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 September 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 October 31, 2003.............
30,275,113
ENCORE ACQUISITION COMPANY
INDEX
PART I. FINANCIAL INFORMATION
Page
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2003 and
December 31, 2002................................................. 3
Consolidated Statements of Operations for the three and
nine months ended September 30, 2003 and 2002..................... 4
Consolidated Statements of Stockholders' Equity for the nine
months ended September 30, 2003................................... 5
Consolidated Statements of Cash Flows for the nine
months ended September 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 Disclosures About Market
Risk.............................................................. 20
Item 4. Controls and Procedures....................................... 20
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.............................. 21
Signatures............................................................ 22
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands except shares and per share amounts)
SEPTEMBER 30, DECEMBER 31,
2003 2002
--------------- ---------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents ........................................ $ 653 $ 13,057
Accounts receivable, net of allowance of
$0 and $7.0 million, respectively ............................. 22,834 21,981
Deferred tax asset ............................................... 1,364 4,833
Derivative assets ................................................ 5,986 3,245
Other current assets ............................................. 5,684 6,349
--------------- ---------------
Total current assets ...................................... 36,521 49,465
--------------- ---------------
Properties and equipment, at cost -- successful efforts method:
Producing properties ............................................. 709,720 581,012
Undeveloped properties ........................................... 955 1,168
Accumulated depletion, depreciation, and amortization ............ (115,309) (94,356)
--------------- ---------------
595,366 487,824
--------------- ---------------
Other property and equipment ..................................... 3,623 3,680
Accumulated depreciation ......................................... (2,423) (1,917)
--------------- ---------------
1,200 1,763
--------------- ---------------
Other assets ....................................................... 11,658 10,844
--------------- ---------------
Total assets .............................................. $ 644,745 $ 549,896
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ................................................. $ 6,365 $ 9,650
Derivative liabilities ........................................... 3,599 8,558
Other current liabilities ........................................ 24,861 18,768
--------------- ---------------
Total current liabilities ................................. 34,825 36,976
--------------- ---------------
Long-term debt ..................................................... 181,000 166,000
Deferred income taxes .............................................. 73,412 47,656
Other non-current liabilities ...................................... 6,158 2,998
--------------- ---------------
Total liabilities ......................................... 295,395 253,630
--------------- ---------------
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,
30,275,113 and 30,162,955 issued and outstanding ............... 303 302
Additional paid-in capital ....................................... 252,823 251,231
Deferred compensation ............................................ (1,877) (2,396)
Retained earnings ................................................ 101,703 53,724
Accumulated other comprehensive income ........................... (3,602) (6,595)
--------------- ---------------
Total stockholders' equity ................................ 349,350 296,266
--------------- ---------------
Total liabilities and stockholders' equity ................ $ 644,745 $ 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Revenues:
Oil ...................................................... $ 44,538 $ 37,127 $ 131,674 $ 95,496
Natural gas .............................................. 11,186 6,375 31,080 18,110
--------- --------- --------- ---------
Total revenues ............................................. 55,724 43,502 162,754 113,606
Expenses:
Production --
Lease operations ...................................... 9,795 8,358 27,888 21,742
Production, ad valorem, and severance taxes ........... 5,449 4,521 16,713 11,080
General and administrative (excluding non-cash stock
based compensation) ................................... 2,006 1,585 6,796 4,462
Non-cash stock based compensation ........................ 165 -- 460 --
Depletion, depreciation, and amortization ................ 8,471 9,033 23,957 26,365
Derivative fair value (gain) loss ........................ 18 (232) (1,818) (911)
Other operating .......................................... 1,031 448 1,913 1,198
--------- --------- --------- ---------
Total expenses ............................................. 26,935 23,713 75,909 63,936
--------- --------- --------- ---------
Operating income ........................................... 28,789 19,789 86,845 49,670
--------- --------- --------- ---------
Other income (expenses):
Interest ................................................. (4,016) (4,122) (12,226) (7,836)
Other .................................................... 82 (35) 168 (15)
--------- --------- --------- ---------
Total other income (expenses) .............................. (3,934) (4,157) (12,058) (7,851)
--------- --------- --------- ---------
Income before income taxes and cumulative effect of
accounting change ........................................ 24,855 15,632 74,787 41,819
Current income tax benefit (provision) ..................... (289) 1,610 (1,647) 1,150
Deferred income tax provision .............................. (8,798) (7,129) (26,024) (16,620)
--------- --------- --------- ---------
Income before cumulative effect of accounting change ....... 15,768 10,113 47,116 26,349
Cumulative effect of accounting change, net of income
taxes of $529 ............................................ -- -- 863 --
--------- --------- --------- ---------
Net income ................................................. $ 15,768 $ 10,113 $ 47,979 $ 26,349
========= ========= ========= =========
Income before cumulative effect of accounting change per
common share:
Basic .................................................... $ 0.52 $ 0.34 $ 1.57 $ 0.88
Diluted .................................................. 0.52 0.33 1.56 0.87
Net income per common share:
Basic .................................................... $ 0.52 $ 0.34 $ 1.60 $ 0.88
Diluted .................................................. 0.52 0.33 1.58 0.87
Weighted average common shares outstanding:
Basic .................................................... 30,103 30,030 30,071 30,030
Diluted .................................................. 30,332 30,208 30,274 30,148
The accompanying notes are an integral part of these consolidated
financial statements.
4
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SEPTEMBER 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 ............ 1 1,651 -- -- -- 1,652
Deferred compensation:
Amortization of expense ........... -- -- 460 -- -- 460
Other changes ..................... -- (59) 59 -- -- --
Components of comprehensive income:
Net income ........................ -- -- -- 47,979 -- 47,979
Change in deferred hedge gain,
net of income taxes of $1,834 ... -- -- -- -- 2,993 2,993
------------
Total comprehensive income .. 50,972
------------ ------------ ------------ ------------ ------------ ------------
Balance at September 30, 2003 ........ $ 303 $ 252,823 $ (1,877) $ 101,703 $ (3,602) $ 349,350
============ ============ ============ ============ ============ ============
The accompanying notes are an integral part of these consolidated
financial statements.
5
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------------------
2003 2002
--------------- ---------------
Operating activities
Net income ................................................ $ 47,979 $ 26,349
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation, and amortization ............... 23,957 26,365
Deferred taxes .......................................... 26,179 16,620
Non-cash stock based compensation ....................... 460 --
Cumulative effect of accounting change .................. (863) --
Non-cash derivative mark-to-market ...................... (874) (1,302)
Other non-cash items .................................... 4,987 (257)
Loss on disposition of assets ........................... 362 253
Changes in operating assets and liabilities:
Accounts receivable ..................................... (853) (7,312)
Other current assets .................................... (1,752) (6,455)
Other assets ............................................ (2,662) 2,578
Accounts payable and other current liabilities .......... (2,114) (337)
--------------- ---------------
Cash provided by operating activities ...................... 94,806 56,502
Investing activities
Proceeds from disposition of assets ....................... 1,144 421
Purchases of other property and equipment ................. (444) (578)
Acquisition of oil and natural gas properties ............. (52,900) (76,954)
Development of oil and natural gas properties ............. (71,662) (58,014)
--------------- ---------------
Cash used by investing activities ........................... (123,862) (135,125)
Financing activities
Proceeds from long-term debt .............................. 77,500 142,000
Payments on long-term debt ................................ (62,500) (204,000)
Proceeds from issuance of 8 3/8% notes .................... -- 150,000
Payments for debt issuance costs .......................... -- (5,884)
Payments on note payable .................................. -- (1,107)
Exercise of stock options ................................. 1,652 51
--------------- ---------------
Cash provided by financing activities ....................... 16,652 81,060
Increase (decrease) in cash and cash equivalents ............ (12,404) 2,437
Cash and cash equivalents, beginning of period .............. 13,057 115
--------------- ---------------
Cash and cash equivalents, end of period .................... $ 653 $ 2,552
=============== ===============
The accompanying notes are an integral part of these consolidated
financial statements.
6
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 September 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, the Paradox Basin of Utah, and the
North Louisiana Salt Basin.
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 September 30, 2003 and results of operations
for the three and nine months ended September 30, 2003 and 2002, and cash flows
for the nine months ended September 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------- ---------- ---------- ----------
2003 2002 2003 2002
---------- ---------- ---------- ----------
As Reported:
Net income ..................................... $ 15,768 $ 10,113 $ 47,979 $ 26,349
Basic net income per common share .............. 0.52 0.34 1.60 0.88
Diluted net income per common share ............ 0.52 0.33 1.58 0.87
Non-cash stock based compensation, net of tax .. 102 -- 285 --
Pro Forma:
Net income ..................................... $ 15,354 $ 9,776 $ 46,805 $ 25,354
Basic net income per common share .............. 0.51 0.33 1.56 0.84
Diluted net income per common share ............ 0.51 0.32 1.55 0.84
Non-cash stock based compensation, net of tax .. 516 337 1,459 995
Currently, the Emerging Issues Task Force 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.
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
7
production method in a manner consistent with the method currently used to
calculate depletion, depreciation, and amortization expense ("DD&A") on these
assets.
At September 30, 2003, the Company had $1.0 million of undeveloped leasehold
costs and $302.4 million of developed leasehold costs (net of accumulated
depletion) that would be reclassified as "Intangible developed and undeveloped
leasehold costs" if the Company were to apply the interpretation as currently
discussed.
3. NEW ACCOUNTING STANDARDS
In August 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS 143, "Accounting for Asset Retirement Obligations", which the Company
adopted as of January 1, 2003. This statement requires that we now record a
liability in the period in which we incur an asset retirement obligation, in an
amount equal to the discounted estimated fair value of the obligation. Also,
upon initial recognition of the liability, we must capitalize an equal amount of
asset cost. Thereafter, each quarter, this liability is accreted and, if needed,
adjusted up to the final cost. Accretion expense is included in 'Other
operating' expense in the Company's Consolidated Statements of Operations.
The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect
of accounting change 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, (iii) a $5.2 million
increase in non-current liabilities, and (iv) a gain of $0.9 million, net of
tax.
The following table shows net income and basic and diluted net income per
common 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 common share
amounts):
NINE MONTHS ENDED
SEPTEMBER 30,
---------------------------
2003 2002
---------- ----------
As Reported:
Net income ................................ $ 47,979 $ 26,349
Basic net income per common share ......... 1.60 0.88
Diluted net income per common share ....... 1.58 0.87
Pro Forma:
Net income ................................ $ 47,116 $ 26,649
Basic net income per common share ......... 1.57 0.89
Diluted net income per common share ....... 1.56 0.88
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 September 30, 2003, the Company had $2.7 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 recorded in 'Other non-current liabilities' on the Company's
Consolidated Balance Sheet from the liability initially recorded upon adoption
of SFAS 143 on January 1, 2003 through September 30, 2003 (in thousands):
NINE MONTHS
ENDED
SEPTEMBER 30,
2003
---------------
Future abandonment liability at January 1, 2003 .. $ 4,791
Acquisition of Elm Grove properties ............ 337
Accretion expense .............................. 200
Other .......................................... 27
---------------
Future abandonment liability at September 30, 2003 $ 5,355
===============
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 'Other
operating' expense in the Consolidated Statements of Operations for
8
the nine months ended September 30, 2002. Additionally, the extraordinary loss
on extinguishment of debt has been reclassified in the Consolidated Statement of
Cash Flows for the nine months ended September 30, 2002 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 nine months ended September 30, 2003 and 2002 (in thousands, except
per share data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
NUMERATOR:
Income before cumulative effect of accounting change ........... $ 15,768 $ 10,113 $ 47,116 $ 26,349
========== ========== ========== ==========
Net income ..................................................... $ 15,768 $ 10,113 $ 47,979 $ 26,349
========== ========== ========== ==========
DENOMINATOR:
Denominator for basic earnings per share --
weighted average shares outstanding .......................... 30,103 30,030 30,071 30,030
Effect of dilutive securities .................................. 229 178 203 118
---------- ---------- ---------- ----------
Denominator for diluted earnings per share ..................... 30,332 30,208 30,274 30,148
========== ========== ========== ==========
BASIC PER COMMON SHARE:
Income before cumulative effect of accounting change ........... $ 0.52 $ 0.34 $ 1.57 $ 0.88
Cumulative effect of accounting change, net of income taxes .... -- -- 0.03 --
---------- ---------- ---------- ----------
Net income ..................................................... $ 0.52 $ 0.34 $ 1.60 $ 0.88
========== ========== ========== ==========
DILUTED PER COMMON SHARE:
Income before cumulative effect of accounting change ........... $ 0.52 $ 0.33 $ 1.56 $ 0.87
Cumulative effect of accounting change, net of income taxes .... -- -- 0.02 --
---------- ---------- ---------- ----------
Net income ..................................................... $ 0.52 $ 0.33 $ 1.58 $ 0.87
========== ========== ========== ==========
For the nine months ended September 30, 2003, 122,001 shares of stock was
issued upon exercise of employee stock options granted under the Company's 2000
Incentive Stock Plan at a weighted average strike price of $13.54 per share.
Additionally, 9,843 shares of restricted stock, which were issued and
outstanding at December 31, 2002, were forfeited during the first nine months of
2003.
5. DERIVATIVE FINANCIAL INSTRUMENTS
We record derivative fair value gains and losses for our basis swaps that
are not designated for hedge accounting and ineffectiveness of our commodity
futures contracts under hedge accounting. As our interest rate swap does not
qualify for hedge accounting, it is also marked to market through 'Derivative
fair value (gain) loss' on the Consolidated Statements of Operations each
period.
The following tables summarize our open commodity hedging positions as of
September 30, 2003:
OIL HEDGES AT SEPTEMBER 30, 2003
DAILY FLOOR DAILY CAP DAILY SWAP
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE
PERIOD (BBLS) (PER Bbl) (BBLS) (PER Bbl) (BBLS) (PER Bbl)
-------------------- ------------ ---------- ---------- ---------- ----------- ----------
Oct - Dec 2003 ..... 9,500 $ 21.05 7,000 $ 27.14 -- $ --
Jan - June 2004 .... 11,000 22.16 7,000 29.06 500 26.48
July - Dec 2004 .... 7,000 22.36 5,000 28.33 500 26.48
Jan - Dec 2005 ..... -- -- -- -- 1,000 25.12
Jan - Dec 2006 ..... -- -- -- -- 2,000 25.03
Jan - Dec 2007 ..... -- -- -- -- 2,000 25.11
In order to more effectively hedge the cash flows received on our oil
production, the Company enters into financial instruments whereby we swap
certain per Bbl floating market indices for a fixed dollar amount. These market
indices are a component of the price the Company is paid on its actual
production and by fixing this component of our marketing price, we are able to
realize a net price with a more consistent differential to NYMEX. Since NYMEX is
the basis of all our derivative oil hedging contracts, a more
9
consistent differential results in a more effective hedge. However, due to
limitations on timing, complexity, and volume differences, we do not use hedge
accounting for these contracts. Instead, we mark these contracts to market each
quarter through 'Derivative fair value (gain) loss' in the Consolidated
Statements of Operations. Thus, as these contracts do not change the Company's
overall hedged volumes, average prices presented in the table above are
exclusive of any effect of these instruments. As of September 30, 2003, the
mark-to-market value of these contracts is $0.1 million. In addition, the
Company has one short oil put contract in place at September 30, 2003 covering
500 Bbls per day through December 31, 2003 at a strike price of $17.00. This
contract also does not qualify for hedge accounting and thus is not included in
the table above. This contract is also marked to market through earnings each
quarter. The value of this contract at September 30, 2003 was less than one
hundred dollars.
NATURAL GAS HEDGES AT SEPTEMBER 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)
-------------------- ------------ ---------- ---------- ---------- ----------- ----------
Oct - Dec 2003 ..... 7,500 $ 3.17 2,500 $ 6.83 7,500 $ 4.80
Jan - Dec 2004 ..... 15,000 4.01 7,500 6.02 5,000 5.01
Jan - Dec 2005 ..... -- -- -- -- 5,000 4.63
In order to more effectively hedge the cash flows received on our natural gas
production, the Company uses basis swaps to better correlate some NYMEX based
natural gas hedging contracts to different underlying price points. These basis
swaps are combined with a floor, collar, or swap contract and are treated as
hedges in combination. As these basis swap contracts do not change the Company's
overall hedged volumes and are only designed to increase the effectiveness of
another natural gas hedging contracts, they have not been presented separately.
However, the average prices indicated above have been adjusted to reflect the
effect of these contracts on the strike price of the underlying NYMEX based
hedge.
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 $1.6 million in the
first nine months of 2003 through amortization of this unrealized loss from
other comprehensive income.
The following table summarizes the Company's only remaining interest rate
swap contract at September 30, 2003:
ENCORE
CONTRACT EXPIRATION NOTIONAL AMOUNT ENCORE PAYS RECEIVES
------------------- --------------- ----------- --------
June 2005 $80,000,000 LIBOR + 3.89% 8.375%
This contract does not qualify for hedge accounting and thus, the changes in
its fair market value are recorded in 'Derivative fair value (gain) loss' on the
Consolidated Statements of Operations. During the quarter ended September 30,
2003, a loss of $0.1 million related to the interest rate swap was recorded in
the Consolidated Statement of Operations.
The actual gains or losses we realize from our derivative transactions may
vary significantly from the deferred loss amount recorded in equity at September
30, 2003 due to fluctuation of prices in the commodities markets and/or
fluctuations in the floating LIBOR interest rate.
6. COMPREHENSIVE INCOME
For the nine months ended September 30, 2003, we had total comprehensive
income of $51.0 million, while net income totaled $48.0 million. The difference
between net income and total comprehensive income is a $3.0 million change in
our deferred hedging gain/loss in 'Accumulated other comprehensive income' from
$6.6 million at December 31, 2002 to $3.6 million at September 30, 2003. For the
nine months ended September 30, 2002, we had a total comprehensive income of
$14.5 million, while net income totaled $26.3 million. The difference between
net income and total comprehensive income is due to a $11.8 million change in
deferred hedging gain/loss.
10
For the three months ended September 30, 2003, we had total comprehensive
income of $19.1 million, while net income totaled $15.8 million. The difference
between net income and total comprehensive income is due to a $3.3 million
change in our deferred hedging loss in 'Accumulated other comprehensive income'
from a deferred loss of $6.9 million at June 30, 2003 to a deferred loss of $3.6
million at September 30, 2003. For the three months ended September 30, 2002, we
had a total comprehensive income of $7.7 million, while net income totaled $10.1
million. The difference between net income and total comprehensive income is a
$2.4 million increase in our deferred hedging loss.
7. FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS
As of September 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 North Louisiana (the "Elm Grove" acquisition) 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. Beginning August 1, 2003,
revenues and expenses from these properties have been included in the Company's
Consolidated Statements of Operations and drilling costs have been included in
'Development of oil and natural gas properties' in the Consolidated Statement of
Cash Flows. From June 1, 2003 to July 31, 2003, revenues, expenses, and
development capital of the properties were treated as adjustments to the
purchase price. 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. As of July 31, 2003, the Company's
internal engineers estimated total proved reserves for the Elm Grove acquisition
to be 6.2 MMBOE.
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, 2002 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- ---------------------
INCREASE / INCREASE /
2003 2002 (DECREASE) 2003 2002 (DECREASE)
--------- --------- ---------- --------- --------- ----------
Operating Results (in thousands):
Oil and natural gas revenues .................... $ 55,724 $ 43,502 $ 12,222 $ 162,754 $ 113,606 $ 49,148
Lease operations expense ........................ 9,795 8,358 1,437 27,888 21,742 6,146
Production, ad valorem, and severance taxes ..... 5,449 4,521 928 16,713 11,080 5,633
Daily sales volumes:
Oil (Bbls) ...................................... 18,255 16,783 1,472 18,172 16,004 2,168
Natural gas (Mcf) ............................... 26,447 21,913 4,534 23,278 22,714 564
Combined (BOE) .................................. 22,663 20,435 2,228 22,052 19,789 2,263
Average prices:
Oil (per Bbl) ................................... $ 26.52 $ 24.05 $ 2.47 $ 26.54 $ 21.86 $ 4.68
Natural gas (per Mcf) ........................... 4.60 3.16 1.44 4.89 2.92 1.97
Combined (per BOE) .............................. 26.73 23.14 3.59 27.04 21.03 6.01
Selected operating expenses per BOE:
Lease operations ................................ $ 4.70 $ 4.45 $ 0.25 $ 4.63 $ 4.02 $ 0.61
Production, ad valorem, and severance taxes ..... 2.61 2.40 0.21 2.78 2.05 0.73
G&A (excluding non-cash stock based
compensation)................................... 0.96 0.84 0.12 1.13 0.83 0.30
DD&A ............................................ 4.06 4.80 (0.74) 3.98 4.88 (0.90)
12
COMPARISON OF QUARTER ENDED SEPTEMBER 30, 2003 TO QUARTER ENDED SEPTEMBER 30,
2002
Set forth below is our comparison of operations during the third
quarter of 2003 with the third quarter of 2002.
REVENUES AND SALES VOLUMES. Oil and natural gas revenues of Encore for
the third quarter of 2003 increased as compared to the third quarter of 2002 by
$12.2 million, from $43.5 million to $55.7 million. The following table
illustrates the primary components of oil and natural gas revenue for the three
months ended September 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 SEPTEMBER 30,
------------------------------------------------- INCREASE /
2003 2002 (DECREASE)
--------------------- --------------------- ---------------------
REVENUES: Revenue $/Unit Revenue $/Unit Revenue $/Unit
-------- ------ -------- ------ -------- ------
Oil wellhead ................. $ 47,123 $28.07 $ 39,556 $25.62 $ 7,567 $ 2.45
Oil hedges ................... (2,685) (1.61) (3,135) (2.03) 450 0.42
Enron gain amortization ...... 100 0.06 706 0.46 (606) (0.40)
-------- ------ -------- ------ -------- ------
Oil Revenues ............ $ 44,538 $26.52 $ 37,127 $24.05 $ 7,411 $ 2.47
======== ====== ======== ====== ======== ======
Natural gas wellhead ......... $ 11,375 $ 4.68 $ 6,098 $ 3.02 $ 5,277 $ 1.66
Natural gas hedges ........... (193) (0.08) (121) (0.06) (72) (0.02)
Enron gain amortization ...... 4 -- 398 0.20 (394) (0.20)
-------- ------ -------- ------ -------- ------
Natural Gas Revenues .... $ 11,186 $ 4.60 $ 6,375 $ 3.16 $ 4,811 $ 1.44
======== ====== ======== ====== ======== ======
Average Average Average
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
------- --------- ----- --------- ------- ---------
Oil (Bbls) .......... 1,679 $ 30.20 1,544 $ 28.27 $ 135 $ 1.93
Natural Gas (Mcf) ... 2,433 4.89 2,016 3.21 417 1.68
Combined (BOE) ...... 2,085 1,880 205
Oil revenues increased from third quarter 2002 to third quarter 2003 by
$7.4 million, due to increased volumes and a higher realized average oil price.
Oil volumes for the quarter ended September 30, 2003 increased 135 MBbls due to
our successful development drilling program in Cedar Creek Anticline ("CCA") and
Central Permian properties, as well as the Paradox Basin acquisition, which was
completed in the third quarter of 2002. Our realized average oil price increased
$2.47 per Bbl in the third quarter of 2003 over the same period in 2002
primarily as a result of an increase in our average wellhead price. This
increase in our average wellhead price is in line with the increase in the
overall market price for oil as reflected in the $1.93 per Bbl increase in the
average NYMEX price over the same period. A decrease in hedging payments of $0.5
million ($0.42 per Bbl) from the third quarter of 2002 to the third quarter of
2003 was offset by a decrease in the Enron gain amortization of $0.6 million
($0.40 per Bbl) over the same period.
Natural gas revenues increased by $4.8 million, or $1.44 per Mcf, in
the third quarter of 2003 from the third quarter of 2002 due to an increase in
sales volumes and an increase in our realized average natural gas price. Sales
volumes increased 417 MMcf in the third quarter of 2003 as compared to the third
quarter of 2002 due to the Elm Grove acquisition which was completed during the
third quarter of 2003. The $1.44 increase in our realized average natural gas
price was primarily due to an increase of $1.66 per Mcf in the average wellhead
price received, partially offset by a $0.4 million decrease in the Enron gain
amortization. The increase in our average wellhead price received of $1.66 per
Mcf for the quarter is consistent with the increase in the overall market price
for natural gas, as reflected in the increase in the average NYMEX price of
$1.68 per Mcf over the same period.
LEASE OPERATIONS. Lease operations expense for the third quarter of
2003 increased as compared to the third quarter of 2002 by $1.4 million. The
increase is primarily attributable to increased sales volumes resulting from our
development drilling program, as well as inclusion of three months of production
from the Paradox Basin acquisition (September 2002) and two months of production
from the Elm Grove acquisition (August 2003). The slight increase in our average
per BOE rate was attributable to increased costs associated with the
high-pressure air injection ("HPAI") project in the CCA, the Paradox Basin
acquisition (September 2002), and increased artificial lift expenses associated
with production decline in our Lodgepole fields.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem,
and severance taxes for the third quarter of 2003 increased as compared to the
third quarter of 2002 by approximately $0.9 million. This increase was primarily
a result of higher revenues. As a percent of oil and natural gas revenues
(excluding the effects of hedges and the Enron Gain amortization), production,
ad valorem, and severance taxes for the third quarter of 2003 decreased when
compared to the third quarter of 2002, down to 9.3% from 9.9%. The
13
decrease is attributable to the addition of the Elm Grove properties added in
the third quarter of 2003, which have a lower rate as a percentage of oil and
natural gas revenues than our historical average. The effect of hedges and
amortization of the Enron Gain 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 third quarter of 2003 decreased by $0.6 million as compared to
the third quarter of 2002, due to a $0.74 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 at December 31, 2002 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, we began subtracting the estimated salvage value of our
equipment from the depreciable base in our DD&A calculation, thus lowering our
per BOE rate. Beginning in August 2003, we began including the financial results
of the Elm Grove acquisition in the Company's financial results. As the Elm
Grove acquisition has a higher per BOE DD&A rate than our historical average, we
expect our DD&A rate per BOE in future periods to be slightly higher than our
historical average as a result.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense (excluding
non-cash stock based compensation) increased $0.4 million for the third quarter
of 2003 as compared to the third quarter of 2002. The overall increase, as well
as the $0.12 increase in the per BOE rate, is a result of increased staffing
levels required to manage our growing asset base and increased outside
consulting services used in the evaluation of potential acquisitions. The
Company expenses third party related acquisition costs to G&A as incurred. If
and when the Company successfully closes on an acquisition, these costs are then
reclassified to producing properties as part of the acquisition's cost. In the
third quarter of 2003, the Company reclassified $0.4 million from G&A to proved
properties upon successful completion of the Elm Grove acquisition.
NON-CASH STOCK BASED COMPENSATION EXPENSE. No amount was recorded
during the three months ended September 30, 2002 related to non-cash stock based
compensation expense, while $0.2 million was recorded during the three months
ended September 30, 2003. This expense represents the amortization of deferred
compensation which is being amortized to expense over the vesting period of the
restricted stock granted at the end of 2002 under the 2000 Incentive Stock Plan.
OTHER OPERATING EXPENSE. Other operating expense for the third quarter
of 2003 increased by $0.2 million as compared to the third quarter of 2002. This
increase is attributable to higher third party transportation expenses in 2003;
inclusion of accretion expense on the Company's SFAS 143 future abandonment
liability, which totaled $0.1 million for the quarter (see Note 3 to the
accompanying financial statements); and the abandonment of $0.2 million in
undeveloped leasehold costs during the third quarter.
INTEREST EXPENSE. Interest expense decreased $0.1 million in the
quarter ended September 30, 2003 from the quarter ended September 30, 2002. The
decrease in interest expense is due to a decrease in the weighted average
interest rate partially offset by an increase in weighted average debt. The
weighted average interest rate, net of hedges, for the third quarter of 2003 was
9.0% compared to 10.3% for the third quarter of 2002. The following table
illustrates the components of interest expense for the three months ended
September 30, 2003 and 2002 (in thousands):
THREE MONTHS ENDED SEPTEMBER 30,
-------------------------------- INCREASE /
2003 2002 (DECREASE)
-------- -------- ----------
8 3/8% notes due 2012 ............. $ 3,141 $ 3,141 $ --
Revolving credit facility ......... 161 76 85
Interest rate hedges .............. 414(1) 806(1) (392)
Banking fees and other ............ 300 99 201
-------- -------- --------
Total ................... $ 4,016 $ 4,122 $ (106)
======== ======== ========
(1) Amount represents non-cash amortization of the unrealized loss from other
comprehensive income to interest expense. This unrealized loss relates to
previously outstanding interest rate swaps which no longer qualified for
hedge accounting. The Company has since cash settled these interest rate
swaps and the swaps are no longer outstanding. See Note 5 to the
accompanying financial statements.
14
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 2003 TO NINE MONTHS ENDED
SEPTEMBER 30, 2002
Set forth below is our comparison of operations during the first nine
months of 2003 with the first nine months of 2002.
REVENUES AND SALES VOLUMES. Oil and natural gas revenues of Encore for
the nine months ended September 30, 2003 increased as compared to 2002 by $49.1
million, from $113.6 million to $162.7 million. The following table illustrates
the primary components of oil and natural gas revenue for the nine months ended
September 30, 2003 and 2002, as well as each period's respective oil and natural
gas volumes (in thousands, except per unit amounts):
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------------------- INCREASE /
2003 2002 (DECREASE)
---------------------- --------------------- ---------------------
REVENUES: Revenue $/Unit Revenue $/Unit Revenue $/Unit
--------- ------ -------- ------ -------- ------
Oil wellhead ................. $ 142,599 $28.74 $ 99,217 $22.71 $ 43,382 $ 6.03
Oil hedges ................... (11,225) (2.26) (5,837) (1.33) (5,388) (0.93)
Enron gain amortization ...... 300 0.06 2,116 0.48 (1,816) (0.42)
--------- ------ -------- ------ -------- ------
Oil Revenues ............ $ 131,674 $26.54 $ 95,496 $21.86 $ 36,178 $ 4.68
========= ====== ======== ====== ======== ======
Natural gas wellhead ......... $ 32,728 $ 5.15 $ 16,910 $ 2.73 $ 15,818 $ 2.42
Natural gas hedges ........... (1,662) (0.26) 4 -- (1,666) (0.26)
Enron gain amortization ...... 14 -- 1,196 0.19 (1,182) (0.19)
--------- ------ -------- ------ -------- ------
Natural Gas Revenues .... $ 31,080 $ 4.89 $ 18,110 $ 2.92 $ 12,970 $ 1.97
========= ====== ======== ====== ======== ======
Average Average Average
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
------- --------- ------- --------- ------- ---------
Oil (Bbls) ............ 4,961 $ 30.99 4,369 $ 25.39 592 $ 5.60
Natural Gas (Mcf) ..... 6,355 5.51 6,201 3.03 154 2.48
Combined (BOE) ........ 6,020 5,403 617
Oil revenues increased $36.2 million for the nine months ended
September 30, 2003 as compared to the nine months ended September 30, 2002 due
to higher sales volumes and a higher realized average oil price. Oil volumes
increased 592 MBbls, resulting from our development drilling program in the CCA
and Permian Basin properties, as well as the Paradox Basin acquisition, which
closed in the third quarter of 2002. Our realized average oil price increased
$4.68 per Bbl due to a $6.03 per Bbl increase in the average wellhead price
received for the first nine months of 2003. However, this increase was partially
offset by a $5.4 million increase in hedging payments and a $1.8 million
decrease in the amortization of the Enron gain over the same period. The
increase in the average wellhead price during the first nine months of 2003 as
compared to the first nine months of 2002 resulted from an increase in the
overall market price of oil during the same period as reflected by an increase
in the average NYMEX oil price of $5.60 per Bbl from period to period.
Natural gas revenues increased by $13.0 million in the first nine
months of 2003 as compared to the first nine months of 2002 due to an increase
in our realized average natural gas price and higher volumes. Natural gas
volumes increased 154 MMcf, primarily resulting from the Elm Grove acquisition,
which closed in the third quarter of 2003. The increase in our realized average
natural gas price is due to a higher average wellhead price of $2.42 per Mcf,
partially offset by a $1.7 million increase in hedging payments and a $1.2
million decrease in the Enron gain amortization from period to period. The
increase from the nine months ended September 30, 2002 to the nine months ended
September 30, 2003 in the average wellhead price received of $2.42 per Mcf is
consistent with the average NYMEX natural gas price increase of $2.48 per Mcf
over the same period. The increase in hedging payments over the periods was a
direct result of this increase in the average NYMEX price per Mcf.
LEASE OPERATIONS. Lease operations expense for the nine months ended
September 30, 2003 increased as compared to the first nine months of 2002 by
$6.1 million. The increase is primarily attributable to increased sales volumes
resulting from our development drilling program, as well as inclusion of nine
months of production from the Paradox Basin acquisition (September 2002), and
two months of production from the Elm Grove acquisition (August 2003). On a per
BOE basis, lease operations expense increased from $4.02 to $4.63 due to
increased costs associated with the HPAI project in the CCA, the Paradox Basin
acquisition (September 2002), and increased artificial lift expenses associated
with production decline in our Lodgepole fields.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem,
and severance taxes for the first nine months of 2003 increased as compared to
the first nine months of 2002 by approximately $5.6 million. This increase was a
result of higher revenues in the first nine 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 settlements and the Enron gain amortization), production, ad
valorem, and severance taxes remained constant, at
15
9.5% for both periods. The effect of hedges and the Enron gain amortization 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 nine months ended September 30, 2003 decreased by approximately
$2.4 million as compared to the nine months ended September 30, 2002 due to a
$0.90 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 at December 31, 2002 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, we began
subtracting the estimated salvage value of our equipment from the depreciable
base in our DD&A calculation, thus lowering our per BOE rate. Beginning in
August 2003, we began including the financial results of the Elm Grove
acquisition in the Company's financial results. As the Elm Grove acquisition has
a higher per BOE DD&A rate than our historical average, we expect our DD&A rate
per BOE in future periods to be slightly higher than our historical average as a
result.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense (excluding
non-cash stock based compensation) increased $2.3 million for the first nine
months of 2003 as compared to the first nine months of 2002. The increase in G&A
expense was a result of increased staffing levels used to manage our growing
asset base and outside consulting services used in the evaluation of potential
acquisitions. The Company expenses third party related acquisition costs to G&A
as incurred. Once the Company successfully closes on an acquisition, theses
costs are then reclassified to producing properties as part of the acquisition's
cost. In the nine months ended September 30, 2003, the Company reclassified $0.4
million from G&A to proved properties upon successful acquisition of the Elm
Grove Field.
NON-CASH STOCK BASED COMPENSATION EXPENSE. No amount was recorded
during the nine months ended September 30, 2002 related to non-cash stock based
compensation expense, while $0.5 million was recorded during the nine months
ended September 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, which is
being amortized to expense over the vesting period of the stock.
OTHER OPERATING EXPENSE. Other operating expense for the first nine
months of 2003 increased by $0.7 million as compared to the first nine months of
2002. This increase is attributable to higher third party transportation
expenses in 2003; inclusion of accretion expense on the Company's SFAS 143
future abandonment liability, which totaled $0.2 million for the first nine
months of 2003 (see Note 3 to the accompanying financial statements); and the
abandonment of $0.2 million in undeveloped leasehold costs during the third
quarter.
INTEREST EXPENSE. Interest expense for the nine months ended September
30, 2003 increased $4.4 million when compared to the nine months ended September
30, 2002 due primarily to an increase in our weighted average interest rate from
period to period, as well as an increase in weighted average debt. The weighted
average interest rate, net of hedges, for the first nine months of 2003 was 9.9%
compared to 7.6% for the first nine months 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 nine months of 2003, while the revolving credit facility with a
lower floating rate was the primary component in the first nine months of 2002.
In conjunction with the issuance of 8 3/8% notes in June 2002, the Company
entered into an interest rate swap, which swaps fixed rates to floating, with
the intent of lowering our effective interest payments. As this transaction does
not qualify for hedge accounting, changes in its fair market value, as well as
settlements, are not recorded in interest expense, but in 'Derivative fair value
gain' on the Consolidated Statements of Operations. During the nine months ended
September 30, 2003, a gain of $2.1 million related to this interest rate swap
was recorded in 'Derivative fair value gain'. See Note 5 to the accompanying
financial statements. The following table illustrates the components of interest
expense for the nine months ended September 30, 2003 and 2002 (in thousands):
NINE MONTHS ENDED SEPTEMBER 30,
------------------------------- INCREASE /
2003 2002 (DECREASE)
------- ------ ----------
8 3/8% notes due 2012 ........ $ 9,422 $3,347 $ 6,075
Revolving credit facility .... 278 2,141 (1,863)
Interest rate hedges ......... 1,612(1) 2,121 (509)
Banking fees and other ....... 914 227 687
------- ------ -------
Total .............. $12,226 $7,836 $ 4,390
======= ====== =======
(1) Amount represents non-cash amortization of the unrealized loss from other
comprehensive income to interest expense. This
16
unrealized loss relates to previously outstanding interest rate swaps
which no longer qualified for hedge accounting. The Company has since
cash settled these interest rate swaps and the swaps are no longer
outstanding. See Note 5 to the accompanying financial statements.
17
LIQUIDITY AND CAPITAL RESOURCES
Principal uses of capital have been for the acquisition and development
of oil and natural gas properties. As of September 30, 2003, our cash and cash
equivalents totaled $0.7 million. The Company's policy is to use any excess cash
not needed for day-to-day operations to pay down any amounts outstanding under
the revolving credit facility. As of September 30, 2002, our cash and cash
equivalents totaled $2.6 million. This excess cash was being held in reserve to
pay state production taxes. Because of timing of payments made for production
taxes, at September 30, 2003 no excess cash reserves were held for this purpose.
Cash Flow
During the nine months ended September 30, 2003, net cash provided by
operations was $94.8 million, an increase of $38.3 million compared to the nine
months ended September 30, 2002. This increase is primarily attributable to
higher oil and natural gas revenues in 2003, which as noted previously, is
primarily a result of increased prices and increased production volumes.
Cash used by investing activities decreased from $135.1 million to
$123.9 million over the same period, largely due to a decrease in the amount
invested in new acquisitions. Acquisition capital accounted for $77.0 million
during the first nine months of 2002 (primarily Central Permian and Paradox
Basin acquisitions), but only $52.9 million in 2003 (primarily Elm Grove
acquisition). Investing less in new acquisitions allowed the Company to increase
the amount of available capital used in the development of our existing asset
base. Cash invested in development of our oil and natural gas properties
increased to $71.7 million in the first nine months of 2003 as compared to $58.0
for the first nine months of 2002. We plan to invest an additional $25.5 million
for development of our oil and natural gas properties during the remainder of
2003. We anticipate funding the additional investment through cash flows from
operations.
Cash provided by financing activities was $16.7 million in the first
nine months of 2003, and $81.1 million in the first nine months of 2002. This
$64.4 million change was caused by a decrease in the cash used in investing
activities and an increase in operating cash flow. The significantly higher oil
and natural gas revenues in the first nine months of 2003 resulting from
increased production and an increase in prices allowed the Company to fund its
development drilling program using operating cash flow, while at the same time
providing enough cash flow to fund a portion of the Elm Grove acquisition, which
closed in the third quarter of 2003. During 2002, however, prices were such that
a portion of the cost of the Company's drilling program, as well as the Central
Permian and Paradox Basin acquisitions were funded with additional borrowings.
Capitalization
At September 30, 2003, Encore had total assets of $644.7 million. Total
capitalization was $530.4 million, of which 65.9% was represented by
stockholders' equity and 34.1% by long-term debt.
Debt Maturities
At September 30, 2003, the Company's long-term debt is comprised of
$150.0 million of 8 3/8% senior subordinated Notes due June 15, 2012 and $31.0
million outstanding under the revolving credit facility due June 25, 2006.
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 September 30, 2003, the amount available to us under our revolving
credit facility was $220.0 million. However, this amount has subsequently been
renegotiated and effective December 1, 2003 the amount available to us has been
increased to $270 million. As of September 30, 2003, $31.0 million is
outstanding under our revolving credit facility which matures on June 25, 2006.
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 Elm Grove acquisition during the
remainder of 2003 which are expected to be approximately $4.3 million. Due to
the timing of capital expenditures related to our HPAI project, the Company's
actual capital expenditures may be below budgeted levels for 2003. The remaining
capital costs not invested at the end of 2003 for HPAI are expected to be
invested during the first of 2004.
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
18
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.
In November 2003, the Board of Directors approved the Company's 2004
capital budget in the amount of $140.0 million. The $140.0 million budgeted
amount includes $104.8 million for development drilling projects, capital
workovers, field facilities, and leasehold costs. The remaining $46.0 million
budgeted capital consists of $34.3 million for HPAI and $0.9 million for other
property, plant, and equipment. The Company plans to fund its 2004 capital
budget using operating cash flow and its existing revolving credit facility.
The following table illustrates the Company's contractual obligations
outstanding at September 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
Revolving Credit Facility .... 31,000 -- -- 31,000 --
Operating Leases ............. 3,081 240 1,938 690 213
-------- ---- ------ ------- --------
Totals ....................... $184,081 $240 $1,938 $31,690 $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 nine months ended September 30, 2003 and 2002.
Average equivalent prices for the first nine months of 2003 and 2002 were
decreased by $2.08 and $0.46 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 September 30, 2003.......................... $26.52 $4.60 $26.73
Quarter ended September 30, 2002.......................... 24.05 3.16 23.14
Nine months ended September 30, 2003...................... 26.54 4.89 27.04
Nine months ended September 30, 2002...................... 21.86 2.92 21.03
AVERAGE WELLHEAD PRICE
Quarter ended September 30, 2003.......................... $28.07 $4.68 $28.06
Quarter ended September 30, 2002.......................... 25.62 3.02 24.28
Nine months ended September 30, 2003...................... 28.74 5.15 29.12
Nine months ended September 30, 2002...................... 22.71 2.73 21.49
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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
September 30, 2003 are discussed in Note 5 to the accompanying financial
statements. As of September 30, 2003, the fair value of our open commodity and
interest rate derivative contracts is $3.4 million.
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 September 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 September 30, 2003 that
has materially affected, or is reasonably likely to materially affect, our
internal controls over financial reporting.
20
PART II. OTHER INFORMATION
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 Exhibit 3.1 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 Exhibit 3.1 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)
99.1 Registration Rights Agreement (incorporated by reference to Exhibit 4.2
to the Company's Registration Statement on Form S-1, filed with the SEC
on October 6, 2002).
Reports on Form 8-K
The Company filed with the SEC the following reports on Form 8-K during
the quarter ended September 30, 2003:
On July 2, 2003, the Company filed a current report on Form 8-K
announcing agreement to acquire natural gas producing properties for
$52.2 million.
On July 10, 2003, the Company filed a current report on Form 8-K for the
purpose of conforming certain information included in the Form 8-K
filed on February 11, 2003 to Regulation G of the Securities Exchange
Commission (the "SEC") which amended Item 10 of Regulation S-K
concerning the use of non-GAAP financial measures.
On July 29, 2003, the Company filed a current report on Form 8-K
announcing second quarter 2003 results.
On July 31, 2003, the Company filed a current report on Form 8-K
announcing the completion of the previously announced acquisition of
interests in natural gas properties located in the Elm Grove Field in
Bossier Parish, Louisiana.
21
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: November 7, 2003 By: /s/ Morris B. Smith
---------------------------------
Morris B. Smith
Chief Financial Officer,
Treasurer, Executive Vice
President and Principal Financial
Officer
Date: November 7, 2003 By: /s/ Robert C. Reeves
---------------------------------
Robert C. Reeves
Vice President, Controller and
Principal Accounting Officer
22