10-Q/A 1 d01588a1e10vqza.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 June 30, 2002 or / / Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to ------ ------ Commission file number 1-16295 ENCORE ACQUISITION COMPANY (Exact name of registrant as specified in its charter) Delaware 75-2759650 ------------------------------- ---------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 777 Main Street, Suite 1400, Fort Worth, Texas 76102 ------------------------------------------------------------ ---------- (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (817) 877-9955 Not applicable (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/ No / / Number of shares of Common Stock outstanding as of August 2, 2002.....30,030,294 This Amendment No. 1 on Form 10-Q/A amends Items 1 and 2 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2002, as filed by the Company on August 9, 2002 and is being filed to revise production disclosures by reducing production volumes by amounts attributable to the financial net profits interests burdening the Company's Cedar Creek Anticline properties. No restatement of the unaudited financial statements is required, or being made, nor have any of the numbers in the unaudited financial statements changed. ENCORE ACQUISITION COMPANY INDEX PART I. FINANCIAL INFORMATION Page Item 1. Financial Statements Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001.................................................... 3 Consolidated Statements of Operations for the three and six months ended June 30, 2002 and 2001.......................................... 4 Consolidated Statements of Stockholders' Equity for the six months ended June 30, 2002........................................... 5 Consolidated Statements of Cash Flows for the six months ended June 30, 2002 and 2001.................................. 6 Notes to Consolidated Financial Statements.............................. 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..................................... 12 Item 3. Quantitative and Qualitative Disclosure about Market Risk.................................................................... 18 PART II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders............... 19 Item 6. Exhibits and Reports on Form 8-K.................................. 19 Signatures................................................................ 20
2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ENCORE ACQUISITION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands except share data)
JUNE 30, DECEMBER 31, 2002 2001 ------------- ------------- (unaudited) ASSETS Current assets: Cash and cash equivalents ..................................... $ 2,417 $ 115 Accounts receivable (Net of allowance of $7.0 million) ........ 18,504 16,286 Deferred tax asset ............................................ 5,074 -- Derivative assets ............................................. 873 7,030 Other current assets .......................................... 8,650 5,117 ------------- ------------- Total current assets ................................... 35,518 28,548 ------------- ------------- Properties and equipment, at cost -- successful efforts method: Producing properties .......................................... 522,857 422,542 Undeveloped properties ........................................ 838 776 Accumulated depletion, depreciation and amortization .......... (77,495) (60,548) ------------- ------------- 446,200 362,770 ------------- ------------- Other property and equipment .................................. 3,161 3,001 Accumulated depletion, depreciation, and amortization ......... (1,567) (1,253) ------------- ------------- 1,594 1,748 ------------- ------------- Other assets .................................................... 10,171 8,934 ------------- ------------- Total assets ........................................... $ 493,483 $ 402,000 ============= ============= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable .............................................. $ 6,635 $ 10,793 Derivative liabilities ........................................ 8,301 3,525 Current portion of note payable ............................... -- 1,107 Other current liabilities ..................................... 15,491 12,016 ------------- ------------- Total current liabilities .............................. 30,427 27,441 ------------- ------------- Derivative liabilities .......................................... 2,020 1,288 Long-term debt .................................................. 150,000 78,000 Deferred income taxes ........................................... 34,885 25,969 ------------- ------------- Total liabilities ...................................... 217,332 132,698 ------------- ------------- Commitments and contingencies ................................... -- -- Stockholders' equity: Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding ................................. -- -- Common stock, $.01 par value, 60,000,000 authorized, 30,029,961 issued and outstanding ........................... 300 300 Additional paid-in capital .................................... 248,786 248,786 Retained earnings ............................................. 32,275 16,039 Accumulated other comprehensive income (loss) ................. (5,210) 4,177 ------------- ------------- Total stockholders' equity ............................. 276,151 269,302 ------------- ------------- Total liabilities and stockholders' equity ............. $ 493,483 $ 402,000 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. 3 ENCORE ACQUISITION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands except per share data) (unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, -------------- ---------- ------------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- Revenues: Oil ............................................................... $ 31,683 $ 26,505 $ 58,369 $ 53,882 Natural gas ....................................................... 6,124 8,103 11,735 16,947 ---------- ---------- ---------- ---------- Total revenues ...................................................... 37,807 34,608 70,104 70,829 Expenses: Production-- Direct lifting costs ........................................... 6,567 6,066 13,384 12,421 Production, ad valorem, and severance taxes .................... 3,546 3,640 6,559 7,910 General and administrative (excluding non-cash stock based compensation) .................................................. 1,384 1,259 2,877 2,522 Non-cash stock based compensation ................................. -- -- -- 9,587 Depletion, depreciation, and amortization ......................... 8,773 7,825 17,332 15,388 Derivative fair value (gain) loss ................................. (26) 37 (679) 139 Other operating expense ........................................... 331 -- 470 -- ---------- ---------- ---------- ---------- Total expenses ...................................................... 20,575 18,827 39,943 47,967 ---------- ---------- ---------- ---------- Operating income .................................................... 17,232 15,781 30,161 22,862 ---------- ---------- ---------- ---------- Other income (expenses): Interest .......................................................... (2,222) (1,176) (3,714) (3,713) Other ............................................................. (10) 9 20 61 ---------- ---------- ---------- ---------- Total other income (expenses) ....................................... (2,232) (1,167) (3,694) (3,652) ---------- ---------- ---------- ---------- Income before income taxes .......................................... 15,000 14,614 26,467 19,210 Provision for income taxes - current ................................ (30) (600) (460) (1,204) Provision for income taxes - deferred ............................... (5,670) (4,953) (9,597) (9,738) ---------- ---------- ---------- ---------- Income before accounting change and extraordinary loss .............. 9,300 9,061 16,410 8,268 Cumulative effect of accounting change, net of income taxes ......... -- -- -- (884) Extraordinary loss from early extinguishment of debt, net of income taxes ............................................... (174) -- (174) -- ---------- ---------- ---------- ---------- Net income .......................................................... $ 9,126 $ 9,061 $ 16,236 $ 7,384 ========== ========== ========== ========== Income per common share before accounting change and extraordinary loss: Basic ............................................................. $ 0.31 $ 0.30 $ 0.55 $ 0.30 Diluted ........................................................... 0.31 0.30 0.54 0.30 Net income per common share: Basic ............................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27 Diluted ........................................................... 0.30 0.30 0.54 0.27 Weighted average common shares outstanding: Basic ............................................................. 30,030 30,030 30,030 27,383 Diluted ........................................................... 30,184 30,034 30,118 27,385
The accompanying notes are an integral part of these consolidated financial statements. 4 ENCORE ACQUISITION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY JUNE 30, 2002 (in thousands) (unaudited)
Accumulated Additional Other Common Paid-In Retained Comprehensive Stockholders' Stock Capital Earnings Income (Loss) Equity ------------ ------------ ------------ ------------- ------------ Balance at December 31, 2001 .......... $ 300 $ 248,786 $ 16,039 $ 4,177 $ 269,302 Components of comprehensive income: Net income .......................... -- -- 16,236 -- 16,236 Change in deferred hedge loss (net of income taxes of $5,753) ....... -- -- -- (9,387) (9,387) ------------ Total comprehensive income .... 6,849 ------------ ------------ ------------ ------------ ------------ Balance at June 30, 2002 .............. $ 300 $ 248,786 $ 32,275 $ (5,210) $ 276,151 ============ ============ ============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 5 ENCORE ACQUISITION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (unaudited)
SIX MONTHS ENDED JUNE 30, ----------------------- 2002 2001 --------- --------- Operating activities Net income .................................................... $ 16,236 $ 7,384 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation, and amortization ................... 17,332 15,388 Deferred taxes .............................................. 9,597 8,368 Non-cash stock based compensation ........................... -- 9,587 Cumulative accounting change ................................ -- 884 Derivative fair value (gain) loss ........................... (679) 139 Extraordinary loss on early extinguishment of debt .......... 174 -- Other non-cash charges ...................................... (774) 948 Loss on disposition of assets ............................... 188 28 Changes in operating assets and liabilities: Accounts receivable ......................................... (2,218) 1,153 Other current assets ........................................ (4,920) (800) Other assets ................................................ 3,277 767 Accounts payable and other current liabilities .............. (697) (2,784) --------- --------- Cash provided by operating activities ........................ 37,516 41,062 Investing activities Proceeds from disposition of assets ......................... 356 145 Purchases of other property and equipment ................... (400) (442) Acquisition of oil and natural gas properties ............... (59,532) (705) Development of oil and natural gas properties ............... (40,845) (34,592) --------- --------- Cash used by investing activities ............................. (100,421) (35,594) Financing activities Proceeds from initial public offering ....................... -- 93,095 Offering costs paid ......................................... -- (1,568) Proceeds from notes receivable - officers and employees ..... -- 19 Proceeds from long-term debt ................................ 255,000 78,000 Payments on long-term debt .................................. (183,000) (166,500) Payments for debt issuance costs ............................ (5,686) -- Payments on note payable .................................... (1,107) (9,005) --------- --------- Cash provided by (used by) financing activities ............... 65,207 (5,959) Increase (decrease) in Cash and Cash Equivalents .............. 2,302 (491) Cash and Cash Equivalents, Beginning of Period ................ 115 876 --------- --------- Cash and Cash Equivalents, End of Period ...................... $ 2,417 $ 385 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 6 ENCORE ACQUISITION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 1. FORMATION OF ENCORE Encore Acquisition Company ("the Company"), a Delaware Corporation, is an independent (non-integrated) oil and natural gas company in the United States. We were organized in April 1998 and are engaged in the acquisition, development, exploitation and production of North American oil and natural gas reserves. Our oil and natural gas reserves are concentrated in fields located in the Williston Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma and the Powder River Basin of Montana. 2. BASIS OF PRESENTATION In the opinion of management, the accompanying unaudited consolidated financial statements of the Company include all adjustments necessary to present fairly our financial position as of June 30, 2002 and results of operations and cash flows for the three and six months ended June 30, 2002 and 2001. All adjustments are of a recurring nature. These interim results are not necessarily indicative of results for an entire year. Certain amounts of prior periods have been reclassified in order to conform to the current period presentation. Certain disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these financial statements should be read in conjunction with the Company's 2001 consolidated financial statements and related notes thereto included in the Company's Annual Report filed on Form 10-K. 3. NEW ACCOUNTING STANDARDS In August 2001, the FASB issued Statement of Financial Accounting Standards No. 143 ("SFAS 143"), "Accounting for Asset Retirement Obligations", which the Company will be required to adopt as of January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation ("ARO") is incurred, based upon the discounted estimated fair value of the obligation. Also, upon initial recognition of the liability, we must capitalize additional asset cost equal to the amount of the liability. In addition to any obligations that arise after the effective date of SFAS 143, upon initial adoption we must recognize (1) a liability for any existing AROs, (2) capitalized cost related to the liability, and (3) accumulated depletion, depreciation, and amortization on that capitalized cost. We are currently reviewing the provisions of the statement and assessing their impact on our financial statements. We do not currently know the effect, if any, the adoption of SFAS 143 will have on our financial statements. In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". Under Statement 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. This Statement eliminates Statement 4 and, thus, the exception to applying Opinion 30 to all gains and losses related to extinguishments of debt. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. This statement is effective for Encore beginning January 1, 2003, at which time the extraordinary loss on extinguishment of debt recorded in the second quarter of 2002 will be reclassified to operating income. 4. INDEBTEDNESS The Company's overall indebtedness has increased by $70.9 million since December 31, 2001. The additional borrowings were used to fund $59.5 in acquisitions, as well as $5.7 in debt issuance costs associated with the 8 3/8% Senior Subordinated Notes and the new Revolving Credit Facility (See below), the development drilling program, and the initial high-pressure air injection project. On June 25, 2002, the Company sold $150 million of 8 3/8% Senior Subordinated Notes maturing on June 15, 2012 (the "Notes"). The offering was made through a private placement pursuant to Rule 144A. As of June 30, 2002, the Notes have not been registered 7 under the Securities Act of 1933 or applicable state securities laws. In conjunction with the issuance of the Notes, the Company executed a registration rights agreement and has agreed to: (i) file a registration statement of the Notes by September 23, 2002, enabling holders of the Notes to exchange the Notes for publicly registered Notes with substantially identical terms and (ii) use our reasonable best efforts to cause the registration statement to become effective by December 22, 2002. The Company received net proceeds of $146.3 million from the sale of the Notes, which were used to repay and retire the Company's prior credit facility. Concurrently with the Company's issuance of the Notes, the Company also entered into a new Revolving Credit Facility, effective June 25, 2002. Borrowings under the facility will be secured by a first priority lien on the Company's proved oil and natural gas reserves. Availability under the facility will be determined through semi-annual borrowing base determinations and may be increased or decreased. As of June 30, 2002, the amount available under the new facility is $220.0 million. No amounts were outstanding at June 30, 2002. The maturity date of the new facility will be June 25, 2006. Amounts outstanding under the facility are subject to varying rates of interest based on the amount outstanding and the Company's borrowing base. Based on our current $220.0 million borrowing base, our applicable interest rates would be calculated as follows:
AMOUNT OUTSTANDING RATE ------------------------------- ------------- $0 to $55,000,000.............. LIBOR + 1.000% $55,000,001 to $110,000,000.... LIBOR + 1.125% $110,000,001 to $165,000,000... LIBOR + 1.250% $165,000,001 to $198,000,000... LIBOR + 1.500% $198,000,001 to $220,000,000... LIBOR + 1.750%
Additionally, under the new Revolving Credit Facility, the Company is subject to certain affirmative, negative, and financial covenants. These include limitations on incurrence of additional debt, restrictions on assets dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and maintenance of an EBITDA to interest expense ratio of at least 2.5 to 1.0. 5. EARNINGS PER SHARE ("EPS") The following table sets forth basic and diluted EPS computations for the three and six months ended June 30, 2002 and 2001 (in thousands, except per share data):
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, --------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- NUMERATOR: ---------- Income before extraordinary item and accounting change ...................... $ 9,300 $ 9,061 $ 16,410 $ 8,268 ======== ======== ======== ======== Net income .................................................................. $ 9,126 $ 9,061 $ 16,236 $ 7,384 ======== ======== ======== ======== DENOMINATOR: ------------ Denominator for basic earnings per share - weighted average shares outstanding ....................................... 30,030 30,030 30,030 27,383 Effect of dilutive securities: Dilutive options .......................................................... 154 4 88 2 -------- -------- -------- -------- Denominator for diluted earnings per share .................................. 30,184 30,034 30,118 27,385 ======== ======== ======== ======== BASIC PER COMMON SHARE: ----------------------- Income before extraordinary item and accounting change ...................... $ 0.31 $ 0.30 $ 0.55 $ 0.30 Cumulative effect of accounting change, net of income taxes ................. -- -- -- (0.03) Extraordinary loss from early extinguishment of debt, net of income taxes ... (0.01) -- (0.01) -- -------- -------- -------- -------- Net income .................................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27 ======== ======== ======== ======== DILUTED PER COMMON SHARE: ------------------------- Income before extraordinary item and accounting change ...................... $ 0.31 $ 0.30 $ 0.54 $ 0.30 Cumulative effect of accounting change, net of income taxes ................. -- -- -- (0.03) Extraordinary loss from early extinguishment of debt, net of income taxes ... (0.01) -- -- -- -------- -------- -------- -------- Net income .................................................................. $ 0.30 $ 0.30 $ 0.54 $ 0.27 ======== ======== ======== ========
8 6. DERIVATIVE FINANCIAL INSTRUMENTS During the first six months of 2002, current derivative assets decreased $6.2 million, while current derivative liabilities increased $4.8 million and long-term derivative liabilities increased $0.7 million. These changes were due primarily to an increase in the futures price of oil and natural gas and lower interest rates. For the six months ended June 30, 2002, we had total comprehensive income of $6.8 million, while net income totaled $16.2 million. The difference between net income and total comprehensive income is due to a $9.4 million change in deferred hedge gain/loss in accumulated other comprehensive income. Due to an increase in the futures price of oil and natural gas and lower interest rates, we went from a deferred hedge gain of $4.2 million, net of tax, at December 31, 2001, to a deferred hedge loss of $5.2 million, net of tax, at June 30, 2002. Exclusive of the Enron gain and interest rate swap loss (See below), the Company expects $3.7 million of the amount in accumulated other comprehensive income to reverse in the next twelve months. At December 31, 2001, we had $4.8 million in gross unrecognized gains in accumulated other comprehensive income related to the termination of hedging contracts with Enron that are being amortized into earnings during 2002 and 2003. The following table illustrates the current and future amortization of this amount to revenue (in thousands):
THREE MONTHS NATURAL ENDED OIL GAS TOTAL -------------------- ------------ ------------ ----------- March 31, 2002........ $ 705 $ 399 $ 1,104 June 30, 2002......... 705 399 1,104 September 30, 2002.... 706 398 1,104 December 31, 2002..... 706 398 1,104 March 31, 2003........ 100 5 105 June 30, 2003......... 100 5 105 September 30, 2003.... 100 4 104 December 31, 2003..... 101 4 105 ----------- ----------- ----------- Total................. $ 3,223 $ 1,612 $ 4,835 =========== =========== ===========
As a result of the retirement of the Company's prior credit facility, the Company's three interest rate swaps, which swap LIBOR based floating rates for fixed rates, no longer qualify for hedge accounting. As a result, the Company marked these contracts to market as of June 25, 2002, the date of the sale of the Notes and related repayment of the amount outstanding under the prior credit facility, which was terminated on that date. This resulted in an unrealized loss of $3.8 million through June 25, 2002, which was recognized in accumulated other comprehensive income and will be amortized to interest expense over the original life of the swaps as follows (in thousands):
YEAR 1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL --------------- ------------ ------------ ------------ ------------ ------------ 2002 .......... $ -- $ (59) $ (806) $ (754) $ (1,619) 2003 .......... (654) (544) (414) (297) (1,909) 2004 .......... (212) (153) (109) (72) (546) 2005 .......... (40) 72 85 60 177 2006 .......... 22 24 29 33 108 2007 .......... 38 1 -- -- 39 ------------ Total ......... $ (3,750) ============
In conjunction with the sale of the Notes (See Note 4), the Company entered into an additional interest rate swap, whereby we pay LIBOR plus 3.89% and receive a fixed 8 3/8% on a notional amount of $80 million through June 15, 2005. Due to the difference in terms between the swap and the underlying debt, this instrument does not qualify for hedge accounting and, along with future changes in the fair value of the three original swaps, will be marked to market through earnings each period in the `Derivative fair value gain/loss' line in the income statement. 9 During the second quarter, we expanded our commodity hedges in 2002 and 2003 for both oil and natural gas. The following tables summarize our open commodity hedging positions as of June 30, 2002: OIL HEDGES AT JUNE 30, 2002
DAILY FLOOR DAILY CAP DAILY SWAP FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE PERIOD (BBL) (PER BBL) (BBL) (PER BBL) (BBL) (PER BBL) --------- --------------- ----------- -------------- ----------- ------------- ---------- July - Dec 2002...... 7,000 $ 22.96 4,500 $ 27.88 3,000 $ 20.15 Jan - June 2003...... 7,500 20.80 6,000 26.52 1,000 24.50 July - Dec 2003...... 4,500 20.00 4,500 26.23 -- --
NATURAL GAS HEDGES AT JUNE 30, 2002
DAILY FLOOR DAILY CAP DAILY SWAP FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE PERIOD (MCF) (PER MCF) (MCF) (PER MCF) (MCF) (PER MCF) ----------- --------------- ----------- -------------- ----------- ------------- ---------- July - Dec 2002...... 5,000 $ 3.13 2,500 $ 8.05 5,000 $ 2.83 Jan - Dec 2003....... 5,000 3.13 -- -- 2,500 3.69
Additionally, as of June 30, 2002, we had short oil put contracts in place covering 1,500 Bbls per day in 2002 and 500 Bbls per day in 2003 at an average strike price of $20 and $17, respectively, which do not qualify for hedge accounting. Accordingly, these contracts are marked to market through earnings each period in the `Derivative fair value gain/loss' line in the income statement. 7. INCOME TAXES Excluding the tax effect of the extraordinary loss from early extinguishment of debt, during the first six months of 2002, Encore incurred $10.1 million in income tax expense. Of this, $9.6 million is deferred income tax expense and relates primarily to intangible drilling costs incurred during the quarter, which are deductible for income tax purposes, but have been capitalized as Properties and Equipment under generally accepted accounting principles. These amounts will be depleted and transferred to earnings over the production life of the wells. Additionally, the Company's current deferred tax asset has increased to $5.1 million from approximately zero at December 31, 2001, due to the change in Other Comprehensive Income related to the mark-to-market change in the value of the Company's derivatives. The Company's High-Pressure Air Injection project ("HPAI") in the Cedar Creek Anticline ("CCA") has been certified as an enhanced oil recovery project for federal income tax purposes. As a result, qualifying expenditures on the project are eligible for a 15% tax credit. We have reduced current income taxes payable by $0.7 million in the second quarter to reflect the expected credit from investments to date in the HPAI project. On July 16, 2002, we began injecting air in the Pennel Unit of the CCA. 8. ACQUISITIONS On January 4, 2002, we completed the acquisition of interests in oil and natural gas properties in the Permian Basin for $50.1 million from Conoco. The two principal operated properties are the East Cowden Grayburg and Fuhrman Nix fields; the non-operated properties are primarily in the North Cowden and Yates fields. Over 40 development wells have been identified, and a drilling program will be initiated in the third quarter of this year. The acquisition was funded by additional borrowings under the Company's prior credit agreement. On April 18, 2002, we agreed to acquire oil and natural gas properties in the Paradox Basin in Utah from a privately held oil and gas company. The purchase price for the Paradox Basin acquisition is $23.4 million, prior to closing adjustments. The Utah properties are interests in the Ratherford Unit operated by Exxon Mobil and the Aneth Unit operated by ChevronTexaco. The working and net revenue interest in the Ratherford Unit are 19.3% and 16.8%, respectively, and the working interest and the net revenue interest in the Aneth Unit are 12.0% and 10.3%, respectively. Approximately 78% of the value of the acquisition is subject to preferential rights held by the Navajo Nation, which are set to expire in mid-August, 2002. We paid an initial deposit for 5% of the purchase price and issued a standby letter of credit for the remainder. Final closing and payment will be made immediately after the preferential rights have expired in mid-August 2002. On May 14, 2002, we completed the acquisition of additional working interests in our operated properties in the East Cowden Grayburg field for $8.4 million. The acquisition was funded by additional borrowings under the Company's prior credit agreement. 10 9. SUBSEQUENT EVENTS Subsequent to the balance sheet date, the Company cash settled one of its outstanding interest rate swaps at a cost of $2.8 million. Since we no longer carried any floating rate debt as of the end of the period, we lessened our exposure to further decreases in the LIBOR interest rate. However, we do anticipate incurring floating rate debt under our new Revolving Credit Agreement to fund development drilling activities, pay the remaining purchase price of the Paradox Basin acquisition, and possibly acquire additional properties in the future. For these reasons, we decided to only cash settle one of the outstanding interest rate swaps. The settled swap had a notional amount of $30.0 million and swapped a LIBOR based floating rate for a 6.72% fixed rate. The remaining two original interest rate swaps on the prior credit facility have a combined notional of $60.0 million and an average fixed rate of 4.75%. 10. FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS All of the Company's subsidiaries are currently subsidiary guarantors of the Notes. Since (i) each subsidiary guarantor is 100% owned by the Company, (ii) the Company has no assets or operations that are independent of its subsidiaries, (iii) the subsidiary guarantees are full and unconditional and joint and several and (iv) all of the Company's subsidiaries are subsidiary guarantors, the Company has not included the financial statements of each subsidiary in this report. The subsidiary guarantors may without restriction transfer funds to the Company in the form of cash dividends, loans and advances. 11 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This document contains forward-looking statements that involve risks and uncertainties that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors, including, but not limited to, those set forth under "SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS" contained in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in Encore's 2001 Annual Report filed on Form 10-K/A. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this document and Encore's 2001 Form 10-K/A. CRITICAL ACCOUNTING POLICIES For a discussion of the Company's critical accounting policies, see the Company's 2001 Annual Report filed on Form 10-K/A. RESULTS OF OPERATIONS The following table sets forth operating information for the periods presented:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------- ---------------------- INCREASE INCREASE 2002 2001 (DECREASE) 2002 2001 (DECREASE) ---------- ---------- ---------- ---------- ---------- ---------- Operating Results (in thousands): Oil and natural gas revenues ........................ $ 37,807 $ 34,608 $ 3,199 $ 70,104 $ 70,829 $ (725) Direct lifting costs ................................ 6,567 6,066 501 13,384 12,421 963 Production, ad valorem and severance taxes .......... 3,546 3,640 (94) 6,559 7,910 (1,351) Daily sales volumes: Oil volumes (Bbls) .................................. 15,714 13,011 2,703 15,602 12,890 2,712 Natural gas volumes (Mcf) ........................... 22,275 22,055 220 23,122 21,564 1,558 Combined volumes (BOE) .............................. 19,427 16,687 2,740 19,456 16,483 2,973 Average prices: Oil (per Bbl) ....................................... $ 22.16 $ 22.39 $ (0.23) $ 20.67 $ 23.10 $ (2.43) Natural gas (per Mcf) ............................... 3.02 4.04 (1.02) 2.80 4.34 (1.54) Combined volumes (per BOE) .......................... 21.39 22.79 (1.40) 19.91 23.74 (3.83) Average costs (per BOE): Direct lifting costs ................................ $ 3.71 $ 3.99 $ (0.28) $ 3.80 $ 4.16 $ (0.36) Production, ad valorem, and severance taxes ......... 2.01 2.40 (0.39) 1.86 2.65 (0.79) G&A (excluding non-cash stock based compensation) ... 0.78 0.83 (0.05) 0.82 0.85 (0.03) DD&A ................................................ 4.96 5.15 (0.19) 4.92 5.16 (0.24)
12 COMPARISON OF QUARTER ENDED JUNE 30, 2002 TO QUARTER ENDED JUNE 30, 2001 Set forth below is our comparison of operations during the second quarter of 2002 with the second quarter of 2001. REVENUES AND SALES VOLUMES. The following table illustrates the primary components of oil and natural gas revenue for the quarters ended June 30, 2002 and 2001, as well as each quarter's respective oil and natural gas volumes (in thousands, except per unit amounts):
Three Months Ended June 30, 2002 2001 Difference -------------------- -------------------- -------------------- Revenues: Revenue $/Unit Revenue $/Unit Revenue $/Unit -------- -------- -------- -------- -------- -------- Oil wellhead ............. $ 33,446 $ 23.39 $ 29,572 $ 24.98 $ 3,874 $ (1.59) Oil hedges ............... (2,469) (1.73) (3,067) (2.59) 598 0.86 Enron hedges ............. 706 0.50 -- -- 706 0.50 -------- -------- -------- -------- -------- -------- Total Oil Revenues .. $ 31,683 $ 22.16 $ 26,505 $ 22.39 $ 5,178 $ (0.23) ======== ======== ======== ======== ======== ======== Natural gas wellhead ..... $ 6,051 $ 2.99 $ 9,592 $ 4.78 $ (3,541) $ (1.79) Gas hedges ............... (325) (0.17) (1,489) (0.74) 1,164 0.57 Enron hedges ............. 398 0.20 -- -- 398 0.20 -------- -------- -------- -------- -------- -------- Total Gas Revenues .. $ 6,124 $ 3.02 $ 8,103 $ 4.04 $ (1,979) $ (1.02) ======== ======== ======== ======== ======== ========
Sales Nymex Sales Nymex Sales Nymex Other Data: Volumes $/Unit Volumes $/Unit Volumes $/Unit -------- -------- -------- -------- -------- -------- Oil (Bbls) ............... 1,430 $ 26.25 1,184 $ 28.73 246 $ (2.48) Gas (Mcf) ................ 2,027 3.40 2,007 6.30 20 (2.90) Combined (BOE)............ 1,768 1,519 249
Total oil revenue increased from second quarter 2001 to second quarter 2002 due to increased volumes, lower hedging losses, lower net profits payments, and amortization of the Enron gain offset by lower wellhead prices. Oil volumes increased 246 MBbls due to our successful development drilling program and the acquisition of the Central Permian properties. Wellhead oil revenues decreased $1.59 per Bbl primarily resulting from a decrease in the overall market price for oil as reflected in the $2.48 per Bbl decrease in the average NYMEX price over the same period. Payments made for hedging decreased $0.6 million. The change in hedging payments had the effect of increasing revenue by $0.86 per Bbl over the second quarter 2001. Amortization of $0.7 million of the Enron gain added $0.50 per Bbl as compared to the same period in 2001. Net profits payments decreased from $1.4 million to $0.4 million from the second quarter of 2001 to the second quarter of 2002. The decrease in net profits was primarily due to lower prices and higher capital expenditures in the CCA in the second quarter of 2002 as compared to the second quarter of 2001. The Company's hedging activities are not a component of the expenses deducted in calculating net profits interest payments. The decrease in hedging payments is a result of the decrease in the average NYMEX price for oil. Total natural gas revenues decreased by $2.0 million, or $1.02 per Mcf, due to a decrease in the wellhead price per Mcf, partially offset by a $1.2 million decrease in payments on hedging settlements and the $0.4 million amortization of the Enron gain. The decrease in the wellhead price received is consistent with the average NYMEX price decrease of $2.90 per Mcf from the three months ended June 30, 2001 to the three months ended June 30, 2002. Hedging payments decreased $0.57 per Mcf due to lower natural gas prices, as well as different contracts being in effect. DIRECT LIFTING COSTS. Direct lifting costs of Encore for the second quarter of 2002 increased as compared to the second quarter of 2001 by $0.5 million, from $6.1 million to $6.6 million. The increase in direct lifting costs is primarily attributable to increased sales volumes attributable to our development drilling program and Central Permian acquisitions in 2002, offset somewhat by a decrease in the per BOE rate. On a per BOE basis, direct lifting costs decreased from $3.99 to $3.71, primarily as a result of decreased workover and maintenance costs over the same period last year. We plan to resume our 2002 planned workover and maintenance programs in the third and fourth quarters of this year. PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and severance taxes for the second quarter of 2002 decreased as compared to the second quarter of 2001 by approximately $0.1 million. This decrease was a result of the lower wellhead prices as compared to the second quarter of 2001. The effect of lower prices was partially offset by increased volumes as a result of the Central Permian acquisition and development drilling. As a percent of oil and natural gas revenues (excluding the effects of hedges), production, ad valorem, and severance taxes remained fairly constant, down to 9.0% from 9.3%. 13 DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense for the second quarter of 2002 increased by $0.9 million, reflecting the volumes associated with our larger asset base resulting from the Central Permian properties and our continued development drilling program. The average DD&A rate of $4.96 per BOE of production during the second quarter of 2002 represents a decrease of $0.19 per BOE from the $5.15 per BOE recorded in the second quarter of 2001. The decrease was attributable to normal production declines in the Lodgepole properties, which have relatively high DD&A rates as compared to our other producing properties. GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.1 million for the second quarter of 2002 as compared to the second quarter of 2001, from $1.3 million to $1.4 million. The increase in G&A expense was a result of the hiring of additional staff after the 2002 Central Permian acquisitions to manage, expand, and exploit our growing asset base. INTEREST EXPENSE. Interest expense for the quarter ended June 30, 2002 was $2.2 million compared to $1.2 million for the quarter ended June 30, 2001. The increase in interest expense is due to higher debt levels, partially offset by lower interest rates. The weighted average interest rate, net of hedges, for the second quarter of 2002 was 5.5% compared to 6.7% for the second quarter of 2001. The weighted average debt level under our credit facility for the second quarter of 2002 was $133.1 million compared to $57.9 million for the second quarter of 2001. The following table illustrates the components of interest expense for the three months ended June 30, 2002 and 2001 (in thousands):
Three Months Ended June 30, 2002 2001 Difference ---------- ---------- ---------- Credit facility ......... $ 1,079 $ 811 $ 268 8 3/8% notes due 2012 ... 207 -- 207 Burlington note ......... -- 110 (110) Interest rate hedges .... 858 156 702 Banking fees ............ 78 99 (21) ---------- ---------- ---------- Total ......... $ 2,222 $ 1,176 $ 1,046 ========== ========== ==========
COMPARISON OF SIX MONTHS ENDED JUNE 30, 2002 TO SIX MONTHS ENDED JUNE 30, 2001 Set forth below is our comparison of operations during the first six months of 2002 with the first six months of 2001. REVENUES AND SALES VOLUMES. The following table illustrates the primary components of oil and natural gas revenue for the six months ended June 30, 2002 and 2001, as well as each period's respective oil and natural gas volumes (in thousands, except per unit amounts):
Six Months Ended June 30, 2002 2001 Difference ------------------------- ------------------------- ------------------------- Revenues: Revenue $/Unit Revenue $/Unit Revenue $/Unit ---------- ---------- ---------- ---------- ---------- ---------- Oil wellhead ............ $ 59,661 $ 21.13 $ 60,249 $ 25.82 $ (588) $ (4.69) Oil hedges .............. (2,703) (0.96) (6,367) (2.72) 3,664 1.76 Enron hedges ............ 1,411 0.50 -- -- 1,411 0.50 ---------- ---------- ---------- ---------- ---------- ---------- Total Oil Revenues . $ 58,369 $ 20.67 $ 53,882 $ 23.10 $ 4,487 $ (2.43) ========== ========== ========== ========== ========== ========== Natural gas wellhead .... $ 10,812 $ 2.58 $ 21,955 $ 5.62 $ (11,143) $ (3.04) Gas hedges .............. 126 0.03 (5,008) (1.28) 5,134 1.31 Enron hedges ............ 797 0.19 -- -- 797 0.19 ---------- ---------- ---------- ---------- ---------- ---------- Total Gas Revenues . $ 11,735 $ 2.80 $ 16,947 $ 4.34 $ (5,212) $ (1.54) ========== ========== ========== ========== ========== ==========
Sales Nymex Sales Nymex Sales Nymex Other Data: Volumes $/Unit Volumes $/Unit Volumes $/Unit ---------- ---------- ---------- ---------- ---------- ---------- Oil (Bbls) .............. 2,824 $ 23.95 2,333 $ 28.34 491 $ (4.39) Gas (Mcf) ............... 4,185 2.95 3,903 5.35 282 (2.40) Combined (BOE)........... 3,522 2,984 538
Although average wellhead price was down for the first half of 2002, total oil revenue increased due to higher volumes, lower hedging losses, lower net profits payments, and amortization of the Enron gain. Oil volumes increased 491 MBbls due to the Company's successful development drilling program and the Central Permian acquisitions. Wellhead oil revenues decreased $4.69 per Bbl primarily from a decrease in the overall market price for oil as reflected in the $4.39 per Bbl decrease in the average NYMEX 14 price over the same period. The decrease in wellhead oil revenues was offset by a decrease in payments made for hedging settlements, which decreased $3.7 million, as well as amortization of $1.4 million of the Enron gain. The decrease in hedging payments is a direct result of the decrease in the average NYMEX price for oil. Net profits payments were $0.7 million and $2.4 million, respectively, for the first six months of 2002 and 2001. The decrease in net profits was primarily due to lower wellhead prices and higher capital expenditures in the second quarter of 2002 in CCA. Natural gas revenues decreased by $5.2 million due to a decrease in the net sales price per Mcf, which was somewhat offset by a 282 MMcf increase in sales volumes, net hedging receipts in the first half of 2002 versus net hedging payments in the first half of 2001, and amortization of $0.8 million of the Enron gain. The increase in volumes is due to increased sales volumes in CCA and Crockett County due to development drilling. Wellhead price received decreased $3.04 per Mcf, consistent with the average NYMEX price decrease of $2.40 per Mcf from the six months ended June 30, 2001 to the six months ended June 30, 2002, while hedging payments decreased $1.31 per Mcf due to lower natural gas prices. DIRECT LIFTING COSTS. Direct lifting costs for the first six months of 2002 increased as compared to the first six months of 2001 by $1.0 million, from $12.4 million to $13.4 million due to increased sales volumes attributable to our development drilling program and Central Permian acquisitions in 2002. On a per BOE basis, direct lifting costs decreased $0.36 from the first quarter of 2001 to the first quarter of 2002 due to decreased workover and maintenance costs over the same period last year. We plan to resume our 2002 planned workover and maintenance programs in the third and fourth quarters of this year. PRODUCTION, AD VALOREM, AND SEVERANCE TAXES. Production, ad valorem, and severance taxes for the first half of 2002 decreased as compared to the first half of 2001 by approximately $1.4 million. The decrease in production, ad valorem, and severance taxes was a result of the lower commodity prices in the first six months of 2002 as compared to the same period of 2001 as reflected in the lower wellhead revenues. As a percent of oil and natural gas revenues (excluding the effects of hedging transactions), production, ad valorem, and severance taxes decreased from 9.6% to 9.3%. DEPLETION, DEPRECIATION, AND AMORTIZATION ("DD&A") EXPENSE. DD&A expense for the six months ended June 30, 2002 increased by approximately $1.9 million, from $15.4 million to $17.3 million as compared to the six months ended June 30, 2001. The increase in DD&A was a product of increased sales volumes in 2002, as well as a larger asset base associated with our 2002 acquisitions. The average DD&A rate of $4.92 per BOE of production during the first six months of 2002 represents a decrease of $0.24 per BOE from the $5.16 per BOE recorded in the first six months of 2001. The decrease is attributable to normal production declines in the Lodgepole properties, which have relatively high DD&A rates as compared to our other producing properties. GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE. G&A expense increased $0.4 million for the first half of 2002 as compared to the first half of 2001, from $2.5 million to $2.9 million (excluding non-cash stock based compensation of $9.6 million in the first six months of 2001). The increase in G&A expense was a result of the hiring of additional staff after the 2002 Central Permian acquisitions to manage, expand and exploit our growing asset base. NON-CASH STOCK BASED COMPENSATION EXPENSE. Non-cash stock based compensation expense decreased from $9.6 million in the first six months of 2001 to zero in the first six months of 2002. This non-cash stock based compensation expense is associated with the purchase by our management stockholders of Class A common stock under our management stock plan adopted in August 1998. This amount represents the vested portion of the shares purchased and is recorded as compensation, calculated in accordance with variable plan accounting under APB 25. The amount recorded in the first half of 2001 represented the final amount of expense to be recorded related to the Class A stock. INTEREST EXPENSE. Interest expense for the six months ended June 30, 2002 remained constant at $3.7 million versus the same period in 2001. The weighted average interest rate, net of hedges, for the first half of 2002 was 4.9% compared to 7.0% for the first half of 2001. The weighted average debt level under our credit facility for the first half of 2002 was $122.3 million compared to $92.9 million for the first half of 2001. The following table illustrates the components of interest expense for the six months ended June 30, 2002 and 2001 (in thousands):
Six Months Ended June 30, 2002 2001 Difference ---------- ---------- ------------- Credit facility......................... $ 2,064 $ 3,178 $ (1,114) 8 3/8% notes due 2012................... 207 -- 207 Burlington note......................... -- 263 (263) Interest rate hedges.................... 1,315 115 1,200 Banking fees........................... 128 157 (29) ---------- ---------- ------------ Total........................ $ 3,714 $ 3,713 $ 1 ========== ========== ============
15 LIQUIDITY AND CAPITAL RESOURCES Principal uses of capital have been for the acquisition and development of oil and natural gas properties. CASH FLOW During the six months ended June 30, 2002, net cash provided by operations was $37.5 million, a decrease of $3.5 million compared to the six months ended June 30, 2001. This decrease is primarily attributable to lower oil and natural gas prices in 2002. Cash used by investing activities increased from $35.6 million to $100.4 million over the same period, largely due to the 2002 acquisitions and an increase in development costs. Cash provided by financing activities was $65.2 million in the first half of 2002, as compared to cash used by financing activities of $6.0 million in the first half of 2001. The increase is primarily attributable to the Central Permian acquisitions in 2002. CAPITALIZATION At June 30, 2002, Encore had total assets of $493.5 million. Total capitalization was $426.2 million, of which 64.8% was represented by stockholders' equity and 35.2% by long-term indebtedness. DEBT MATURITIES On June 25, 2002, the Company sold $150 million of 8 3/8% Senior Subordinated Notes maturing on June 15, 2012. The offering was made through a private placement pursuant to Rule 144A. As of June 30, 2002, the Notes have not been registered under the Securities Act of 1933 or applicable state securities laws. In conjunction with the issuance of the Notes, the Company executed a registration rights agreement and has agreed to: (i) file a registration statement of the Notes by September 23, 2002, enabling holders of the Notes to exchange the Notes for publicly registered Notes with substantially identical terms and (ii) use our reasonable best efforts to cause the registration statement to become effective by December 22, 2002. The Company received net proceeds of $146.3 million from the sale of the Notes, which were used to repay and retire the Company's prior credit facility. REVOLVING CREDIT FACILITY Concurrently with the Company's issuance of the Notes, the Company also entered into a new Revolving Credit Facility, effective June 25, 2002. Borrowings under the facility will be secured by a first priority lien on the Company's proved oil and natural gas reserves. Availability under the facility will be determined through semi-annual borrowing base determinations and may be increased or decreased. As of June 30, 2002, the amount available under the new facility is $220.0 million. No amounts were outstanding at June 30, 2002. The maturity date of the new facility will be June 25, 2006. LETTERS OF CREDIT The Company issued three standby letters of credit during the second quarter 2002. The first, in the amount of $24.7 million, which expires January 1, 2003, guarantees the purchase price of the Paradox Basin acquisition less the 5% deposit made in the second quarter. The remaining two, totaling $7.0 million and expiring on December 31, 2002 and January 1, 2003, secure potential future settlements under certain outstanding hedging contracts. FUTURE CAPITAL REQUIREMENTS We anticipate that our capital expenditures will total approximately $21.0 million, exclusive of the Paradox Basin acquisition, for the third quarter of 2002. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. We plan to finance our ongoing development and acquisition expenditures using internally generated cash flow, available cash, and our existing credit agreement. As previously announced, Encore plans to invest $81.0 million, excluding acquisitions, in capital expenditures in 2002. The Company believes that its capital resources are adequate to meet the requirements of its business. Based on our anticipated capital investment programs, we expect to invest our internally generated cash flow to replace sales volumes and enhance our waterflood programs. Additional capital may be required to pursue acquisitions and longer-term capital projects, such as our high-pressure air injection tertiary recovery project in the CCA, to increase our reserve base. Substantially all of these expenditures are discretionary and will be undertaken only if funds are available and the projected rates of return are satisfactory. Future cash flows are subject to a number of variables, including the level of oil and natural gas sales volumes and prices. Operations and other capital resources may not provide cash in sufficient amounts to maintain planned levels of capital expenditures. 16 INFLATION AND CHANGES IN PRICES While the general level of inflation affects certain of our costs, factors unique to the petroleum industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us. The following table indicates the average oil and natural gas prices received for the three and six months ended June 30, 2002 and 2001. Average equivalent prices for the first half of 2002 and 2001 were decreased by $0.72 and $3.81 per BOE, respectively, as a result of our hedging activities. Average prices per equivalent barrel indicate the composite impact of changes in oil and natural gas prices. Natural gas sales volumes are converted to oil equivalents at the conversion rate of six Mcf per Bbl. All prices are before amortization of the Enron-related gain.
Oil Natural Gas Equiv. Oil (Per Bbl) (Per Mcf) (Per Boe) ------------ ------------ ------------ NET PRICE REALIZATION WITH HEDGES Quarter ended June 30, 2002 .............. $ 21.66 $ 2.82 $ 20.76 Quarter ended June 30, 2001 .............. 22.39 4.04 22.78 Six months ended June 30, 2002 ........... 20.17 2.61 19.28 Six months ended June 30, 2001 ........... 23.10 4.34 23.74 AVERAGE WELLHEAD PRICE Quarter ended June 30, 2002 .............. $ 23.39 $ 2.99 $ 22.34 Quarter ended June 30, 2001 .............. 24.98 4.78 25.78 Six months ended June 30, 2002 ........... 21.13 2.58 20.00 Six months ended June 30, 2001 ........... 25.82 5.63 27.55
17 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information included in "Quantitative and Qualitative Disclosures About Market Risk" in Encore's 2001 Annual Report filed on Form 10-K is incorporated herein by reference. Such information includes a description of Encore's potential exposure to market risks, including commodity price risk and interest rate risk. Encore's open commodity positions as of June 30, 2002 are presented in Note 6 to the accompanying financial statements. The fair value of our open commodity and interest rate hedges is ($9.0) million as of June 30, 2002. Subsequent to the end of the second quarter of 2002, we entered into several additional oil hedges. The following table summarizes the additional commodity hedging positions entered into through August 2, 2002:
Daily Floor Daily Cap Floor Volume Price Cap Volume Price Period (Bbl) (Per Bbl) (Bbl) (Per Bbl) --------- ------------ ------------ ------------ ------------ Jan - Dec 2003 ..... 1,500 $ 22.00 1,500 $ 28.53 Jan - June 2004 .... 1,500 21.00 1,500 27.65
18 PART II. OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Company's annual meeting of stockholders was held Tuesday, April 23, 2002. The sole item submitted to stockholders for vote was the election of seven nominees to serve on the Company's board of directors during 2002 and until the Company's next annual meeting. Notice of the meeting and proxy information was distributed to stockholders prior to the meeting in accordance with federal securities laws. There were no solicitations in opposition to the nominees. Out of a total of 30,028,439 shares of the Company's Common Stock outstanding and entitled to vote, 19,605,568 shares (65.29%) were present at the meeting in person or by proxy. The vote tabulation with respect to each nominee was as follows:
AUTHORITY NOMINEE FOR WITHHELD --------------------- ----------- ---------- I. Jon Brumley 19,110,407 495,161 Jon S. Brumley 19,096,132 509,436 Arnold L. Chavkin 19,540,593 64,975 Howard H. Newman 19,600,593 4,979 Ted A. Gardner 19,600,793 4,775 Ted Collins, Jr. 19,600,593 4,975 James A. Winne, III 19,600,593 4,975
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K EXHIBITS 4.1 Indenture, dated June 25, 2002, between the Company and Wells Fargo Bank, N.A., as Trustee. 4.2 Rights Agreement, dated June 19, 2002, between the Company and Credit Suisse First Boston Corporation, as Rights Agent. 10.1 $300,000,000 Credit Agreement dated June 25, 2002, among the Company, as Borrower, Fleet National Bank, as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent, and certain financial institutions, as banks. 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 REPORTS ON FORM 8-K During the three months ended June 30, 2002, the Company filed with the SEC current reports on Form 8-K on April 5, June 10, and June 26. The Company's April 5 Form 8-K discloses the Company's dismissal of Arthur Andersen LLP and appointment of Ernst & Young LLP as its independent auditors for the fiscal year 2002. The Company filed two Form 8-Ks on June 10. The first (i) reporting estimates of the Company's pro forma oil and natural gas reserves at March 31, 2002 to reflect acquisitions completed since January 1, 2002 and (ii) updating the Company's estimated average daily sales volumes for 2002. The second includes as an exhibit a press release stating the Company's intentions to offer approximately $150 million of Senior Subordinated Notes through a private placement. The Company's June 26 Form 8-K filing includes as an exhibit a press release announcing the private placement sale of $150 million of its 8 3/8% Senior Subordinated Notes due 2012. 19 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ENCORE ACQUISITION COMPANY Date: December 5, 2002 By: /s/ Morris B. Smith --------------------------------------------------- Morris B. Smith Chief Financial Officer, Treasurer, Executive Vice President, Secretary, and Principal Financial Officer Date: December 5, 2002 By: /s/ Robert C. Reeves --------------------------------------------------- Robert C. Reeves Vice President, Controller and Principal Accounting Officer 20 INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION ------- ----------- 4.1 Indenture, dated June 25, 2002, between the Company and Wells Fargo Bank, N.A., as Trustee. 4.2 Rights Agreement, dated June 19, 2002, between the Company and Credit Suisse First Boston Corporation, as Rights Agent. 10.1 $300,000,000 Credit Agreement dated June 25, 2002, among the Company, as Borrower, Fleet National Bank, as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent, and certain financial institutions, as banks. 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002