, EAC adopted the provisions of FIN No. 48, Accounting for Uncertainty in
Income Taxes an Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the
accounting for uncertainty in income taxes
14
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
recognized in a companys financial statements in
accordance with SFAS No. 109, Accounting for Income Taxes (SFAS 109). FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. EAC and its
subsidiaries file income tax returns in the U.S. federal jurisdiction and various state
jurisdictions. Subject to statutory exceptions that allow for a possible extension of the
assessment period, EAC is no longer subject to U.S. federal, state, and local income tax
examinations for years prior to 2003.
EAC has performed its evaluation of tax positions and has determined that the adoption of FIN
48 did not have a material impact on EACs financial condition, results of operations, or cash
flows. This evaluation is a review of the appropriate recognition threshold for each tax position
recognized in EACs financial statements. The evaluation included, but was not limited to:
|
|
|
a review of documentation of tax positions taken on previous returns including an
assessment of whether EAC followed industry practice or the applicable requirements under
the tax code; |
|
|
|
|
a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as
supporting documentation used to support those tax returns; |
|
|
|
|
a review of the results of past tax examinations; |
|
|
|
|
a review of whether tax returns have been filed in all appropriate jurisdictions; |
|
|
|
|
a review of existing permanent and temporary differences; and |
|
|
|
|
consideration of any tax planning strategies that may have been used to support
realization of deferred tax assets. |
Based on this evaluation, EAC did not identify any tax positions that did not meet the highly
certain positions threshold. As a result, no additional tax expense, interest, or penalties have
been accrued as a result of the review.
EAC includes interest assessed by the taxing authorities in Interest expense and penalties
related to income taxes in Other expense on its Consolidated Statements of Operations. For the
nine months ended September 30, 2007 and 2006, EAC recorded only a nominal amount of interest and
penalties on certain tax positions.
Note 10. Earnings Per Share (EPS)
The following table reflects EPS computations for the three and nine months ended September
30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
11,985 |
|
|
$ |
42,135 |
|
|
$ |
(2,272 |
) |
|
$ |
82,306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
53,198 |
|
|
|
52,968 |
|
|
|
53,140 |
|
|
|
51,481 |
|
Effect of dilutive options and
diluted restricted stock (a) |
|
|
981 |
|
|
|
808 |
|
|
|
|
|
|
|
894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted EPS |
|
|
54,179 |
|
|
|
53,776 |
|
|
|
53,140 |
|
|
|
52,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.23 |
|
|
$ |
0.80 |
|
|
$ |
(0.04 |
) |
|
$ |
1.60 |
|
Diluted |
|
$ |
0.22 |
|
|
$ |
0.78 |
|
|
$ |
(0.04 |
) |
|
$ |
1.57 |
|
|
|
|
(a) |
|
For the three months ended September 30, 2007 and 2006, options to purchase 95,253 shares
of common stock and 106,274 shares of common stock, respectively, were outstanding but not
included in the above calculation of diluted EPS because their effect would have been
antidilutive. For the nine months ended September 30, 2007 and 2006, options to purchase
1,422,350 shares of common stock and 95,395 shares of common stock, respectively, were
outstanding but not included in the above calculation of diluted EPS because their effect
would have been antidilutive. The effect of dilutive options and diluted restricted stock
for the nine months ended September 30, 2007 and 2006 is an average of the effect of the
dilutive options and diluted restricted stock for the first three quarters of each respective
year. |
15
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
Note 11. Incentive Stock Plan
During 2000, EACs Board of Directors (the Board) and stockholders approved the 2000
Incentive Stock Plan (the EAC Plan). The EAC Plan was amended and restated effective March 18,
2004. The purpose of the EAC Plan is to attract, motivate, and retain selected employees of EAC
and to provide EAC with the ability to provide incentives more directly linked to the profitability
of the business and increases in shareholder value. All directors and full-time regular employees
of EAC and its subsidiaries and affiliates are eligible to be granted awards under the EAC Plan.
The total number of shares of common stock reserved for issuance pursuant to the EAC Plan is
4,500,000. As of September 30, 2007, there were 849,538 shares available for issuance under the
EAC Plan. Shares delivered or withheld for payment of the exercise price of an option, shares
withheld for payment of tax withholding, or shares subject to options or other awards that expire
or are terminated and restricted shares that are forfeited will again become available for issuance
under the EAC Plan. The EAC Plan provides for the granting of cash awards, incentive stock
options, non-qualified stock options, restricted stock, and stock appreciation rights at the
discretion of the Compensation Committee of the Board. The Board also has a Restricted Stock Award
Committee having Jon S. Brumley, EACs Chief Executive Officer and President, as its sole member.
The Restricted Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual
basis to non-executive employees at its discretion.
The EAC Plan contains the following individual limits:
|
|
|
an employee may not be granted awards covering or relating to more than 225,000
shares of common stock in any calendar year; |
|
|
|
|
a non-employee director may not be granted awards covering or relating to more than
15,000 shares of common stock in any calendar year; and |
|
|
|
|
an employee may not receive awards consisting of cash (including cash awards that are
granted as performance awards) in respect of any calendar year having a value determined
on the grant date in excess of $1.0 million. |
All options that have been granted under the EAC Plan have a strike price equal to the fair
market value of EACs common stock on the date of grant. Additionally, all options have a ten-year
life and vest equally over a three-year period. Restricted stock granted under the EAC Plan vests
over varying periods from one to five years, subject to performance-based vesting for certain
members of senior management.
The compensation cost related to the EAC Plan that has been recorded in the accompanying
Consolidated Statements of Operations for the nine months ended September 30, 2007 and 2006 was
$7.0 million and $6.6 million, respectively. The income tax benefit related to the EAC Plan that
has been recorded in the accompanying Consolidated Statements of Operations for the nine months
ended September 30, 2007 and 2006 was $2.6 million and $2.4 million, respectively. During each of
the nine months ended September 30, 2007 and 2006, EAC also capitalized $0.9 million of non-cash
stock-based compensation cost as a component of Properties and equipment in the accompanying
Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to lease
operations expense, general and administrative expense, and exploration expense based on the
allocation of the respective employees cash compensation.
See Note 16. ENP for a discussion of ENPs unit-based compensation plan.
Stock Options
The fair value of each option award granted during the nine months ended September 30, 2007
and 2006 was estimated on the date of grant using the Black-Scholes option valuation model based on
the assumptions noted in the following table. The expected volatility is based on the historical
volatility of EACs common stock for a period of time commensurate with the expected term of the
award. EAC uses the simplified method prescribed by SEC Staff Accounting Bulletin No. 107 to
estimate the expected term of the options, which is calculated as the average midpoint between each
vesting date and the life of the option. The risk-free rate is based on the U.S Treasury yield
curve in effect at the time of grant for periods commensurate with the expected terms of the
options.
16
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
2007 |
|
2006 |
Expected volatility |
|
|
35.7 |
% |
|
|
42.8 |
% |
Expected dividend yield |
|
|
0.0 |
% |
|
|
0.0 |
% |
Expected term (in years) |
|
|
6.0 |
|
|
|
6.0 |
|
Risk-free interest rate |
|
|
4.8 |
% |
|
|
4.6 |
% |
The following table summarizes the change in the number of outstanding options and the related
weighted average strike prices during the nine months ended September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
Weighted |
|
Average |
|
Aggregate |
|
|
Number of |
|
Average |
|
Remaining |
|
Intrinsic |
|
|
Options |
|
Strike Price |
|
Contractual Term |
|
Value |
|
|
(in thousands) |
Outstanding at January 1, 2007 |
|
|
1,337,118 |
|
|
$ |
14.44 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
200,059 |
|
|
|
25.73 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(23,118 |
) |
|
|
28.30 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(91,709 |
) |
|
|
13.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2007 |
|
|
1,422,350 |
|
|
|
15.89 |
|
|
|
5.8 |
|
|
$ |
22,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at September 30, 2007 |
|
|
1,141,977 |
|
|
|
13.16 |
|
|
|
5.0 |
|
|
|
21,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average fair value per share of individual options granted during the nine months
ended September 30, 2007 and 2006 was $11.16 and $14.96, respectively. The total intrinsic value
of options exercised during the nine months ended September 30, 2007 and 2006 was $1.3 million and
$2.4 million, respectively. During the nine months ended September 30, 2007 and 2006, EAC received
proceeds from the exercise of stock options of $1.0 million and $2.3 million, respectively, and
realized tax benefits related to stock options of $0.4 million and $0.9 million, respectively. At
September 30, 2007, EAC had $1.6 million of total unrecognized compensation cost related to
unvested stock options, which is expected to be recognized over a weighted average period of 2.0
years.
Restricted Stock
During the nine months ended September 30, 2007 and 2006, EAC recognized expense related to
restricted stock of $5.8 million and $5.6 million, respectively, and realized tax benefits related
to restricted stock of $2.2 million and $2.1 million, respectively. A summary of the status of
EACs unvested restricted stock outstanding as of September 30, 2007, and changes during the nine
months then ended, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
Number of |
|
Grant Date |
|
|
Shares |
|
Fair Value |
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2007 |
|
|
828,619 |
|
|
$ |
26.17 |
|
Granted |
|
|
342,133 |
|
|
|
25.90 |
|
Vested |
|
|
(118,273 |
) |
|
|
25.40 |
|
Forfeited |
|
|
(61,145 |
) |
|
|
26.22 |
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2007 |
|
|
991,334 |
|
|
|
26.17 |
|
|
|
|
|
|
|
|
|
|
As of September 30, 2007, there were 819,059 shares of unvested restricted stock outstanding,
dependent only on the passage of time and continued employment for vesting, 159,869 shares of which
were granted during the nine months ended September 30, 2007. Additionally, as of September 30,
2007, there were 172,275 shares of unvested restricted stock outstanding that not only depend on
the passage of time and continued employment, but on certain performance measures for vesting, all
of which were granted during the nine months ended September 30, 2007. None of EACs unvested
restricted stock outstanding are subject to variable accounting.
17
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
As of September 30, 2007, EAC had $11.3 million of total unrecognized compensation cost
related to unvested, outstanding restricted stock, which is expected to be recognized over a
weighted average period of 2.7 years. During the nine months ended September 30, 2007 and 2006,
there were 118,273 shares and 27,909 shares, respectively, of restricted stock that vested and
employees elected to satisfy minimum tax withholding obligations related to these shares by
allowing EAC to withhold 5,545 shares and 6,553 shares of common stock, respectively. These shares
are treated as treasury stock by EAC until the shares are formally retired and have been reflected
as such in the accompanying consolidated financial statements.
Note 12. Comprehensive Income
Components of comprehensive income, net of related tax, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Net income (loss) |
|
$ |
11,985 |
|
|
$ |
42,135 |
|
|
$ |
(2,272 |
) |
|
$ |
82,306 |
|
Amortization of deferred loss on commodity derivatives |
|
|
8,596 |
|
|
|
8,894 |
|
|
|
25,150 |
|
|
|
28,448 |
|
Amortization of deferred gain on interest rate swap |
|
|
|
|
|
|
(63 |
) |
|
|
|
|
|
|
(92 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
20,581 |
|
|
$ |
50,966 |
|
|
$ |
22,878 |
|
|
$ |
110,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 13. Financial Statements of Subsidiary Guarantors
In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the
formation of ENP. See Note 16. ENP for additional discussion of ENPs formation and other
matters. As of September 30, 2007, certain of EACs wholly owned subsidiaries were subsidiary
guarantors of EACs outstanding notes. The subsidiary guarantees are full and unconditional, and
joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in
the form of cash dividends, loans, and advances. In accordance with SEC rules, EAC has prepared
condensed consolidating financial statements in order to quantify the assets and results of
operations of the subsidiary guarantors. The following Condensed Consolidating Balance Sheet as of
September 30, 2007, Condensed Consolidating Statements of Operations and Comprehensive Income
(Loss) for the three and nine months ended September 30, 2007, and Condensed Consolidating
Statement of Cash Flows for the nine months ended September 30, 2007 present consolidating
financial information for Encore Acquisition Company (Parent) on a stand alone, unconsolidated
basis, and its combined guarantor and combined non-guarantor subsidiaries. The guarantor
subsidiaries are:
|
|
|
EAP Energy, Inc.; |
|
|
|
|
EAP Properties Inc.; |
|
|
|
|
EAP Operating Inc.; |
|
|
|
|
EAP Energy Services, L.P.; |
|
|
|
|
Encore Operating; and |
|
|
|
|
Encore Operating Louisiana, LLC. |
The non-guarantor subsidiaries are:
|
|
|
ENP; |
|
|
|
|
OLLC; |
|
|
|
|
Encore Partners GP Holdings LLC; |
|
|
|
|
Encore Partners LP Holdings LLC; |
|
|
|
|
Encore Energy Partners GP LLC; and |
|
|
|
|
Encore Clear Fork Pipeline LLC. |
All intercompany investments in, loans due to/from, subsidiary equity, income and expenses between
the Parent, the guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to final
consolidation with the Parent and then eliminated to arrive at consolidated totals per the
accompanying consolidated financial statements of EAC. Prior to February 2007, all of EACs
subsidiaries were subsidiary guarantors of EACs outstanding senior notes. Therefore, comparative
condensed consolidating financial statements are not presented as of December 31, 2006 or for the
three and nine months ended September 30, 2006.
Income taxes in the Condensed Consolidating Statements of Operations and Comprehensive Income
(Loss) are shown as an expense of the Parent as EAC files a consolidated return. Additionally,
EACs net current deferred tax asset and net long-term deferred tax liability have been included in
the balance sheet of the Parent in the Condensed Consolidating Balance Sheet.
18
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2007
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
Consolidated |
|
|
|
Parent |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Total |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
1,353 |
|
|
$ |
7,114 |
|
|
$ |
|
|
|
$ |
8,467 |
|
Other current assets |
|
|
134,385 |
|
|
|
135,252 |
|
|
|
15,791 |
|
|
|
(121,255 |
) |
|
|
164,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
134,385 |
|
|
|
136,605 |
|
|
|
22,905 |
|
|
|
(121,255 |
) |
|
|
172,640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, at cost successful efforts
method: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties, including wells and related equipment |
|
|
|
|
|
|
2,369,011 |
|
|
|
371,794 |
|
|
|
|
|
|
|
2,740,805 |
|
Unproved properties |
|
|
|
|
|
|
56,427 |
|
|
|
|
|
|
|
|
|
|
|
56,427 |
|
Accumulated depletion, depreciation, and amortization |
|
|
|
|
|
|
(411,883 |
) |
|
|
(30,510 |
) |
|
|
|
|
|
|
(442,393 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,013,555 |
|
|
|
341,284 |
|
|
|
|
|
|
|
2,354,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment, net |
|
|
|
|
|
|
10,436 |
|
|
|
62 |
|
|
|
|
|
|
|
10,498 |
|
Other assets, net |
|
|
15,571 |
|
|
|
142,649 |
|
|
|
13,960 |
|
|
|
(10,357 |
) |
|
|
161,823 |
|
Investment in subsidiaries |
|
|
2,266,381 |
|
|
|
|
|
|
|
|
|
|
|
(2,266,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,416,337 |
|
|
$ |
2,303,245 |
|
|
$ |
378,211 |
|
|
$ |
(2,397,993 |
) |
|
$ |
2,699,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
15,795 |
|
|
$ |
278,283 |
|
|
$ |
12,752 |
|
|
$ |
(121,255 |
) |
|
$ |
185,575 |
|
Deferred taxes |
|
|
294,849 |
|
|
|
|
|
|
|
122 |
|
|
|
|
|
|
|
294,971 |
|
Long-term debt |
|
|
1,082,956 |
|
|
|
|
|
|
|
66,500 |
|
|
|
(10,357 |
) |
|
|
1,139,099 |
|
Other liabilities |
|
|
|
|
|
|
46,363 |
|
|
|
11,055 |
|
|
|
|
|
|
|
57,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
1,393,600 |
|
|
|
324,646 |
|
|
|
90,429 |
|
|
|
(131,612 |
) |
|
|
1,677,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (see Note 14) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in consolidated partnership |
|
|
181,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
841,325 |
|
|
|
1,978,599 |
|
|
|
287,782 |
|
|
|
(2,266,381 |
) |
|
|
841,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
2,416,337 |
|
|
$ |
2,303,245 |
|
|
$ |
378,211 |
|
|
$ |
(2,397,993 |
) |
|
$ |
2,699,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended September 30, 2007
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
Consolidated |
|
|
|
Parent |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Total |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
|
|
|
$ |
141,185 |
|
|
$ |
18,110 |
|
|
$ |
|
|
|
$ |
159,295 |
|
Natural gas |
|
|
|
|
|
|
29,523 |
|
|
|
2,916 |
|
|
|
|
|
|
|
32,439 |
|
Marketing |
|
|
|
|
|
|
1,148 |
|
|
|
2,134 |
|
|
|
|
|
|
|
3,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
|
|
|
|
171,856 |
|
|
|
23,160 |
|
|
|
|
|
|
|
195,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
|
|
|
|
|
32,722 |
|
|
|
4,392 |
|
|
|
|
|
|
|
37,114 |
|
Production, ad valorem, and severance taxes |
|
|
|
|
|
|
17,432 |
|
|
|
2,571 |
|
|
|
|
|
|
|
20,003 |
|
Depletion, depreciation, and amortization |
|
|
|
|
|
|
40,668 |
|
|
|
8,358 |
|
|
|
|
|
|
|
49,026 |
|
Exploration |
|
|
|
|
|
|
8,914 |
|
|
|
6 |
|
|
|
|
|
|
|
8,920 |
|
General and administrative |
|
|
20 |
|
|
|
6,072 |
|
|
|
6,576 |
|
|
|
|
|
|
|
12,668 |
|
Marketing |
|
|
|
|
|
|
2,789 |
|
|
|
1,300 |
|
|
|
|
|
|
|
4,089 |
|
Derivative fair value loss |
|
|
|
|
|
|
12,797 |
|
|
|
2,989 |
|
|
|
|
|
|
|
15,786 |
|
Other operating |
|
|
41 |
|
|
|
6,073 |
|
|
|
237 |
|
|
|
|
|
|
|
6,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
61 |
|
|
|
127,467 |
|
|
|
26,429 |
|
|
|
|
|
|
|
153,957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(61 |
) |
|
|
44,389 |
|
|
|
(3,269 |
) |
|
|
|
|
|
|
41,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
(10,601 |
) |
|
|
(14,052 |
) |
|
|
(4,829 |
) |
|
|
5,549 |
|
|
|
(23,933 |
) |
Equity income (loss) from subsidiaries |
|
|
25,775 |
|
|
|
|
|
|
|
|
|
|
|
(25,775 |
) |
|
|
|
|
Other |
|
|
2,794 |
|
|
|
3,565 |
|
|
|
47 |
|
|
|
(5,549 |
) |
|
|
857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses) |
|
|
17,968 |
|
|
|
(10,487 |
) |
|
|
(4,782 |
) |
|
|
(25,775 |
) |
|
|
(23,076 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest |
|
|
17,907 |
|
|
|
33,902 |
|
|
|
(8,051 |
) |
|
|
(25,775 |
) |
|
|
17,983 |
|
Income tax provision |
|
|
(8,910 |
) |
|
|
(61 |
) |
|
|
(15 |
) |
|
|
|
|
|
|
(8,986 |
) |
Minority interest in loss of consolidated partnership |
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
11,985 |
|
|
|
33,841 |
|
|
|
(8,066 |
) |
|
|
(25,775 |
) |
|
|
11,985 |
|
Amortization of deferred hedge (gains) losses, net of tax |
|
|
(4,801 |
) |
|
|
13,397 |
|
|
|
|
|
|
|
|
|
|
|
8,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
7,184 |
|
|
$ |
47,238 |
|
|
$ |
(8,066 |
) |
|
$ |
(25,775 |
) |
|
$ |
20,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2007
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
Consolidated |
|
|
|
Parent |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Total |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
|
|
|
$ |
338,935 |
|
|
$ |
38,579 |
|
|
$ |
|
|
|
$ |
377,514 |
|
Natural gas |
|
|
|
|
|
|
101,728 |
|
|
|
8,820 |
|
|
|
|
|
|
|
110,548 |
|
Marketing |
|
|
|
|
|
|
20,153 |
|
|
|
6,986 |
|
|
|
|
|
|
|
27,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
|
|
|
|
460,816 |
|
|
|
54,385 |
|
|
|
|
|
|
|
515,201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
|
|
|
|
|
95,843 |
|
|
|
9,343 |
|
|
|
|
|
|
|
105,186 |
|
Production, ad valorem, and severance taxes |
|
|
|
|
|
|
45,893 |
|
|
|
5,857 |
|
|
|
|
|
|
|
51,750 |
|
Depletion, depreciation, and amortization |
|
|
|
|
|
|
117,602 |
|
|
|
18,770 |
|
|
|
|
|
|
|
136,372 |
|
Exploration |
|
|
|
|
|
|
23,847 |
|
|
|
9 |
|
|
|
|
|
|
|
23,856 |
|
General and administrative |
|
|
57 |
|
|
|
18,491 |
|
|
|
7,668 |
|
|
|
|
|
|
|
26,216 |
|
Marketing |
|
|
|
|
|
|
21,952 |
|
|
|
5,655 |
|
|
|
|
|
|
|
27,607 |
|
Derivative fair value loss |
|
|
|
|
|
|
58,680 |
|
|
|
9,486 |
|
|
|
|
|
|
|
68,166 |
|
Other operating |
|
|
124 |
|
|
|
13,018 |
|
|
|
525 |
|
|
|
|
|
|
|
13,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
181 |
|
|
|
395,326 |
|
|
|
57,313 |
|
|
|
|
|
|
|
452,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(181 |
) |
|
|
65,490 |
|
|
|
(2,928 |
) |
|
|
|
|
|
|
62,381 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
(63,182 |
) |
|
|
(6,415 |
) |
|
|
(11,273 |
) |
|
|
12,830 |
|
|
|
(68,040 |
) |
Equity income (loss) from subsidiaries |
|
|
53,098 |
|
|
|
|
|
|
|
|
|
|
|
(53,098 |
) |
|
|
|
|
Other |
|
|
6,419 |
|
|
|
8,226 |
|
|
|
74 |
|
|
|
(12,830 |
) |
|
|
1,889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses) |
|
|
(3,665 |
) |
|
|
1,811 |
|
|
|
(11,199 |
) |
|
|
(53,098 |
) |
|
|
(66,151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interest |
|
|
(3,846 |
) |
|
|
67,301 |
|
|
|
(14,127 |
) |
|
|
(53,098 |
) |
|
|
(3,770 |
) |
Income tax provision |
|
|
(1,414 |
) |
|
|
(22 |
) |
|
|
(54 |
) |
|
|
|
|
|
|
(1,490 |
) |
Minority interest in loss of consolidated partnership |
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(2,272 |
) |
|
|
67,279 |
|
|
|
(14,181 |
) |
|
|
(53,098 |
) |
|
|
(2,272 |
) |
Amortization of deferred hedge (gains) losses, net of tax |
|
|
(15,041 |
) |
|
|
40,191 |
|
|
|
|
|
|
|
|
|
|
|
25,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(17,313 |
) |
|
$ |
107,470 |
|
|
$ |
(14,181 |
) |
|
$ |
(53,098 |
) |
|
$ |
22,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2007
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
Consolidated |
|
|
|
Parent |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Total |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
|
|
|
$ |
199,333 |
|
|
$ |
14,311 |
|
|
$ |
|
|
|
$ |
213,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from disposition of assets |
|
|
|
|
|
|
291,339 |
|
|
|
|
|
|
|
|
|
|
|
291,339 |
|
Acquisition of oil and natural gas properties |
|
|
|
|
|
|
(509,630 |
) |
|
|
(330,315 |
) |
|
|
|
|
|
|
(839,945 |
) |
Development of oil and natural gas properties |
|
|
|
|
|
|
(256,797 |
) |
|
|
(2,660 |
) |
|
|
|
|
|
|
(259,457 |
) |
Investments in subsidiaries |
|
|
(400,158 |
) |
|
|
|
|
|
|
|
|
|
|
400,158 |
|
|
|
|
|
Other |
|
|
|
|
|
|
(25,013 |
) |
|
|
(74 |
) |
|
|
|
|
|
|
(25,087 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
(400,158 |
) |
|
|
(500,101 |
) |
|
|
(333,049 |
) |
|
|
400,158 |
|
|
|
(833,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of ENP common units,
net of issuance costs |
|
|
|
|
|
|
|
|
|
|
171,220 |
|
|
|
|
|
|
|
171,220 |
|
Exercise of stock options and vesting of
restricted stock, net of treasury stock purchases |
|
|
1,053 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,053 |
|
Proceeds from long-term debt, net of issuance costs |
|
|
1,020,533 |
|
|
|
|
|
|
|
248,758 |
|
|
|
|
|
|
|
1,269,291 |
|
Payments on long-term debt |
|
|
(621,428 |
) |
|
|
|
|
|
|
(184,000 |
) |
|
|
|
|
|
|
(805,428 |
) |
Net equity contributions |
|
|
|
|
|
|
306,500 |
|
|
|
93,658 |
|
|
|
(400,158 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
(5,142 |
) |
|
|
(3,784 |
) |
|
|
|
|
|
|
(8,926 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
400,158 |
|
|
|
301,358 |
|
|
|
325,852 |
|
|
|
(400,158 |
) |
|
|
627,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents |
|
|
|
|
|
|
590 |
|
|
|
7,114 |
|
|
|
|
|
|
|
7,704 |
|
Cash and cash equivalents, beginning of period |
|
|
|
|
|
|
763 |
|
|
|
|
|
|
|
|
|
|
|
763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
|
|
|
$ |
1,353 |
|
|
$ |
7,114 |
|
|
$ |
|
|
|
$ |
8,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 14. Commitments and Contingencies
Litigation
EAC is a party to ongoing legal proceedings in the ordinary course of business. Management
does not believe the result of these proceedings will have a material adverse effect on EAC.
ExxonMobil
In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop
legacy natural gas fields in West Texas. Under the terms of the agreement, EAC will have the
opportunity to develop approximately 100,000 gross acres. EAC will earn 30 percent of ExxonMobils
working interest and 22.5 percent of ExxonMobils net revenue interest in each well drilled. EAC
will operate each well during the drilling and completion phase, after which ExxonMobil will assume
operational control of the well.
EAC will earn the right to participate in all fields by drilling a total of 24 commitment
wells. During the commitment phase, ExxonMobil will have the option to receive non-recourse
advanced funds from EAC attributable to ExxonMobils 70 percent working interest in each commitment
well. Once a commitment well is producing, ExxonMobil will repay 95 percent of the advanced funds
plus accrued interest assessed on the unpaid balance through EACs monthly receipt of future
proceeds of oil and natural gas sales. As an alternative to receiving advanced funds during the
commitment phase, ExxonMobil can elect to pay their share of capital costs for each well. After
EAC has fulfilled its obligations under the commitment phase, it will be entitled to a 30 percent
working interest in future drilling locations. EAC will have the right to propose and drill wells
for as long as it is engaged in continuous drilling operations.
During the nine months ended September 30, 2007 and the year ended December 31, 2006, EAC
advanced $30.8 million and $22.4 million, respectively, to ExxonMobil for its portion of capital
related to drilling commitment wells, of which $48.0 million and $21.0 million remained outstanding
at September 30, 2007 and December 31, 2006, respectively. At September 30,
22
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
2007, $2.5 million is included in Accounts receivable and $45.5 million is included in
Long-term receivables on the accompanying Consolidated Balance Sheet based on when EAC expects
repayment. At December 31, 2006, $3.0 million is included in Accounts receivable and $18.0
million is included in Long-term receivables on the accompanying Consolidated Balance Sheet. As
of September 30, 2007, EAC had seven additional wells to drill in order to fulfill its drilling
obligation under the joint development agreement at a minimum cost of $1.0 million per well.
Note 15. Related Party Transactions
EAC paid $1.3 million and $2.8 million to affiliates of Hanover Compressor Company (Hanover)
during the nine months ended September 30, 2007 and 2006, respectively, for compressors and field
compression services. Mr. I. Jon Brumley, EACs Chairman of the Board, served as a director of
Hanover until August 2007.
EAC also received $47.2 million and $5.9 million from affiliates of Tesoro Corporation
(Tesoro) during the nine months ended September 30, 2007 and 2006, respectively, related to its
working interest in wells operated by EAC. Mr. John V. Genova, a member of the Board, is employed
by Tesoro.
Note 16. ENP
On September 17, 2007, ENP completed its IPO of 9,000,000 common units, representing a 37.4
percent limited partner interest, at a price to the public of $21.00 per unit. The net proceeds of
$171.2 million, after deducting the underwriters discount and a structuring fee of $13.2 million,
in the aggregate, and estimated offering expenses of $4.6 million, were used to repay in full the
$126.4 million of outstanding indebtedness under ENPs subordinated credit agreement with EAP
Operating Inc., and $43.5 million of outstanding borrowings under the OLLC Credit Agreement.
In connection with the closing of the IPO, EAC, ENP, and certain of their respective
subsidiaries entered into a contribution, conveyance and assumption agreement (the Contribution
Agreement) and an amended and restated administrative services agreement (the Administrative
Services Agreement), each as more fully described below. In addition, prior to the IPO, Encore
Energy Partners GP LLC approved a long-term incentive plan (the ENP Plan) for employees,
consultants, and directors of Encore Operating, Encore Energy Partners GP LLC, and any of their
affiliates who perform services for ENP, as more fully described below.
Contribution, Conveyance and Assumption Agreement
ENP entered into the Contribution Agreement with Encore Energy Partners GP LLC, ENPs general
partner and wholly owned subsidiary of EAC, OLLC, EAC, Encore Operating, and Encore Partners LP
Holdings LLC. At the closing of the IPO, the following transactions, among others, occurred
pursuant to the Contribution Agreement:
|
|
|
Encore Operating transferred certain assets in the Permian Basin, as described in the
ENPs final prospectus (the Prospectus) dated September 11, 2007 (File No. 333-142847)
and filed with the SEC on September 12, 2007, to ENP in exchange for 4,043,478 common
units; and |
|
|
|
|
EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities,
and title defects, as well as defects relating to retained assets and liabilities,
occurring or existing before the closing. |
These transfers and distributions were made in a series of steps outlined in the Contribution
Agreement.
In connection with the issuance of the common units by ENP in exchange for the Permian Basin
assets, the IPO, and the exercise of the underwriters option to purchase additional common units,
Encore Energy Partners GP LLC exchanged such number of common units for general partner units as
was necessary to enable it to maintain its two percent general partner interest. Encore Energy
Partners GP LLC received the common units through capital contributions from EAC and its
subsidiaries of common units they owned.
Administrative Services Agreement
ENP entered into the Administrative Services Agreement with Encore Energy Partners GP LLC,
OLLC, Encore Operating,
23
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
and EAC. As more fully described in the Prospectus, Encore Operating will perform
administrative services for ENP, such as accounting, corporate development, finance, land, legal,
and engineering. In addition, Encore Operating will provide all personnel and any facilities,
goods, and equipment necessary to perform these services and not otherwise provided by the
Partnership. Encore Operating will receive an administrative fee of $1.75 per BOE of ENPs
production for such services and reimbursement of actual third-party expenses incurred on ENPs
behalf.
In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with
drilling and operating wells that would otherwise be paid by non-operating interest owners to the
operator of a well. Most joint operating agreements provide for an annual increase or decrease in
the COPAS overhead rate for drilling and producing wells. The rate change, which occurs in April,
is based on the change in average weekly earnings as measured by an index published by the United
States Department of Labor, Bureau of Labor Statistics. The COPAS overhead cost is charged to all
non-operating interest owners under a joint operating agreement each month.
ENP will also reimburse EAC for any additional state income, franchise, or similar tax paid by
EAC resulting from the inclusion of ENP (and its subsidiaries) in a combined state income,
franchise, or similar tax report with EAC as required by applicable law. The amount of any such
reimbursement will be limited to the tax that ENP (and its subsidiaries) would have paid had it not
been included in a combined group with EAC.
ENP does not have any employees. The employees supporting the operation of ENP are employees
of Encore Operating. Accordingly, EAC recognizes all employee-related liabilities in its
consolidated financial statements. Encore Operating has substantial discretion in determining
which third-party expenses to incur on ENPs behalf. ENP also pays its share of expenses that are
directly chargeable to wells under joint operating agreements. Encore Operating is not liable to
ENP for its performance of, or failure to perform, services under the Administrative Services
Agreement unless its acts or omissions constitute gross negligence or willful misconduct.
Long-Term Incentive Plan
The ENP Plan is for employees, consultants, and directors of Encore Operating, Encore Energy
Partners GP LLC, and any of their affiliates who perform services for ENP. As more fully described
in the Prospectus, the ENP Plan provides for the grant of options, restricted units, phantom units,
unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards.
An aggregate of 1,150,000 common units may be delivered pursuant to awards under the ENP Plan.
The ENP Plan will be administered by the board of directors of Encore Energy Partners GP LLC or a
committee thereof, referred to as the plan administrator.
As of September 30, 2007, no awards had been granted under the ENP Plan.
Management Incentive Units
In May 2007, the board of directors of Encore Energy Partners GP LLC issued 550,000 management
incentive units to the executive officers of Encore Energy Partners GP LLC. A management incentive
unit is a limited partner interest in ENP that entitles the holder to an initial quarterly
distribution of $0.35 (or $1.40 on an annualized basis) to the extent paid to ENPs common
unitholders and to increasing distributions upon the achievement of 10 percent compounding
increases in ENPs distribution rate to common unitholders. A management incentive unit is also
convertible into common units upon the occurrence of certain events. The management incentive
units are subject to a maximum limit on the aggregate number of common units issuable to, and the
aggregate distributions payable to, holders of management incentive units as follows:
|
|
|
the holders of management incentive units are not entitled to receive, in the aggregate,
common units upon conversion of the management incentive units that exceed a maximum limit
of 5.1 percent of all ENPs then-outstanding common units; and |
|
|
|
|
the holders of management incentive units are not entitled to receive, in the aggregate,
distributions of ENPs available cash in an amount that exceeds a maximum limit of 5.1
percent of all such distributions to all unitholders at the time of any such distribution. |
The holders of management incentive units do not have any voting rights with respect to the
unit.
24
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Continued
(unaudited)
The management incentive units vest in three equal installments. The first installment vested
upon the closing of the IPO, and the subsequent vesting will occur on the first and second
anniversary of such closing date. For the three and nine months ended September 30, 2007, ENP
recognized total compensation expense for the management incentive units of $5.7 million, which is
included in General and administrative expense in the accompanying Consolidated Statements of
Operations. As of September 30, 2007, ENP had $5.8 million of total unrecognized compensation cost
related to unvested, outstanding management incentive units, which is expected to be recognized
over a weighted average period of 1.5 years. For the fourth quarter 2007 through the third quarter
of 2008, the expense will be approximately $1.1 million per quarter, and for the fourth quarter
2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter.
There have been no additional issuances or forfeitures of management incentive units since the
initial issuance.
Note 17. Subsequent Events
On October 11, 2007, the underwriters exercised their over-allotment option to purchase an
additional 1,148,400 common units of ENP, representing an additional 2.9 percent limited partner interest,
which closed on October 16, 2007. The Company expects to use the net proceeds of $22.4 million,
after deducting the underwriters discount of $1.7 million, to repay outstanding borrowings under
the OLLC Credit Agreement.
On October 29, 2007, ENP issued 20,000 phantom units to members of the Encore Energy Partners
GP LLC board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive
a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator,
cash equivalent to the value of a common unit. The phantom units vest in four equal installments
beginning on the first anniversary of the date of grant. The holders of phantom units are also
entitled to receive distribution equivalent rights prior to vesting, which entitle the grantee to
receive cash equal to the amount of any cash distributions made by the Partnership with respect to
a common unit during the period the right is outstanding.
On October 29, 2007, ENP declared a distribution for the third quarter of 2007 to unitholders
of record as of the close of business on November 8, 2007. The $1.3 million total cash
distribution will be paid on November 14, 2007 to unitholders at a rate of $0.053 per unit. The
prorated quarterly distribution of $0.053 per unit is based on an initial quarterly distribution of
$0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of
the IPO) through September 30, 2007.
25
ENCORE ACQUISITION COMPANY
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
This document contains forward-looking statements, which give our current expectations or
forecasts of future events. Actual results may differ materially from those discussed in our
forward-looking statements due to many factors, including, but not limited to, those set forth
under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31,
2006. The following discussion should be read in conjunction with the consolidated financial
statements and notes thereto included in Item 1. Financial Statements of this Report and in Item
8. Financial Statements and Supplementary Data of our 2006 Annual Report on Form 10-K.
Introduction
In this managements discussion and analysis of financial condition and results of operations,
the following will be discussed and analyzed:
|
|
|
Third Quarter 2007 Highlights |
|
|
|
|
Results of Operations |
|
|
|
Comparison of Quarter Ended September 30, 2007 to Quarter Ended September 30, 2006 |
|
|
|
|
Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006 |
|
|
|
Capital Resources |
|
|
|
|
Capital Commitments and Contingencies |
|
|
|
|
Liquidity |
|
|
|
|
Critical Accounting Policies and Estimates |
|
|
|
|
New Accounting Pronouncements |
Third Quarter 2007 Highlights
Our financial and operating results for the third quarter of 2007 included the following:
|
|
|
Our oil and natural gas revenues increased 46 percent to $191.7 million as compared to
$131.7 million in the third quarter of 2006. Our oil and natural gas revenues increased as
a result of increased production volumes and higher realized average prices. |
|
|
|
|
Our realized average oil price, including the effects of commodity derivative contracts,
increased $8.68 per Bbl to $63.48 per Bbl as compared to $54.80 per Bbl in the third
quarter of 2006. Our realized average natural gas price, including the effects of
commodity derivative contracts, increased $0.21 per Mcf to $6.09 per Mcf as compared to
$5.88 per Mcf in the third quarter of 2006. |
|
|
|
|
Production volumes increased 25 percent to 36,917 BOE/D as compared to 29,651 BOE/D for
the third quarter of 2006. The rise in production volumes was primarily attributable to
our Big Horn Basin and Williston Basin acquisitions and our development programs. Oil
represented 74 percent and 67 percent of our total production volumes in the third quarter
of 2007 and 2006, respectively. |
|
|
|
|
We invested $124.9 million in oil and natural gas activities (excluding related asset
retirement obligations of $0.3 million). Of this amount, we invested $78.0 million in
development, exploitation, HPAI expansion, and exploration activities, which yielded 49
gross (15.5 net) productive wells, and $46.9 million in acquisitions. We operated between
six and nine drilling rigs, including four to six rigs related to our West Texas joint
development agreement. |
|
|
|
|
On September 17, 2007, ENP completed its IPO of 9,000,000 common units, representing a
37.4 percent limited partner interest in ENP, at a price to the public of $21.00 per unit.
On October 11, 2007, the underwriters exercised their over- allotment option to purchase 1,148,400 additional ENP common units, representing an
additional 2.9 percent limited partner interest in ENP. EAC currently owns approximately
58.0 percent of ENPs common units, as well as all the interests of ENPs general partner,
which a wholly owned subsidiary of EAC. |
26
ENCORE ACQUISITION COMPANY
Results of Operations
Comparison of Quarter Ended September 30, 2007 to Quarter Ended September 30, 2006
Oil and natural gas revenues and production. The following table illustrates the primary
components of oil and natural gas revenues for the three months ended September 30, 2007 and 2006,
as well as each quarters respective oil and natural gas production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
Increase / (Decrease) |
|
Revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead |
|
$ |
170,118 |
|
|
$ |
112,959 |
|
|
$ |
57,159 |
|
|
|
|
|
Oil hedges |
|
|
(10,823 |
) |
|
|
(13,443 |
) |
|
|
2,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil revenues |
|
$ |
159,295 |
|
|
$ |
99,516 |
|
|
$ |
59,779 |
|
|
|
60 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas wellhead |
|
$ |
35,012 |
|
|
$ |
33,144 |
|
|
$ |
1,868 |
|
|
|
|
|
Natural gas hedges |
|
|
(2,573 |
) |
|
|
(967 |
) |
|
|
(1,606 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas revenues |
|
$ |
32,439 |
|
|
$ |
32,177 |
|
|
$ |
262 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead |
|
$ |
205,130 |
|
|
$ |
146,103 |
|
|
$ |
59,027 |
|
|
|
|
|
Combined hedges |
|
|
(13,396 |
) |
|
|
(14,410 |
) |
|
|
1,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total combined oil and natural gas revenues |
|
$ |
191,734 |
|
|
$ |
131,693 |
|
|
$ |
60,041 |
|
|
|
46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead ($/Bbl) |
|
$ |
67.80 |
|
|
$ |
62.20 |
|
|
$ |
5.60 |
|
|
|
|
|
Oil hedges ($/Bbl) |
|
|
(4.32 |
) |
|
|
(7.40 |
) |
|
|
3.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil revenues ($/Bbl) |
|
$ |
63.48 |
|
|
$ |
54.80 |
|
|
$ |
8.68 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas wellhead ($/Mcf) |
|
$ |
6.58 |
|
|
$ |
6.06 |
|
|
$ |
0.52 |
|
|
|
|
|
Natural gas hedges ($/Mcf) |
|
|
(0.49 |
) |
|
|
(0.18 |
) |
|
|
(0.31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas revenues ($/Mcf) |
|
$ |
6.09 |
|
|
$ |
5.88 |
|
|
$ |
0.21 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead ($/BOE) |
|
$ |
60.39 |
|
|
$ |
53.56 |
|
|
$ |
6.83 |
|
|
|
|
|
Combined hedges ($/BOE) |
|
|
(3.94 |
) |
|
|
(5.28 |
) |
|
|
1.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total combined oil and natural gas revenues ($/BOE) |
|
$ |
56.45 |
|
|
$ |
48.28 |
|
|
$ |
8.17 |
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
2,509 |
|
|
|
1,816 |
|
|
|
693 |
|
|
|
38 |
% |
Natural gas (MMcf) |
|
|
5,323 |
|
|
|
5,471 |
|
|
|
(148 |
) |
|
|
-3 |
% |
Combined (MBOE) |
|
|
3,396 |
|
|
|
2,728 |
|
|
|
668 |
|
|
|
24 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/D) |
|
|
27,275 |
|
|
|
19,740 |
|
|
|
7,535 |
|
|
|
38 |
% |
Natural gas (Mcf/D) |
|
|
57,857 |
|
|
|
59,463 |
|
|
|
(1,606 |
) |
|
|
-3 |
% |
Combined (BOE/D) |
|
|
36,917 |
|
|
|
29,651 |
|
|
|
7,266 |
|
|
|
25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
75.21 |
|
|
$ |
70.62 |
|
|
$ |
4.59 |
|
|
|
6 |
% |
Natural gas (per Mcf) |
|
$ |
6.16 |
|
|
$ |
6.58 |
|
|
$ |
(0.42 |
) |
|
|
-6 |
% |
Oil revenues increased $59.8 million from $99.5 million in the third quarter of 2006 to $159.3
million in the third quarter of 2007. The increase is primarily due to an increase in oil
production volumes of 693 MBbls, which contributed approximately $43.1 million in additional oil
revenues. The increase in oil production volumes is primarily the result of our Big Horn Basin and
Williston Basin acquisitions and our development programs.
Our average realized oil price increased $8.68 per Bbl as a result of an increase in our
wellhead price and a decrease in the effects of commodity derivative contracts included in oil
revenues. Our higher average oil wellhead price increased oil revenues by $14.0 million, or $5.60
per Bbl, and the decrease in the effects of commodity derivative contracts, which were previously
designated as hedges, increased oil revenues by $2.6 million, or $3.08 per Bbl. Our average oil
wellhead price increased as a result of increases in the overall market price for oil, as reflected
in the increase in the average NYMEX price from $70.62 per
27
ENCORE ACQUISITION COMPANY
Bbl in the third quarter of 2006 to
$75.21 per Bbl in the third quarter of 2007.
Our oil wellhead revenue was reduced by $9.8 million and $7.1 million in the third quarter of
2007 and 2006, respectively, for the net profits interests payments related to our CCA properties.
Natural gas revenues increased $0.3 million from $32.2 million in the third quarter of 2006 to
$32.4 million in the third quarter of 2007. The increase is primarily due to an increase in our
average realized natural gas price. Our average realized natural gas price increased $0.21 per Mcf
as a result of an increase in our wellhead price, partially offset by an increase in the effects of
commodity derivative contracts, which were previously designated as hedges, included in natural gas
revenues. Our higher average natural gas wellhead price increased natural gas revenues by $2.8
million, or $0.52 per Mcf, while the increase in the effects of commodity derivative contracts
reduced natural gas revenues by $1.6 million, or $0.31 per Mcf. Our average natural gas wellhead
price increased as a result of the tightening of our natural gas differential despite decreases in
the overall market price for natural gas, as reflected in the decrease in the average NYMEX price
from $6.58 per Mcf in the third quarter of 2006 to $6.16 per Mcf in the third quarter of 2007.
Production volumes decreased 148 MMcf, which reduced natural gas revenues by approximately
$0.9 million. The decrease in natural gas production volumes is primarily the result of, 18,218
Mcf/D of natural gas production in the third quarter of 2006 associated with our Mid-Continent
disposition, partially offset by production added through our development programs on the West
Texas joint development agreement with ExxonMobil and in the Mid-Continent area.
The table below illustrates the relationship between oil and natural gas wellhead prices as a
percentage of average NYMEX prices for the three months ended September 30, 2007 and 2006.
Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas
revenues.
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
2007 |
|
2006 |
Oil wellhead ($/Bbl) |
|
$ |
67.80 |
|
|
$ |
62.20 |
|
Average NYMEX ($/Bbl) |
|
$ |
75.21 |
|
|
$ |
70.62 |
|
Differential to NYMEX |
|
$ |
(7.41 |
) |
|
$ |
(8.42 |
) |
Oil wellhead to NYMEX percentage |
|
|
90 |
% |
|
|
88 |
% |
|
|
|
|
|
|
|
|
|
Natural gas wellhead ($/Mcf) |
|
$ |
6.58 |
|
|
$ |
6.06 |
|
Average NYMEX ($/Mcf) |
|
$ |
6.16 |
|
|
$ |
6.58 |
|
Differential to NYMEX |
|
$ |
0.42 |
|
|
$ |
(0.52 |
) |
Natural gas wellhead to NYMEX percentage |
|
|
107 |
% |
|
|
92 |
% |
Our oil wellhead price as a percentage of the average NYMEX price tightened to 90 percent in
the third quarter of 2007 as compared to 88 percent in the third quarter of 2006. We expect our
oil wellhead differentials to remain approximately constant or to widen slightly in the fourth
quarter of 2007 as compared to the third quarter of 2007 due to continued production increases from
competing Canadian and Rocky Mountain producers, limited refining and pipeline capacity in the
Rocky Mountain area, and corresponding steep pricing discounts.
Our natural gas wellhead price as a percentage of the average NYMEX price improved to 107
percent in the third quarter of 2007 as compared to 92 percent in the third quarter of 2006. The
differential improved because of efforts to reduce natural gas transportation and gathering costs.
We expect our natural gas wellhead differentials to remain approximately constant or to widen
slightly in the fourth quarter of 2007 as compared to the third quarter of 2007.
Marketing revenues and expenses. In 2006 and in declining quantities during 2007, we began
purchasing third-party oil Bbls from a counterparty other than to whom the Bbls were sold for
aggregation and sale with our own equity production in various markets. These purchases assist us
in marketing our production by decreasing our dependence on individual markets. These activities allow us to aggregate larger volumes, facilitate our efforts to maximize the
prices we receive for production, provide for a greater allocation of future pipeline capacity in
the event of curtailments, and enable us to reach other markets.
In March 2007, we acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin
acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the
pipeline and resold downstream to various local and off-system markets.
28
ENCORE ACQUISITION COMPANY
The following table summarizes our marketing activities for the three months ended September
30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per BOE amounts) |
|
Marketing revenues |
|
$ |
3,282 |
|
|
$ |
46,004 |
|
Marketing expenses |
|
|
4,089 |
|
|
|
48,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing, net |
|
$ |
(807 |
) |
|
$ |
(1,997 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing revenues per BOE |
|
$ |
0.97 |
|
|
$ |
16.86 |
|
Marketing expenses per BOE |
|
|
1.21 |
|
|
|
17.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing, net per BOE |
|
$ |
(0.24 |
) |
|
$ |
(0.74 |
) |
|
|
|
|
|
|
|
Expenses. The following table summarizes our expenses, excluding marketing expenses shown
above, for the three months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
Increase / (Decrease) |
|
Expenses (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
$ |
37,114 |
|
|
$ |
24,478 |
|
|
$ |
12,636 |
|
|
|
|
|
Production, ad valorem, and severance taxes |
|
|
20,003 |
|
|
|
13,560 |
|
|
|
6,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
|
57,117 |
|
|
|
38,038 |
|
|
|
19,079 |
|
|
|
50 |
% |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
49,026 |
|
|
|
27,471 |
|
|
|
21,555 |
|
|
|
|
|
Exploration |
|
|
8,920 |
|
|
|
12,322 |
|
|
|
(3,402 |
) |
|
|
|
|
General and administrative |
|
|
12,668 |
|
|
|
6,250 |
|
|
|
6,418 |
|
|
|
|
|
Derivative fair value loss (gain) |
|
|
15,786 |
|
|
|
(33,363 |
) |
|
|
49,149 |
|
|
|
|
|
Other operating |
|
|
6,351 |
|
|
|
976 |
|
|
|
5,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating |
|
|
149,868 |
|
|
|
51,694 |
|
|
|
98,174 |
|
|
|
190 |
% |
Interest |
|
|
23,933 |
|
|
|
11,261 |
|
|
|
12,672 |
|
|
|
|
|
Income tax provision |
|
|
8,986 |
|
|
|
25,069 |
|
|
|
(16,083 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
$ |
182,787 |
|
|
$ |
88,024 |
|
|
$ |
94,763 |
|
|
|
108 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (per BOE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
$ |
10.93 |
|
|
$ |
8.97 |
|
|
$ |
1.96 |
|
|
|
|
|
Production, ad valorem, and severance taxes |
|
|
5.89 |
|
|
|
4.97 |
|
|
|
0.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
|
16.82 |
|
|
|
13.94 |
|
|
|
2.88 |
|
|
|
21 |
% |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
14.43 |
|
|
|
10.07 |
|
|
|
4.36 |
|
|
|
|
|
Exploration |
|
|
2.63 |
|
|
|
4.52 |
|
|
|
(1.89 |
) |
|
|
|
|
General and administrative |
|
|
3.73 |
|
|
|
2.29 |
|
|
|
1.44 |
|
|
|
|
|
Derivative fair value loss (gain) |
|
|
4.65 |
|
|
|
(12.23 |
) |
|
|
16.88 |
|
|
|
|
|
Other operating |
|
|
1.87 |
|
|
|
0.36 |
|
|
|
1.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating |
|
|
44.13 |
|
|
|
18.95 |
|
|
|
25.18 |
|
|
|
133 |
% |
Interest |
|
|
7.05 |
|
|
|
4.13 |
|
|
|
2.92 |
|
|
|
|
|
Income tax provision |
|
|
2.65 |
|
|
|
9.19 |
|
|
|
(6.54 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
$ |
53.83 |
|
|
$ |
32.27 |
|
|
$ |
21.56 |
|
|
|
67 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
ENCORE ACQUISITION COMPANY
Production expenses. Total production expenses increased $19.1 million from $38.0 million in
the third quarter of 2006 to $57.1 million in the third quarter of 2007. This increase resulted
from an increase in total production volumes, as well as a $2.88 increase in production expenses
per BOE. Our production margin (defined as oil and natural gas revenues less production expenses)
for the third quarter of 2007 increased by $41.0 million (44 percent) to $134.6 million in the
third quarter of 2007 as compared to $93.7 million in the third quarter of 2006. Total production
expenses per BOE increased by 21 percent while total oil and natural gas revenues per BOE increased
by only 17 percent. On a per BOE basis, our production margin increased 15 percent to $39.63 per
BOE for the third quarter of 2007 as compared to $34.34 per BOE for the third quarter of 2006.
The production expense attributable to lease operations expense (LOE) increased $12.6
million from $24.5 million in the third quarter of 2006 to $37.1 million in the third quarter of
2007, primarily as a result of an increase in production volumes, which contributed approximately
$6.0 million of additional LOE, and an $1.96 increase in the average per BOE rate, which
contributed approximately $6.6 million of additional LOE. The increase in production volumes is
the result of our Big Horn Basin and Williston Basin acquisitions. The increase in our average LOE
per BOE rate was attributable to:
|
|
|
increases in prices paid to oilfield service companies and suppliers; |
|
|
|
|
increased operational activity to maximize production; |
|
|
|
|
HPAI expensed at the CCA; and |
|
|
|
|
higher salary levels for engineers and other technical professionals. |
The production expense attributable to production, ad valorem, and severance taxes
(production taxes) increased $6.4 million from $13.6 million in the third quarter of 2006 to
$20.0 million in the third quarter of 2007. The increase is due to higher wellhead revenues. As a
percentage of oil and natural gas revenues (excluding the effects of commodity derivative
contracts), production taxes increased to 9.8 percent in the third quarter of 2007 as compared to
9.3 percent in the third quarter of 2006 as a result of higher rates in the states where the
properties associated with the Williston Basin acquisition are located. The effect of commodity
derivative contracts is excluded from oil and natural gas revenues in the calculation of these
percentages because this method more closely reflects the method used to calculate actual
production taxes paid to taxing authorities.
Depletion, depreciation, and amortization (DD&A) expense. DD&A expense increased $21.6
million from $27.5 million in the third quarter of 2006 to $49.0 million in the third quarter of
2007 due to an increase in the per BOE rate of $4.36 and increased production volumes. The
increase in the per BOE rate was due to the higher cost basis of our recently acquired Big Horn
Basin and Williston Basin properties, development of proved undeveloped reserves and higher
finding, development, and acquisition costs resulting from increases in rig rates, oilfield
services costs, and acquisition costs. These factors resulted in additional DD&A expense of
approximately $14.8 million, while the increase in production volumes resulted in additional DD&A
expense of approximately $6.7 million.
Exploration expense. Exploration expense decreased $3.4 million from $12.3 million in the
third quarter of 2006 to $8.9 million in the third quarter of 2007. During the third quarter of
2007, we expensed two exploratory dry holes totaling $5.7 million. During the third quarter of
2006, we expensed four exploratory dry holes totaling $10.0 million. However, impairment of
unproved acreage in the third quarter of 2007 increased $1.0 million as compared to the third
quarter of 2006 as we added additional leasehold costs and refined our estimated success rate in
certain areas. The following table details our exploration expenses for the three months ended
September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
(in thousands) |
|
Dry holes |
|
$ |
5,683 |
|
|
$ |
9,962 |
|
|
$ |
(4,279 |
) |
Geological and seismic |
|
|
153 |
|
|
|
222 |
|
|
|
(69 |
) |
Delay rentals |
|
|
126 |
|
|
|
175 |
|
|
|
(49 |
) |
Impairment of unproved acreage |
|
|
2,958 |
|
|
|
1,963 |
|
|
|
995 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,920 |
|
|
$ |
12,322 |
|
|
$ |
(3,402 |
) |
|
|
|
|
|
|
|
|
|
|
General and administrative (G&A) expense. G&A expense increased $6.4 million from $6.3
million in the third quarter of 2006 to $12.7 million in the third quarter of 2007. The overall
increase is primarily the result of $5.7 million of non-cash unit-based compensation related to
ENPs management incentive units.
30
ENCORE ACQUISITION COMPANY
Derivative fair value loss (gain). To increase clarity in our financial statements by
accounting for all commodity derivative contracts under the same method, we elected to discontinue
hedge accounting prospectively for all commodity derivative contracts beginning in July 2006.
While this change has no effect on our cash flows, results of operations are affected by
mark-to-market gains and losses, which fluctuate with the changes in oil and natural gas prices.
During the third quarter of 2007, we recorded a $15.8 million derivative fair value loss as
compared to a $33.4 million derivative fair value gain in the third quarter of 2006, the components
of which were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
(in thousands) |
|
Mark-to-market loss (gain) on commodity contracts |
|
$ |
9,686 |
|
|
$ |
(37,729 |
) |
|
$ |
47,415 |
|
Premium amortization |
|
|
10,462 |
|
|
|
3,449 |
|
|
|
7,013 |
|
Settlements on commodity contracts |
|
|
(4,362 |
) |
|
|
917 |
|
|
|
(5,279 |
) |
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain) |
|
$ |
15,786 |
|
|
$ |
(33,363 |
) |
|
$ |
49,149 |
|
|
|
|
|
|
|
|
|
|
|
Other operating expense. Other operating expense increased $5.4 million from $1.0 million in
the third quarter of 2006 to $6.4 million in the third quarter of 2007. The increase is primarily
due to a $3.5 million loss on the sale of the Mid-Continent properties and increases in third-party
transportation costs attributable to moving our CCA production into markets outside the immediate
area of the production.
Interest expense. Interest expense increased $12.7 million from $11.3 million in the third
quarter of 2006 to $23.9 million the third quarter of 2007. The increase is primarily due to
additional debt used to finance the Big Horn Basin and Williston Basin acquisitions. The weighted
average interest rate for all long-term debt for the third quarter of 2007 was 7.1 percent as
compared to 6.9 percent for the third quarter of 2006.
The following table illustrates the components of interest expense for the three months ended
September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
(in thousands) |
|
6 1/4% Notes |
|
$ |
2,427 |
|
|
$ |
2,422 |
|
|
$ |
5 |
|
6% Notes |
|
|
4,631 |
|
|
|
4,624 |
|
|
|
7 |
|
7 1/4% Notes |
|
|
2,747 |
|
|
|
2,745 |
|
|
|
2 |
|
Revolving credit facilities |
|
|
13,186 |
|
|
|
550 |
|
|
|
12,636 |
|
Other |
|
|
942 |
|
|
|
920 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
23,933 |
|
|
$ |
11,261 |
|
|
$ |
12,672 |
|
|
|
|
|
|
|
|
|
|
|
Minority interest. After ENPs IPO in September 2007 and the underwriters over-allotment
exercise in October 2007, public unitholders have a limited partner interest of approximately 40.2
percent. We include ENP in our consolidated financial statements and show the ownership by the
public as a minority interest. The minority interest loss in ENP was $3.0 million for the third
quarter of 2007.
Income taxes. During the third quarter of 2007, we recorded an income tax provision of $9.0
million as compared to $25.1 million in the third quarter of 2006. Our effective tax rate
increased to 42.9 percent in the third quarter of 2007 as compared to 37.3 percent in the third
quarter of 2006 primarily due to a permanent rate adjustment for ENPs management incentive units.
31
ENCORE ACQUISITION COMPANY
Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006
Oil and natural gas revenues and production. The following table illustrates the primary
components of oil and natural gas revenues for the nine months ended September 30, 2007 and 2006,
as well as each periods respective oil and natural gas production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
Increase / (Decrease) |
|
Revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead |
|
$ |
409,985 |
|
|
$ |
306,833 |
|
|
$ |
103,152 |
|
|
|
|
|
Oil hedges |
|
|
(32,471 |
) |
|
|
(38,767 |
) |
|
|
6,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil revenues |
|
$ |
377,514 |
|
|
$ |
268,066 |
|
|
$ |
109,448 |
|
|
|
41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas wellhead |
|
$ |
118,267 |
|
|
$ |
115,948 |
|
|
$ |
2,319 |
|
|
|
|
|
Natural gas hedges |
|
|
(7,719 |
) |
|
|
(6,898 |
) |
|
|
(821 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas revenues |
|
$ |
110,548 |
|
|
$ |
109,050 |
|
|
$ |
1,498 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead |
|
$ |
528,252 |
|
|
$ |
422,781 |
|
|
$ |
105,471 |
|
|
|
|
|
Combined hedges |
|
|
(40,190 |
) |
|
|
(45,665 |
) |
|
|
5,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total combined oil and natural gas revenues |
|
$ |
488,062 |
|
|
$ |
377,116 |
|
|
$ |
110,946 |
|
|
|
29 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead ($/Bbl) |
|
$ |
58.35 |
|
|
$ |
55.85 |
|
|
$ |
2.50 |
|
|
|
|
|
Oil hedges ($/Bbl) |
|
|
(4.62 |
) |
|
|
(7.06 |
) |
|
|
2.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil revenues ($/Bbl) |
|
$ |
53.73 |
|
|
$ |
48.79 |
|
|
$ |
4.94 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas wellhead ($/Mcf) |
|
$ |
6.44 |
|
|
$ |
6.60 |
|
|
$ |
(0.16 |
) |
|
|
|
|
Natural gas hedges ($/Mcf) |
|
|
(0.42 |
) |
|
|
(0.39 |
) |
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas revenues ($/Mcf) |
|
$ |
6.02 |
|
|
$ |
6.21 |
|
|
$ |
(0.19 |
) |
|
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead ($/BOE) |
|
$ |
52.37 |
|
|
$ |
50.21 |
|
|
$ |
2.16 |
|
|
|
|
|
Combined hedges ($/BOE) |
|
|
(3.98 |
) |
|
|
(5.42 |
) |
|
|
1.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total combined oil and natural gas revenues ($/BOE) |
|
$ |
48.39 |
|
|
$ |
44.79 |
|
|
$ |
3.60 |
|
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
7,027 |
|
|
|
5,494 |
|
|
|
1,533 |
|
|
|
28 |
% |
Natural gas (MMcf) |
|
|
18,359 |
|
|
|
17,555 |
|
|
|
804 |
|
|
|
5 |
% |
Combined (MBOE) |
|
|
10,086 |
|
|
|
8,420 |
|
|
|
1,666 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/D) |
|
|
25,738 |
|
|
|
20,124 |
|
|
|
5,614 |
|
|
|
28 |
% |
Natural gas (Mcf/D) |
|
|
67,249 |
|
|
|
64,304 |
|
|
|
2,945 |
|
|
|
5 |
% |
Combined (BOE/D) |
|
|
36,946 |
|
|
|
30,842 |
|
|
|
6,104 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
66.21 |
|
|
$ |
68.23 |
|
|
$ |
(2.02 |
) |
|
|
-3 |
% |
Natural gas (per Mcf) |
|
$ |
6.83 |
|
|
$ |
7.39 |
|
|
$ |
(0.56 |
) |
|
|
-8 |
% |
Oil revenues increased $109.4 million from $268.1 million in the first nine months of 2006 to
$377.5 million in the first nine months of 2007. The increase is primarily due to an increase in
oil production volumes of 1,533 MBbls, which contributed approximately $85.6 million in additional
oil revenues. The increase in oil production volumes is primarily the result of our Big Horn Basin
and Williston Basin acquisitions and our development programs.
Our average realized oil price increased $4.94 per Bbl as a result of an increase in our
wellhead price and a decrease in the effects of commodity derivative contracts included in oil
revenues. Our higher average oil wellhead price increased oil revenues by $17.6 million, or $2.50
per Bbl, and the decrease in the effects of commodity derivative contracts, which were previously
designated as hedges, increased oil revenues by $6.3 million, or $2.44 per Bbl. Our average oil
wellhead price increased as a result of the tightening of our oil differential despite decreases in
the overall market price for oil, as reflected in the decrease in the average NYMEX price from
$68.23 per Bbl in the first nine months of 2006 to $66.21 per Bbl in the first nine months of
32
ENCORE ACQUISITION COMPANY
2007.
Our oil wellhead revenue was reduced by $20.0 million and $19.2 million in the first nine
months of 2007 and 2006, respectively, for the net profits interests payments related to our CCA
properties.
Natural gas revenues increased $1.5 million from $109.1 million for the first nine months of
2006 to $110.5 million for the first nine months of 2007. The increase is primarily due to an
increase in production volumes of 804 MMcf, which contributed approximately $5.3 million in
additional natural gas revenues. The increase in natural gas production volumes is the result of
our West Texas joint development program with ExxonMobil and our development program in the
Mid-Continent area, partially offset by natural gas production sold in conjunction with our
Mid-Continent disposition. Our natural gas production volumes would have been 53,445 Mcf/D and
47,258 Mcf/D for the first nine months of 2007 and 2006, respectively, excluding volumes associated
with our Mid-Continent disposition.
Our average realized natural gas price decreased $0.19 per Mcf as a result of a decrease in
our wellhead price and an increase in the effects of commodity derivative contracts included in
natural gas revenues. Our lower average natural gas wellhead price reduced natural gas revenues by
$3.0 million, or $0.16 per Mcf, and the increase in the effects of commodity derivative contracts,
which were previously designated as hedges, reduced natural gas revenues by $0.8 million, or $0.03
per Mcf. Our average natural gas wellhead price decreased as a result of decreases in the overall
market price for natural gas, as reflected in the decrease in the average NYMEX price from $7.39
per Mcf in the first nine months of 2006 to $6.83 per Mcf in the first nine months of 2007.
The table below illustrates the relationship between oil and natural gas wellhead prices as a
percentage of average NYMEX prices for the nine months ended September 30, 2007 and 2006.
Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas
revenues.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
2007 |
|
2006 |
Oil wellhead ($/Bbl) |
|
$ |
58.35 |
|
|
$ |
55.85 |
|
Average NYMEX ($/Bbl) |
|
$ |
66.21 |
|
|
$ |
68.23 |
|
Differential to NYMEX |
|
$ |
(7.86 |
) |
|
$ |
(12.38 |
) |
Oil wellhead to NYMEX percentage |
|
|
88 |
% |
|
|
82 |
% |
|
|
|
|
|
|
|
|
|
Natural gas wellhead ($/Mcf) |
|
$ |
6.44 |
|
|
$ |
6.60 |
|
Average NYMEX ($/Mcf) |
|
$ |
6.83 |
|
|
$ |
7.39 |
|
Differential to NYMEX |
|
$ |
(0.39 |
) |
|
$ |
(0.79 |
) |
Natural gas wellhead to NYMEX percentage |
|
|
94 |
% |
|
|
89 |
% |
Our oil wellhead price as a percentage of the average NYMEX price tightened to 88 percent in
the first nine months of 2007 as compared to 82 percent in the first nine months of 2006.
Our natural gas wellhead price as a percentage of the average NYMEX price tightened to 94
percent in the first nine months of 2007 as compared to 89 percent in the first nine months of
2006.
Marketing revenues and expenses. The following table summarizes our marketing activities for
the nine months ended September 30, 2007 and 2006:
33
ENCORE ACQUISITION COMPANY
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per BOE amounts) |
|
Marketing revenues |
|
$ |
27,139 |
|
|
$ |
106,036 |
|
Marketing expenses |
|
|
27,607 |
|
|
|
105,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing, net |
|
$ |
(468 |
) |
|
$ |
375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing revenues per BOE |
|
$ |
2.69 |
|
|
$ |
12.59 |
|
Marketing expenses per BOE |
|
|
2.74 |
|
|
|
12.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing, net per BOE |
|
$ |
(0.05 |
) |
|
$ |
0.04 |
|
|
|
|
|
|
|
|
Expenses. The following table summarizes our expenses, excluding marketing expenses shown
above, for the nine months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase / (Decrease) |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
Expenses (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
$ |
105,186 |
|
|
$ |
70,332 |
|
|
$ |
34,854 |
|
|
|
|
|
Production, ad valorem, and severance taxes |
|
|
51,750 |
|
|
|
38,382 |
|
|
|
13,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
|
156,936 |
|
|
|
108,714 |
|
|
|
48,222 |
|
|
|
44 |
% |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
136,372 |
|
|
|
82,479 |
|
|
|
53,893 |
|
|
|
|
|
Exploration |
|
|
23,856 |
|
|
|
18,347 |
|
|
|
5,509 |
|
|
|
|
|
General and administrative |
|
|
26,216 |
|
|
|
18,199 |
|
|
|
8,017 |
|
|
|
|
|
Derivative fair value loss (gain) |
|
|
68,166 |
|
|
|
(20,263 |
) |
|
|
88,429 |
|
|
|
|
|
Other operating |
|
|
13,667 |
|
|
|
3,573 |
|
|
|
10,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating |
|
|
425,213 |
|
|
|
211,049 |
|
|
|
214,164 |
|
|
|
101 |
% |
Interest |
|
|
68,040 |
|
|
|
33,766 |
|
|
|
34,274 |
|
|
|
|
|
Income tax provision |
|
|
1,490 |
|
|
|
51,382 |
|
|
|
(49,892 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
$ |
494,743 |
|
|
$ |
296,197 |
|
|
$ |
198,546 |
|
|
|
67 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (per BOE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operations |
|
$ |
10.43 |
|
|
$ |
8.35 |
|
|
$ |
2.08 |
|
|
|
|
|
Production, ad valorem, and severance taxes |
|
|
5.13 |
|
|
|
4.56 |
|
|
|
0.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
|
15.56 |
|
|
|
12.91 |
|
|
|
2.65 |
|
|
|
21 |
% |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
13.52 |
|
|
|
9.80 |
|
|
|
3.72 |
|
|
|
|
|
Exploration |
|
|
2.37 |
|
|
|
2.18 |
|
|
|
0.19 |
|
|
|
|
|
General and administrative |
|
|
2.60 |
|
|
|
2.16 |
|
|
|
0.44 |
|
|
|
|
|
Derivative fair value loss (gain) |
|
|
6.76 |
|
|
|
(2.41 |
) |
|
|
9.17 |
|
|
|
|
|
Other operating |
|
|
1.35 |
|
|
|
0.42 |
|
|
|
0.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating |
|
|
42.16 |
|
|
|
25.06 |
|
|
|
17.10 |
|
|
|
68 |
% |
Interest |
|
|
6.75 |
|
|
|
4.01 |
|
|
|
2.74 |
|
|
|
|
|
Income tax provision |
|
|
0.15 |
|
|
|
6.10 |
|
|
|
(5.95 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
$ |
49.06 |
|
|
$ |
35.17 |
|
|
$ |
13.89 |
|
|
|
39 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses. Total production expenses increased $48.2 million from $108.7 million in
the first nine months of 2006 to $156.9 million in the first nine months of 2007. This increase
resulted from an increase in total production volumes, as
34
ENCORE ACQUISITION COMPANY
well as a $2.65 increase in production
expenses per BOE. Our production margin for the first nine months of 2007 increased by $62.7
million (23 percent) to $331.1 million in the first nine months of 2007 as compared to $268.4
million for the first nine months of 2006. Total production expenses per BOE increased by 21
percent while total oil and natural gas revenues per BOE increased by only eight percent. On a per
BOE basis, our production margin increased three percent to $32.83 per BOE for the first nine
months of 2007 as compared to $31.88 per BOE for the first nine months of 2006.
The production expense attributable to LOE increased $34.9 million from $70.3 million in the
first nine months of 2006 to $105.2 million in the first nine months of 2007, primarily as a result
of an $2.08 increase in the average per BOE rate, which contributed approximately $20.9 million of
additional LOE, and an increase in production volumes, which contributed approximately $13.9
million of additional LOE. The increase in production volumes is the result of our Big Horn Basin
and Williston Basin acquisitions. The increase in our average LOE per BOE rate was attributable
to:
|
|
|
increases in prices paid to oilfield service companies and suppliers; |
|
|
|
|
increased operational activity to maximize production; |
|
|
|
|
HPAI expensed at the CCA; and |
|
|
|
|
higher salary levels for engineers and other technical professionals. |
The production expense attributable to production taxes increased $13.4 million from $38.4
million for the first nine months of 2006 to $51.8 million for the first nine months of 2007. The
increase is due to higher wellhead revenues. As a percentage of oil and natural gas revenues
(excluding the effects of commodity derivative contracts), production taxes increased to 9.8
percent in the first nine months of 2007 as compared to 9.1 percent in the first nine months of
2006 as a result of higher rates in the states where the properties associated with the Big Horn
Basin and Williston Basin acquisitions are located.
DD&A expense. DD&A expense increased $53.9 million from $82.5 million for the first nine
months of 2006 to $136.4 million for the first nine months of 2007 due to an increase in the per
BOE rate of $3.72 and increased production volumes. The per BOE rate increased due to the higher
cost basis of our recently acquired Big Horn Basin and Williston Basin properties, development of
proved undeveloped reserves and higher finding, development, and acquisition costs resulting from
increases in rig rates, oilfield services costs, and acquisition costs. These factors resulted in
additional DD&A expense of approximately $37.6 million, while the increase in production volumes
resulted in additional DD&A expense of approximately $16.3 million.
Exploration expense. Exploration expense increased $5.5 million from $18.3 million in the
first nine months of 2006 to $23.9 million in the first nine months of 2007. During the first nine
months of 2007, we expensed five exploratory dry holes totaling $14.7 million. During the first
nine months of 2006, we expensed 11 exploratory dry holes totaling $12.5 million. In addition,
impairment of unproved acreage in the first nine months of 2007 increased $4.0 million as compared
to the first nine months of 2006 as we added additional leasehold costs and refined our estimated
success rate in certain areas. The following table details our exploration expenses for the nine
months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
(in thousands) |
|
Dry holes |
|
$ |
14,703 |
|
|
$ |
12,542 |
|
|
$ |
2,161 |
|
Geological and seismic |
|
|
878 |
|
|
|
1,474 |
|
|
|
(596 |
) |
Delay rentals |
|
|
467 |
|
|
|
530 |
|
|
|
(63 |
) |
Impairment of unproved acreage |
|
|
7,808 |
|
|
|
3,801 |
|
|
|
4,007 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
23,856 |
|
|
$ |
18,347 |
|
|
$ |
5,509 |
|
|
|
|
|
|
|
|
|
|
|
G&A expense. G&A expense increased $8.0 million from $18.2 million in the first nine months
of 2006 to $26.2 million in the first nine months of 2007. The overall increase is primarily the
result of $5.7 million of non-cash unit-based compensation related to ENPs management incentive
units, increased staffing to manage our larger asset base, higher activity levels, and increased
personnel costs due to intense competition for human resources within the industry.
Derivative fair value loss (gain). During the first nine months of 2007, we recorded a $68.2
million derivative fair value loss as compared to a derivative fair value gain of $20.3 million in
the first nine months of 2006, the components of which were as follows:
35
ENCORE ACQUISITION COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
(in thousands) |
|
Ineffectiveness on designated cash flow hedges |
|
$ |
|
|
|
$ |
1,748 |
|
|
$ |
(1,748 |
) |
Mark-to-market loss (gain) on commodity contracts |
|
|
56,122 |
|
|
|
(30,639 |
) |
|
|
86,761 |
|
Premium amortization |
|
|
28,151 |
|
|
|
9,820 |
|
|
|
18,331 |
|
Settlements on commodity contracts |
|
|
(16,107 |
) |
|
|
(1,192 |
) |
|
|
(14,915 |
) |
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain) |
|
$ |
68,166 |
|
|
$ |
(20,263 |
) |
|
$ |
88,429 |
|
|
|
|
|
|
|
|
|
|
|
Other operating expense. Other operating expense increased $10.1 million from $3.6 million in
the first nine months of 2006 to $13.7 million in the first nine months of 2007. The increase is
primarily due to a $5.8 million loss on the sale of the Mid-Continent properties and increases in
third-party transportation costs attributable to moving our CCA production into markets outside the
immediate area of the production.
Interest expense. Interest expense increased $34.3 million from $33.8 million in the first
nine months of 2006 to $68.0 million in the first nine months of 2007. The increase is primarily
due to additional debt used to finance the Big Horn Basin and Williston Basin acquisitions. The
weighted average interest rate for all long-term debt for the first nine months of 2007 was 7.0
percent as compared to 6.7 percent for the first nine months of 2006.
The following table illustrates the components of interest expense for the nine months ended
September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase / |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
6 1/4% Notes |
|
$ |
7,277 |
|
|
$ |
7,262 |
|
|
$ |
15 |
|
6% Notes |
|
|
13,886 |
|
|
|
13,795 |
|
|
|
91 |
|
7 1/4% Notes |
|
|
8,240 |
|
|
|
8,238 |
|
|
|
2 |
|
Revolving credit facilities |
|
|
36,208 |
|
|
|
2,773 |
|
|
|
33,435 |
|
Other |
|
|
2,429 |
|
|
|
1,698 |
|
|
|
731 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
68,040 |
|
|
$ |
33,766 |
|
|
$ |
34,274 |
|
|
|
|
|
|
|
|
|
|
|
Minority interest. After ENPs IPO in September 2007 and the underwriters over-allotment
exercise in October 2007, public unitholders have a limited partner interest of approximately 40.2 percent. We include
ENP in our consolidated financial statements and show the ownership by the public as a minority
interest. The minority interest loss in ENP was $3.0 million for the first nine months of 2007.
Income taxes. During the first nine months 2007, we recorded an income tax provision of $1.5
million as compared to an income tax provision of $51.4 million in the first nine months of 2006.
Our effective tax rate increased to 45.2 percent in the first nine months of 2007 as compared to
38.4 percent in the first nine months of 2006 primarily due to a permanent rate adjustment for
ENPs management incentive units and a state rate adjustment due to larger apportionment of future
taxable income to states with higher tax rates, partially offset by a benefit for the true-up to
actual tax expense for the filing of our 2006 consolidated tax returns.
On January 1, 2007, we adopted the provisions of FIN 48. FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in a companys financial statements in accordance with SFAS
109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax
return. We have performed an evaluation of tax positions and have determined that the adoption of
FIN 48 did not have a material impact on our financial condition, results of operations, or cash
flows.
Capital Resources
Our primary capital resources are as follows:
|
|
|
Cash flows from operating activities; and |
|
|
|
|
Cash flows from financing activities. |
36
ENCORE ACQUISITION COMPANY
Cash flows from operating activities. Cash provided by operating activities decreased $20.7
million from $234.4 million for the first nine months of 2006 to $213.6 million for the first nine
months of 2007. The decrease was primarily due to an increase in our net derivative liabilities as
a result of increases in our commodity derivative positions and the forward price curve, and an
increase in accounts receivable as a result of increased oil and natural gas sales, partially
offset by an increase in our production margin.
Cash flows from financing activities. Our cash flows from financing activities consist
primarily of proceeds from and payments on long-term debt and net proceeds received from the sale
of additional equity. We periodically draw on our revolving credit facilities to fund acquisitions
and other capital commitments. Historically, we have repaid large balances on our revolving credit
facilities with proceeds from the issuance of senior subordinated notes in order to extend the
maturity date of the debt and fix the interest rate.
During the first nine months of 2007, we received net cash of $627.2 million from financing
activities, including net borrowings on our revolving credit facilities of $463.9 million and net
proceeds of $171.2 million from ENPs issuance of 9,000,000 common units in its IPO. Our net
borrowings on our revolving credit facilities resulted in a net increase in outstanding borrowings
under our revolving credit facilities from $68 million at December 31, 2006 to $545 million at
September 30, 2007, primarily due to borrowings used to finance the Big Horn Basin and Williston
Basin acquisitions, which were partially offset by repayments from the net proceeds received from
the Mid-Continent disposition and ENPs IPO.
During the first nine months of 2006, we received net cash of $41.8 million from financing
activities. This consisted primarily of net proceeds of $127.1 million from the issuance of
4,000,000 shares of our common stock in April 2006, which was used to reduce outstanding borrowings
under our revolving credit facility, invest in oil and natural gas activities, and to pay general
corporate expenses.
Current capitalization. At September 30, 2007, we had total assets of $2.7 billion and total
capitalization of $2.0 billion, of which 42 percent was represented by stockholders equity and 58
percent by long-term debt. At December 31, 2006, we had total assets of $2.0 billion and total
capitalization of $1.5 billion, of which 55 percent was represented by stockholders equity and 45
percent by long-term debt. The percentages of our capitalization represented by stockholders
equity and long-term debt could vary in the future if debt is used to finance future capital
projects or potential acquisitions.
Capital Commitments and Contingencies
Our primary needs for cash are as follows:
|
|
|
Cash flows from investing activities including: |
|
|
|
Development, exploitation, and exploration of existing oil and natural gas properties; and |
|
|
|
|
Acquisitions of oil and natural gas properties and leasehold acreage; |
|
|
|
Funding of necessary working capital; and |
|
|
|
|
Contractual obligations. |
Cash flows from investing activities. Cash used in investing activities increased $555.9
million from $277.3 million in the first nine months of 2006 to $833.2 million in the first nine
months of 2007. The increase was primarily due to a $817.1 million increase in amounts paid for
the acquisition of oil and natural gas properties, namely our Big Horn Basin and Williston Basin
acquisitions, partially offset by a $290.7 million increase in amounts received for the disposition
of oil and natural gas properties, primarily due to the Mid-Continent disposition.
Development, exploitation, and exploration of existing oil and natural gas properties. The
following table summarizes our costs incurred (excluding asset retirement obligations) related to
development, exploitation, and exploration activities during the three and nine months ended
September 30, 2007 and 2006:
37
ENCORE ACQUISITION COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Development and exploitation |
|
$ |
49,291 |
|
|
$ |
63,499 |
|
|
$ |
185,812 |
|
|
$ |
159,394 |
|
Exploration |
|
|
27,424 |
|
|
|
27,289 |
|
|
|
77,647 |
|
|
|
65,922 |
|
HPAI |
|
|
1,252 |
|
|
|
4,454 |
|
|
|
3,248 |
|
|
|
18,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
77,967 |
|
|
$ |
95,242 |
|
|
$ |
266,707 |
|
|
$ |
244,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development and exploitation. Our expenditures for development and exploitation investments
primarily relate to drilling development and infill wells, workovers of existing wells, and field
related facilities. Our development and exploitation capital for the third quarter of 2007
included a total of 35 gross (10.1 net) successful wells and one gross (0.9 net) development dry
holes. Our development and exploitation capital for the first nine months of 2007 included a total
of 123 gross (46.2 net) successful wells and three gross and (2.3 net) development dry holes.
We currently have eight operated rigs drilling on the onshore continental United States with
one rig in the Mid-Continent, one rig in the Northern region, one rig in the New Mexico region, and
five rigs in West Texas.
Exploration. Our expenditures for exploration investments primarily relate to drilling
exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. In the
third quarter of 2007, our exploration capital yielded 14 gross (5.4 net) successful wells and two
gross (1.1 net) exploratory dry holes. During the first nine months of 2007, our exploration
capital yielded 42 gross (15.8 net) exploratory wells that were productive and five gross (2.6 net)
exploratory dry holes.
HPAI. During the third quarter of 2007 and 2006, we invested $1.3 million and $4.5 million on
our HPAI programs. For the first nine months of 2007 and 2006, we invested $3.2 million and $18.9
million on our HPAI programs.
Acquisitions of oil and natural gas properties and leasehold acreage. The following table
summarizes our costs incurred (excluding asset retirement obligations) for oil and natural gas
property acquisitions during the three and nine months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Acquisitions of proved property |
|
$ |
30,079 |
|
|
$ |
263 |
|
|
$ |
791,964 |
|
|
$ |
4,315 |
|
Acquisitions of leasehold acreage |
|
|
16,832 |
|
|
|
6,629 |
|
|
|
40,615 |
|
|
|
18,494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
46,911 |
|
|
$ |
6,892 |
|
|
$ |
832,579 |
|
|
$ |
22,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions. On March 7, 2007, we acquired oil and natural gas properties in the Big Horn
Basin for a purchase price of approximately $393.2 million, including $1.3 million of estimated
transaction costs. On April 11, 2007, we acquired oil and natural gas properties in the Williston
Basin for a purchase price of approximately $392.0 million, including $1.3 million of estimated
transaction costs. The total purchase price of these acquisitions allocated to proved properties
was $779.3 million.
Leasehold acreage costs. During the three and nine months ended September 30, 2007, our
capital expenditures for leasehold acreage totaled $16.8 million and $40.6 million, respectively.
During the third quarter of 2007, our capital expenditures for leasehold acreage related to the
acquisition of unproved acreage in various areas. During the first nine months of 2007, $16.1
million related to the Williston Basin acquisition and the remainder related to the acquisition of
unproved acreage in various areas. During the three and nine months ended September 30, 2006, our
capital expenditures for leasehold acreage totaled $6.6 million and $18.5 million, respectively,
all of which related to the acquisition of unproved acreage in various areas.
Funding of necessary working capital. At September 30, 2007, our working capital (defined as
total current assets less total current liabilities) was negative $12.9 million while at December
31, 2006 our working capital was negative $40.7 million, an improvement of $27.8 million. The
improvement is primarily attributable to an increase in accounts receivable as a result of
increased oil and natural gas sales.
For the remainder of 2007, we expect working capital to remain negative. Negative working
capital is expected mainly due to fair values of our commodity derivative contracts (the
settlements of which will be offset by cash flows from the sale of
38
ENCORE ACQUISITION COMPANY
production mitigated against
price risk under those contracts) and deferred commodity derivative contract premiums. We
anticipate cash reserves to be close to zero because we intend to use any excess cash to fund
capital obligations and pay down any outstanding borrowings under our revolving credit facilities.
We do not plan to pay cash dividends in the foreseeable future. Our production volumes and the
overall 2007 commodity prices and our related differentials for oil and natural gas will be the
largest variables affecting working capital. Our operating cash flow is determined in large part
by production volumes and commodity prices. Assuming moderate to high commodity prices and
constant or increasing production volumes, our operating cash flow should remain positive in 2007.
The Board has approved a capital budget of approximately $385 million for 2007. The level of
these and other future expenditures is largely discretionary, and the amount of funds devoted to
any particular activity may increase or decrease significantly, depending on available
opportunities, timing of projects, and market conditions. We plan to finance our ongoing
expenditures using internally generated cash flow, cash on hand, and borrowings under our revolving
credit facilities.
Contractual obligations. The following table illustrates our contractual obligations and
commercial commitments outstanding at September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Quarter Ended |
|
|
Years Ended |
|
|
Years Ended |
|
|
|
|
Contractual Obligations |
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
|
|
and Commitments |
|
Total |
|
|
2007 |
|
|
2008 2009 |
|
|
2010 2011 |
|
|
Thereafter |
|
|
|
(in thousands) |
|
6 1/4% Notes (a) |
|
$ |
215,626 |
|
|
$ |
4,688 |
|
|
$ |
18,750 |
|
|
$ |
18,750 |
|
|
$ |
173,438 |
|
6% Notes (a) |
|
|
444,000 |
|
|
|
|
|
|
|
36,000 |
|
|
|
36,000 |
|
|
|
372,000 |
|
7 1/4% Notes (a) |
|
|
264,188 |
|
|
|
5,438 |
|
|
|
21,750 |
|
|
|
21,750 |
|
|
|
215,250 |
|
Revolving credit facilities (a) |
|
|
722,841 |
|
|
|
19,054 |
|
|
|
76,218 |
|
|
|
76,218 |
|
|
|
551,351 |
|
Derivative obligations (b) |
|
|
63,910 |
|
|
|
17,859 |
|
|
|
45,170 |
|
|
|
881 |
|
|
|
|
|
Development commitments (c) |
|
|
105,912 |
|
|
|
55,533 |
|
|
|
50,379 |
|
|
|
|
|
|
|
|
|
Operating leases and commitments (d) |
|
|
14,552 |
|
|
|
738 |
|
|
|
5,348 |
|
|
|
4,569 |
|
|
|
3,897 |
|
Asset retirement obligations (e) |
|
|
156,371 |
|
|
|
358 |
|
|
|
2,862 |
|
|
|
2,862 |
|
|
|
150,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,987,400 |
|
|
$ |
103,668 |
|
|
$ |
256,477 |
|
|
$ |
161,030 |
|
|
$ |
1,466,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Amounts included in the table above include both principal and projected interest
payments. Please read Note 8 of Notes to Consolidated Financial Statements included in
Item 1. Financial Statements for additional information regarding our long-term debt. |
|
(b) |
|
Derivative obligations represent net liabilities for derivatives that were valued
as of September 30, 2007. With the exception of $48.6 million of deferred premiums on
derivative contracts, the ultimate settlement amounts of the remaining portions of our
derivative obligations are unknown because they are subject to continuing market risk.
Please read Item 3. Quantitative and Qualitative Disclosures about Market Risk and
Note 6 of Notes to Consolidated Financial Statements included in Item 1. Financial
Statements for additional information regarding our derivative obligations. |
|
(c) |
|
Development commitments include: authorized purchases for work in process of
$38.8 million; future minimum payments for drilling rig operations of $60.1 million; and
$7.0 million for minimum capital obligations associated with the remaining seven
commitment wells to be drilled under the ExxonMobil joint development agreement. Also
at September 30, 2007, we had $181.3 million of authorized purchases not placed to
vendors (authorized AFEs), which were not accrued and are excluded from the above table
but are budgeted for and expected to be made unless circumstances change. |
|
(d) |
|
Operating leases and commitments include office space and equipment obligations
that have non-cancelable lease terms in excess of one year of $13.0 million and future
minimum payments for other operating commitments of $1.6 million. |
|
(e) |
|
Asset retirement obligations represent the undiscounted future plugging and
abandonment expenses on oil and natural gas properties and related facilities disposal
at the completion of field life. Please read Note 7 of Notes to Consolidated Financial
Statements included in Item 1. Financial Statements for additional information
regarding our asset retirement obligations. |
Other contingencies and commitments. In order to facilitate ongoing sales of our oil
production in the CCA, we ship a portion of our production in pipelines downstream and sell to
purchasers at major U.S. market hubs. From time to time, shipping delays, purchaser stipulations,
or other conditions may require that we sell our oil production in periods subsequent to the period
in which it is produced. In such case, the deferred sale would have an adverse effect in the
period of production on reported production volumes, oil and natural gas revenues, and costs as
measured on a unit-of-production basis.
The marketing of our CCA oil production is mainly dependent on transportation through the
Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative
transportation routes and markets have been developed by moving a portion of the crude oil
production through Enbridge Pipeline to the Clearbrook, Minnesota hub. In addition, new markets to
the west have been identified and a portion of our crude oil is being moved that direction through
the Rocky Mountain
39
ENCORE ACQUISITION COMPANY
Pipeline. To a lesser extent, our production also depends on transportation
through Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the
Guernsey, Wyoming area. While shipments on Platte Pipeline are currently
oversubscribed and have been subject to apportionment since December 2005, we were allocated
transportation effective January 1, 2007. However, further restrictions on available capacity to
transport oil through any of the above mentioned pipelines, or any other pipelines, or any refinery
upsets could have a material adverse effect on our production volumes and the prices we receive for
our production.
We expect the differential between the NYMEX price of crude oil and the wellhead price we
receive to remain approximately constant or to widen slightly in the fourth quarter of 2007 as
compared to the third quarter of 2007. In recent years, production increases from competing
Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity
from the Rocky Mountain area, have gradually widened this differential. We cannot accurately
predict crude oil differentials. Natural gas differentials are expected to remain approximately
constant or to slightly widen in the fourth quarter of 2007 as compared to the third quarter of
2007. Increases in the differential between the NYMEX price for oil and natural gas and the
wellhead price we receive could have a material adverse effect on our results of operations,
financial position, and cash flows.
Liquidity
Our primary sources of liquidity are internally generated cash flows and the borrowing
capacity under the EAC Credit Agreement. We also have the ability to adjust our level of capital
expenditures. We may use other sources of capital, including the issuance of additional debt or
equity securities, to fund any major acquisitions we might secure in the future and to maintain our
financial flexibility.
Internally generated cash flows. Our internally generated cash flows, results of operations,
and financing for our operations are largely dependent on oil and natural gas prices. Realized oil
and natural gas prices for the first nine months 2007 increased by 10 percent and decreased by
three percent, respectively, as compared to the first nine months of 2006. These prices have
historically fluctuated widely in response to changing market forces. For the first nine months of
2007, approximately 70 percent of our production was oil. As we previously discussed, our oil
wellhead differentials during the first nine months of 2007 tightened as compared to the first nine
months of 2006, favorably impacting the amount of oil revenues we received on our oil production.
We expect our oil and natural gas wellhead differentials to remain approximately constant or to
widen slightly in the fourth quarter of 2007 as compared to the third quarter of 2007. To the
extent oil and natural gas prices decline or we experience significant widening of our wellhead differentials, our earnings, cash flows from
operations, and availability under our revolving credit facilities may be adversely impacted.
Prolonged periods of low oil and natural gas prices or sustained wider than historical wellhead
differentials could cause us to not be in compliance with financial covenants under our revolving
credit facilities and thereby affect our liquidity. We believe that our internally generated cash
flows and unused availability under our revolving credit facilities are sufficient to fund our
planned capital expenditures for the foreseeable future.
Revolving credit facilities. Our principal source of short-term liquidity is the EAC Credit
Agreement, which matures on March 7, 2012.
On March 7, 2007, we entered into the EAC Credit Agreement with a bank syndicate comprised of
Bank of America, N.A. and other lenders. The EAC Credit Agreement amended and restated our Amended
and Restated Credit Agreement dated as of August 19, 2004, as amended. The borrowing base is
redetermined semi-annually and upon requested special redeterminations and may be increased or
decreased, up to a maximum of $1.25 billion. The borrowing base on September 30, 2007 was $870
million.
Also on March 7, 2007, OLLC entered into the OLLC Credit Agreement with a bank syndicate
comprised of Bank of America, N.A. and other lenders. The OLLC Credit Agreement provides for
revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from
time to time for the account of OLLC or any of its restricted subsidiaries. The borrowing base is
redetermined semi-annually and upon requested special redeterminations and may be increased or
decreased, up to a maximum of $300 million. The borrowing base on September 30, 2007 was $145
million. Amounts borrowed under the OLLC Credit Agreement may only be used to fund the operations
of ENP.
On September 30, 2007 and October 31, 2007, EAC had $478.5 million and $483 million
outstanding, respectively, and $371.5 million $367 million available to borrow, respectively, under
the EAC Credit Agreement. On September 30, 2007 and October 31, 2007, ENP had $66.5 million and
$60 million outstanding, respectively, and $78.5 million $84.9 million available to
40
ENCORE ACQUISITION COMPANY
borrow,
respectively, under the EAC Credit Agreement. Please read Note 8 of Notes to Consolidated
Financial Statements included in Item 1. Financial Statements for additional information
regarding our revolving credit facilities.
Debt covenants. At September 30, 2007, we were in compliance with all of our debt covenants.
Letters of credit. As of September 30, 2007 and October 31, 2007, EAC had $20 million in
outstanding letters of credit, all of which related to its ExxonMobil joint development agreement.
As of September 30, 2007 and October 31, 2007, ENP had none and $0.1 million in outstanding letters
of credit, respectively.
Critical Accounting Policies and Estimates
On January 1, 2007, we adopted the provisions of FIN 48. FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in a companys financial statements in accordance with SFAS
109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax
return. See Note 9 of Notes to Consolidated Financial Statements included in Item 1. Financial
Statements for more information.
Please read Managements Discussion and Analysis of Financial Condition and Results of
Operations Critical Accounting Policies and Estimates in our 2006 Annual Report on Form 10-K
for more information.
New Accounting Pronouncements
The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated
Financial Statements included in Item 1. Financial Statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The information included in Quantitative and Qualitative Disclosures about Market Risk in
our 2006 Annual Report on Form 10-K is incorporated herein by reference. Such information includes
a description of our potential exposure to market risks, including commodity price risk and
interest rate risk.
Commodity Price Sensitivity
Our outstanding commodity derivative contracts as of September 30, 2007 are discussed in Note
6 of Notes to Consolidated Financial Statements included in Item 1. Financial Statements. As of
September 30, 2007, the fair market value of our oil and natural gas derivative contracts was a net
asset of $7.7 million and $7.6 million, respectively. Based on our open commodity derivative
positions at September 30, 2007, a $1.00 increase in the respective NYMEX prices for oil and
natural gas would decrease our net derivative fair value asset by approximately $8.4 million, while
a $1.00 decrease in the respective NYMEX prices for oil and natural gas would increase our net
derivative fair value assets by approximately $10.7 million.
Interest Rate Sensitivity
At September 30, 2007, we had total long-term debt of $1.1 billion, which is recorded net of
discount of $5.9 million. Of this amount, $150 million bears interest at a fixed rate of 6 1/4
percent, $300 million bears interest at a fixed rate of 6 percent, and $150 million bears interest
at a fixed rate of 7 1/4 percent. The remaining outstanding long-term debt balance of $545 million
is under our revolving credit facilities and is subject to floating market rates of interest that
are linked to LIBOR.
At this level of floating rate debt, if LIBOR increased one percent, we would incur an
additional $5.5 million of interest expense per year, and if the rate decreased one percent, we
would incur $5.5 million less. Additionally, if LIBOR increased one percent, we estimate the fair
value of our fixed rate debt at September 30, 2007 would decrease from $535.3 million to $501.2
million, and if the rate decreased one percent, we estimate the fair value would increase to $572.4
million.
Item 4. Controls and Procedures
In accordance with the Securities Exchange Act of 1934 (the Exchange Act) Rules 13a-15 and
15d-15, we carried out an evaluation, under the supervision and with the participation of
management, including our Chief Executive Officer and Chief
41
ENCORE ACQUISITION COMPANY
Financial Officer, of the effectiveness
of our disclosure controls and procedures as of September 30, 2007. Based on that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of September 30, 2007 to ensure that information required to be disclosed in our
reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported
within the time periods specified in the SECs rules and forms and that information required to be
disclosed is accumulated and communicated to management, including our Chief Executive Officer and
Chief Financial Officer, to allow timely decisions regarding required disclosure.
There were no changes in our internal control over financial reporting that occurred during
the third quarter of 2007 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are a party to ongoing legal proceedings in the ordinary course of business. Management
does not believe the result of these legal proceedings will have a material adverse effect on us.
Item 1A. Risk Factors
In addition to the other information set forth in this Report, you should carefully consider
the factors discussed in Part I, Item 1A. Risk Factors in our 2006 Annual Report on Form 10-K,
which could materially affect our business, financial condition, and/or future results. The risks
described in our 2006 Annual Report on Form 10-K are not the only risks we face. Additional risks
and uncertainties not currently known to us or that we currently deem to be immaterial also may
materially adversely affect our business, financial condition, or results of operations.
Item 6. Exhibits
|
|
|
Exhibits |
|
|
|
|
|
3.1
|
|
Second Amended and Restated Certificate of Incorporation of Encore Acquisition Company
(incorporated by reference from EACs Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, filed with the SEC on November 7, 2001). |
|
|
|
3.1.2
|
|
Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of
Encore Acquisition Company (incorporated by reference from EACs Quarterly Report on Form 10-Q
for the quarter ended March 31, 2005, filed with the SEC on May 5, 2005). |
|
|
|
3.2
|
|
Second Amended and Restated Bylaws of Encore Acquisition Company (incorporated by reference
from EACs Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, filed with
the SEC on November 7, 2001). |
|
|
|
10.1
|
|
First Amendment to Credit Agreement, dated August 22, 2007, by and among Encore Energy
Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as administrative
agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book
manager and other lenders (incorporated by reference from Exhibit 10.1 to EACs Current Report
on Form 8-K, filed with the SEC on August 28, 2007). |
|
|
|
10.2
|
|
Contribution, Conveyance and Assumption Agreement, dated as of September 17, 2007, by and
among Encore Energy Partners LP, Encore Energy Partners GP LLC, Encore Acquisition Company,
Encore Operating, L.P., Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and
Encore Energy Partners Operating LLC (incorporated by reference from Exhibit 10.1 to EACs
Current Report on Form 8-K, filed with the SEC on September 21, 2007). |
|
|
|
10.3
|
|
Amended and Restated Administrative Services Agreement, dated as of September 17, 2007, by
and among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners
Operating LLC, Encore Acquisition Company and Encore Operating, L.P. (incorporated by
reference from Exhibit 10.2 to EACs Current Report on Form 8-K, filed with the SEC on
September 21, 2007). |
|
|
|
31.1*
|
|
Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer). |
|
|
|
31.2*
|
|
Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer). |
|
|
|
32.1*
|
|
Section 1350 Certification (Principal Executive Officer). |
|
|
|
32.2*
|
|
Section 1350 Certification (Principal Financial Officer). |
|
|
|
99.1*
|
|
Statement showing computation of ratios of earnings to fixed charges. |
42
ENCORE ACQUISITION COMPANY
SIGNATURE
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.
|
|
|
|
|
|
ENCORE ACQUISITION COMPANY
|
|
Date: November 6, 2007 |
/s/ Robert C. Reeves
|
|
|
Robert C. Reeves |
|
|
Senior Vice President, Chief Financial
Officer, and Treasurer |
|
|
43