Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
/x/ Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2003
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 / /
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes /x/ No / /
Number of shares of Common Stock outstanding as of July 31, 2003......30,211,882
ENCORE ACQUISITION COMPANY
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2003 and
December 31, 2002................................................ 3
Consolidated Statements of Operations for the three and six
months ended June 30, 2003 and 2002.............................. 4
Consolidated Statements of Stockholders' Equity for the six
months ended June 30, 2003....................................... 5
Consolidated Statements of Cash Flows for the six
months ended June 30, 2003 and 2002.............................. 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........................................................ 19
Item 4. Controls and Procedures..................................... 19
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K............................ 20
Signatures.......................................................... 21
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands except shares and per share amounts)
JUNE 30, DECEMBER 31,
2003 2002
----------- -----------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents ................................... $ 2,825 $ 13,057
Accounts receivable (Net of allowance of
$0 and $7.0 million, respectively) ....................... 22,357 21,981
Deferred tax asset .......................................... 3,410 4,833
Derivative assets ........................................... 3,081 3,245
Other current assets ........................................ 5,993 6,349
----------- -----------
Total current assets ................................. 37,666 49,465
----------- -----------
Properties and equipment, at cost -- successful efforts
method:
Producing properties ........................................ 631,458 581,012
Undeveloped properties ...................................... 1,282 1,168
Accumulated depletion, depreciation, and amortization ....... (107,234) (94,356)
----------- -----------
525,506 487,824
----------- -----------
Other property and equipment ................................ 3,660 3,680
Accumulated depreciation .................................... (2,259) (1,917)
----------- -----------
1,401 1,763
----------- -----------
Other assets .................................................. 17,348 10,844
----------- -----------
Total assets ......................................... $ 581,921 $ 549,896
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................................ $ 6,775 $ 9,650
Derivative liabilities ...................................... 6,257 8,558
Other current liabilities ................................... 19,175 18,768
----------- -----------
Total current liabilities ............................ 32,207 36,976
----------- -----------
Long-term debt ................................................ 150,000 166,000
Deferred income taxes ......................................... 65,050 47,656
Other non-current liabilities ................................. 5,421 2,998
----------- -----------
Total liabilities .................................... 252,678 253,630
----------- -----------
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,
30,211,215 and 30,162,955 issued and outstanding .......... 302 302
Additional paid-in capital .................................. 251,869 251,231
Deferred compensation ....................................... (1,962) (2,396)
Retained earnings ........................................... 85,935 53,724
Accumulated other comprehensive income ...................... (6,901) (6,595)
----------- -----------
Total stockholders' equity ........................... 329,243 296,266
----------- -----------
Total liabilities and stockholders' equity ........... $ 581,921 $ 549,896
=========== ===========
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 amounts)
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Revenues:
Oil ................................................................ $ 40,704 $ 31,683 $ 87,136 $ 58,369
Natural gas ........................................................ 10,539 6,124 19,894 11,735
--------- --------- --------- ---------
Total revenues ....................................................... 51,243 37,807 107,030 70,104
Expenses:
Production --
Lease operations ................................................ 9,140 6,567 18,093 13,384
Production, ad valorem, and severance taxes ..................... 5,095 3,546 11,264 6,559
General and administrative (excluding non-cash stock
based compensation) .............................................. 2,340 1,384 4,790 2,877
Non-cash stock based compensation .................................. 150 -- 295 --
Depletion, depreciation, and amortization .......................... 7,703 8,773 15,486 17,332
Derivative fair value gain ......................................... (576) (26) (1,836) (679)
Other operating .................................................... 712 612 882 751
--------- --------- --------- ---------
Total expenses ....................................................... 24,564 20,856 48,974 40,224
--------- --------- --------- ---------
Operating income ..................................................... 26,679 16,951 58,056 29,880
--------- --------- --------- ---------
Other income (expenses):
Interest ........................................................... (4,039) (2,222) (8,210) (3,714)
Other .............................................................. 39 (10) 86 20
--------- --------- --------- ---------
Total other income (expenses) ........................................ (4,000) (2,232) (8,124) (3,694)
--------- --------- --------- ---------
Income before income taxes and cumulative effect of
accounting change .................................................. 22,679 14,719 49,932 26,186
Current income tax provision ......................................... (591) (30) (1,358) (460)
Deferred income tax provision ........................................ (7,855) (5,563) (17,226) (9,490)
--------- --------- --------- ---------
Income before cumulative effect of accounting change ................. 14,233 9,126 31,348 16,236
Cumulative effect of accounting change, net of income
taxes of $529 ...................................................... -- -- 863 --
--------- --------- --------- ---------
Net income ........................................................... $ 14,233 $ 9,126 $ 32,211 $ 16,236
========= ========= ========= =========
Income before cumulative effect of accounting change per common share:
Basic .............................................................. $ 0.47 $ 0.30 $ 1.04 $ 0.54
Diluted ............................................................ 0.47 0.30 1.04 0.54
Net income per common share:
Basic .............................................................. $ 0.47 $ 0.30 $ 1.07 $ 0.54
Diluted ............................................................ 0.47 0.30 1.06 0.54
Weighted average common shares outstanding:
Basic .............................................................. 30,089 30,030 30,063 30,030
Diluted ............................................................ 30,284 30,184 30,253 30,118
The accompanying notes are an integral part of these consolidated financial
statements.
4
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
JUNE 30, 2003
(in thousands)
(unaudited)
Accumulated
Additional Other Total
Common Paid-In Deferred Retained Comprehensive Stockholders'
Stock Capital Compensation Earnings Income Equity
----------- ----------- ------------ ----------- ------------ -----------
Balance at December 31, 2002 ...... $ 302 $ 251,231 $ (2,396) $ 53,724 $ (6,595) $ 296,266
Exercise of stock options ......... -- 777 -- -- -- 777
Deferred compensation:
Amortization of expense ........ -- -- 295 -- -- 295
Other changes .................. -- (139) 139 -- -- --
Components of comprehensive income:
Net income ..................... -- -- -- 32,211 -- 32,211
Change in deferred hedge loss
(net of income taxes of
$188)....................... -- -- -- -- (306) (306)
-----------
Total comprehensive income 31,905
----------- ----------- ----------- ----------- ----------- -----------
Balance at June 30, 2003 ......... $ 302 $ 251,869 $ (1,962) $ 85,935 $ (6,901) $ 329,243
=========== =========== =========== =========== =========== ===========
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,
----------------------
2003 2002
--------- ---------
Operating activities
Net income ................................................ $ 32,211 $ 16,236
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation, and amortization ............... 15,486 17,332
Deferred taxes .......................................... 17,226 9,490
Non-cash stock based compensation ....................... 295 --
Cumulative effect of accounting change .................. (863) --
Non-cash derivative mark-to-market ...................... (892) (679)
Other non-cash items .................................... 3,472 (493)
Loss on disposition of assets ........................... 129 188
Changes in operating assets and liabilities:
Accounts receivable ..................................... (376) (2,218)
Other current assets .................................... (692) (4,920)
Other assets ............................................ (7,456) 3,277
Accounts payable and other current liabilities .......... (7,390) (697)
--------- ---------
Cash provided by operating activities ...................... 51,150 37,516
Investing activities
Proceeds from disposition of assets ....................... 590 356
Purchases of other property and equipment ................. (292) (400)
Acquisition of oil and natural gas properties ............. (259) (59,532)
Development of oil and natural gas properties ............. (46,198) (40,845)
--------- ---------
Cash used by investing activities ........................... (46,159) (100,421)
Financing activities
Proceeds from long-term debt .............................. 24,500 255,000
Payments on long-term debt ................................ (40,500) (183,000)
Payments for debt issuance costs .......................... -- (5,686)
Payments on note payable .................................. -- (1,107)
Exercise of stock options.................................. 777 --
--------- ---------
Cash provided by (used by) financing activities ............. (15,223) 65,207
Increase (decrease) in cash and cash equivalents ............ (10,232) 2,302
Cash and cash equivalents, beginning of period .............. 13,057 115
--------- ---------
Cash and cash equivalents, end of period .................... $ 2,825 $ 2,417
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
6
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2003
(unaudited)
1. FORMATION OF ENCORE
Encore Acquisition Company ("Encore" or 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. As of June 30, 2003, 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, the Powder River Basin of Montana, and the Paradox Basin of Utah.
2. BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited consolidated
financial statements of Encore include all adjustments necessary to present
fairly our financial position as of June 30, 2003 and results of operations for
the three and six months ended June 30, 2003 and 2002, and cash flows for the
six months ended June 30, 2003 and 2002. All adjustments are of a recurring
nature. These interim results are not necessarily indicative of results for an
entire year.
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 2002 consolidated financial statements and
related notes thereto included in the Company's Annual Report filed on Form
10-K.
Employee stock options and restricted stock awards are accounted for at
intrinsic value under the provisions of Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" ("APB 25"). Accordingly, no
compensation expense is recorded for stock options that are granted to employees
or non-employee directors with an exercise price equal to or above the Company's
stock price on the date of grant. If employee stock options and restricted stock
awards were accounted for at fair value under the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation", the Company's reported net income and net income per share
amounts would have been adjusted to the pro forma amounts indicated below (in
thousands, except per share amounts):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- -----------------------
2003 2002 2003 2002
---------- --------- ---------- ----------
As Reported:
Net income .............................. $ 14,233 $ 9,126 $ 32,211 $ 16,236
Basic net income per common share ....... 0.47 0.30 1.07 0.54
Diluted net income per common share ..... 0.47 0.30 1.06 0.54
Non-cash stock based compensation, net of
tax ................................ 95 -- 186 --
Pro Forma:
Net income .............................. $ 13,805 $ 8,790 $ 31,451 $ 15,578
Basic net income per common share ....... 0.46 0.29 1.05 0.52
Diluted net income per common share ..... 0.46 0.29 1.04 0.52
Non-cash stock based compensation, net of
tax ................................ 523 336 946 658
Currently, the FASB and representatives of the SEC accounting staff are
engaged in discussions on the issue of whether SFAS 141, "Business Combinations"
and SFAS 142, "Goodwill and Other Intangibles", which were effective June 30,
2001, called for mineral rights held under a lease or other contractual
arrangement to be classified on the balance sheet as intangible assets and
accompanied by specific footnote disclosures. Historically, oil and gas
companies, including Encore, have included these costs with all other oil and
gas property costs in Property, Plant, and Equipment on the consolidated balance
sheet.
7
In the event this interpretation is adopted, a substantial portion of the
acquisition costs of oil and gas properties would be required to be classified
on the balance sheet as an intangible asset. The Company believes this
interpretation would not have a material effect on our results of operations for
the periods presented or in the future as these intangible assets would be
depleted using the units of production method in a manner consistent with the
method currently used to calculate depletion, depreciation, and amortization
expense ("DD&A") on those assets.
3. NEW ACCOUNTING STANDARDS
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS 143"), which the Company adopted as of January 1,
2003. This statement requires that we now record a liability in the period in
which an asset retirement obligation is incurred, in an amount equal to 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. Thereafter, each quarter, this liability is
accreted and, if needed, adjusted up to the final cost.
The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect
adjustment to record (i) a $4.0 million increase in the carrying values of
proved properties, (ii) a $2.1 million decrease in accumulated depletion,
depreciation, and amortization, and (iii) a $5.2 million increase in other
non-current liabilities, and (iv) a cumulative effect of accounting change gain
of $0.9 million, net of tax.
The following table shows net income and basic and diluted earnings per
share as reported, as well as pro forma amounts as if the Company had adopted
SFAS 143 prior to January 1, 2002 (in thousands, except per share amounts):
SIX MONTHS ENDED
JUNE 30,
-----------------------
2003 2002
---------- ----------
As Reported:
Net income ........................ $ 32,211 $ 16,236
Basic net income per common share . 1.07 0.54
Diluted net income per common share 1.06 0.54
Pro Forma:
Net income ........................ $ 31,348 $ 16,334
Basic net income per common share . 1.04 0.54
Diluted net income per common share 1.04 0.54
The Company's primary asset retirement obligations relate to future
plugging and abandonment expenses on our oil and natural gas properties and
related facilities disposal. As of June 30, 2003, the Company had $2.6 million
held in an escrow account from which funds are released only for reimbursement
of plugging and abandonment expenses on our Bell Creek property. This amount is
included in 'Other assets' in the accompanying Consolidated Balance Sheet. The
following table summarizes the changes in the Company's future abandonment
liability from the initial liability, recorded upon adoption of SFAS 143 on
January 1, 2003, through June 30, 2003 (in thousands):
SIX MONTHS
ENDED
JUNE 30,
2003
----------
Future abandonment liability at January 1, 2003................ $ 4,791
Accretion expense ........................................... 130
Additional liability incurred ............................... 30
----------
Future abandonment liability at June 30, 2003.................. $ 4,951
==========
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 SFAS 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. SFAS 145 eliminates SFAS 4 and, thus, the exception
to applying Opinion 30 to all gains and losses related to extinguishments of
debt. As a result, beginning January 1, 2003, gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in Opinion 30. As the extraordinary loss on extinguishment of
debt recorded in the second quarter of 2002 of $0.2 million, net of tax, does
not meet the criteria of Opinion 30, it has been reclassified to 'Operating
income' in the Consolidated Statements of Operations for the three
8
and six months ended June 30, 2002. Additionally, the extraordinary loss on
extinguishment of debt has been reclassified in the Consolidated Statement of
Cash Flows for the six months ended June 30 to conform to this new presentation.
4. EARNINGS PER SHARE ("EPS")
The following table sets forth basic and diluted EPS computations for the
three and six months ended June 30, 2003 and 2002 (in thousands, except per
share data):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- ------------------------
2003 2002 2003 2002
----------- ----------- ----------- ----------
NUMERATOR:
Income before cumulative effect of accounting change ........ $ 14,233 $ 9,126 $ 31,348 $ 16,236
=========== =========== =========== ==========
Net income .................................................. $ 14,233 $ 9,126 $ 32,211 $ 16,236
=========== =========== =========== ==========
DENOMINATOR:
Denominator for basic earnings per share -
weighted average shares outstanding ....................... 30,089 30,030 30,063 30,030
Effect of dilutive securities ............................... 195 154 190 88
----------- ----------- ----------- ----------
Denominator for diluted earnings per share .................. 30,284 30,184 30,253 30,118
=========== =========== =========== ==========
BASIC PER COMMON SHARE:
Income before cumulative effect of accounting change ........ $ 0.47 $ 0.30 $ 1.04 $ 0.54
Cumulative effect of accounting change, net of income taxes . -- -- 0.03 --
----------- ----------- ----------- ----------
Net income .................................................. $ 0.47 $ 0.30 $ 1.07 $ 0.54
=========== =========== =========== ==========
DILUTED PER COMMON SHARE:
Income before cumulative effect of accounting change ........ $ 0.47 $ 0.30 $ 1.04 $ 0.54
Cumulative effect of accounting change, net of income taxes . -- -- 0.02 --
----------- ----------- ----------- ----------
Net income .................................................. $ 0.47 $ 0.30 $ 1.06 $ 0.54
=========== =========== =========== ==========
For the three months ended June 30, 2003 and 2002, outstanding employee
stock options of 240,000 and zero, respectively, were excluded from the
calculation of diluted earnings per share because their effect would have been
antidilutive, as the strike price of these options exceeded the average price of
the Company's common stock during the quarter.
5. DERIVATIVE FINANCIAL INSTRUMENTS
For the three months ended June 30, 2003 we recorded a $0.6 million
derivative fair value gain, which was primarily due to an overall decrease in
the forward LIBOR curve which caused the fair value of our interest rate swap to
increase. As our interest rate swap does not qualify for hedge accounting, it is
marked to market through 'Derivative fair value gain' on the Consolidated
Statement of Operations each period.
The following tables summarize our open commodity hedging positions as of
June 30, 2003:
OIL HEDGES AT JUNE 30, 2003
DAILY FLOOR DAILY CAP
FLOOR VOLUME PRICE CAP VOLUME PRICE
PERIOD (Bbl) (PER Bbl) (Bbl) (PER Bbl)
------ ------------ --------- ---------- ---------
July - Dec 2003....... 9,500 $ 21.05 7,000 $ 27.14
Jan - June 2004....... 8,500 21.41 5,500 28.39
July - Dec 2004....... 4,500 21.44 3,000 28.52
In addition to the amounts noted in the table above, as of June 30, 2003,
we had one short oil put contract in place covering 500 Bbls per day at a strike
price of $17.00 which does not qualify for hedge accounting. Accordingly, this
contract is marked to market through earnings each period. In order to more
effectively hedge the cash flows received on our oil production, the Company
uses basis swaps in conjunction with NYMEX based oil hedging contracts. As these
do not change the Company's overall hedged volumes, they have not been presented
separately.
9
NATURAL GAS HEDGES AT JUNE 30, 2003
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 2003... 7,500 $ 3.17 2,500 $ 6.83 2,500 $ 3.69
Aug - Dec 2003.... -- -- -- -- 2,500 5.59
2004.............. 10,000 3.75 5,000 6.10 2,500 5.19
2005.............. -- -- -- -- 2,500 4.80
The natural gas based contracts above originally are based on NYMEX or
certain other price points. In order to more effectively hedge the cash flows
received on our natural gas production, the Company uses basis swaps to change a
NYMEX based natural gas hedging contract to a different underlying price point.
As these do not change the Company's overall hedged volumes, they have not been
presented separately.
INTEREST RATE DERIVATIVES
In conjunction with the sale of our $150 million 8 3/8% Senior Subordinated
Notes (the "Notes") on June 25, 2002, the Company repaid all amounts outstanding
under our previous credit facility on June 25, 2002, and terminated the facility
on that date. At the time, the Company had three interest rate swaps
outstanding, with a notional amount of $30 million each, which swapped LIBOR
based floating rates for fixed rates. According to the provisions of SFAS 133,
these no longer qualified for hedge accounting. The unrealized loss of $3.8
million at June 25, 2002 was recognized in accumulated other comprehensive
income at that date and is being amortized to interest expense over the original
life of the swaps. We increased interest expense by $1.2 million in the first
six months of 2003 through amortization of this unrealized loss from other
comprehensive income.
At the end of 2002, the Company had outstanding two of the previously
mentioned $30 million floating for fixed interest rate swap contracts and one
additional interest rate swap contract whereby we pay LIBOR + 3.89% and receive
8.375% on a $80 million notional amount. During January 2003, we cash settled
the two $30 million floating for fixed swap contracts at a total cost of $4.3
million. This resulted in a gain of $647,000 recorded in 'Derivative fair value
gain' on the Consolidated Statement of Operations. The following table
summarizes the Company's only remaining interest rate swap contract at June 30,
2003:
ENCORE
CONTRACT EXPIRATION NOTIONAL AMOUNT ENCORE PAYS RECEIVES
- ------------------- --------------- ----------- --------
June 2005........ $80,000,000 LIBOR + 3.89% 8.375%
As this contract does not qualify for hedge accounting, changes in its fair
market value are recorded in 'Derivative fair value gain' on the Consolidated
Statement of Operations.
The actual gains or losses we realize from our derivative transactions may
vary significantly from the amounts recorded in the June 30, 2003 Consolidated
Balance Sheet due to fluctuation of prices in the commodities markets and/or
fluctuations in the floating LIBOR interest rate.
6. COMPREHENSIVE INCOME
For the six months ended June 30, 2003, we had total comprehensive income
of $31.9 million, while net income totaled $32.2 million. The difference between
net income and total comprehensive income is due to a $0.3 million change in our
deferred hedging gain/loss in 'Accumulated Other Comprehensive Income' from $6.6
million at December 31, 2002 to $6.9 million at June 30, 2003. For the six
months ended June 30, 2002, we had a 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 hedging
gain/loss.
For the three months ended June 30, 2003, we had total comprehensive income
of $12.8 million, while net income totaled $14.2 million. The difference between
net income and total comprehensive income is due to a $1.4 million change in our
deferred hedging loss in 'Accumulated Other Comprehensive Income' from a
deferred loss of $5.5 million at March 30, 2003 to a deferred loss of $6.9
million at June 30, 2003. For the three months ended June 30, 2002, we had a
total comprehensive income of $7.5 million, while net income totaled $9.1
million. The difference between net income and total comprehensive income is due
to a $1.6 million increase in our deferred hedging loss.
10
7. FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS
As of June 30, 2003, all of the Company's subsidiaries were 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.
8. PROPERTY PURCHASE
On July 31, 2003, the Company closed the purchase of interests in natural
gas properties in Northern Louisiana from a group of private sellers at a cost
of $52.5 million subject to additional post-closing adjustments. The purchase
was effective June 1, 2003. The properties are located in the Elm Grove Field in
Bossier Parish, Louisiana and are non-operated working interests ranging from 2%
to 38% across 1,800 net acres in 15 sections. In addition, Encore has acquired
approximately 1,500 net acres of deep rights. Current net production from the
interests average 7,200 MCFE per day, and there are two active development
drilling projects underway.
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 2002 Annual Report filed on Form 10-K. The following discussion should
be read in conjunction with the consolidated financial statements and notes
thereto included in this document and Encore's 2002 Form 10-K.
DESCRIPTION OF CRITICAL ACCOUNTING POLICIES
The information included in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Description of Critical
Accounting Policies" in Encore's 2002 Annual Report filed on Form 10-K is
incorporated herein by reference. There have been no material changes to our
accounting policies since December 31, 2003 with the exception of the adoption
of SFAS 143 and SFAS 145 discussed in Note 3 to the accompanying financial
statements. See also discussion in Note 2 to the accompanying financial
statements of SFAS 141 and SFAS 142 and the related possible interpretation of
these statements by the FASB and the SEC and their potential impact on the
Company's financial statements.
RESULTS OF OPERATIONS
The following table sets forth selected operating information for the
periods presented:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------------- -------------------------------------
INCREASE / INCREASE /
2003 2002 (DECREASE) 2003 2002 (DECREASE)
--------- --------- ---------- ----------- ---------- ----------
Operating Results (in thousands):
Oil and natural gas revenues.................. $ 51,243 $ 37,807 $ 13,436 $ 107,030 $ 70,104 $ 36,926
Lease operations.............................. 9,140 6,567 2,573 18,093 13,384 4,709
Production, ad valorem, and severance taxes... 5,095 3,546 1,549 11,264 6,559 4,705
Daily sales volumes:
Oil volumes (Bbls)............................ 17,755 15,714 2,041 18,130 15,602 2,528
Natural gas volumes (Mcf)..................... 21,858 22,275 (417) 21,667 23,122 (1,455)
Combined volumes (BOE)........................ 21,398 19,427 1,971 21,741 19,456 2,285
Average prices:
Oil (per Bbl)................................. $ 25.19 $ 22.16 $ 3.03 $ 26.55 $ 20.67 $ 5.88
Natural gas (per Mcf)......................... 5.30 3.02 2.28 5.07 2.80 2.27
Combined volumes (per BOE).................... 26.32 21.39 4.93 27.20 19.91 7.29
Selected operating expenses per BOE:
Lease operations.............................. $ 4.69 $ 3.71 $ 0.98 $ 4.60 $ 3.80 $ 0.80
Production, ad valorem, and severance taxes... 2.62 2.01 0.61 2.86 1.86 1.00
G&A (excluding non-cash stock based
compensation)............................ 1.20 0.78 0.42 1.22 0.82 0.40
DD&A.......................................... 3.96 4.96 (1.00) 3.94 4.92 (0.98)
12
COMPARISON OF QUARTER ENDED JUNE 30, 2003 TO QUARTER ENDED JUNE 30, 2002
Set forth below is our comparison of operations during the second quarter
of 2003 with the second quarter of 2002.
REVENUES AND SALES VOLUMES. Oil and natural gas revenues of Encore for the
second quarter of 2003 increased as compared to 2002 by $13.4 million, from
$37.8 million to $51.2 million. The following table illustrates the primary
components of oil and natural gas revenue for the three months ended June 30,
2003 and 2002, as well as each quarter's respective oil and natural gas volumes
(in thousands, except per unit amounts):
THREE MONTHS ENDED JUNE 30,
----------------------------------------------------- INCREASE /
2003 2002 (DECREASE)
------------------------- ------------------------ ------------------------
REVENUES: REVENUE $/UNIT REVENUE $/UNIT REVENUE $/UNIT
------------ ---------- ---------- ---------- ----------- ----------
Oil wellhead............ $ 43,262 $ 26.77 $ 33,446 $ 23.39 $ 9,816 $ 3.38
Oil hedges.............. (2,658) (1.64) (2,469) (1.73) (189) 0.09
Enron gain amortization. 100 0.06 706 0.50 (606) (0.44)
------------ ---------- ---------- ---------- ----------- ----------
Oil Revenues....... $ 40,704 $ 25.19 $ 31,683 $ 22.16 $ 9,021 $ 3.03
============ ========== ========== ========== =========== ==========
Natural gas wellhead.... $ 11,040 $ 5.55 $ 6,051 $ 2.99 $ 4,989 $ 2.56
Gas hedges.............. (506) (0.25) (325) (0.17) (181) (0.08)
Enron gain amortization. 5 -- 398 0.20 (393) (0.20)
------------ ---------- ---------- ---------- ----------- ----------
Gas Revenues....... $ 10,539 $ 5.30 $ 6,124 $ 3.02 $ 4,415 $ 2.28
============ ========== ========== ========== =========== ==========
Average Average Average
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
------------ ---------- ---------- ---------- ----------- ----------
Oil (Bbls).............. 1,616 $ 28.91 1,430 $ 26.25 186 $ 2.66
Gas (Mcf)............... 1,989 5.74 2,027 3.40 (38) 2.34
Combined (BOE) ......... 1,947 1,768 179
Oil revenues increased from second quarter 2002 to second quarter 2003 by
$9.0 million, due to increased volumes and a higher average wellhead price
received. Oil volumes for the quarter ended June 30, 2003 increased 186 MBbls
due to our successful development drilling program and the Paradox Basin
acquisition, which closed in the second half of 2002. Our average wellhead oil
price increased $3.38 per Bbl in the second quarter of 2003 over the same period
in 2002 primarily as a result of an increase in the overall market price for oil
as reflected in the $2.66 per Bbl increase in the average NYMEX price over the
same period. This increase in wellhead revenues was offset slightly by an
increase in hedging payments of $0.2 million and a decrease in the Enron gain
amortization of $0.6 million from the second quarter of 2002 to the second
quarter of 2003.
Natural gas revenues increased by $4.4 million, or $2.28 per Mcf, in the
second quarter of 2003 from the second quarter of 2002 due to an increase in the
average wellhead price received, partially offset by a $0.2 million increase in
hedging payments and a decrease of $0.4 million in the Enron gain amortization.
The increase in our average wellhead price received for the quarter of $2.56 is
consistent with the increase in the overall market price for gas, as reflected
by the increase in the average NYMEX price per Mcf of $2.34 over the same
period.
LEASE OPERATIONS. Lease operations expense for the second quarter of 2003
increased as compared to the second quarter of 2002 by $2.6 million. The
increase is primarily attributable to increased production volumes and an
increase in the per BOE rate. On a per BOE basis, lease operations expense
increased from $3.71 to $4.69 from the second quarter of 2002 to the second
quarter of 2003, due to the Paradox Basin properties, which have higher per BOE
operating costs than the Company's historical average per BOE lease operations
expense, as well as higher electricity costs on our Permian and Cedar Creek
Anticline ("CCA") properties. However, the Company's average per BOE rate for
the second quarter of 2003 was lower than expected, reflecting higher than
anticipated production and lower than anticipated maintenance costs in the CCA.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the second quarter of 2003 increased as compared to the
second quarter of 2002 by approximately $1.5 million. This increase was
primarily a result of higher revenues. As a percent of oil and natural gas
revenues (excluding the effects of hedges), production, ad valorem, and
severance taxes for the second quarter of 2003 remained comparable to the second
quarter of 2002, up to 9.4% from 9.0%. The effect of hedges are 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, ad valorem, and severance taxes paid to taxing authorities.
13
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense
for the second quarter of 2003 decreased by $1.1 million as compared to the
second quarter of 2002, due to a $1.00 decrease in the per BOE rate partially
offset by an increase in production. The decrease in the per BOE rate is a
result of an increase in reserves and the adoption of SFAS 143 on January 1,
2003 (see Note 3 to the accompanying financial statements). Historically,
consistent with industry practice, the Company assumed salvage value would be
offset by plugging and abandonment expenses. However, upon adoption of SFAS 143,
the Company began subtracting the estimated salvage value of its equipment from
its depreciable base in its DD&A calculation, thus lowering our per BOE rate.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense (excluding non-cash
stock based compensation) increased $1.0 million for the second quarter of 2003
as compared to the second quarter of 2002. This increase is a result of
increased staffing levels and consulting services, which also caused a $0.42
increase in the per BOE rate. We believe G&A expense per BOE will remain at
approximately $1.20 in the third quarter as the Company continues to review oil
and natural gas properties currently on the market and incur incremental related
expenses.
NON-CASH STOCK BASED COMPENSATION EXPENSE. No amount was recorded during
the three months ended June 30, 2002 related to non-cash stock based
compensation expense, while $0.2 million was recorded during the three months
ended June 30, 2003. This expense represents the amortization of deferred
compensation. The deferred compensation recorded in equity relates to restricted
stock granted at the end of 2002 under the 2000 Incentive Stock Plan and is
being amortized to expense over the vesting period of the stock.
INTEREST EXPENSE. Interest expense increased $1.8 million in the quarter
ended June 30, 2003 from the quarter ended June 30, 2002. The increase in
interest expense is due to an increase in the weighted average interest rate
offset by a slight decrease in weighted average debt. The weighted average
interest rate, net of hedges, for the second quarter of 2003 was 10.7% compared
to 5.5% for the second quarter of 2002. This higher rate is the result of the
Notes, issued in June 2002, with a higher 8 3/8 % fixed rate being the primary
component of the Company's total indebtedness during the first half of 2003,
while the revolving credit facility with a lower floating rate was the primary
component in the first half of 2002. The following table illustrates the
components of interest expense for the three months ended June 30, 2003 and 2002
(in thousands):
THREE MONTHS ENDED JUNE 30,
------------------------------ INCREASE /
2003 2002 (DECREASE)
----------- ------------ ------------
8 3/8% notes due 2012............. $ 3,141 $ 207 $ 2,934
Revolving credit facility......... 15 1,079 (1,064)
Interest rate hedges.............. 544 (1) 858 (314)
Banking fees and other........... 339 78 261
----------- ------------ ------------
Total.................. $ 4,039 $ 2,222 $ 1,817
=========== ============ ============
(1) Amount represents non-cash amortization of the unrealized loss in other
comprehensive income of interest rate swaps outstanding which no longer
qualified for hedge accounting. See Note 5 to the accompanying financial
statements.
COMPARISON OF SIX MONTHS ENDED JUNE 30, 2003 TO SIX MONTHS ENDED JUNE 30, 2002
Set forth below is our comparison of operations during the first six months
of 2003 with the first six months of 2002.
REVENUES AND SALES VOLUMES. Oil and natural gas revenues of Encore for the
six months ended June 30, 2003 increased as compared to 2002 by $36.9 million,
from $70.1 million to $107.0 million. The following table illustrates the
primary components of oil and natural gas revenue for the six months ended June
30, 2003 and 2002, as well as each period's respective oil and natural gas
volumes (in thousands, except per unit amounts):
SIX MONTHS ENDED JUNE 30,
------------------------------------------------------ INCREASE /
2003 2002 (DECREASE)
-------------------------- ------------------------ ------------------------
REVENUES: REVENUE $/UNIT REVENUE $/UNIT REVENUE $/UNIT
----------- ---------- ----------- --------- ---------- ----------
Oil wellhead............ $ 95,476 $ 29.10 $ 59,661 $ 21.13 $ 35,815 $ 7.97
Oil hedges.............. (8,540) (2.61) (2,703) (0.96) (5,837) (1.65)
Enron gain amortization. 200 0.06 1,411 0.50 (1,211) (0.44)
----------- ---------- ----------- --------- ---------- ----------
Oil Revenues....... $ 87,136 $ 26.55 $ 58,369 $ 20.67 $ 28,767 $ 5.88
=========== ========== =========== ========= ========== ==========
Natural gas wellhead.... $ 21,352 $ 5.44 $ 10,812 $ 2.58 $ 10,540 $ 2.86
Gas hedges.............. (1,468) (0.37) 126 0.03 (1,594) (0.40)
Enron gain amortization. 10 -- 797 0.19 (787) (0.19)
----------- ---------- ----------- --------- ---------- ----------
Gas Revenues....... $ 19,894 $ 5.07 $ 11,735 $ 2.80 $ 8,159 $ 2.27
=========== ========== =========== ========= ========== ==========
14
Average Average Average
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
----- -------- ----- -------- ------- --------
Oil (Bbls).............. 3,281 $ 31.39 2,824 $ 23.95 457 $ 7.44
Gas (Mcf)............... 3,922 5.82 4,185 2.95 (263) 2.87
Combined (BOE) ......... 3,935 3,522 413
Oil revenues increased $28.8 million for the six months ended June 30, 2003
as compared to the six months ended June 30, 2002 due to higher sales volumes
and a higher average wellhead price received. Oil sales volumes increased 457
MBbls, resulting from our development drilling program and the Paradox Basin
acquisition, which closed in the third quarter of 2002. The average wellhead
price received for the first half of 2003 increased $7.97 per Bbl, which when
combined with the increase in sales volumes for the period, caused a $35.8
million increase in oil wellhead revenues. However, this increase was offset by
a $5.8 million increase in hedging payments during the first six months of 2003
as compared to the first six months of 2002 resulting from the higher average
NYMEX price during the first half of 2003 over the same period in 2002. The
increase in wellhead oil revenues was also reduced by a reduction in the Enron
gain amortization during the first half of 2003 as compared to the corresponding
period in 2002, dropping by $1.2 million.
Natural gas revenues increased by $8.2 million, or $2.27 per Mcf in the
first half of 2003, due to an increase in the wellhead price, partially offset
by a $1.6 million increase in payments on hedges and a decrease of $0.8 million
in the amortization of the Enron gain for the period. The increase in the
wellhead price received of $2.86 per Mcf from the six months ended June 30, 2002
to the six months ended June 30, 2003 is consistent with the average NYMEX price
increase of $2.87 per Mcf over the same period.
LEASE OPERATIONS. Lease operations expense for the six months ended June
30, 2003 increased as compared to the first six months of 2002 by $4.7 million.
The increase is primarily attributable to increased production volumes and an
increase in the per BOE rate. On a per BOE basis, lease operations expense
increased from $3.80 to $4.60, due to the inclusion of the Paradox Basin
properties in the first half of 2003, which have higher per BOE operating costs
than the Company's historical average, as well as higher electricity costs on
our Central Permian and CCA properties. However, the Company's average per BOE
rate for the quarter of 2003 was lower than expected, reflecting higher than
anticipated production and lower than anticipated maintenance costs in the CCA.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the first half of 2003 increased as compared to the first
half of 2002 by approximately $4.7 million. This increase in production, ad
valorem, and severance taxes was a result of higher revenues in the first six
months of 2003 as compared to the same period of 2002. As a percent of oil and
natural gas revenues (excluding the effects of hedging transactions),
production, ad valorem, and severance taxes remained fairly constant, up to 9.6%
for the first six months of 2003 from 9.3% for the first six months of 2002. The
effect of hedges are 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, ad valorem, and severance taxes paid
to taxing authorities.
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense
for the six months ended June 30, 2003 decreased by approximately $1.8 million
as compared to the six months ended June 30, 2002 due to a $0.98 decrease in the
BOE rate, partially offset by an increase in production. The decrease in the per
BOE rate is a result of an increase in reserves and the adoption of SFAS 143 on
January 1, 2003 (see Note 3 to the accompanying financial statements).
Historically, consistent with industry practice, the Company assumed salvage
value would be offset by plugging and abandonment expenses. However, upon
adoption of SFAS 143, the Company began subtracting the estimated salvage value
of its equipment from its depreciable base in its DD&A calculation, thus
lowering its per BOE rate.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense (excluding non-cash
stock based compensation) increased $1.9 million for the first half of 2003 as
compared to the first half of 2002. The increase in G&A expense was a result of
increased staffing levels and consulting services, which also caused a $0.40
increase in the per BOE rate. We believe G&A expense per BOE will remain at
approximately $1.20 in the third quarter as the Company continues to review oil
and natural gas properties currently on the market and incur incremental related
expenses.
NON-CASH STOCK BASED COMPENSATION EXPENSE. No amount was recorded during
the six months ended June 30, 2002 related to non-cash stock based compensation
expense, while $0.3 million was recorded during the six months ended June 30,
2003. This expense represents the amortization of deferred compensation. The
deferred compensation was recorded in equity relates to restricted stock granted
at the end of 2002 under the 2000 Incentive Stock Plan and is being amortized to
expense over the vesting period of the stock.
15
INTEREST EXPENSE. Interest expense for the six months ended June 30, 2003
increased $4.5 million when compared to the six months ended June 30, 2002 due
primarily to an increase in our weighted average interest rate from period to
period. The weighted average interest rate, net of hedges, for the first half of
2003 was 10.4% compared to 4.9% for the first half of 2002. This higher weighted
average interest rate is the result of the Notes, issued in June 2002, with a
higher 8 3/8 % fixed rate being the primary component of the Company's total
indebtedness during the first half of 2003, while the revolving credit facility
with a lower floating rate was the primary component in the first half of 2002.
The following table illustrates the components of interest expense for the six
months ended June 30, 2003 and 2002 (in thousands):
SIX MONTHS ENDED JUNE 30,
------------------------- INCREASE /
2003 2002 (DECREASE)
---------- ---------- -----------
8 3/8% notes due 2012............. $ 6,281 $ 207 $ 6,074
Revolving credit facility......... 117 2,064 (1,947)
Interest rate hedges.............. 1,198(1) 1,315 (117)
Banking fees and other........... 614 128 486
---------- ---------- -----------
Total.................. $ 8,210 $ 3,714 $ 4,496
========== ========== ===========
(1) Amount represents non-cash amortization of the unrealized loss in other
comprehensive income of previous interest rate swaps outstanding which no longer
qualified for hedge accounting. See Note 5 to the accompanying financial
statements.
16
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, 2003, net cash provided by operations
was $51.2 million, an increase of $13.6 million compared to the six months ended
June 30, 2002. This increase is primarily attributable to higher oil and natural
gas prices in 2003; combined with increased production volumes. Cash used by
investing activities decreased from $100.4 million to $46.2 million over the
same period, largely due to the 2002 Central Permian acquisition ($50.1 million)
partially offset by an increase in development costs. Cash used by financing
activities was $15.2 million in the first half of 2003, as compared to cash
provided by financing activities of $65.2 million in the first half of 2002.
This $80.4 million change was caused by borrowings in 2002 used to finance the
Central Permian acquisition and the subsequent refinancing of our revolving
credit facility and issuance of the Notes. The net proceeds received upon
issuance of the Notes were greater than needed to pay all amounts outstanding
under the old revolving credit facility and the issuance cost of the new debt,
contributing to the cash provided by financing in the first half of 2002. This
compares with the first half of 2003 with the only major property acquisition
closing during the third quarter. Higher revenues in the first half of 2003 as
compared to 2002 allowed the Company to fund its projected capital budget while
simultaneously reducing the overall indebtedness of the Company. This compares
with a price environment during the first half of 2002 in which the Company, at
times, financed a portion of its development program with borrowings under the
Company's revolving credit facility.
Capitalization
At June 30, 2003, Encore had total assets of $581.9 million. Total
capitalization was $479.2 million, of which 68.7% was represented by
stockholders' equity and 31.3% by long-term debt.
Debt Maturities
The only long-term debt outstanding at June 30, 2003 is the $150 million of
8 3/8% senior subordinated Notes due June 15, 2012.
Revolving Credit Facility
The maximum amount available under our revolving credit facility is $300.0
million, which is secured by a first priority lien on our proved oil and natural
gas reserves representing at least 80% of the present discounted reserve value.
As of June 30, 2003, the amount available to us under our revolving credit
facility is $220.0 million which may be increased and decreased subject to a
borrowing base calculation. The credit facility expires on June 25, 2006. No
amounts were outstanding under our revolving credit facility as of June 30,
2003.
Future Capital Requirements
In April 2003, the Board of Directors approved an increase to Encore's 2003
capital budget in the amount of $20.0 million to begin the second phase of the
high-pressure air injection ("HPAI") tertiary recovery project in the CCA. This,
when added to the previously announced $105.0 million capital budget, will give
the Company a capital budget of $125.0 million for 2003. These Board approved
amounts do not include any capital expenditures which the Company will likely
incur in the development of our newly acquired Louisiana properties during the
remainder of 2003. The Company will review the Board approved capital budget
during the remainder of the year to determine its adequacy in light of the new
acquisition.
We anticipate that our capital expenditures will total approximately $78.2
million for the third quarter of 2003, of which $52.2 million relates to the
acquisition of interests in Northern Louisiana from a group of private sellers.
The properties are located in the Elm Grove Field in Bossier Parish, Louisiana.
The purchase closed on July 31, 2003, effective June 1, 2003, and was funded
with cash on hand and with $41 million in new borrowings under our revolving
credit facility. 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.
The Company believes that its capital resources from internally generated
cash flows and funds available under the credit facility are adequate to meet
the requirements of its business through 2004. 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 to
increase our reserve base, such as our high-pressure air injection tertiary
recovery project in the CCA. 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 the Company's capital resources may not provide cash
in sufficient amounts to maintain planned levels of capital expenditures.
17
The following table illustrates the Company's contractual obligations
outstanding at June 30, 2003 (in thousands):
PAYMENTS DUE BY PERIOD
---------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS TOTAL 2003 2004 - 2005 2006 - 2007 THEREAFTER
---------- --------- ----------- ----------- ----------
8 3/8% Notes............ $ 150,000 $ -- $ -- $ -- $ 150,000
Operating Leases......... 3,321 480 1,938 690 213
---------- --------- ----------- ----------- ----------
Totals................... $ 153,321 $ 480 $ 1,938 $ 690 $ 150,213
========== ========= =========== =========== ==========
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 the Company.
The following table indicates the average oil and natural gas prices
realized for the three and six months ended June 30, 2003 and 2002. Average
equivalent prices for the first half of 2003 and 2002 were decreased by $2.49
and $0.10 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.
OIL NATURAL GAS EQUIV. OIL
(PER Bbl) (PER Mcf) (PER BOE)
--------- --------- ---------
NET PRICE REALIZATION WITH HEDGES
Quarter ended June 30, 2003..... $ 25.19 $ 5.30 $ 26.32
Quarter ended June 30, 2002..... 22.16 3.02 21.39
Six months ended June 30, 2003.. 26.55 5.07 27.20
Six months ended June 30, 2002.. 20.67 2.80 19.91
AVERAGE WELLHEAD PRICE
Quarter ended June 30, 2003..... $ 26.77 $ 5.55 $ 27.89
Quarter ended June 30, 2002..... 23.39 2.99 22.34
Six months ended June 30, 2003.. 29.10 5.44 29.69
Six months ended June 30, 2002.. 21.13 2.58 20.01
18
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information included in "Quantitative and Qualitative Disclosures about
Market Risk" in Encore's 2002 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. The Company's outstanding derivative contracts as of June 30, 2003
are discussed in Note 5 to the accompanying financial statements. As of June 30,
2003, the fair value of our open commodity and interest rate derivative
contracts is ($1.3) million.
Subsequent to the end of the second quarter of 2003, we entered into
additional oil and natural gas hedging contracts. The following table summarizes
the hedging contracts entered into from July 1, 2003 through July 31, 2003 (not
including net gas basis swaps - see Note 5 to the accompanying financial
statements):
ADDITIONAL OIL HEDGING CONTRACTS:
DAILY FLOOR DAILY CAP DAILY SWAP
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE
CONTRACT EXPIRATION (BBL) (PER BBL) (BBL) (PER BBL) (BBL) (PER BBL)
- ------------------- ------------- ---------- ----------- --------- ----------- ---------
Jan - June 2004.... 3,500 $ 24.14 3,000 $ 29.76 500 $ 26.48
July - Dec 2004.... 2,500 24.00 2,000 28.05 500 26.48
ADDITIONAL NATURAL GAS HEDGING CONTRACTS:
DAILY FLOOR DAILY CAP DAILY SWAP
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE
CONTRACT EXPIRATION (MCF) (PER MCF) (MCF) (PER MCF) (MCF) (PER MCF)
- ------------------- ------------ --------- ---------- --------- ----------- ---------
Aug - Dec 2003... -- $ -- -- $ -- 2,500 $ 5.44
2004............. 5,000 4.55 2,500 5.90 2,500 5.13
2005............. -- -- -- -- 2,500 4.76
ITEM 4. CONTROLS AND PROCEDURES
In accordance with 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 Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of June 30, 2003 to provide reasonable assurance
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 Securities and Exchange Commission's rules and
forms.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended June 30, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
19
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's annual meeting of shareholders was held on Wednesday,
April 30, 2003. The sole item submitted to stockholders for vote was
the election of seven nominees to serve on the Company's board of
directors during 2003 and until the Company's next annual meeting.
(b) At the meeting, the following individuals were elected to comprise the
entire Board of Directors of the Company:
I. Jon Brumley
Jon S. Brumley
Arnold L. Chavkin
Howard H. Newman
Ted A. Gardner
Ted Collins, Jr.
James A. Winne III
(c) Out of a total of 30,678,866 shares of the Company's Common Stock
outstanding and entitled to vote, 28,933,474 shares (94.3%) were
present at the meeting in person or by proxy. The vote tabulation with
respect to each nominee was as follows:
AUTHORITY
FOR WITHHELD
---------- -----------
I. Jon Brumley..................... 27,944,997 988,477
Jon S. Brumley..................... 27,944,997 988,477
Arnold L. Chavkin.................. 28,820,972 112,502
Howard H. Newman................... 28,820,972 112,502
Ted A. Gardner..................... 28,820,872 112,602
Ted Collins, Jr.................... 28,820,972 112,502
James A. Winne III................. 28,820,872 112,602
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
- --------
3.1 Second Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to the Company's Quarterly Report on Form
10-Q for the fiscal quarter ended September 30, 2001, filed with the
SEC on November 7, 2001).
3.2 Second Amended and Restated Bylaws of the Company (incorporated by
reference to the Company's Quarterly Report on Form 10-Q for the fiscal
quarter ended September 30, 2001, filed with the SEC on November 7,
2001).
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)
Reports on Form 8-K
On May 1, 2003, the Company filed with the SEC a current report on Form 8-K
under Item 9.
The Company's May 1, 2003 Form 8-K included as an exhibit a press release
announcing first quarter 2003 results.
20
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: August 8, 2003 By: /s/ Morris B. Smith
----------------------------------
Morris B. Smith
Chief Financial Officer, Treasurer,
Executive Vice President
and Principal Financial Officer
Date: August 8, 2003 By: /s/ Robert C. Reeves
----------------------------------
Robert C. Reeves
Vice President, Controller and
Principal Accounting Officer
21