10-Q/A 1 d01589a1e10vqza.txt AMENDMENT NO. 1 TO FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q/A Amendment No. 1 /x/ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended 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 This Amendment No. 1 on Form 10-Q/A amends Items 1 and 2 of the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2002, as filed by the Company on November 14, 2002, and is being filed to revise production disclosures by reducing production volumes by amounts attributable to the financial net profits interests burdening the Company's Cedar Creek Anticline properties. No restatement of the unaudited financial statements is required, or being made, nor have any of the numbers in the unaudited financial statements changed. ENCORE ACQUISITION COMPANY INDEX
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. 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/A. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this document and Encore's 2001 Form 10-K/A. 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/A. 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) ............................ 16,783 13,826 2,957 16,004 13,209 2,795 Natural gas volumes (Mcf) ..................... 21,913 22,446 (533) 22,714 21,864 850 Combined volumes (BOE) ........................ 20,435 17,567 2,868 19,789 16,853 2,936 Average prices: Oil (per Bbl) ................................. $ 24.05 $ 22.04 $ 2.01 $ 21.86 $ 22.72 $ (0.86) Natural gas (per Mcf) ......................... 3.16 3.15 0.01 2.92 3.93 (1.01) Combined volumes (per BOE) .................... 23.14 21.37 1.77 21.03 22.90 (1.87) Average costs (per BOE): Direct lifting costs .......................... $ 4.45 $ 3.91 $ 0.54 $ 4.02 $ 4.07 $ (0.05) Production, ad valorem, and severance taxes ... 2.40 2.16 0.24 2.05 2.48 (0.43) G&A (excluding non-cash stock based compensation) ............................... 0.84 0.79 0.05 0.83 0.83 -- DD&A .......................................... 4.80 5.02 (0.22) 4.88 5.11 (0.23)
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 ................. $ 39,556 $ 25.62 $ 30,594 $ 24.05 $ 8,962 $ 1.57 Oil hedges ................... (3,135) (2.03) (2,560) (2.01) (575) (0.02) Enron hedges ................. 706 0.46 -- -- 706 0.46 ---------- ---------- ---------- ---------- ---------- ---------- Total Oil Revenues ...... $ 37,127 $ 24.05 $ 28,034 $ 22.04 $ 9,093 $ 2.01 ========== ========== ========== ========== ========== ========== Natural gas wellhead ......... $ 6,098 $ 3.02 $ 6,299 $ 3.05 $ (201) $ (0.03) Gas hedges ................... (121) (0.06) 206 0.10 (327) (0.16) Enron hedges ................. 398 0.20 -- -- 398 0.20 ---------- ---------- ---------- ---------- ---------- ---------- Total Gas Revenues ...... $ 6,375 $ 3.16 $ 6,505 $ 3.15 $ (130) $ 0.01 ========== ========== ========== ========== ========== ==========
Sales NYMEX Sales NYMEX Sales NYMEX OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit ---------- ---------- ---------- ---------- ---------- ---------- Oil (Bbls) ................... 1,544 $ 28.27 1,272 $ 26.57 272 $ 1.70 Gas (Mcf) .................... 2,016 3.21 2,065 2.80 (49) 0.41 Combined (BOE)................ 1,880 1,616 264
Total oil revenues increased from third quarter 2001 to third quarter 2002 due to increased volumes and higher wellhead prices. Oil volumes increased 272 MBbls due to our successful development drilling program and the acquisition of the Central Permian and Paradox Basin properties. Wellhead oil revenues increased $1.57 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, from $0.2 million to $0.5 million for the third quarter 2002 compared to third quarter 2001. Hedging payments increased by $0.6 million over the third quarter 2001. Amortization of $0.7 million of the Enron gain added $0.46 per Bbl to the average price as compared to the same period in 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 natural 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 $3.91 to $4.45, 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 $4.80 per BOE of production during the third quarter of 2002 represents a decrease of $0.22 per BOE from the $5.02 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 ................. $ 99,217 $ 22.71 $ 90,843 $ 25.19 $ 8,374 $ (2.48) Oil hedges ................... (5,837) (1.33) (8,927) (2.47) 3,090 1.14 Enron hedges ................. 2,116 0.48 -- -- 2,116 0.48 ---------- ---------- ---------- ---------- ---------- ---------- Total Oil Revenues ...... $ 95,496 $ 21.86 $ 81,916 $ 22.72 $ 13,580 $ (0.86) ========== ========== ========== ========== ========== ========== Natural gas wellhead ......... $ 16,910 $ 2.73 $ 28,254 $ 4.73 $ (11,344) $ (2.00) Gas hedges ................... 4 -- (4,802) (0.80) 4,806 0.80 Enron hedges ................. 1,196 0.19 -- -- 1,196 0.19 ---------- ---------- ---------- ---------- ---------- ---------- Total Gas Revenues ...... $ 18,110 $ 2.92 $ 23,452 $ 3.93 $ (5,342) $ (1.01) ========== ========== ========== ========== ========== ==========
Sales NYMEX Sales NYMEX Sales NYMEX OTHER DATA: Volumes $/Unit Volumes $/Unit Volumes $/Unit ---------- ---------- ---------- ---------- ---------- ---------- Oil (Bbls) ................... 4,369 $ 25.39 3,606 $ 27.75 763 $ (2.36) Gas (Mcf) .................... 6,201 3.03 5,969 4.50 232 (1.47) Combined (BOE) ............... 5,403 4,601 802
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 763 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 hedging of $3.1 million, as well as amortization of $2.1 million of the Enron gain. 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. Net profits payments were $1.2 million and $2.7 million, respectively, in the first nine months of 2002 and 2001. Natural gas revenues decreased by $5.3 million due to a decrease in the wellhead price per Mcf, partially offset by a 232 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 $2.02 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 remained fairly constant at $4.02 per BOE for the first nine months of 2002 compared with $4.07 per BOE for the first nine months of 2001. 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 $4.88 per BOE of production during the first nine months of 2002 represents a decrease of $0.23 per BOE from the $5.11 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 and ________________, 2002. 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 $1.08 and $2.99 per BOE, respectively, as a result of our hedging activities. Average prices per equivalent barrel indicate the composite impact of changes in oil and natural gas prices. Natural gas sales volumes are converted to oil equivalents at the conversion rate of six Mcf per Bbl. All prices are before amortization of the Enron-related gain.
OIL NATURAL GAS EQUIV. OIL (PER Bbl) (PER Mcf) (PER BOE) ------------ ------------ ------------ NET PRICE REALIZATION WITH HEDGES Quarter ended September 30, 2002 ...... $ 23.59 $ 2.96 $ 22.55 Quarter ended September 30, 2001 ...... 22.04 3.15 21.37 Nine months ended September 30, 2002 ................................ 21.37 2.73 20.41 Nine months ended September 30, 2001 ................................ 22.72 3.93 22.90 AVERAGE WELLHEAD PRICE Quarter ended September 30, 2002 ...... 25.62 3.02 24.28 Quarter ended September 30, 2001 ...... 24.05 3.05 22.83 Nine months ended September 30, 2002 ................................ 22.71 2.73 21.49 Nine months ended September 30, 2001 ................................ 25.19 4.73 25.89
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: December 5, 2002 By: /s/ Morris B. Smith --------------------------------------- Morris B. Smith Chief Financial Officer, Treasurer, Executive Vice President, Secretary, and Principal Financial Officer Date: December 5, 2002 By: /s/ Robert C. Reeves --------------------------------------- Robert C. Reeves Vice President, Controller and Principal Accounting Officer 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.