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, 2002
or
/ / Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _______ to ________
Commission file number 1-16295
ENCORE ACQUISITION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 75-2759650
-------------------------------- -----------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
777 Main Street, Suite 1400, Fort Worth, Texas 76102
------------------------------------------------------------ --------
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (817) 877-9955
Not applicable
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes /x/ No / /
Number of shares of Common Stock outstanding as of November 13, 2002..30,033,627
ENCORE ACQUISITION COMPANY
INDEX
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2002 and
December 31, 2001............................................ 3
Consolidated Statements of Operations for the three and
nine months ended September 30, 2002 and 2001............ 4
Consolidated Statements of Stockholders' Equity for the nine
months ended September 30, 2002.............................. 5
Consolidated Statements of Cash Flows for the nine
months ended September 30, 2002 and 2001..................... 6
Notes to Consolidated Financial Statements...................... 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 12
Item 3. Quantitative and Qualitative Disclosure about Market
Risk............................................................ 19
Item 4. Controls and Procedures................................... 19
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.......................... 20
Signatures........................................................ 21
Certifications.................................................... 22
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------ ------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents .......................................... $ 2,552 $ 115
Accounts receivable (Net of allowance of $7.0 million) ............. 23,598 16,286
Deferred tax asset ................................................. 6,452 --
Derivative assets .................................................. 3,046 7,030
Other current assets ............................................... 9,686 5,117
------------ ------------
Total current assets ........................................ 45,334 28,548
------------ ------------
Properties and equipment, at cost -- successful efforts method:
Producing properties ............................................... 557,207 422,542
Undeveloped properties ............................................. 1,080 776
Accumulated depletion, depreciation and amortization ............... (86,363) (60,548)
------------ ------------
471,924 362,770
Other property and equipment ....................................... 3,304 3,001
Accumulated depletion, depreciation, and amortization .............. (1,705) (1,253)
------------ ------------
1,599 1,748
------------ ------------
Other assets ......................................................... 11,180 8,934
------------ ------------
Total assets ................................................ $ 530,037 $ 402,000
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ................................................... $ 7,647 $ 10,793
Derivative liabilities ............................................. 10,560 3,525
Current portion of note payable .................................... -- 1,107
Other current liabilities .......................................... 17,130 12,016
------------ ------------
Total current liabilities ................................... 35,337 27,441
------------ ------------
Derivative liabilities ............................................... 2,902 1,288
Long-term debt ....................................................... 166,000 78,000
Deferred income taxes ................................................ 41,943 25,969
------------ ------------
Total liabilities ........................................... 246,182 132,698
------------ ------------
Commitments and contingencies ........................................ -- --
Stockholders' equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized,
none issued and outstanding ...................................... -- --
Common stock, $.01 par value, 60,000,000 authorized,
30,033,627 and 30,029,961 issued and outstanding at
September 30, 2002 and December 31, 2001, respectively ........... 300 300
Additional paid-in capital ......................................... 248,837 248,786
Retained earnings .................................................. 42,388 16,039
Accumulated other comprehensive income (loss) ...................... (7,670) 4,177
------------ ------------
Total stockholders' equity .................................. 283,855 269,302
------------ ------------
Total liabilities and stockholders' equity .................. $ 530,037 $ 402,000
============ ============
The accompanying notes are an integral part of these consolidated
financial statements.
3
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Revenues:
Oil ......................................................... $ 37,127 $ 28,034 $ 95,496 $ 81,916
Natural gas ................................................. 6,375 6,505 18,110 23,452
------------ ------------ ------------ ------------
Total revenues ................................................ 43,502 34,539 113,606 105,368
Expenses:
Production --
Direct lifting costs ..................................... 8,358 6,323 21,742 18,744
Production, ad valorem, and severance taxes .............. 4,521 3,496 11,080 11,406
General and administrative (excluding non-cash stock
based compensation) ...................................... 1,585 1,282 4,462 3,804
Non-cash stock based compensation ........................... -- -- -- 9,587
Depletion, depreciation, and amortization ................... 9,033 8,107 26,365 23,495
Derivative fair value (gain) loss ........................... (232) 257 (911) 396
Other operating expense ..................................... 448 419 918 419
------------ ------------ ------------ ------------
Total expenses ................................................ 23,713 19,884 63,656 67,851
------------ ------------ ------------ ------------
Operating income .............................................. 19,789 14,655 49,950 37,517
------------ ------------ ------------ ------------
Other income (expenses):
Interest .................................................... (4,122) (1,152) (7,836) (4,865)
Other ....................................................... (35) 83 (15) 144
------------ ------------ ------------ ------------
Total other expenses .......................................... (4,157) (1,069) (7,851) (4,721)
------------ ------------ ------------ ------------
Income before income taxes .................................... 15,632 13,586 42,099 32,796
Current income tax benefit (provision) ........................ 1,610 (537) 1,150 (1,741)
Deferred income tax provision ................................. (7,129) (4,626) (16,726) (14,364)
------------ ------------ ------------ ------------
Income before accounting change and extraordinary loss ........ 10,113 8,423 26,523 16,691
Cumulative effect of accounting change, net of income taxes ... -- -- -- (884)
Extraordinary loss from early extinguishment of debt,
net of income taxes ......................................... -- -- (174) --
------------ ------------ ------------ ------------
Net income .................................................... $ 10,113 $ 8,423 $ 26,349 $ 15,807
============ ============ ============ ============
Income per common share before accounting change
and extraordinary loss:
Basic ....................................................... $ 0.34 $ 0.28 $ 0.88 $ 0.59
Diluted ..................................................... 0.33 0.28 0.88 0.59
Net income per common share:
Basic ....................................................... $ 0.34 $ 0.28 $ 0.88 $ 0.56
Diluted ..................................................... 0.33 0.28 0.87 0.56
Weighted average common shares outstanding:
Basic ....................................................... 30,030 30,030 30,030 28,275
Diluted ..................................................... 30,208 30,030 30,148 28,277
The accompanying notes are an integral part of these consolidated
financial statements.
4
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SEPTEMBER 30, 2002
(in thousands)
(unaudited)
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Stockholders'
Stock Capital Earnings Income (Loss) Equity
------------ ------------ ------------ ------------ ------------
Balance at December 31, 2001 ........... $ 300 $ 248,786 $ 16,039 $ 4,177 $ 269,302
Exercise of stock options .............. -- 51 -- -- 51
Components of comprehensive income:
Net income .......................... -- -- 26,349 -- 26,349
Change in deferred hedge
gain/(loss) (net of income
taxes of $6,958) .................. -- -- -- (11,847) (11,847)
------------
Total comprehensive income .... 14,502
------------ ------------ ------------ ------------ ------------
Balance at September 30, 2002 ......... $ 300 $ 248,837 $ 42,388 $ (7,670) $ 283,855
============ ============ ============ ============ ============
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,
-----------------------------
2002 2001
------------ ------------
Operating activities
Net income ...................................................... $ 26,349 $ 15,807
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation, and amortization ..................... 26,365 23,495
Deferred taxes ................................................ 16,620 13,607
Non-cash stock based compensation ............................. -- 9,587
Cumulative accounting change .................................. -- 884
Derivative fair value (gain) loss ............................. (1,302) 396
Extraordinary loss on early extinguishment of debt ............ 174 --
Other non-cash items .......................................... (431) 1,357
Loss on disposition of assets ................................. 253 33
Changes in operating assets and liabilities:
Accounts receivable ........................................... (7,312) 2,143
Other current assets .......................................... (6,455) (1,563)
Other assets .................................................. 2,578 143
Accounts payable and other current liabilities ................ (337) (3,227)
------------ ------------
Cash provided by operating activities .......................... 56,502 62,662
Investing activities
Proceeds from disposition of assets ........................... 421 211
Purchases of other property and equipment ..................... (578) (885)
Acquisition of oil and natural gas properties ................. (76,954) (1,130)
Development of oil and natural gas properties ................. (58,014) (62,446)
------------ ------------
Cash used by investing activities ............................... (135,125) (64,250)
Financing activities
Proceeds from initial public offering ......................... -- 93,095
Offering costs paid ........................................... -- (1,568)
Proceeds from notes receivable - officers and employees ....... -- 21
Exercise of stock options ..................................... 51 --
Proceeds from long-term debt .................................. 142,000 115,000
Payments on long-term debt .................................... (204,000) (195,500)
Proceeds from issuance of 8 3/8% notes ........................ 150,000 --
Payments for debt issuance costs .............................. (5,884) --
Payments on note payable ...................................... (1,107) (12,951)
Increase in cash overdrafts ................................... -- 2,770
------------ ------------
Cash provided by financing activities ........................... 81,060 867
Increase (decrease) in Cash and Cash Equivalents ................ 2,437 (721)
Cash and Cash Equivalents, Beginning of Period .................. 115 876
------------ ------------
Cash and Cash Equivalents, End of Period ........................ $ 2,552 $ 155
============ ============
The accompanying notes are an integral part of these consolidated
financial statements.
6
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. FORMATION OF ENCORE
Encore Acquisition Company ("the Company"), a Delaware Corporation, is an
independent (non-integrated) oil and natural gas company in the United States.
We were organized in April 1998 and are engaged in the acquisition, development,
exploitation and production of North American oil and natural gas reserves. Our
oil and natural gas reserves are concentrated in fields located in the Williston
Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico,
the Anadarko Basin of Oklahoma and the Powder River Basin of Montana.
2. BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited consolidated
financial statements of the Company include all adjustments necessary to present
fairly our financial position as of September 30, 2002, results of operations
for the three and nine months ended September 30, 2002 and 2001, and cash flows
for the nine months ended September 30, 2002 and 2001. All adjustments are of a
recurring nature. These interim results are not necessarily indicative of
results for an entire year. Certain amounts of prior periods have been
reclassified in order to conform to the current period presentation.
Certain disclosures have been condensed or omitted from these consolidated
financial statements pursuant to the rules and regulations of the Securities and
Exchange Commission. Therefore, these financial statements should be read in
conjunction with the Company's 2001 consolidated financial statements and
related notes thereto included in the Company's Annual Report filed on Form
10-K.
In connection with a pending examination of our S-4 registration statement
filed under the Securities Act of 1933 to permit an exchange of new registered 8
3/8% notes that will be freely tradable for notes with identical terms that we
issued privately in June 2002, the Staff of the Division of Corporation Finance
of the SEC has questioned whether it would be more appropriate to allocate
reserve and production volumes to current and anticipated future net profits
interest ("NPI") payments and reduce our reported reserve and production data by
these amounts. We continue to believe that our method of reporting reserves and
production best conforms to economic reality and provides the most appropriate
method of reporting the NPIs, and we are engaged in continuing discussions with
the Staff regarding our position.
3. NEW ACCOUNTING STANDARDS
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143 ("SFAS 143"), "Accounting for Asset Retirement Obligations", which the
Company will be required to adopt as of January 1, 2003. This statement requires
us to record a liability in the period in which an asset retirement obligation
("ARO") is incurred, based upon the discounted estimated fair value of the
obligation. Also, upon initial recognition of the liability, we must capitalize
additional asset cost equal to the amount of the liability. In addition to any
obligations that arise after the effective date of SFAS 143, upon initial
adoption we must recognize (1) a liability for any existing AROs, (2)
capitalized cost related to the liability, and (3) accumulated depletion,
depreciation, and amortization on that capitalized cost. We are currently
reviewing the provisions of the statement and assessing their impact on our
financial statements. We do not currently know the effect, if any, the adoption
of SFAS 143 will have on our financial statements.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections".
Under Statement 4, all gains and losses from extinguishment of debt were
required to be aggregated and, if material, classified as an extraordinary item,
net of related income tax effect. This Statement eliminates Statement 4 and,
thus, the exception to applying Opinion 30 to all gains and losses related to
extinguishments of debt. As a result, gains and losses from extinguishment of
debt should be classified as extraordinary items only if they meet the criteria
in Opinion 30. Applying the provisions of Opinion 30 will distinguish
transactions that are part of an entity's recurring operations from those that
are unusual or infrequent or that meet the criteria for classification as an
extraordinary item. This statement is effective for Encore beginning January 1,
2003, at which time the extraordinary loss on extinguishment of debt recorded in
the second quarter of 2002 will be reclassified to operating income.
7
4. INDEBTEDNESS
The Company's overall indebtedness has increased by $86.9 million since
December 31, 2001. The additional borrowings were used to fund $77.0 million in
acquisitions, as well as pay $5.9 million in debt issuance costs associated with
the issuance of the 8 3/8% Senior Subordinated Notes and entering into the new
Revolving Credit Facility (See below), fund the development drilling program,
and fund the Company's initial high-pressure air injection project in the Cedar
Creek Anticline.
On June 25, 2002, the Company sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012 (the "Notes"). The offering was
made through a private placement pursuant to Rule 144A. Subsequently, the
Company filed a registration statement on Form S-4 on September 13, 2002 and
will use its best efforts to cause this statement to become effective by
December 7, 2002. Should we fail to cause the registration statement to become
effective by December 7, 2002, special interest will accrue in the amount of
$7,500 per week during the 90-day period immediately following December 7, 2002,
and shall increase by $7,500 per week at the end of each subsequent 90-day
period, up to a maximum amount of $45,000 per week. The additional interest
would cease to accrue once the registration statement is effective. The Company
received net proceeds of $145.6 million from the sale of the Notes, after
deducting debt issuance costs. The proceeds were used to repay and retire the
Company's prior credit facility ($143.0 million), to pay the fees and expenses
related to the new credit facility ($1.5 million), and to hold in reserve for
the Aneth acquisition ($1.1 million).
Concurrently with the Company's issuance of the Notes, the Company also
entered into a new Revolving Credit Facility on June 25, 2002. Borrowings under
the facility are secured by a first priority lien on the Company's proved oil
and natural gas reserves. Availability under the facility is determined through
semi-annual borrowing base determinations and may be increased or decreased. The
amount available under the new facility is $220.0 million, with $16.0 million
outstanding as of September 30, 2002. The maturity date of the new facility is
June 25, 2006.
Amounts outstanding under the facility are subject to varying rates of
interest based on the amount outstanding and the Company's borrowing base. Based
on our current $220.0 million borrowing base, our applicable interest rates
would be calculated as follows:
AMOUNT OUTSTANDING RATE
---------------------- --------------
$0 to $55,000,000......................................................................... LIBOR + 1.000%
$55,000,001 to $110,000,000............................................................... LIBOR + 1.125%
$110,000,001 to $165,000,000.............................................................. LIBOR + 1.250%
$165,000,001 to $198,000,000.............................................................. LIBOR + 1.500%
$198,000,001 to $220,000,000.............................................................. LIBOR + 1.750%
Additionally, under the new Revolving Credit Facility, the Company is
subject to certain affirmative, negative, and financial covenants. These include
limitations on incurrence of additional debt, restrictions on asset dispositions
and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and
maintenance of an EBITDA, as defined, to interest expense ratio of at least 2.5
to 1.0. As of September 30, 2002, the Company was in compliance with all
covenants.
5. EARNINGS PER SHARE ("EPS")
The following table sets forth basic and diluted EPS computations for the
three and nine months ended September 30, 2002 and 2001 (in thousands, except
per share data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
NUMERATOR:
Income before extraordinary item and accounting change ..... $ 10,113 $ 8,423 $ 26,523 $ 16,691
============ ============ ============ ============
Net income ................................................. $ 10,113 $ 8,423 $ 26,349 $ 15,807
============ ============ ============ ============
DENOMINATOR:
Denominator for basic earnings per share --
weighted average shares outstanding ...................... 30,030 30,030 30,030 28,275
Effect of dilutive securities:
Dilutive options ......................................... 178 -- 118 2
------------ ------------ ------------ ------------
Denominator for diluted earnings per share ................. 30,208 30,030 30,148 28,277
============ ============ ============ ============
8
BASIC PER COMMON SHARE:
Income before extraordinary item and accounting change .......... $ 0.34 $ 0.28 $ 0.88 $ 0.59
Cumulative effect of accounting change, net of income taxes ..... -- -- -- (0.03)
Extraordinary loss from early extinguishment of debt,
net of income taxes ........................................... -- -- -- --
------------ ------------ ------------ ------------
Net income ...................................................... $ 0.34 $ 0.28 $ 0.88 $ 0.56
============ ============ ============ ============
DILUTED PER COMMON SHARE:
Income before extraordinary item and accounting change .......... $ 0.33 $ 0.28 $ 0.88 $ 0.59
Cumulative effect of accounting change, net of income taxes ..... -- -- -- (0.03)
Extraordinary loss from early extinguishment of debt,
net of income taxes ........................................... -- -- (0.01) --
------------ ------------ ------------ ------------
Net income ...................................................... $ 0.33 $ 0.28 $ 0.87 $ 0.56
============ ============ ============ ============
6. DERIVATIVE FINANCIAL INSTRUMENTS
During the first nine months of 2002, current derivative assets decreased
$4.0 million and long-term derivative assets increased $2.0 million, while
current derivative liabilities increased $7.0 million and long-term derivative
liabilities increased $1.6 million. These changes resulted from an increase in
the futures price of oil and natural gas and a lower forward LIBOR curve.
Additionally, the Company entered into numerous additional oil and natural gas
hedges during the first three quarters of the year.
For the nine months ended September 30, 2002, we had 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 hedge gain/loss in accumulated other comprehensive income.
Due to an increase in the futures price of oil and natural gas and a lower
forward LIBOR curve, we went from a deferred hedge gain of $4.2 million, net of
tax, at December 31, 2001, to a deferred hedge loss of $7.7 million, net of tax,
at September 30, 2002. Exclusive of the Enron gain and interest rate swap loss
(See below), $6.0 million of the deferred loss in accumulated other
comprehensive income is related to current derivative assets and liabilities and
thus is expected to be recorded in earnings during the next twelve months as
these contracts settle.
At December 31, 2001, we had $4.8 million in gross unrecognized gains in
accumulated other comprehensive income related to the termination of hedging
contracts with Enron that are being amortized into earnings during 2002 and
2003. The following table illustrates the current and future amortization of
this amount to revenue (in thousands):
THREE MONTHS NATURAL
ENDED OIL GAS TOTAL
------------------------------------------------------- ----------- ----------- ------------
March 31, 2002 ........................................ $ 705 $ 399 $ 1,104
June 30, 2002 ......................................... 705 399 1,104
September 30, 2002 .................................... 706 398 1,104
December 31, 2002 ..................................... 706 398 1,104
March 31, 2003 ........................................ 100 5 105
June 30, 2003 ......................................... 100 5 105
September 30, 2003 .................................... 100 4 104
December 31, 2003 ..................................... 101 4 105
----------- ----------- ------------
Total ................................................. $ 3,223 $ 1,612 $ 4,835
=========== =========== ============
As previously discussed, in conjunction with the sale of the Notes, the
Company repaid all amounts outstanding under its 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. This resulted in an unrealized loss of $3.8 million through June 25,
2002, which was recognized in accumulated other comprehensive income and is
being amortized to interest expense over the original life of the swaps as
follows (in thousands):
YEAR 1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL
---------- ------------ ------------ ------------ ------------ ------------
2002 ..... $ -- $ (59) $ (806) $ (754) $ (1,619)
2003 ..... (654) (544) (414) (297) (1,909)
2004 ..... (212) (153) (109) (72) (546)
2005 ..... (40) 72 85 60 177
2006 ..... 22 24 29 33 108
2007 ..... 38 1 -- -- 39
------------
Total .... $ (3,750)
============
9
During the third quarter of 2002, the Company cash settled one of the three
interest rate swaps discussed above, resulting in an additional loss of $0.4
million, which was recognized in the 'Derivative fair value gain/loss' line in
the income statement.
In conjunction with the sale of the Notes (See Note 4), the Company entered
into an additional interest rate swap, whereby we pay LIBOR plus 3.89% and
receive a fixed 8 3/8% on a notional of $80 million through June 15, 2005. Due
to the difference in terms between the swap and the underlying debt, this
instrument does not qualify for hedge accounting and, along with future changes
in the fair value of the two remaining swaps discussed above, will be marked to
market through earnings each period in the 'Derivative fair value gain/loss'
line in the income statement.
During the third quarter, we expanded our commodity hedges in 2003 and 2004
for both oil and natural gas. The following tables summarize our open commodity
hedging positions as of September 30, 2002:
OIL HEDGES AT SEPTEMBER 30, 2002
DAILY AVG. DAILY AVG. DAILY AVG.
FLOOR VOLUME FLOOR PRICE CAP VOLUME CAP PRICE SWAP VOLUME SWAP PRICE
PERIOD (Bbl) (PER Bbl) (Bbl) (PER Bbl) (Bbl) (PER Bbl)
----------------------- ------------ ------------ ------------ ------------ ------------ ------------
Oct - Dec 2002 ........ 7,000 $ 22.96 4,500 $ 27.88 3,000 $ 20.15
Jan - June 2003 ....... 12,000 21.25 7,500 26.93 1,000 24.50
July - Dec 2003 ....... 9,500 21.05 7,000 27.14 -- --
Jan - June 2004 ....... 3,500 21.00 3,500 28.25 -- --
NATURAL GAS HEDGES AT SEPTEMBER 30, 2002
DAILY AVG. DAILY AVG. DAILY AVG.
FLOOR VOLUME FLOOR PRICE CAP VOLUME CAP PRICE SWAP VOLUME SWAP PRICE
PERIOD (Mcf) (PER Mcf) (Mcf) (PER Mcf) (Mcf) (PER Mcf)
----------------------- ------------ ------------ ------------ ------------ ------------ ------------
Oct - Dec 2002 ........ 5,000 $ 3.13 2,500 $ 8.05 5,000 $ 2.83
Jan - Dec 2003 ........ 5,000 3.13 -- -- 2,500 3.69
Additionally, as of September 30, 2002, we have basis swaps outstanding
covering 3,000 Bbls per day in 2003 and short oil put contracts in place
covering 1,500 Bbls per day in 2002 and 500 Bbls per day in 2003 at an average
strike price of $20 and $17, respectively. The short puts do not qualify for
hedge accounting. Accordingly, these contracts are marked to market through
earnings each period in the `Derivative fair value gain/loss' line in the income
statement.
7. INCOME TAXES
Excluding the tax effect of the extraordinary loss from early extinguishment
of debt, during the first nine months of 2002, Encore incurred $15.6 million in
income tax expense. Of this, $16.7 million is deferred income tax expense and
relates primarily to intangible drilling costs incurred during the year, which
are deductible for income tax purposes, but have been capitalized as Properties
and Equipment under generally accepted accounting principles. These amounts will
be depleted and transferred to earnings over the production life of the wells.
The deferred expense is partially offset by a current tax benefit of $1.2
million, mainly due to a $2.1 million refund of taxes paid during 2000 due to
the carryback of a 2001 tax loss. Additionally, the Company's current deferred
tax asset has increased to $6.4 million from approximately zero at December 31,
2001, due to the change in Accumulated Other Comprehensive Income related to the
mark-to-market change in the value of the Company's derivatives.
The Company's High-Pressure Air Injection project ("HPAI") in the Cedar
Creek Anticline ("CCA") has been certified as an enhanced oil recovery project
for federal income tax purposes. As a result, qualifying expenditures on the
project are eligible for a 15% tax credit. The effective tax rate for the nine
months ended September 30, 2002 has been revised downward to 37% from the 38%
rate used during the first six months of 2002 as a result of this 15% credit.
The entire nine month tax rate adjustment is reflected in the third quarter
lowering the effective tax rate for the quarter ended September 30, 2002 to
approximately 35%.
10
8. ACQUISITIONS
On January 4, 2002, we completed the acquisition of interests in oil and
natural gas properties in the Permian Basin for $50.1 million from Conoco. The
two principal operated properties are the East Cowden Grayburg and Fuhrman Nix
fields; the non-operated properties are primarily in the North Cowden and Yates
fields. Over 40 development wells have been identified, and a drilling program
was initiated in the third quarter of this year. The acquisition was funded by
additional borrowings under the Company's prior credit agreement.
On May 14, 2002, we completed the acquisition of additional working
interests in our operated properties in the East Cowden Grayburg field for $8.4
million. The acquisition was funded by additional borrowings under the Company's
prior credit agreement.
On August 29, 2002, we completed an acquisition of interests in oil and
natural gas properties in southeast Utah's Paradox Basin. The final purchase
price after the exercise of preferential rights was $17.9 million ($17.0 million
after closing adjustments). The properties are divided between two oil producing
units: the Ratherford Unit operated by ExxonMobil and the Aneth Unit operated by
ChevronTexaco. The acquisition was funded by the Company's prior and existing
credit agreements.
9. FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS
All of the Company's subsidiaries are currently subsidiary guarantors of the
Notes. Since (i) each subsidiary guarantor is 100% owned by the Company, (ii)
the Company has no assets or operations that are independent of its
subsidiaries, (iii) the subsidiary guarantees are full and unconditional and
joint and several and (iv) all of the Company's subsidiaries are subsidiary
guarantors, the Company has not included the financial statements of each
subsidiary in this report. The subsidiary guarantors may without restriction
transfer funds to the Company in the form of cash dividends, loans and advances.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This document contains forward-looking statements that involve risks and
uncertainties that are made pursuant to the Safe Harbor Provisions of the
Private Securities Litigation Reform Act of 1995. Actual results may differ
materially from those anticipated in our forward-looking statements due to many
factors, including, but not limited to, those set forth under "SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS" contained in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations, in
Encore's 2001 Annual Report filed on Form 10-K. The following discussion should
be read in conjunction with the consolidated financial statements and notes
thereto included in this document and Encore's 2001 Form 10-K. All volumetric
information and computations are presented without attributing volumes to the
financial net profits interests, unless otherwise indicated, and all production
volumes disclosed represent amounts net to Encore.
CRITICAL ACCOUNTING POLICIES
For a discussion of the Company's critical accounting policies, see the
Company's 2001 Annual Report filed on Form 10-K.
RESULTS OF OPERATIONS
The following table sets forth operating information for the periods
presented:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
INCREASE INCREASE
2002 2001 (DECREASE) 2002 2001 (DECREASE)
----------- ----------- ----------- ----------- ----------- -----------
Operating Results (in thousands):
Oil and natural gas revenues .................. $ 43,502 $ 34,539 $ 8,963 $ 113,606 $ 105,368 $ 8,238
Direct lifting costs .......................... 8,358 6,323 2,035 21,742 18,744 2,998
Production, ad valorem and severance taxes .... 4,521 3,496 1,025 11,080 11,406 (326)
Daily sales volumes:
Oil volumes (Bbls) ............................ 17,014 13,928 3,086 16,199 13,594 2,605
Natural gas volumes (Mcf) ..................... 21,972 22,451 (479) 22,761 21,948 813
Combined volumes (BOE) (1) .................... 20,676 17,670 3,006 19,992 17,252 2,740
Average prices:
Oil (per Bbl) ................................. $ 23.72 $ 21.88 $ 1.84 $ 21.59 $ 22.07 $ (0.48)
Natural gas (per Mcf) ......................... 3.15 3.15 -- 2.91 3.91 (1.00)
Combined volumes (per BOE) .................... 22.87 21.25 1.62 20.82 22.37 (1.55)
Average costs (per BOE):
Direct lifting costs .......................... $ 4.39 $ 3.89 $ 0.50 $ 3.98 $ 3.98 $ --
Production, ad valorem, and severance taxes ... 2.38 2.15 0.23 2.03 2.42 (0.39)
G&A (excluding non-cash stock based
compensation) ............................... 0.83 0.79 0.04 0.82 0.81 0.01
DD&A .......................................... 4.75 4.99 (0.24) 4.83 4.99 (0.16)
(1) In accordance with the specific provisions of our net profits interest
agreements, the Company does not allocate volumes to financial net profits
interest payments. If the Company allocated production volumes to the net
profits interests by computing the equivalent volume necessary to fund the
net profit interests payments, combined net daily sales volumes for the
three months ended September 30, 2002 and 2001 would have been 20,442 BOE
and 17,572 BOE, respectively and 19,792 BOE and 16,852 BOE, respectively,
for the nine months ended September 30, 2002 and 2001.
12
COMPARISON OF QUARTER ENDED SEPTEMBER 30, 2002 TO QUARTER ENDED SEPTEMBER 30,
2001
Set forth below is our comparison of operations during the third quarter of
2002 with the third quarter of 2001.
REVENUES AND SALES VOLUMES. The following table illustrates the primary
components of oil and natural gas revenue for the quarters ended September 30,
2002 and 2001, as well as each quarter's respective oil and natural gas volumes
(in thousands, except per unit amounts):
THREE MONTHS ENDED SEPTEMBER 30,
2002 2001 DIFFERENCE
------------------------ ------------------------ ------------------------
REVENUES: Revenue $/Unit Revenue $/Unit Revenue $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil wellhead ................. $ 40,082 $ 25.61 $ 30,807 $ 24.05 $ 9,275 $ 1.56
Net profits oil .............. (526) (0.34) (213) (0.17) (313) (0.17)
Oil hedges ................... (3,135) (2.00) (2,560) (2.00) (575) --
Enron hedges ................. 706 0.45 -- -- 706 0.45
---------- ---------- ---------- ---------- ---------- ----------
Total Oil Revenues ...... $ 37,127 $ 23.72 $ 28,034 $ 21.88 $ 9,093 $ 1.84
========== ========== ========== ========== ========== ==========
Natural gas wellhead ......... $ 6,107 $ 3.02 $ 6,300 $ 3.05 $ (193) $ (0.03)
Net profits gas .............. (9) -- (1) -- (8) --
Gas hedges ................... (121) (0.06) 206 0.10 (327) (0.16)
Enron hedges ................. 398 0.19 -- -- 398 0.19
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues ...... $ 6,375 $ 3.15 $ 6,505 $ 3.15 $ (130) $ --
========== ========== ========== ========== ========== ==========
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil (Bbls) ................... 1,565 $ 28.27 1,281 $ 26.57 284 $ 1.70
Gas (Mcf) .................... 2,021 3.21 2,065 2.80 (44) 0.41
Combined (BOE) (1) ........... 1,902 1,626 276
(1) In accordance with the specific provisions of our net profits interest
agreements, the Company does not allocate volumes to financial net profits
interest payments. If the Company allocated production volumes to the net
profits interests by computing the equivalent volume necessary to fund the
net profit interests payments, combined net sales volumes for the three
months ended September 30, 2002 and 2001 would have been 1,881 MBOE and
1,617 MBOE, respectively.
Total oil revenues increased from third quarter 2001 to third quarter 2002
due to increased volumes and higher wellhead prices. Oil volumes increased 284
MBbls due to our successful development drilling program and the acquisition of
the Central Permian and Paradox Basin properties. Wellhead oil revenues
increased $1.56 per Bbl primarily resulting from an increase in the overall
market price for oil as reflected in the $1.70 per Bbl increase in the average
NYMEX price over the same period. Payments made for net profits increased $0.3
million, reducing revenue by an additional $0.17 per Bbl for the third quarter
2002 compared to third quarter 2001. Hedging payments increased by $0.6 million
over the third quarter 2001, but the per Bbl effect remained a reduction of
$2.00 per Bbl. Amortization of $0.7 million of the Enron gain added $0.45 per
Bbl to the average price as compared to the same period in 2001. The increase in
net profits was primarily due to higher oil prices and lower capital
expenditures in the CCA in the third quarter of 2002 as compared to the third
quarter of 2001. The Company's hedging activities are not a component of the
expenses deducted in calculating net profits interest payments. The increase in
hedging payments is a result of the increase in the average NYMEX price for oil.
Total natural gas revenues decreased by $0.1 million due to the combination
of a slight decrease in the wellhead price per Mcf, relatively flat gas
production, and a $0.3 million change from a $0.2 million hedging receipt to a
$0.1 million hedging payment. These factors were partially offset by the $0.4
million amortization of the Enron gain. Hedging settlements changed due to
higher natural gas prices in the third quarter of 2002 compared with the third
quarter of 2001.
DIRECT LIFTING COSTS. Direct lifting costs of Encore for the third quarter
of 2002 increased as compared to the third quarter of 2001 by $2.1 million, from
$6.3 million to $8.4 million. The increase in direct lifting costs is partially
attributable to increased sales volumes attributable to our development drilling
program and Central Permian and Paradox Basin acquisitions in 2002.
Additionally, on a per BOE basis, direct lifting costs increased from $3.89 to
$4.39, primarily as a result of increased workover and maintenance costs over
the same period last year, due to the deferral of some costs from the first half
of 2002 until the current quarter.
13
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the third quarter of 2002 increased as compared to the third
quarter of 2001 by approximately $1.0 million. This increase was a result of
higher wellhead oil prices and increased volumes as a result of the Central
Permian and Paradox Basin acquisitions and development drilling. As a percent of
oil and natural gas wellhead revenues, production, ad valorem, and severance
taxes remained fairly constant, up to 9.8% from 9.4%.
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense for
the third quarter of 2002 increased by $0.9 million, reflecting the volumes
associated with our larger asset base resulting from the Central Permian and
Paradox Basin acquisitions and our continued development drilling program. The
average DD&A rate of $4.75 per BOE of production during the third quarter of
2002 represents a decrease of $0.24 per BOE from the $4.99 per BOE recorded in
the third quarter of 2001. The per BOE rate decrease was attributable to normal
production declines in the Lodgepole properties, which have relatively high DD&A
rates as compared to our other producing properties.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.3
million for the third quarter of 2002 as compared to the third quarter of 2001,
from $1.3 million to $1.6 million. The increase in G&A expense was a result of
the hiring of additional staff after the 2002 acquisitions to manage, expand,
and exploit our growing asset base.
OTHER OPERATING EXPENSE. Other operating expense remained constant at $0.4
million for both the third quarter of 2002 and the third quarter of 2001.
INTEREST EXPENSE. Interest expense for the quarter ended September 30, 2002
was $4.1 million compared to $1.2 million for the quarter ended September 30,
2001. The increase in interest expense is due to higher debt levels and a higher
weighted average interest rate. The weighted average interest rate, net of
hedges, for the third quarter of 2002 was 10.3% compared to 6.5% for the third
quarter of 2001. The weighted average debt level for the third quarter of 2002
was $158.3 million compared to $70.8 million for the third quarter of 2001.
Interest expense related to hedges for the three months ended September 30, 2002
reflected in the table below represents the amortization of a mark-to-market
loss on our interest rate hedges recorded in conjunction with the issuance of
the Notes in the second quarter of 2002 (See Note 6). The following table
illustrates the components of interest expense for the three months ended
September 30, 2002 and 2001 (in thousands):
THREE MONTHS ENDED SEPTEMBER 30,
2002 2001 DIFFERENCE
------------ ------------ ------------
Credit facility .............. $ 76 $ 760 $ (684)
8 3/8% notes due 2012 ........ 3,141 -- 3,141
Burlington note .............. -- 71 (71)
Interest rate hedges ......... 806 227 579
Banking fees ................. 99 94 5
------------ ------------ ------------
Total .............. $ 4,122 $ 1,152 $ 2,970
============ ============ ============
14
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 2002 TO NINE MONTHS ENDED
SEPTEMBER 30, 2001
Set forth below is our comparison of operations during the first nine months
of 2002 with the first nine months of 2001.
REVENUES AND SALES VOLUMES. The following table illustrates the primary
components of oil and natural gas revenue for the nine months ended September
30, 2002 and 2001, as well as each period's respective oil and natural gas
volumes (in thousands, except per unit amounts):
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001 DIFFERENCE
------------------------ ------------------------ ------------------------
REVENUES: Revenue $/Unit Revenue $/Unit Revenue $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil wellhead ................. $ 100,460 $ 22.72 $ 93,501 $ 25.20 $ 6,959 $ (2.48)
Net profits oil .............. (1,243) (0.28) (2,658) (0.72) 1,415 0.44
Oil hedges ................... (5,837) (1.33) (8,927) (2.41) 3,090 1.08
Enron hedges ................. 2,116 0.48 -- -- 2,116 0.48
---------- ---------- ---------- ---------- ---------- ----------
Total Oil Revenues ...... $ 95,496 $ 21.59 $ 81,916 $ 22.07 $ 13,580 $ (0.48)
========== ========== ========== ========== ========== ==========
Natural gas wellhead ......... $ 16,935 $ 2.73 $ 28,356 $ 4.73 $ (11,421) $ (2.00)
Net profits gas .............. (25) -- (102) (0.02) 77 0.02
Gas hedges ................... 4 -- (4,802) (0.80) 4,806 0.80
Enron hedges ................. 1,196 0.18 -- -- 1,196 0.18
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues ...... $ 18,110 $ 2.91 $ 23,452 $ 3.91 $ (5,342) $ (1.00)
========== ========== ========== ========== ========== ==========
Sales NYMEX Sales NYMEX Sales NYMEX
OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit
---------- ---------- ---------- ---------- ---------- ----------
Oil (Bbls) ................... 4,422 $ 25.39 3,711 $ 27.75 711 $ (2.36)
Gas (Mcf) .................... 6,214 3.03 5,992 4.50 222 (1.47)
Combined (BOE) (1) ........... 5,458 4,710 748
(1) In accordance with the specific provisions of our net profits interest
agreements, the Company does not allocate volumes to financial net profits
interest payments. If the Company allocated production volumes to the net
profits interests by computing the equivalent volume necessary to fund the
net profit interests payments, combined net sales volumes for the nine
months ended September 30, 2002 and 2001 would have been 5,403 MBOE and
4,601 MBOE, respectively.
Although the average wellhead oil price was down for the first nine months
of 2002, total oil revenue increased due to higher volumes, lower hedging
settlement payments, lower net profits payments, and amortization of the Enron
gain. Oil volumes increased 711 MBbls due to the Company's successful
development drilling program and the Central Permian and Paradox Basin
acquisitions. Wellhead oil revenues decreased $2.48 per Bbl primarily from a
decrease in the overall market price for oil as reflected in the $2.36 per Bbl
decrease in the average NYMEX price over the same period. The decrease in
wellhead price was offset by a decrease in payments made for net profits and
hedging loss, which decreased $1.4 million and $3.1 million, respectively, as
well as amortization of $2.1 million of the Enron gain. The decrease in net
profits was primarily due to lower wellhead prices and higher capital
expenditures in the CCA in 2002. The decrease in hedging payments is a result of
the decrease in the average NYMEX price for oil, as well as different contracts
being in place.
Natural gas revenues decreased by $5.3 million due to a decrease in the net
sales price per Mcf, partially offset by a 222 MMcf increase in sales volumes,
net hedging receipts in the first nine months of 2002 versus net hedging
payments in the first nine months of 2001, and amortization of $1.2 million of
the Enron gain. The increase in volumes is due to increased sales volumes in CCA
and Crockett County due to development drilling and from the Central Permian and
Paradox Basin acquisitions. Wellhead price received decreased $2.00 per Mcf,
consistent with the average NYMEX price decrease of $1.47 per Mcf from the nine
months ended September 30, 2001 to the nine months ended September 30, 2002,
while hedging payments decreased $0.80 per Mcf due to lower natural gas prices,
as well as different contracts being in place.
DIRECT LIFTING COSTS. Direct lifting costs for the first nine months of 2002
increased as compared to the first nine months of 2001 by $3.0 million, from
$18.7 million to $21.7 million due to increased sales volumes attributable to
our development drilling program and Central Permian and Paradox Basin
acquisitions in 2002. On a per BOE basis, direct lifting costs were $3.98 for
both periods.
PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and
severance taxes for the first nine months of 2002 decreased as compared to the
first nine months of 2001 by approximately $0.3 million. The decrease in
production, ad valorem, and severance taxes was a result of the lower commodity
prices in the first nine months of 2002 as compared to the same period of 2001.
15
As a percent of oil and natural gas revenues (excluding the effects of hedging
transactions), production, ad valorem, and severance taxes remained constant at
9.4%.
DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense for
the nine months ended September 30, 2002 increased by approximately $2.9
million, from $23.5 million to $26.4 million as compared to the nine months
ended September 30, 2001. The increase in DD&A was a result of increased sales
volumes in 2002, as well as a larger asset base associated with our 2002
acquisitions. The average DD&A rate of $4.83 per BOE of production during the
first nine months of 2002 represents a decrease of $0.16 per BOE from the $4.99
per BOE recorded in the first nine months of 2001. The decrease is attributable
to normal production declines in the Lodgepole properties, which have relatively
high DD&A rates as compared to our other producing properties.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.7
million for the first nine months of 2002 as compared to the first nine months
of 2001, from $3.8 million to $4.5 million (excluding non-cash stock based
compensation of $9.6 million in the first nine months of 2001). The increase in
G&A expense was a result of the hiring of additional staff after the 2002
acquisitions to manage, expand and exploit our growing asset base.
NON-CASH STOCK BASED COMPENSATION EXPENSE. Non-cash stock based compensation
expense decreased from $9.6 million in the first nine months of 2001 to zero in
the first nine months of 2002. This non-cash stock based compensation expense is
associated with the purchase by our management stockholders of Class A common
stock under our management stock plan adopted in August 1998. This amount
represents the vested portion of the shares purchased and is recorded as
compensation, calculated in accordance with variable plan accounting under APB
25. The amount recorded in the first nine months of 2001 represented the final
amount of expense to be recorded related to the Class A stock.
OTHER OPERATING EXPENSE. Other operating expense increased from $0.4 million
in the first nine months of 2001 to $0.9 million in the first nine months of
2002 as a result of increased transportation and geological and geophysical
expenses.
INTEREST EXPENSE. Interest expense for the nine months ended September 30,
2002 increased by $2.9 million, to $7.8 million from $4.9 million over the same
period in 2001, due to higher debt levels and an increase in the weighted
average interest rate. The weighted average interest rate, net of hedges, for
the first nine months of 2002 was 7.6% compared to 6.9% for the first nine
months of 2001. The weighted average debt level for the first nine months of
2002 was $137.7 million compared to $94.2 million for the first nine months of
2001. Interest expense related to hedges for the nine months ended September 30,
2002 includes three months of amortization of a mark-to-market loss recorded in
conjunction with the issuance of the Notes in the second quarter of 2002 (See
Note 6). The following table illustrates the components of interest expense for
the nine months ended September 30, 2002 and 2001 (in thousands):
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001 DIFFERENCE
------------ ------------ ------------
Credit facility .............. $ 2,141 $ 3,938 $ (1,797)
8 3/8% notes due 2012 ........ 3,347 -- 3,347
Burlington note .............. -- 333 (333)
Interest rate hedges ......... 2,121 342 1,779
Banking fees ................. 227 252 (25)
------------ ------------ ------------
Total .............. $ 7,836 $ 4,865 $ 2,971
============ ============ ============
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 nine months ended September 30, 2002, net cash provided by
operations was $56.5 million, a decrease of $6.2 million compared to the nine
months ended September 30, 2001. This decrease is primarily attributable to an
increase in accounts receivable resulting from higher oil production and higher
realized commodity prices in September 2002 versus December 2001. Cash used by
investing activities increased from $64.3 million to $135.1 million over the
same period, primarily due to the Central Permian and Paradox Basin
acquisitions. Cash provided by financing activities was $81.1 million in the
first nine months of 2002, as compared to cash provided by financing activities
of $0.9 million in the first nine months of 2001. The increase is primarily
attributable to borrowings used to fund the 2002 Central Permian and Paradox
Basin acquisitions.
Capitalization
At September 30, 2002, Encore had total assets of $530.0 million. Total
capitalization was $449.9 million, of which 63.1% was represented by
stockholders' equity and 36.9% by long-term indebtedness.
Debt Maturities
On June 25, 2002, the Company sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012. The offering was made through a
private placement pursuant to Rule 144A. Subsequently, in compliance with the
terms of the registration rights agreement dated June 19, 2002, the Company
filed a registration statement on Form S-4 on September 13, 2002 to register
notes to be issued in exchange for the private notes. We filed an amendment to
the registration statement on October 28, 2002. The amended registration
statement is currently being reviewed by the Staff of the SEC and is not yet
effective. The Company received net proceeds of $145.6 million from the sale of
the Notes, after deducting debt issuance costs. The proceeds were used to repay
and retire the Company's prior credit facility ($143.0 million), to pay the fees
and expenses related to the new credit facility ($1.5 million), and to hold in
reserve for the Aneth acquisition ($1.1 million).
Revolving Credit Facility
Concurrently with the Company's issuance of the Notes, the Company also
entered into a new Revolving Credit Facility (the "Facility"), effective June
25, 2002. Borrowings under the Facility are secured by a first priority lien on
the Company's proved oil and natural gas reserves. Availability under the
facility will be determined through semi-annual borrowing base determinations
and may be increased or decreased. The amount currently available under the
Facility is $220.0 million, with $16.0 million outstanding at September 30,
2002. Our availability under the Facility is further reduced by the amount of
any outstanding letters of credit (See below). The maturity date of the new
facility is June 25, 2006.
Letters of Credit
The Company has two standby letters of credit outstanding at September 30,
2002. These letters, which secure potential future settlements under certain
outstanding hedging contracts, total $4.8 million and expire on January 1, 2003.
Future Capital Requirements
We anticipate that our capital expenditures will total approximately $26
million for the fourth quarter of 2002. This reflects a $5 million increase
above the original budget due to additional expenditures for non-operated
drilling, and facility costs. The level of these and other future expenditures
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 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, such as
our high-pressure air injection tertiary recovery project in the CCA, to
increase our reserve base. Substantially all of these expenditures are
discretionary and will be undertaken only if funds are available and the
projected rates of return are satisfactory. Future cash flows are subject to a
number of variables, including the level of oil and natural gas sales volumes
and prices. Operations and other capital resources may not provide cash in
sufficient amounts to maintain planned levels of capital expenditures.
17
INFLATION AND CHANGES IN PRICES
While the general level of inflation affects certain of our costs, factors
unique to the petroleum industry result in independent price fluctuations.
Historically, significant fluctuations have occurred in oil and natural gas
prices. In addition, changing prices often cause costs of equipment and supplies
to vary as industry activity levels increase and decrease to reflect perceptions
of future price levels. Although it is difficult to estimate future prices of
oil and natural gas, price fluctuations have had, and will continue to have, a
material effect on us.
The following table indicates the average oil and natural gas prices
received for the three and nine months ended September 30, 2002 and 2001.
Average equivalent prices for the first nine months of 2002 and 2001 were
decreased by $1.07 and $2.92 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. Average
prices shown in the following table are net of net profits interests. All prices
are before amortization of the Enron-related gain.
OIL NATURAL GAS EQUIV. OIL
(PER Bbl) (PER Mcf) (PER BOE)
------------ ------------ ------------
NET PRICE REALIZATION WITH HEDGES
Quarter ended September 30, 2002 ....... $ 23.27 $ 2.96 $ 22.29
Quarter ended September 30, 2001 ....... 21.88 3.15 21.25
Nine months ended September 30,
2002 ................................. 21.11 2.73 20.21
Nine months ended September 30,
2001 ................................. 22.07 3.91 22.37
AVERAGE WELLHEAD PRICE
Quarter ended September 30, 2002 ....... $ 25.27 $ 3.02 $ 24.00
Quarter ended September 30, 2001 ....... 23.87 3.05 22.70
Nine months ended September 30,
2002 ................................. 22.44 2.73 21.28
Nine months ended September 30,
2001 ................................. 24.47 4.71 25.29
18
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information included in "Quantitative and Qualitative Disclosures About
Market Risk" in Encore's 2001 Annual Report filed on Form 10-K is incorporated
herein by reference. Such information includes a description of Encore's
potential exposure to market risks, including commodity price risk and interest
rate risk. Encore's open commodity positions as of September 30, 2002 are
presented in Note 6 to the accompanying financial statements. The fair value of
our open commodity and interest rate hedges is ($7.8) million as of September
30, 2002. Subsequent to September 30, 2002, we entered into the following
hedges:
OIL HEDGES
DAILY FLOOR DAILY CAP
FLOOR VOLUME PRICE CAP VOLUME PRICE
PERIOD (Bbl) (PER Bbl) (Bbl) (PER Bbl)
----------------------- ------------ ------------ ------------ ------------
Jan - Dec 2004 ........ 500 $ 21.00 500 $ 26.00
NATURAL GAS HEDGES
DAILY FLOOR DAILY CAP
FLOOR VOLUME PRICE CAP VOLUME PRICE
PERIOD (Mcf) (PER Mcf) (Mcf) (PER Mcf)
----------------------- ------------ ------------ ------------ ------------
Jan - Dec 2003......... 2,500 $ 3.25 2,500 $ 6.83
Jan - Dec 2004......... 5,000 3.25 2,500 6.10
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures. Within 90 days prior
to the filing date of this Report, the Company's principal executive officer
("CEO") and principal financial officer ("CFO") carried out an evaluation of the
effectiveness of the Company's disclosure controls and procedures. Based on
those evaluations, the Company's CEO and CFO believe (i) that the Company's
disclosure controls and procedures are designed to ensure that information
required to be disclosed by the Company in the reports it files under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and forms and that such
information is accumulated and communicated to the Company's management,
including the CEO and CFO, as appropriate to allow timely decisions regarding
required disclosure; and (ii) that the Company's disclosure controls and
procedures are effective.
(b) Changes in internal controls. There have been no significant changes in
the Company's internal controls or in other factors that could significantly
affect the Company's internal controls subsequent to the evaluation referred to
in Item 4. (a), above, nor have there been any corrective actions with regard to
significant deficiencies or material weaknesses.
19
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
Reports on Form 8-K
During the three months ended September 30, 2002, the Company filed with the
SEC a current report on Form 8-K on August 26, announcing the promotion of Jon
S. Brumley, Executive Vice President, Business Development to the position of
President of the Company and the promotion of Gene R. Carlson to Executive Vice
President and Chief Operating Officer.
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: November 13, 2002 By: /s/ Morris B. Smith
---------------------------------------
Morris B. Smith
Chief Financial Officer, Treasurer,
Executive Vice President
and Principal Financial Officer
Date: November 13, 2002 By: /s/ Robert C. Reeves
---------------------------------------
Robert C. Reeves
Vice President, Controller and
Principal Accounting Officer
21
CERTIFICATIONS
I, I. Jon Brumley, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Encore Acquisition
Company (the "Company"):
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of circumstances under which such statements were
made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Company as of, and for, the periods presented in this quarterly report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period
in which this quarterly report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of the
Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the Company's ability to record, process,
summarize and report financial data and have identified for the Company's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Company's internal controls; and
6. The Company's other certifying officer and I have indicated in this quarterly
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: November 13, 2002 By: /s/ I. Jon Brumley
---------------------------------------
I. Jon Brumley
Chairman and Chief Executive Officer
22
I, Morris B. Smith, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Encore Acquisition
Company (the "Company"):
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of circumstances under which such statements were
made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Company as of, and for, the periods presented in this quarterly report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period
in which this quarterly report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of the
Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the Company's ability to record, process,
summarize and report financial data and have identified for the Company's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Company's internal controls; and
6. The Company's other certifying officer and I have indicated in this quarterly
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: November 13, 2002 By: /s/ Morris B. Smith
-------------------------------------
Morris B. Smith
Chief Financial Officer, Treasurer,
Executive Vice President
and Principal Financial Officer
23
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.