UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q/A
Amendment No. 1
/x/ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 2002
or
/ / 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 1-16295
ENCORE ACQUISITION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 75-2759650
------------------------------- ----------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
777 Main Street, Suite 1400, Fort Worth, Texas 76102
------------------------------------------------------------ ----------
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (817) 877-9955
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 /x/ No / /
Number of shares of Common Stock outstanding as of August 2, 2002.....30,030,294
This Amendment No. 1 on Form 10-Q/A amends Items 1 and 2 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2002, as filed by
the Company on August 9, 2002 and is being filed to revise production
disclosures by reducing production volumes by amounts attributable to the
financial net profits interests burdening the Company's Cedar Creek Anticline
properties. No restatement of the unaudited financial statements is required, or
being made, nor have any of the numbers in the unaudited financial statements
changed.
ENCORE ACQUISITION COMPANY
INDEX
PART I. FINANCIAL INFORMATION
Page
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2002 and
December 31, 2001.................................................... 3
Consolidated Statements of Operations for the three and six months
ended June 30, 2002 and 2001.......................................... 4
Consolidated Statements of Stockholders' Equity for the six
months ended June 30, 2002........................................... 5
Consolidated Statements of Cash Flows for the six
months ended June 30, 2002 and 2001.................................. 6
Notes to Consolidated Financial Statements.............................. 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................... 12
Item 3. Quantitative and Qualitative Disclosure about Market
Risk.................................................................... 18
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders............... 19
Item 6. Exhibits and Reports on Form 8-K.................................. 19
Signatures................................................................ 20
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
JUNE 30, DECEMBER 31,
2002 2001
------------- -------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents ..................................... $ 2,417 $ 115
Accounts receivable (Net of allowance of $7.0 million) ........ 18,504 16,286
Deferred tax asset ............................................ 5,074 --
Derivative assets ............................................. 873 7,030
Other current assets .......................................... 8,650 5,117
------------- -------------
Total current assets ................................... 35,518 28,548
------------- -------------
Properties and equipment, at cost -- successful efforts method:
Producing properties .......................................... 522,857 422,542
Undeveloped properties ........................................ 838 776
Accumulated depletion, depreciation and amortization .......... (77,495) (60,548)
------------- -------------
446,200 362,770
------------- -------------
Other property and equipment .................................. 3,161 3,001
Accumulated depletion, depreciation, and amortization ......... (1,567) (1,253)
------------- -------------
1,594 1,748
------------- -------------
Other assets .................................................... 10,171 8,934
------------- -------------
Total assets ........................................... $ 493,483 $ 402,000
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable .............................................. $ 6,635 $ 10,793
Derivative liabilities ........................................ 8,301 3,525
Current portion of note payable ............................... -- 1,107
Other current liabilities ..................................... 15,491 12,016
------------- -------------
Total current liabilities .............................. 30,427 27,441
------------- -------------
Derivative liabilities .......................................... 2,020 1,288
Long-term debt .................................................. 150,000 78,000
Deferred income taxes ........................................... 34,885 25,969
------------- -------------
Total liabilities ...................................... 217,332 132,698
------------- -------------
Commitments and contingencies ................................... -- --
Stockholders' equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized,
none issued and outstanding ................................. -- --
Common stock, $.01 par value, 60,000,000 authorized,
30,029,961 issued and outstanding ........................... 300 300
Additional paid-in capital .................................... 248,786 248,786
Retained earnings ............................................. 32,275 16,039
Accumulated other comprehensive income (loss) ................. (5,210) 4,177
------------- -------------
Total stockholders' equity ............................. 276,151 269,302
------------- -------------
Total liabilities and stockholders' equity ............. $ 493,483 $ 402,000
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
3
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------- ---------- -------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
Revenues:
Oil ............................................................... $ 31,683 $ 26,505 $ 58,369 $ 53,882
Natural gas ....................................................... 6,124 8,103 11,735 16,947
---------- ---------- ---------- ----------
Total revenues ...................................................... 37,807 34,608 70,104 70,829
Expenses:
Production--
Direct lifting costs ........................................... 6,567 6,066 13,384 12,421
Production, ad valorem, and severance taxes .................... 3,546 3,640 6,559 7,910
General and administrative (excluding non-cash stock based
compensation) .................................................. 1,384 1,259 2,877 2,522
Non-cash stock based compensation ................................. -- -- -- 9,587
Depletion, depreciation, and amortization ......................... 8,773 7,825 17,332 15,388
Derivative fair value (gain) loss ................................. (26) 37 (679) 139
Other operating expense ........................................... 331 -- 470 --
---------- ---------- ---------- ----------
Total expenses ...................................................... 20,575 18,827 39,943 47,967
---------- ---------- ---------- ----------
Operating income .................................................... 17,232 15,781 30,161 22,862
---------- ---------- ---------- ----------
Other income (expenses):
Interest .......................................................... (2,222) (1,176) (3,714) (3,713)
Other ............................................................. (10) 9 20 61
---------- ---------- ---------- ----------
Total other income (expenses) ....................................... (2,232) (1,167) (3,694) (3,652)
---------- ---------- ---------- ----------
Income before income taxes .......................................... 15,000 14,614 26,467 19,210
Provision for income taxes - current ................................ (30) (600) (460) (1,204)
Provision for income taxes - deferred ............................... (5,670) (4,953) (9,597) (9,738)
---------- ---------- ---------- ----------
Income before accounting change and extraordinary loss .............. 9,300 9,061 16,410 8,268
Cumulative effect of accounting change, net of income taxes ......... -- -- -- (884)
Extraordinary loss from early extinguishment of debt,
net of income taxes ............................................... (174) -- (174) --
---------- ---------- ---------- ----------
Net income .......................................................... $ 9,126 $ 9,061 $ 16,236 $ 7,384
========== ========== ========== ==========
Income per common share before accounting change and extraordinary
loss:
Basic ............................................................. $ 0.31 $ 0.30 $ 0.55 $ 0.30
Diluted ........................................................... 0.31 0.30 0.54 0.30
Net income per common share:
Basic ............................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27
Diluted ........................................................... 0.30 0.30 0.54 0.27
Weighted average common shares outstanding:
Basic ............................................................. 30,030 30,030 30,030 27,383
Diluted ........................................................... 30,184 30,034 30,118 27,385
The accompanying notes are an integral part of these consolidated financial
statements.
4
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
JUNE 30, 2002
(in thousands)
(unaudited)
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Stockholders'
Stock Capital Earnings Income (Loss) Equity
------------ ------------ ------------ ------------- ------------
Balance at December 31, 2001 .......... $ 300 $ 248,786 $ 16,039 $ 4,177 $ 269,302
Components of comprehensive income:
Net income .......................... -- -- 16,236 -- 16,236
Change in deferred hedge loss (net
of income taxes of $5,753) ....... -- -- -- (9,387) (9,387)
------------
Total comprehensive income .... 6,849
------------ ------------ ------------ ------------ ------------
Balance at June 30, 2002 .............. $ 300 $ 248,786 $ 32,275 $ (5,210) $ 276,151
============ ============ ============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
5
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
SIX MONTHS ENDED
JUNE 30,
-----------------------
2002 2001
--------- ---------
Operating activities
Net income .................................................... $ 16,236 $ 7,384
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation, and amortization ................... 17,332 15,388
Deferred taxes .............................................. 9,597 8,368
Non-cash stock based compensation ........................... -- 9,587
Cumulative accounting change ................................ -- 884
Derivative fair value (gain) loss ........................... (679) 139
Extraordinary loss on early extinguishment of debt .......... 174 --
Other non-cash charges ...................................... (774) 948
Loss on disposition of assets ............................... 188 28
Changes in operating assets and liabilities:
Accounts receivable ......................................... (2,218) 1,153
Other current assets ........................................ (4,920) (800)
Other assets ................................................ 3,277 767
Accounts payable and other current liabilities .............. (697) (2,784)
--------- ---------
Cash provided by operating activities ........................ 37,516 41,062
Investing activities
Proceeds from disposition of assets ......................... 356 145
Purchases of other property and equipment ................... (400) (442)
Acquisition of oil and natural gas properties ............... (59,532) (705)
Development of oil and natural gas properties ............... (40,845) (34,592)
--------- ---------
Cash used by investing activities ............................. (100,421) (35,594)
Financing activities
Proceeds from initial public offering ....................... -- 93,095
Offering costs paid ......................................... -- (1,568)
Proceeds from notes receivable - officers and employees ..... -- 19
Proceeds from long-term debt ................................ 255,000 78,000
Payments on long-term debt .................................. (183,000) (166,500)
Payments for debt issuance costs ............................ (5,686) --
Payments on note payable .................................... (1,107) (9,005)
--------- ---------
Cash provided by (used by) financing activities ............... 65,207 (5,959)
Increase (decrease) in Cash and Cash Equivalents .............. 2,302 (491)
Cash and Cash Equivalents, Beginning of Period ................ 115 876
--------- ---------
Cash and Cash Equivalents, End of Period ...................... $ 2,417 $ 385
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
6
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. FORMATION OF ENCORE
Encore Acquisition Company ("the Company"), a Delaware Corporation, is an
independent (non-integrated) oil and natural gas company in the United States.
We were organized in April 1998 and are engaged in the acquisition, development,
exploitation and production of North American oil and natural gas reserves. Our
oil and natural gas reserves are concentrated in fields located in the Williston
Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico,
the Anadarko Basin of Oklahoma and the Powder River Basin of Montana.
2. BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited consolidated
financial statements of the Company include all adjustments necessary to present
fairly our financial position as of June 30, 2002 and results of operations and
cash flows for the three and six months ended June 30, 2002 and 2001. All
adjustments are of a recurring nature. These interim results are not necessarily
indicative of results for an entire year. Certain amounts of prior periods have
been reclassified in order to conform to the current period presentation.
Certain disclosures have been condensed or omitted from these consolidated
financial statements pursuant to the rules and regulations of the Securities and
Exchange Commission. Therefore, these financial statements should be read in
conjunction with the Company's 2001 consolidated financial statements and
related notes thereto included in the Company's Annual Report filed on Form
10-K.
3. NEW ACCOUNTING STANDARDS
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 143 ("SFAS 143"), "Accounting for Asset Retirement Obligations",
which the Company will be required to adopt as of January 1, 2003. This
statement requires us to record a liability in the period in which an asset
retirement obligation ("ARO") is incurred, based upon the discounted estimated
fair value of the obligation. Also, upon initial recognition of the liability,
we must capitalize additional asset cost equal to the amount of the liability.
In addition to any obligations that arise after the effective date of SFAS 143,
upon initial adoption we must recognize (1) a liability for any existing AROs,
(2) capitalized cost related to the liability, and (3) accumulated depletion,
depreciation, and amortization on that capitalized cost. We are currently
reviewing the provisions of the statement and assessing their impact on our
financial statements. We do not currently know the effect, if any, the adoption
of SFAS 143 will have on our financial statements.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". Under Statement 4, all gains and losses from extinguishment of
debt were required to be aggregated and, if material, classified as an
extraordinary item, net of related income tax effect. This Statement eliminates
Statement 4 and, thus, the exception to applying Opinion 30 to all gains and
losses related to extinguishments of debt. As a result, gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will
distinguish transactions that are part of an entity's recurring operations from
those that are unusual or infrequent or that meet the criteria for
classification as an extraordinary item. This statement is effective for Encore
beginning January 1, 2003, at which time the extraordinary loss on
extinguishment of debt recorded in the second quarter of 2002 will be
reclassified to operating income.
4. INDEBTEDNESS
The Company's overall indebtedness has increased by $70.9 million since
December 31, 2001. The additional borrowings were used to fund $59.5 in
acquisitions, as well as $5.7 in debt issuance costs associated with the 8 3/8%
Senior Subordinated Notes and the new Revolving Credit Facility (See below), the
development drilling program, and the initial high-pressure air injection
project.
On June 25, 2002, the Company sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012 (the "Notes"). The offering was
made through a private placement pursuant to Rule 144A. As of June 30, 2002, the
Notes have not been registered
7
under the Securities Act of 1933 or applicable state securities laws. In
conjunction with the issuance of the Notes, the Company executed a registration
rights agreement and has agreed to: (i) file a registration statement of the
Notes by September 23, 2002, enabling holders of the Notes to exchange the Notes
for publicly registered Notes with substantially identical terms and (ii) use
our reasonable best efforts to cause the registration statement to become
effective by December 22, 2002. The Company received net proceeds of $146.3
million from the sale of the Notes, which were used to repay and retire the
Company's prior credit facility.
Concurrently with the Company's issuance of the Notes, the Company also
entered into a new Revolving Credit Facility, effective June 25, 2002.
Borrowings under the facility will be secured by a first priority lien on the
Company's proved oil and natural gas reserves. Availability under the facility
will be determined through semi-annual borrowing base determinations and may be
increased or decreased. As of June 30, 2002, the amount available under the new
facility is $220.0 million. No amounts were outstanding at June 30, 2002. The
maturity date of the new facility will be June 25, 2006.
Amounts outstanding under the facility are subject to varying rates of
interest based on the amount outstanding and the Company's borrowing base. Based
on our current $220.0 million borrowing base, our applicable interest rates
would be calculated as follows:
AMOUNT OUTSTANDING RATE
------------------------------- -------------
$0 to $55,000,000.............. LIBOR + 1.000%
$55,000,001 to $110,000,000.... LIBOR + 1.125%
$110,000,001 to $165,000,000... LIBOR + 1.250%
$165,000,001 to $198,000,000... LIBOR + 1.500%
$198,000,001 to $220,000,000... LIBOR + 1.750%
Additionally, under the new Revolving Credit Facility, the Company is
subject to certain affirmative, negative, and financial covenants. These include
limitations on incurrence of additional debt, restrictions on assets
dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio,
and maintenance of an EBITDA to interest expense ratio of at least 2.5 to 1.0.
5. EARNINGS PER SHARE ("EPS")
The following table sets forth basic and diluted EPS computations for the
three and six months ended June 30, 2002 and 2001 (in thousands, except per
share data):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ---------------------
2002 2001 2002 2001
-------- -------- -------- --------
NUMERATOR:
----------
Income before extraordinary item and accounting change ...................... $ 9,300 $ 9,061 $ 16,410 $ 8,268
======== ======== ======== ========
Net income .................................................................. $ 9,126 $ 9,061 $ 16,236 $ 7,384
======== ======== ======== ========
DENOMINATOR:
------------
Denominator for basic earnings per share -
weighted average shares outstanding ....................................... 30,030 30,030 30,030 27,383
Effect of dilutive securities:
Dilutive options .......................................................... 154 4 88 2
-------- -------- -------- --------
Denominator for diluted earnings per share .................................. 30,184 30,034 30,118 27,385
======== ======== ======== ========
BASIC PER COMMON SHARE:
-----------------------
Income before extraordinary item and accounting change ...................... $ 0.31 $ 0.30 $ 0.55 $ 0.30
Cumulative effect of accounting change, net of income taxes ................. -- -- -- (0.03)
Extraordinary loss from early extinguishment of debt, net of income taxes ... (0.01) -- (0.01) --
-------- -------- -------- --------
Net income .................................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27
======== ======== ======== ========
DILUTED PER COMMON SHARE:
-------------------------
Income before extraordinary item and accounting change ...................... $ 0.31 $ 0.30 $ 0.54 $ 0.30
Cumulative effect of accounting change, net of income taxes ................. -- -- -- (0.03)
Extraordinary loss from early extinguishment of debt, net of income taxes ... (0.01) -- -- --
-------- -------- -------- --------
Net income .................................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27
======== ======== ======== ========
8
6. DERIVATIVE FINANCIAL INSTRUMENTS
During the first six months of 2002, current derivative assets decreased
$6.2 million, while current derivative liabilities increased $4.8 million and
long-term derivative liabilities increased $0.7 million. These changes were due
primarily to an increase in the futures price of oil and natural gas and lower
interest rates.
For the six months ended June 30, 2002, we had total comprehensive income
of $6.8 million, while net income totaled $16.2 million. The difference between
net income and total comprehensive income is due to a $9.4 million change in
deferred hedge gain/loss in accumulated other comprehensive income. Due to an
increase in the futures price of oil and natural gas and lower interest rates,
we went from a deferred hedge gain of $4.2 million, net of tax, at December 31,
2001, to a deferred hedge loss of $5.2 million, net of tax, at June 30, 2002.
Exclusive of the Enron gain and interest rate swap loss (See below), the Company
expects $3.7 million of the amount in accumulated other comprehensive income to
reverse in the next twelve months.
At December 31, 2001, we had $4.8 million in gross unrecognized gains in
accumulated other comprehensive income related to the termination of hedging
contracts with Enron that are being amortized into earnings during 2002 and
2003. The following table illustrates the current and future amortization of
this amount to revenue (in thousands):
THREE MONTHS NATURAL
ENDED OIL GAS TOTAL
-------------------- ------------ ------------ -----------
March 31, 2002........ $ 705 $ 399 $ 1,104
June 30, 2002......... 705 399 1,104
September 30, 2002.... 706 398 1,104
December 31, 2002..... 706 398 1,104
March 31, 2003........ 100 5 105
June 30, 2003......... 100 5 105
September 30, 2003.... 100 4 104
December 31, 2003..... 101 4 105
----------- ----------- -----------
Total................. $ 3,223 $ 1,612 $ 4,835
=========== =========== ===========
As a result of the retirement of the Company's prior credit facility, the
Company's three interest rate swaps, which swap LIBOR based floating rates for
fixed rates, no longer qualify for hedge accounting. As a result, the Company
marked these contracts to market as of June 25, 2002, the date of the sale of
the Notes and related repayment of the amount outstanding under the prior credit
facility, which was terminated on that date. This resulted in an unrealized loss
of $3.8 million through June 25, 2002, which was recognized in accumulated other
comprehensive income and will be amortized to interest expense over the original
life of the swaps as follows (in thousands):
YEAR 1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL
--------------- ------------ ------------ ------------ ------------ ------------
2002 .......... $ -- $ (59) $ (806) $ (754) $ (1,619)
2003 .......... (654) (544) (414) (297) (1,909)
2004 .......... (212) (153) (109) (72) (546)
2005 .......... (40) 72 85 60 177
2006 .......... 22 24 29 33 108
2007 .......... 38 1 -- -- 39
------------
Total ......... $ (3,750)
============
In conjunction with the sale of the Notes (See Note 4), the Company
entered into an additional interest rate swap, whereby we pay LIBOR plus 3.89%
and receive a fixed 8 3/8% on a notional amount of $80 million through June 15,
2005. Due to the difference in terms between the swap and the underlying debt,
this instrument does not qualify for hedge accounting and, along with future
changes in the fair value of the three original swaps, will be marked to market
through earnings each period in the `Derivative fair value gain/loss' line in
the income statement.
9
During the second quarter, we expanded our commodity hedges in 2002 and
2003 for both oil and natural gas. The following tables summarize our open
commodity hedging positions as of June 30, 2002:
OIL HEDGES AT JUNE 30, 2002
DAILY FLOOR DAILY CAP DAILY SWAP
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE
PERIOD (BBL) (PER BBL) (BBL) (PER BBL) (BBL) (PER BBL)
--------- --------------- ----------- -------------- ----------- ------------- ----------
July - Dec 2002...... 7,000 $ 22.96 4,500 $ 27.88 3,000 $ 20.15
Jan - June 2003...... 7,500 20.80 6,000 26.52 1,000 24.50
July - Dec 2003...... 4,500 20.00 4,500 26.23 -- --
NATURAL GAS HEDGES AT JUNE 30, 2002
DAILY FLOOR DAILY CAP DAILY SWAP
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE
PERIOD (MCF) (PER MCF) (MCF) (PER MCF) (MCF) (PER MCF)
----------- --------------- ----------- -------------- ----------- ------------- ----------
July - Dec 2002...... 5,000 $ 3.13 2,500 $ 8.05 5,000 $ 2.83
Jan - Dec 2003....... 5,000 3.13 -- -- 2,500 3.69
Additionally, as of June 30, 2002, we had short oil put contracts in place
covering 1,500 Bbls per day in 2002 and 500 Bbls per day in 2003 at an average
strike price of $20 and $17, respectively, which do not qualify for hedge
accounting. Accordingly, these contracts are marked to market through earnings
each period in the `Derivative fair value gain/loss' line in the income
statement.
7. INCOME TAXES
Excluding the tax effect of the extraordinary loss from early
extinguishment of debt, during the first six months of 2002, Encore incurred
$10.1 million in income tax expense. Of this, $9.6 million is deferred income
tax expense and relates primarily to intangible drilling costs incurred during
the quarter, which are deductible for income tax purposes, but have been
capitalized as Properties and Equipment under generally accepted accounting
principles. These amounts will be depleted and transferred to earnings over the
production life of the wells. Additionally, the Company's current deferred tax
asset has increased to $5.1 million from approximately zero at December 31,
2001, due to the change in Other Comprehensive Income related to the
mark-to-market change in the value of the Company's derivatives.
The Company's High-Pressure Air Injection project ("HPAI") in the Cedar
Creek Anticline ("CCA") has been certified as an enhanced oil recovery project
for federal income tax purposes. As a result, qualifying expenditures on the
project are eligible for a 15% tax credit. We have reduced current income taxes
payable by $0.7 million in the second quarter to reflect the expected credit
from investments to date in the HPAI project. On July 16, 2002, we began
injecting air in the Pennel Unit of the CCA.
8. ACQUISITIONS
On January 4, 2002, we completed the acquisition of interests in oil and
natural gas properties in the Permian Basin for $50.1 million from Conoco. The
two principal operated properties are the East Cowden Grayburg and Fuhrman Nix
fields; the non-operated properties are primarily in the North Cowden and Yates
fields. Over 40 development wells have been identified, and a drilling program
will be initiated in the third quarter of this year. The acquisition was funded
by additional borrowings under the Company's prior credit agreement.
On April 18, 2002, we agreed to acquire oil and natural gas properties in
the Paradox Basin in Utah from a privately held oil and gas company. The
purchase price for the Paradox Basin acquisition is $23.4 million, prior to
closing adjustments. The Utah properties are interests in the Ratherford Unit
operated by Exxon Mobil and the Aneth Unit operated by ChevronTexaco. The
working and net revenue interest in the Ratherford Unit are 19.3% and 16.8%,
respectively, and the working interest and the net revenue interest in the Aneth
Unit are 12.0% and 10.3%, respectively. Approximately 78% of the value of the
acquisition is subject to preferential rights held by the Navajo Nation, which
are set to expire in mid-August, 2002. We paid an initial deposit for 5% of the
purchase price and issued a standby letter of credit for the remainder. Final
closing and payment will be made immediately after the preferential rights have
expired in mid-August 2002.
On May 14, 2002, we completed the acquisition of additional working
interests in our operated properties in the East Cowden Grayburg field for $8.4
million. The acquisition was funded by additional borrowings under the Company's
prior credit agreement.
10
9. SUBSEQUENT EVENTS
Subsequent to the balance sheet date, the Company cash settled one of its
outstanding interest rate swaps at a cost of $2.8 million. Since we no longer
carried any floating rate debt as of the end of the period, we lessened our
exposure to further decreases in the LIBOR interest rate. However, we do
anticipate incurring floating rate debt under our new Revolving Credit Agreement
to fund development drilling activities, pay the remaining purchase price of the
Paradox Basin acquisition, and possibly acquire additional properties in the
future. For these reasons, we decided to only cash settle one of the outstanding
interest rate swaps. The settled swap had a notional amount of $30.0 million and
swapped a LIBOR based floating rate for a 6.72% fixed rate. The remaining two
original interest rate swaps on the prior credit facility have a combined
notional of $60.0 million and an average fixed rate of 4.75%.
10. FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS
All of the Company's subsidiaries are currently subsidiary guarantors of
the Notes. Since (i) each subsidiary guarantor is 100% owned by the Company,
(ii) the Company has no assets or operations that are independent of its
subsidiaries, (iii) the subsidiary guarantees are full and unconditional and
joint and several and (iv) all of the Company's subsidiaries are subsidiary
guarantors, the Company has not included the financial statements of each
subsidiary in this report. The subsidiary guarantors may without restriction
transfer funds to the Company in the form of cash dividends, loans and advances.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This document contains forward-looking statements that involve risks and
uncertainties that are made pursuant to the Safe Harbor Provisions of the
Private Securities Litigation Reform Act of 1995. Actual results may differ
materially from those anticipated in our forward-looking statements due to many
factors, including, but not limited to, those set forth under "SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS" contained in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations, in
Encore's 2001 Annual Report filed on Form 10-K/A. The following discussion
should be read in conjunction with the consolidated financial statements and
notes thereto included in this document and Encore's 2001 Form 10-K/A.
CRITICAL ACCOUNTING POLICIES
For a discussion of the Company's critical accounting policies, see the
Company's 2001 Annual Report filed on Form 10-K/A.
RESULTS OF OPERATIONS
The following table sets forth operating information for the periods
presented:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
INCREASE INCREASE
2002 2001 (DECREASE) 2002 2001 (DECREASE)
---------- ---------- ---------- ---------- ---------- ----------
Operating Results (in thousands):
Oil and natural gas revenues ........................ $ 37,807 $ 34,608 $ 3,199 $ 70,104 $ 70,829 $ (725)
Direct lifting costs ................................ 6,567 6,066 501 13,384 12,421 963
Production, ad valorem and severance taxes .......... 3,546 3,640 (94) 6,559 7,910 (1,351)
Daily sales volumes:
Oil volumes (Bbls) .................................. 15,714 13,011 2,703 15,602 12,890 2,712
Natural gas volumes (Mcf) ........................... 22,275 22,055 220 23,122 21,564 1,558
Combined volumes (BOE) .............................. 19,427 16,687 2,740 19,456 16,483 2,973
Average prices:
Oil (per Bbl) ....................................... $ 22.16 $ 22.39 $ (0.23) $ 20.67 $ 23.10 $ (2.43)
Natural gas (per Mcf) ............................... 3.02 4.04 (1.02) 2.80 4.34 (1.54)
Combined volumes (per BOE) .......................... 21.39 22.79 (1.40) 19.91 23.74 (3.83)
Average costs (per BOE):
Direct lifting costs ................................ $ 3.71 $ 3.99 $ (0.28) $ 3.80 $ 4.16 $ (0.36)
Production, ad valorem, and severance taxes ......... 2.01 2.40 (0.39) 1.86 2.65 (0.79)
G&A (excluding non-cash stock based compensation) ... 0.78 0.83 (0.05) 0.82 0.85 (0.03)
DD&A ................................................ 4.96 5.15 (0.19) 4.92 5.16 (0.24)
12
COMPARISON OF QUARTER ENDED JUNE 30, 2002 TO QUARTER ENDED JUNE 30, 2001
Set forth below is our comparison of operations during the second quarter
of 2002 with the second quarter of 2001.
REVENUES AND SALES VOLUMES. The following table illustrates the primary
components of oil and natural gas revenue for the quarters ended June 30, 2002
and 2001, as well as each quarter's respective oil and natural gas volumes (in
thousands, except per unit amounts):
Three Months Ended June 30,
2002 2001 Difference
-------------------- -------------------- --------------------
Revenues: Revenue $/Unit Revenue $/Unit Revenue $/Unit
-------- -------- -------- -------- -------- --------
Oil wellhead ............. $ 33,446 $ 23.39 $ 29,572 $ 24.98 $ 3,874 $ (1.59)
Oil hedges ............... (2,469) (1.73) (3,067) (2.59) 598 0.86
Enron hedges ............. 706 0.50 -- -- 706 0.50
-------- -------- -------- -------- -------- --------
Total Oil Revenues .. $ 31,683 $ 22.16 $ 26,505 $ 22.39 $ 5,178 $ (0.23)
======== ======== ======== ======== ======== ========
Natural gas wellhead ..... $ 6,051 $ 2.99 $ 9,592 $ 4.78 $ (3,541) $ (1.79)
Gas hedges ............... (325) (0.17) (1,489) (0.74) 1,164 0.57
Enron hedges ............. 398 0.20 -- -- 398 0.20
-------- -------- -------- -------- -------- --------
Total Gas Revenues .. $ 6,124 $ 3.02 $ 8,103 $ 4.04 $ (1,979) $ (1.02)
======== ======== ======== ======== ======== ========
Sales Nymex Sales Nymex Sales Nymex
Other Data: Volumes $/Unit Volumes $/Unit Volumes $/Unit
-------- -------- -------- -------- -------- --------
Oil (Bbls) ............... 1,430 $ 26.25 1,184 $ 28.73 246 $ (2.48)
Gas (Mcf) ................ 2,027 3.40 2,007 6.30 20 (2.90)
Combined (BOE)............ 1,768 1,519 249
Total oil revenue increased from second quarter 2001 to second quarter 2002
due to increased volumes, lower hedging losses, lower net profits payments, and
amortization of the Enron gain offset by lower wellhead prices. Oil volumes
increased 246 MBbls due to our successful development drilling program and the
acquisition of the Central Permian properties. Wellhead oil revenues decreased
$1.59 per Bbl primarily resulting from a decrease in the overall market price
for oil as reflected in the $2.48 per Bbl decrease in the average NYMEX price
over the same period. Payments made for hedging decreased $0.6 million. The
change in hedging payments had the effect of increasing revenue by $0.86 per Bbl
over the second quarter 2001. Amortization of $0.7 million of the Enron gain
added $0.50 per Bbl as compared to the same period in 2001. Net profits payments
decreased from $1.4 million to $0.4 million from the second quarter of 2001 to
the second quarter of 2002. The decrease in net profits was primarily due to
lower prices and higher capital expenditures in the CCA in the second quarter of
2002 as compared to the second quarter of 2001. The Company's hedging activities
are not a component of the expenses deducted in calculating net profits interest
payments. The decrease in hedging payments is a result of the decrease in the
average NYMEX price for oil.
Total natural gas revenues decreased by $2.0 million, or $1.02 per Mcf,
due to a decrease in the wellhead price per Mcf, partially offset by a $1.2
million decrease in payments on hedging settlements and the $0.4 million
amortization of the Enron gain. The decrease in the wellhead price received is
consistent with the average NYMEX price decrease of $2.90 per Mcf from the three
months ended June 30, 2001 to the three months ended June 30, 2002. Hedging
payments decreased $0.57 per Mcf due to lower natural gas prices, as well as
different contracts being in effect.
DIRECT LIFTING COSTS. Direct lifting costs of Encore for the second
quarter of 2002 increased as compared to the second quarter of 2001 by $0.5
million, from $6.1 million to $6.6 million. The increase in direct lifting costs
is primarily attributable to increased sales volumes attributable to our
development drilling program and Central Permian acquisitions in 2002, offset
somewhat by a decrease in the per BOE rate. On a per BOE basis, direct lifting
costs decreased from $3.99 to $3.71, primarily as a result of decreased workover
and maintenance costs over the same period last year. We plan to resume our 2002
planned workover and maintenance programs in the third and fourth quarters of
this year.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the second quarter of 2002 decreased as compared to the
second quarter of 2001 by approximately $0.1 million. This decrease was a result
of the lower wellhead prices as compared to the second quarter of 2001. The
effect of lower prices was partially offset by increased volumes as a result of
the Central Permian acquisition and development drilling. As a percent of oil
and natural gas revenues (excluding the effects of hedges), production, ad
valorem, and severance taxes remained fairly constant, down to 9.0% from 9.3%.
13
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense
for the second quarter of 2002 increased by $0.9 million, reflecting the volumes
associated with our larger asset base resulting from the Central Permian
properties and our continued development drilling program. The average DD&A rate
of $4.96 per BOE of production during the second quarter of 2002 represents a
decrease of $0.19 per BOE from the $5.15 per BOE recorded in the second quarter
of 2001. The decrease was attributable to normal production declines in the
Lodgepole properties, which have relatively high DD&A rates as compared to our
other producing properties.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.1
million for the second quarter of 2002 as compared to the second quarter of
2001, from $1.3 million to $1.4 million. The increase in G&A expense was a
result of the hiring of additional staff after the 2002 Central Permian
acquisitions to manage, expand, and exploit our growing asset base.
INTEREST EXPENSE. Interest expense for the quarter ended June 30, 2002 was
$2.2 million compared to $1.2 million for the quarter ended June 30, 2001. The
increase in interest expense is due to higher debt levels, partially offset by
lower interest rates. The weighted average interest rate, net of hedges, for the
second quarter of 2002 was 5.5% compared to 6.7% for the second quarter of 2001.
The weighted average debt level under our credit facility for the second quarter
of 2002 was $133.1 million compared to $57.9 million for the second quarter of
2001. The following table illustrates the components of interest expense for the
three months ended June 30, 2002 and 2001 (in thousands):
Three Months Ended June 30,
2002 2001 Difference
---------- ---------- ----------
Credit facility ......... $ 1,079 $ 811 $ 268
8 3/8% notes due 2012 ... 207 -- 207
Burlington note ......... -- 110 (110)
Interest rate hedges .... 858 156 702
Banking fees ............ 78 99 (21)
---------- ---------- ----------
Total ......... $ 2,222 $ 1,176 $ 1,046
========== ========== ==========
COMPARISON OF SIX MONTHS ENDED JUNE 30, 2002 TO SIX MONTHS ENDED JUNE 30, 2001
Set forth below is our comparison of operations during the first six
months of 2002 with the first six months of 2001.
REVENUES AND SALES VOLUMES. The following table illustrates the primary
components of oil and natural gas revenue for the six months ended June 30, 2002
and 2001, as well as each period's respective oil and natural gas volumes (in
thousands, except per unit amounts):
Six Months Ended June 30,
2002 2001 Difference
------------------------- ------------------------- -------------------------
Revenues: Revenue $/Unit Revenue $/Unit Revenue $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil wellhead ............ $ 59,661 $ 21.13 $ 60,249 $ 25.82 $ (588) $ (4.69)
Oil hedges .............. (2,703) (0.96) (6,367) (2.72) 3,664 1.76
Enron hedges ............ 1,411 0.50 -- -- 1,411 0.50
---------- ---------- ---------- ---------- ---------- ----------
Total Oil Revenues . $ 58,369 $ 20.67 $ 53,882 $ 23.10 $ 4,487 $ (2.43)
========== ========== ========== ========== ========== ==========
Natural gas wellhead .... $ 10,812 $ 2.58 $ 21,955 $ 5.62 $ (11,143) $ (3.04)
Gas hedges .............. 126 0.03 (5,008) (1.28) 5,134 1.31
Enron hedges ............ 797 0.19 -- -- 797 0.19
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues . $ 11,735 $ 2.80 $ 16,947 $ 4.34 $ (5,212) $ (1.54)
========== ========== ========== ========== ========== ==========
Sales Nymex Sales Nymex Sales Nymex
Other Data: Volumes $/Unit Volumes $/Unit Volumes $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil (Bbls) .............. 2,824 $ 23.95 2,333 $ 28.34 491 $ (4.39)
Gas (Mcf) ............... 4,185 2.95 3,903 5.35 282 (2.40)
Combined (BOE)........... 3,522 2,984 538
Although average wellhead price was down for the first half of 2002, total
oil revenue increased due to higher volumes, lower hedging losses, lower net
profits payments, and amortization of the Enron gain. Oil volumes increased 491
MBbls due to the Company's successful development drilling program and the
Central Permian acquisitions. Wellhead oil revenues decreased $4.69 per Bbl
primarily from a decrease in the overall market price for oil as reflected in
the $4.39 per Bbl decrease in the average NYMEX
14
price over the same period. The decrease in wellhead oil revenues was offset by
a decrease in payments made for hedging settlements, which decreased $3.7
million, as well as amortization of $1.4 million of the Enron gain. The decrease
in hedging payments is a direct result of the decrease in the average NYMEX
price for oil. Net profits payments were $0.7 million and $2.4 million,
respectively, for the first six months of 2002 and 2001. The decrease in net
profits was primarily due to lower wellhead prices and higher capital
expenditures in the second quarter of 2002 in CCA.
Natural gas revenues decreased by $5.2 million due to a decrease in the
net sales price per Mcf, which was somewhat offset by a 282 MMcf increase in
sales volumes, net hedging receipts in the first half of 2002 versus net hedging
payments in the first half of 2001, and amortization of $0.8 million of the
Enron gain. The increase in volumes is due to increased sales volumes in CCA and
Crockett County due to development drilling. Wellhead price received decreased
$3.04 per Mcf, consistent with the average NYMEX price decrease of $2.40 per Mcf
from the six months ended June 30, 2001 to the six months ended June 30, 2002,
while hedging payments decreased $1.31 per Mcf due to lower natural gas prices.
DIRECT LIFTING COSTS. Direct lifting costs for the first six months of
2002 increased as compared to the first six months of 2001 by $1.0 million, from
$12.4 million to $13.4 million due to increased sales volumes attributable to
our development drilling program and Central Permian acquisitions in 2002. On a
per BOE basis, direct lifting costs decreased $0.36 from the first quarter of
2001 to the first quarter of 2002 due to decreased workover and maintenance
costs over the same period last year. We plan to resume our 2002 planned
workover and maintenance programs in the third and fourth quarters of this year.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the first half of 2002 decreased as compared to the first
half of 2001 by approximately $1.4 million. The decrease in production, ad
valorem, and severance taxes was a result of the lower commodity prices in the
first six months of 2002 as compared to the same period of 2001 as reflected in
the lower wellhead revenues. As a percent of oil and natural gas revenues
(excluding the effects of hedging transactions), production, ad valorem, and
severance taxes decreased from 9.6% to 9.3%.
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense
for the six months ended June 30, 2002 increased by approximately $1.9 million,
from $15.4 million to $17.3 million as compared to the six months ended June 30,
2001. The increase in DD&A was a product of increased sales volumes in 2002, as
well as a larger asset base associated with our 2002 acquisitions. The average
DD&A rate of $4.92 per BOE of production during the first six months of 2002
represents a decrease of $0.24 per BOE from the $5.16 per BOE recorded in the
first six months of 2001. The decrease is attributable to normal production
declines in the Lodgepole properties, which have relatively high DD&A rates as
compared to our other producing properties.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.4
million for the first half of 2002 as compared to the first half of 2001, from
$2.5 million to $2.9 million (excluding non-cash stock based compensation of
$9.6 million in the first six months of 2001). The increase in G&A expense was a
result of the hiring of additional staff after the 2002 Central Permian
acquisitions to manage, expand and exploit our growing asset base.
NON-CASH STOCK BASED COMPENSATION EXPENSE. Non-cash stock based
compensation expense decreased from $9.6 million in the first six months of 2001
to zero in the first six months of 2002. This non-cash stock based compensation
expense is associated with the purchase by our management stockholders of Class
A common stock under our management stock plan adopted in August 1998. This
amount represents the vested portion of the shares purchased and is recorded as
compensation, calculated in accordance with variable plan accounting under APB
25. The amount recorded in the first half of 2001 represented the final amount
of expense to be recorded related to the Class A stock.
INTEREST EXPENSE. Interest expense for the six months ended June 30, 2002
remained constant at $3.7 million versus the same period in 2001. The weighted
average interest rate, net of hedges, for the first half of 2002 was 4.9%
compared to 7.0% for the first half of 2001. The weighted average debt level
under our credit facility for the first half of 2002 was $122.3 million compared
to $92.9 million for the first half of 2001. The following table illustrates the
components of interest expense for the six months ended June 30, 2002 and 2001
(in thousands):
Six Months Ended June 30,
2002 2001 Difference
---------- ---------- -------------
Credit facility......................... $ 2,064 $ 3,178 $ (1,114)
8 3/8% notes due 2012................... 207 -- 207
Burlington note......................... -- 263 (263)
Interest rate hedges.................... 1,315 115 1,200
Banking fees........................... 128 157 (29)
---------- ---------- ------------
Total........................ $ 3,714 $ 3,713 $ 1
========== ========== ============
15
LIQUIDITY AND CAPITAL RESOURCES
Principal uses of capital have been for the acquisition and development of
oil and natural gas properties.
CASH FLOW
During the six months ended June 30, 2002, net cash provided by operations
was $37.5 million, a decrease of $3.5 million compared to the six months ended
June 30, 2001. This decrease is primarily attributable to lower oil and natural
gas prices in 2002. Cash used by investing activities increased from $35.6
million to $100.4 million over the same period, largely due to the 2002
acquisitions and an increase in development costs. Cash provided by financing
activities was $65.2 million in the first half of 2002, as compared to cash used
by financing activities of $6.0 million in the first half of 2001. The increase
is primarily attributable to the Central Permian acquisitions in 2002.
CAPITALIZATION
At June 30, 2002, Encore had total assets of $493.5 million. Total
capitalization was $426.2 million, of which 64.8% was represented by
stockholders' equity and 35.2% by long-term indebtedness.
DEBT MATURITIES
On June 25, 2002, the Company sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012. The offering was made through a
private placement pursuant to Rule 144A. As of June 30, 2002, the Notes have not
been registered under the Securities Act of 1933 or applicable state securities
laws. In conjunction with the issuance of the Notes, the Company executed a
registration rights agreement and has agreed to: (i) file a registration
statement of the Notes by September 23, 2002, enabling holders of the Notes to
exchange the Notes for publicly registered Notes with substantially identical
terms and (ii) use our reasonable best efforts to cause the registration
statement to become effective by December 22, 2002. The Company received net
proceeds of $146.3 million from the sale of the Notes, which were used to repay
and retire the Company's prior credit facility.
REVOLVING CREDIT FACILITY
Concurrently with the Company's issuance of the Notes, the Company also
entered into a new Revolving Credit Facility, effective June 25, 2002.
Borrowings under the facility will be secured by a first priority lien on the
Company's proved oil and natural gas reserves. Availability under the facility
will be determined through semi-annual borrowing base determinations and may be
increased or decreased. As of June 30, 2002, the amount available under the new
facility is $220.0 million. No amounts were outstanding at June 30, 2002. The
maturity date of the new facility will be June 25, 2006.
LETTERS OF CREDIT
The Company issued three standby letters of credit during the second
quarter 2002. The first, in the amount of $24.7 million, which expires January
1, 2003, guarantees the purchase price of the Paradox Basin acquisition less the
5% deposit made in the second quarter. The remaining two, totaling $7.0 million
and expiring on December 31, 2002 and January 1, 2003, secure potential future
settlements under certain outstanding hedging contracts.
FUTURE CAPITAL REQUIREMENTS
We anticipate that our capital expenditures will total approximately $21.0
million, exclusive of the Paradox Basin acquisition, for the third quarter of
2002. 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 and market
conditions. We plan to finance our ongoing development and acquisition
expenditures using internally generated cash flow, available cash, and our
existing credit agreement. As previously announced, Encore plans to invest $81.0
million, excluding acquisitions, in capital expenditures in 2002.
The Company believes that its capital resources are adequate to meet the
requirements of its business. Based on our anticipated capital investment
programs, we expect to invest our internally generated cash flow to replace
sales volumes and enhance our waterflood programs. Additional capital may be
required to pursue acquisitions and longer-term capital projects, such as our
high-pressure air injection tertiary recovery project in the CCA, to increase
our reserve base. Substantially all of these expenditures are discretionary and
will be undertaken only if funds are available and the projected rates of return
are satisfactory. Future cash flows are subject to a number of variables,
including the level of oil and natural gas sales volumes and prices. Operations
and other capital resources may not provide cash in sufficient amounts to
maintain planned levels of capital expenditures.
16
INFLATION AND CHANGES IN PRICES
While the general level of inflation affects certain of our costs, factors
unique to the petroleum industry result in independent price fluctuations.
Historically, significant fluctuations have occurred in oil and natural gas
prices. In addition, changing prices often cause costs of equipment and supplies
to vary as industry activity levels increase and decrease to reflect perceptions
of future price levels. Although it is difficult to estimate future prices of
oil and natural gas, price fluctuations have had, and will continue to have, a
material effect on us.
The following table indicates the average oil and natural gas prices
received for the three and six months ended June 30, 2002 and 2001. Average
equivalent prices for the first half of 2002 and 2001 were decreased by $0.72
and $3.81 per BOE, respectively, as a result of our hedging activities. Average
prices per equivalent barrel indicate the composite impact of changes in oil and
natural gas prices. Natural gas sales volumes are converted to oil equivalents
at the conversion rate of six Mcf per Bbl. All prices are before amortization of
the Enron-related gain.
Oil Natural Gas Equiv. Oil
(Per Bbl) (Per Mcf) (Per Boe)
------------ ------------ ------------
NET PRICE REALIZATION WITH HEDGES
Quarter ended June 30, 2002 .............. $ 21.66 $ 2.82 $ 20.76
Quarter ended June 30, 2001 .............. 22.39 4.04 22.78
Six months ended June 30, 2002 ........... 20.17 2.61 19.28
Six months ended June 30, 2001 ........... 23.10 4.34 23.74
AVERAGE WELLHEAD PRICE
Quarter ended June 30, 2002 .............. $ 23.39 $ 2.99 $ 22.34
Quarter ended June 30, 2001 .............. 24.98 4.78 25.78
Six months ended June 30, 2002 ........... 21.13 2.58 20.00
Six months ended June 30, 2001 ........... 25.82 5.63 27.55
17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information included in "Quantitative and Qualitative Disclosures
About Market Risk" in Encore's 2001 Annual Report filed on Form 10-K is
incorporated herein by reference. Such information includes a description of
Encore's potential exposure to market risks, including commodity price risk and
interest rate risk. Encore's open commodity positions as of June 30, 2002 are
presented in Note 6 to the accompanying financial statements. The fair value of
our open commodity and interest rate hedges is ($9.0) million as of June 30,
2002.
Subsequent to the end of the second quarter of 2002, we entered into
several additional oil hedges. The following table summarizes the additional
commodity hedging positions entered into through August 2, 2002:
Daily Floor Daily Cap
Floor Volume Price Cap Volume Price
Period (Bbl) (Per Bbl) (Bbl) (Per Bbl)
--------- ------------ ------------ ------------ ------------
Jan - Dec 2003 ..... 1,500 $ 22.00 1,500 $ 28.53
Jan - June 2004 .... 1,500 21.00 1,500 27.65
18
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's annual meeting of stockholders was held Tuesday, April 23,
2002. The sole item submitted to stockholders for vote was the election of seven
nominees to serve on the Company's board of directors during 2002 and until the
Company's next annual meeting. Notice of the meeting and proxy information was
distributed to stockholders prior to the meeting in accordance with federal
securities laws. There were no solicitations in opposition to the nominees.
Out of a total of 30,028,439 shares of the Company's Common Stock
outstanding and entitled to vote, 19,605,568 shares (65.29%) were present at the
meeting in person or by proxy. The vote tabulation with respect to each nominee
was as follows:
AUTHORITY
NOMINEE FOR WITHHELD
--------------------- ----------- ----------
I. Jon Brumley 19,110,407 495,161
Jon S. Brumley 19,096,132 509,436
Arnold L. Chavkin 19,540,593 64,975
Howard H. Newman 19,600,593 4,979
Ted A. Gardner 19,600,793 4,775
Ted Collins, Jr. 19,600,593 4,975
James A. Winne, III 19,600,593 4,975
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
4.1 Indenture, dated June 25, 2002, between the Company and Wells Fargo Bank,
N.A., as Trustee.
4.2 Rights Agreement, dated June 19, 2002, between the Company and Credit
Suisse First Boston Corporation, as Rights Agent.
10.1 $300,000,000 Credit Agreement dated June 25, 2002, among the Company, as
Borrower, Fleet National Bank, as Administrative Agent, Wachovia Bank,
N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent,
and certain financial institutions, as banks.
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
REPORTS ON FORM 8-K
During the three months ended June 30, 2002, the Company filed with the
SEC current reports on Form 8-K on April 5, June 10, and June 26.
The Company's April 5 Form 8-K discloses the Company's dismissal of Arthur
Andersen LLP and appointment of Ernst & Young LLP as its independent auditors
for the fiscal year 2002.
The Company filed two Form 8-Ks on June 10. The first (i) reporting
estimates of the Company's pro forma oil and natural gas reserves at March 31,
2002 to reflect acquisitions completed since January 1, 2002 and (ii) updating
the Company's estimated average daily sales volumes for 2002. The second
includes as an exhibit a press release stating the Company's intentions to offer
approximately $150 million of Senior Subordinated Notes through a private
placement.
The Company's June 26 Form 8-K filing includes as an exhibit a press
release announcing the private placement sale of $150 million of its 8 3/8%
Senior Subordinated Notes due 2012.
19
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENCORE ACQUISITION COMPANY
Date: December 5, 2002 By: /s/ Morris B. Smith
---------------------------------------------------
Morris B. Smith
Chief Financial Officer, Treasurer, Executive
Vice President, Secretary, and Principal
Financial Officer
Date: December 5, 2002 By: /s/ Robert C. Reeves
---------------------------------------------------
Robert C. Reeves
Vice President, Controller and Principal Accounting
Officer
20
INDEX TO EXHIBITS
EXHIBIT
NO. DESCRIPTION
------- -----------
4.1 Indenture, dated June 25, 2002, between the Company and Wells Fargo Bank,
N.A., as Trustee.
4.2 Rights Agreement, dated June 19, 2002, between the Company and Credit
Suisse First Boston Corporation, as Rights Agent.
10.1 $300,000,000 Credit Agreement dated June 25, 2002, among the Company, as
Borrower, Fleet National Bank, as Administrative Agent, Wachovia Bank,
N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent,
and certain financial institutions, as banks.
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002