10-Q 1 d92114e10-q.txt FORM 10-Q FOR QUARTER ENDED SEPTEMBER 30, 2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 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 0-22576 COHO ENERGY, INC. (Exact name of registrant as specified in its charter) Texas 75-2488635 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification Number) 14785 Preston Road, Suite 860 Dallas, Texas 75254 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (972) 774-8300 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 twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X No Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Class Outstanding at November 13, 2001 Common Stock, par value $.01 per share 18,714,175
INDEX
PAGE PART I. FINANCIAL INFORMATION Item 1. Financial Statements Report of Independent Public Accountants 3 Condensed Consolidated Balance Sheets - December 31, 2000 and September 30, 2001 (Unaudited) 4 Condensed Consolidated Statements of Operations - three and nine months ended September 30, 2000 and 2001 (Unaudited) 5 Condensed Consolidated Statement of Shareholders' Equity - nine months ended September 30, 2001 (Unaudited) 6 Condensed Consolidated Statements of Cash Flows - nine months ended September 30, 2000 and 2001 (Unaudited) 7 Notes to Condensed Consolidated Financial Statements 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 3. Quantitative and Qualitative Disclosures About Market Risk 28 PART II. OTHER INFORMATION Item 1. Legal Proceedings 30 Item 2. Changes in Securities 30 Item 3. Defaults Upon Senior Securities 30 Item 4. Submission of Matters to a Vote of Security Holders 30 Item 5. Other Information 30 Item 6. Exhibits and Reports on Form 8-K 31 Signatures 32
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Coho Energy, Inc.: We have reviewed the accompanying condensed consolidated balance sheet of Coho Energy, Inc. (a Texas corporation) and subsidiaries as of September 30, 2001, and the related condensed consolidated statements of operations for the three-month and nine-month periods ended September 30, 2001 and 2000, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Coho Energy, Inc. and subsidiaries as of December 31, 2000 (not presented herein) and, in our report dated March 27, 2001, we expressed an unqualified opinion on that statement. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived. ARTHUR ANDERSEN LLP Dallas, Texas November 8, 2001 3 COHO ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS) ASSETS
DECEMBER 31 SEPTEMBER 30 2000 2001 ----------- ------------ (UNAUDITED) Current assets Cash and cash equivalents .................................... $ 6,661 $ 8,013 Cash in escrow ............................................... 1,042 25 Accounts receivable .......................................... 11,517 10,802 Accrued unrealized gains on derivatives ...................... -- 1,064 Other current assets ......................................... 483 922 -------- -------- 19,703 20,826 Property and equipment, at cost net of accumulated depletion and depreciation, based on full cost accounting method ........... 317,667 334,149 Other assets ................................................... 29,421 25,132 -------- -------- $ 366,791 $ 380,107 ========= ========= LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable, principally trade .......................... $ 5,343 $ 4,237 Accrued liabilities and other payables ....................... 9,773 6,680 Accrued reorganization costs ................................. 2,120 115 Accrued unrealized losses on derivatives .................... -- 2,700 Accrued interest ............................................. 4,078 1,996 Current portion of long term debt ............................ 1,036 1,698 -------- -------- 22,350 17,426 Long term debt, excluding current portion ...................... 282,412 280,038 Long term derivative liabilities ............................... -- 18,012 Commitments and contingencies .................................. 520 520 Shareholders' equity Preferred stock, par value $0.01 per share Authorized 10,000,000 shares, none issued .................. -- -- Common stock, par value $0.01 per share Authorized 50,000,000 shares Issued and outstanding 18,714,175 shares ................... 187 187 Additional paid-in capital ................................... 324,070 324,380 Other comprehensive loss ..................................... -- (149) Retained deficit ............................................. (262,748) (260,307) -------- -------- Total shareholders' equity .............................. 61,509 64,111 -------- -------- $ 366,791 $ 380,107 ========= =========
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 4 COHO ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
NINE MONTHS ENDED THREE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ----------------- ------------------ 2000 2001 2000 2001 ---- ---- ---- ---- Operating revenues Net crude oil and natural gas production ....... $ 68,451 $ 60,826 $ 21,947 $ 19,681 -------- -------- -------- -------- Operating expenses Crude oil and natural gas production ........... 17,330 18,864 6,087 6,816 Taxes on oil and gas production ................ 4,122 3,932 1,516 1,226 General and administrative ..................... 5,408 3,980 1,703 1,143 Loss on derivatives ............................ -- 1,705 -- 118 Allowance for bad debt ......................... 765 -- -- -- Depletion and depreciation ..................... 11,173 12,764 3,777 4,354 -------- -------- -------- -------- Total operating expenses .................. 38,798 41,245 13,083 13,657 -------- -------- -------- -------- Operating income ................................. 29,653 19,581 8,864 6,024 -------- -------- -------- -------- Other income and expenses Interest and other income ...................... 322 214 181 71 Interest expense ............................... (26,611) (26,889) (9,307) (8,670) (Loss) gain on standby loan embedded derivative (26,460) (1,840) (22,500) 1,140 -------- -------- -------- -------- (52,749) (28,515) (31,626) (7,459) -------- -------- -------- -------- Loss from operations before reorganization costs, income taxes, accumulated effect of an accounting change and extraordinary item ....... (23,096) (8,934) (22,762) (1,435) Reorganization costs ............................. (12,459) 2,195 (277) 45 -------- -------- -------- -------- Loss before income taxes, accumulated effect of an accounting change and extraordinary item ....... (35,555) (6,739) (23,039) (1,390) Income tax expense (benefit) ..................... -- -- -- -- -------- -------- -------- -------- Loss before accumulated effect of an accounting change and extraordinary item .................. (35,555) (6,739) (23,039) (1,390) Accumulated effect of an accounting change ....... -- 9,180 -- -- Extraordinary item - loss on extinguishment of indebtedness ................................... (4,428) -- -- -- -------- -------- -------- -------- Net (loss) income ................................ $(39,983) $ 2,441 $(23,039) $ (1,390) ======== ======== ======== ======== Basic and diluted loss per common share Loss before extraordinary item and accumulated effect of an accounting change ............... $ (2.78) $ (.36) $ (1.23) $ (.07) Net (loss) income .............................. $ (3.13) $ .13 $ (1.23) $ (.07)
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 5 COHO ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT SHARE AMOUNTS)
NUMBER OF COMMON ADDITIONAL OTHER RETAINED SHARES COMMON PAID-IN COMPREHENSIVE EARNINGS OUTSTANDING STOCK CAPITAL INCOME (LOSS) (DEFICIT) TOTAL ----------- ----- ------- ------------- --------- ----- Balance at December 31, 2000 ... 18,714,175 $ 187 $ 324,070 $ -- $ (262,748) $ 61,509 Stock option compensation .... -- -- 310 -- -- 310 Net income ................... -- -- -- -- 2,441 2,441 Change in fair market value of hedging derivatives ....... -- -- -- 5,678 -- 5,678 Accumulated effect of an accounting change ......... -- -- -- (5,827) -- (5,827) ---------- ---------- ---------- ---------- ---------- ---------- Balance at September 30, 2001 .. 18,714,175 $ 187 $ 324,380 $ (149) $ (260,307) $ 64,111 ========== ========== ========== ========== ========== ==========
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 6 COHO ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30 ----------------- 2000 2001 ---- ---- Cash flows from operating activities Net (loss) income ................................................. $ (39,983) $ 2,441 Adjustments to reconcile net (loss) income to net cash provided by operating activities: Depletion and depreciation .................................... 11,173 12,764 Extraordinary item - loss on extinguishment of debt ........... 4,428 -- Standby loan interest ......................................... 6,523 10,306 Loss on standby loan embedded derivative ...................... 26,460 1,840 Accumulated effect of an accounting change .................... -- (9,180) Loss on derivatives ........................................... -- 1,212 Amortization of debt issuance costs and other ................. 5,240 3,833 Changes in operating assets and liabilities: Accounts receivable and other assets .......................... (1,870) 1,081 Accounts payable and accrued liabilities ...................... (7,331) (6,986) --------- -------- Net cash provided by operating activities ........................... 4,640 17,311 --------- -------- Cash flows from investing activities Property and equipment ........................................ (15,545) (29,311) Changes in accounts payable and accrued liabilities related to exploration and development ................................ 1,790 (1,365) --------- -------- Net cash used in investing activities ............................... (13,755) (30,676) --------- -------- Cash flows from financing activities Increase in long term debt .................................... 255,000 15,000 Repayment of long term debt ................................... (239,600) (283) Debt issuance costs ........................................... (9,427) -- Debt extinguishment costs ..................................... (2,126) -- --------- -------- Net cash provided by financing activities ........................... 3,847 14,717 --------- -------- Net decrease (increase) in cash and cash equivalents ................ (5,268) 1,352 Cash and cash equivalents at beginning of period..................... 18,805 6,661 --------- -------- Cash and cash equivalents at end of period .......................... $ 13,537 $ 8,013 ========= ======== Cash paid (received) during the period for: Interest ...................................................... $ 28,721 $ 13,995 Income taxes .................................................. $ -- $ 283 Reorganization costs .......................................... $ 6,730 $ 2,452 Reorganization receipts (interest income) ..................... $ (260) $ --
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 7 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) 1. BASIS OF PRESENTATION General The accompanying condensed consolidated financial statements of Coho Energy, Inc. (the "Company") and subsidiaries have been prepared without audit, in accordance with the rules and regulations of the Securities and Exchange Commission and do not include all disclosures normally required by generally accepted accounting principles or those normally made in annual reports on Form 10-K. All material adjustments, consisting only of normal recurring accruals other than adjustments related to the Company's plan of reorganization and adjustments to record the accumulated effect of an accounting change, which, in the opinion of management, were necessary for a fair presentation of the results for the interim periods, have been made. The results of operations for the nine month period ended September 30, 2001 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements should be read in conjunction with the notes to the financial statements, which are included as part of the Company's Annual Report on Form 10-K for the year ended December 31, 2000. On August 23, 1999, the Company and certain wholly-owned subsidiaries filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. On March 31, 2000, the Company emerged from bankruptcy. The reorganized value of the Company's assets exceeded the total of all postpetition liabilities and allowed claims; therefore, the Company did not qualify for fresh-start accounting. See the Company's Annual Report on Form 10-K for the year ended December 31, 2000 for further discussion on the Company's bankruptcy proceedings and reorganization. Accounts Receivable The Company performs ongoing reviews with respect to accounts receivable and maintains an allowance for doubtful accounts receivable ($675,000 and $495,000 at December 31, 2000 and September 30, 2001, respectively) based on expected collectibility. Other Assets Other assets at December 31, 2000 and September 30, 2001 include unamortized debt issuance costs related to the Company's senior subordinated notes due 2007, also referred to as the standby loan, of $24.1 million and $21.3 million, respectively, and senior revolving credit facility of $5.2 million and $3.5 million, respectively. These costs are amortized using the straight line method over the terms of the related financing. In addition, other assets at September 30, 2001 include accrued unrealized long term gains of $297,000 on the Company's cash flow hedge arrangements. Stock-Based Compensation The Company has elected to follow Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for its stock option plans. Pursuant to APB No. 25, no compensation expense is recognized for stock option awards when the exercise price of the Company's stock options equals the market price of the underlying stock on the measurement date. On April 1, 2000, the Company awarded approximately 491,000 stock options with an exercise price less than the market price on the measurement date by $1.68 per share. Compensation costs are being amortized using the straight line method over the two-year vesting period of the stock options. The Company has recognized $310,000 of compensation expense related to such stock options at September 30, 2001. Hedging Activities and Other Derivative Instruments The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement required the Company to recognize all derivative instruments (including certain 8 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability based on fair value on January 1, 2001. The accumulated effect of this accounting change resulted in an increase in net income of $9.2 million and a decrease in other comprehensive income ("OCI") of $5.8 million during the nine months ended September 30, 2001. Subsequent changes in fair value for the effective portion of derivatives qualifying as hedges will be recognized in OCI until the sale of the related hedged production is recognized in earnings, at which time changes in fair value previously recognized in other comprehensive income will be reclassified to earnings and recognized in operating revenues. Based on the OCI recorded as of September 30, 2001, $388,000 of deferred net losses on derivatives would be reclassified to earnings during the next twelve-month period upon the sale of hedged production. Subsequent changes in fair value for the ineffective portion of derivatives qualifying as hedges and for derivatives that are not hedges must be adjusted to fair value through earnings and recognized in loss on derivatives in the period where the change in fair value occurs. For the nine month and three month periods ended September 30, 2001, the Company recorded losses on derivatives due to changes in the fair value for the ineffective portion of derivatives of $1.7 million and $255,000, respectively. Certain derivatives, representing 4% of our hedging arrangements, which previously qualified for hedge accounting treatment under SFAS No. 133 failed to qualify for such treatment during the third quarter of 2001, resulting in a reduction in loss on derivatives of $80,000 for the nine and three month periods ended September 30, 2001. The Company has entered into certain arrangements that fix a minimum and maximum price range for a portion of its future crude oil and natural gas production. The Company entered into these arrangements to reduce the downside risk associated with potential crude oil and natural gas price declines by setting a floor price for its future production based on the NYMEX crude oil and natural gas prices. Due to working capital constraints, the Company entered into the "costless collar" type of transactions because they do not require upfront premiums. These hedge arrangements qualify as cash flow hedges under SFAS No. 133. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for further discussion on the Company's hedge arrangements and a summary of the Company's existing hedge arrangements. The Company has entered into notes in connection with the standby loan agreement and certain lease agreements which contain provisions for payments based on crude oil and natural gas prices. These agreements are considered to include embedded derivatives under SFAS No. 133. See note 4 for additional discussion on agreements containing embedded derivatives. 2. PROPERTY AND EQUIPMENT
December 31, September 30, 2000 2001 ------------ ------------- Crude oil and natural gas leases and rights including exploration, development and equipment thereon, at cost ................................... $ 709,118 $ 738,364 Accumulated depletion and depreciation ......................................... (391,451) (404,215) -------- -------- $ 317,667 $ 334,149 ========= =========
Due to a cessation of exploration and development of crude oil and natural gas reserves during the first quarter of 2000 all overhead expenditures were charged to general and administrative expense. Subsequent to the first quarter of 2000, the Company increased development work, therefore related overhead and expenditures of $510,000 were capitalized in the second and third quarters of 2000 and related overhead and expenditures of $720,000 have been capitalized for the nine months ended September 30, 2001. During the nine months ended September 30, 2000 and 2001, the Company did not capitalize any interest or other financing charges on funds borrowed to finance unproved properties or major development projects. 9 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) Unproved crude oil and natural gas properties totaling $30,603,000 and $31,305,000 at December 31, 2000 and September 30, 2001, respectively, were excluded from costs subject to depletion. These costs are anticipated to be included in costs subject to depletion within the next five years. 3. LONG-TERM DEBT
December 31, September 30, 2000 2001 ------------ ------------- Credit facility ................................... $ 180,000 $ 195,000 Standby loan (senior subordinated notes due 2007) . 77,358 93,452 Standby loan embedded derivative .................. 15,163 18,012 Standby loan interest to be paid-in-kind .......... 4,732 117 Promissory notes .................................. 5,195 3,589 Other ............................................. 1,000 1,000 --------- ---------- 283,448 311,170 Unamortized original issue discount on standby loan -- (11,422) Current maturities of long-term debt .............. (1,036) (1,698) --------- ---------- $ 282,412 $ 298,050 ========= =========
Credit Facility The senior revolving credit facility was obtained from a syndicate of lenders led by The Chase Manhattan Bank, as agent for the lenders, and has a maximum loan commitment amount of $250 million. The credit facility limits permitted advances to the amount of the borrowing base, which is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on the Company's reserve reports, and will be made at the sole discretion of the lenders. The April 1, 2001 redetermination resulted in a decrease in the Company's borrowing base from $205 million to $195 million. At September 30, 2001, $195 million in advances were outstanding under the revolving credit facility. See note 9 for discussion on the redetermination of the borrowing base to $175 million effective November 1, 2001. The credit agreement contains financial and other covenants including: - maintenance of required ratios of cash flow to interest expense paid or payable in cash (not less than 2.50 to 1 for the average of the last four consecutive quarters most recently ended September 30, 2001; 2.75 to 1 for the average of the last four consecutive quarters ending December 31, 2001; and 3.0 to 1 for the average of the last four quarters for any quarter ending after January 1, 2002), senior debt to cash flow required (not to exceed 4.25 to 1 for the average of the last four consecutive quarters most recently ended September 30, 2001; 3.75 to 1 for the average of the last four quarters ending December 31, 2001; and 3.5 to 1 for the average of the last four consecutive quarters for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be not less than 1 to 1 as of the end of each quarter); - restrictions on the payment of dividends; and - limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. The credit agreement covenants exclude non-cash transactions resulting from the adoption and accounting treatment under SFAS No. 133. 10 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) Standby Loan On March 31, 2000, the Company issued, mainly to its majority shareholders, an aggregate principal amount of $72 million in senior subordinated notes due March 31, 2007. These senior subordinated notes, herein referred to as the "standby loan," bear interest at a minimum annual rate of 15% plus additional interest, after March 31, 2001, in an amount equal to 1/2% for every $0.25 that the "actual price" for the Company's crude oil and natural gas production exceeds $15 per barrel of oil equivalent up to a maximum of 10% additional interest per year. Any time the average realized price exceeds $20 per barrel of oil equivalent, the Company will have to pay the 10% maximum additional interest. See the notes to the consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2000 for a detailed description of the additional interest calculations. The senior subordinated notes require semiannual interest payments which are required to be paid-in-kind under the intercreditor arrangement between the standby lenders and the lenders under the senior revolving credit facility unless we meet specified financial tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The standby loan semiannual interest payments of $5.8 million were paid-in-kind when due on March 30, 2001 and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $4.4 million and $1.4 million, respectively. The standby loan interest payments of $10.3 million, which were at the maximum interest rate of 25%, were paid-in-kind when due on September 28, 2001 and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $8.3 million and $2.0 million, respectively. Interest accruing on the standby loan, subsequent to the previous semiannual interest payment, is reflected in long term debt until the next semiannual interest payment is paid in cash or paid-in-kind. We may prepay, or may be required to repay, under certain circumstances, the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1 million, plus a prepayment fee calculated in accordance with the prepayment provision of the standby loan agreement. As of September 30, 2001, the prepayment fee for the then total outstanding principal amounts, using then current treasury rates, would have been approximately $33.9 million. The Company adopted SFAS No. 133 effective January 1, 2001. This statement required the Company to record the fair value of the additional semiannual interest feature, which is considered an embedded derivative, in long term derivative liabilities (see note 4). Accordingly, a debt discount has been recorded related to the standby loans reflecting the fair value of the embedded derivatives at the date the original notes were issued. The debt discount is amortized into interest expense using the straight line method over the term of the related notes. Promissory Notes Claims for tax, penalty and interest were filed against the Company by the State of Louisiana and the State of Mississippi. The Company has settled claims with both taxing authorities. Five-year, interest-bearing promissory notes were issued for settlement of these priority tax claims, of which $2.9 million is included in long term debt and $698,000 is included in current portion of long term debt. Other The Company has settled the claims of Chevron Corp. and Chevron USA for indemnification of any environmental liabilities in the Brookhaven field. The terms of this settlement require the Company to fund $2.5 million over a two year period to partially finance the implementation of a remediation plan. The Company paid $1.0 million in June 2000, $500,000 on January 1, 2001 and the remaining $1.0 million, due on January 1, 2002, is included in current portion of long term debt. 11 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) 4. LONG TERM DERIVATIVE LIABILITIES The standby loan agreement (see note 3) contains an additional semiannual interest feature which is calculated based on the actual price the Company receives for its oil and gas production. The additional interest feature of the standby loan agreement is considered an embedded derivative under SFAS No. 133. The fair value of the embedded derivative is recorded on the balance sheet and included in long term derivative liabilities in the amount of $17.7 million at September 30, 2001. Certain leases in Laurel, Mississippi contain provisions for a portion of the lease payments to be based on the price of crude oil. These provisions are considered embedded derivatives under SFAS No. 133 and are recorded at their fair value of $327,000, with $55,000 recorded in current liabilities and $272,000 in long term derivative liabilities, at September 30, 2001. 5. EARNINGS PER SHARE Basic and diluted earnings per share ("EPS") have been calculated based on the weighted average number of shares outstanding for the nine months ended September 30, 2000 and 2001 of 12,772,900 and 18,714,175, respectively, and for the three months ended September 30, 2000 and 2001 of 18,714,175. For the nine months ended September 30, 2000 and for the three months ended September 30, 2000 and 2001, conversion of stock options and warrants would have been antidilutive and, therefore, was not considered in diluted EPS. 6. COMPREHENSIVE INCOME Comprehensive income includes net income and certain items recorded directly to Stockholders' Equity and classified as OCI. Following the adoption of SFAS No. 133 on January 1, 2001, the Company recorded a decrease of $5.8 million in OCI and has subsequently recorded additional changes in OCI related to the Company's crude oil and natural gas hedging arrangements. Comprehensive income for the nine months ended September 30, 2001 and September 30, 2000 is as follows:
Nine Months Ended September 30 ------------------ 2001 2000 ---- ---- Net Income (Loss) ................................... $ 2,441 $(39,983) Other Comprehensive Income Cumulative effect of change in accounting ....... (5,827) -- Changes in fair value of open hedging positions . 1,101 -- Reclassification adjustment for settled contracts 4,577 -- ------- -------- Comprehensive Income (Loss) ......................... $ 2,292 $(39,983) ======= ========
7. COMMITMENTS AND CONTINGENCIES Like other crude oil and natural gas producers, the Company's operations are subject to extensive and rapidly changing federal and state environmental regulations governing emissions into the atmosphere, waste water discharges, solid and hazardous waste management activities and site restoration and abandonment activities. At September 30, 2001, the Company has accrued approximately $584,000 related to such costs, of which $64,000 is included in current liabilities and $520,000 is included in contingent liabilities. At this time, the Company does not believe that any potential liability, in excess of amounts already provided for, would have a significant effect on the Company's financial position. On May 27, 1999, the Company filed a lawsuit against five affiliates of Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by 12 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998, (2) breach of the oral agreements reached with HM4 on the restructured transaction in February 1999 and (3) promissory estoppel. The Company reached a settlement of the litigation in May, 2001, subject to approval of the United States Bankruptcy Court (the "Bankruptcy Court") and resolution of certain disputes relating to a matter under seal by order of the Bankruptcy Court as discussed below. Final settlement documents were signed during October 2001 and the Company anticipates presenting the matter to the Bankruptcy Court for approval during the fourth quarter of 2001 or early 2002. The Company does not expect the settlement to have a material impact on the Company's financial position or results of operations. Pursuant to the Company's plan of reorganization, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of the proceeds available from the Hicks Muse lawsuit settlement after fees and expenses. During 2001, the Company became involved in a matter in connection with the lawsuit filed by the Company against Hicks Muse. This matter is under seal by order of the Bankruptcy Court. The matter involves a termination issue and the plaintiff claims damages that are based on a percentage of the ultimate amount recovered, if any, in the lawsuit against Hicks Muse. These percentages would be calculated on a graduated scale decreasing from 30% to 10% as the amount recovered increases. Alternatively, the plaintiff claims damages on the basis of lost time. However, the Company does not believe that either of these methods represents an appropriate measure of damages. The Company believes that the claim is without merit. At the order of the Bankruptcy Court, certain matters were arbitrated. The arbitration panel's sealed findings have been forwarded to the Bankruptcy Court for further proceedings and consideration in conjunction with the pending settlement discussed above. The Company does not expect this matter to have a material impact on its financial position or results of operations. Resolution of this matter may, however, impact the amount of proceeds available to the Company from the settlement of the Hicks Muse lawsuit. On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit against certain former officers of the Company alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by the Company. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. Subsequently, the plaintiff named Ryder Scott Company and Sproule Associates Inc., the independent petroleum consultants which evaluate the Company's oil and gas reserves, as additional defendants. Pursuant to the Company's bylaws, the Company may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by the Company's directors' and officers' liability insurance policy. The settlement of the Company's lawsuit against certain affiliates of Hicks, Muse, Tate & Furst, as described above, requires dismissal of the claims against the former officers. If the suit continues against Ryder Scott Company and Sproule Associates Inc., the Company may be required to indemnify these companies subject to terms and conditions contained in certain agreements with these companies; however, the Company does not expect this matter to have a material impact on its financial position or results of operations. 8. TUNISIAN OPERATIONS The Company decided to discontinue its participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to its interest. The two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May 2001, Coho International entered into a settlement agreement with the other joint owners in the permit area. Under this agreement, Coho International assigned its interest in the Fejaj permit to the other joint owners in exchange for the assumption by the other joint owners of Coho International's existing obligations and existing payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a definitive agreement to sell all of its interest in the Anaguid permit to Pioneer Natural Resources Company and the other joint owners in the permit area for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's obligations under the permit totaling in excess of $7 million. These sales agreements have been approved by the United States Bankruptcy Court, but the sale of the Anaguid permit is still subject to approval by the Tunisian government. The Company intends to convert the bankruptcy proceedings for Coho Anaguid and Coho International from Chapter 11 reorganization proceedings to Chapter 7 liquidation proceedings during the fourth quarter of 2001 to wind down these proceedings. The Company has not recorded the liabilities subject to compromise for these subsidiaries in its consolidated balance sheet as of September 30, 2001 because these 13 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) liabilities are solely obligations of the bankrupt subsidiaries and, furthermore, substantially all of the obligations of these subsidiaries will be assumed under the sales agreements. The Chapter 11 filing included Coho Anaguid, Inc. and Coho International Limited. The following information summarizes the combined results of operations for these subsidiaries. This information has been prepared on the same basis as the consolidated financial statements.
Nine Months Ended September 30, 2001 ------------------ Current assets ............... $ 23 -------- Total assets ............... $ 23 ======== Current liabilities .......... $ 17 Accounts payable to affiliates 10,278 Shareholder's equity ......... (10,272) -------- $ 23 ======== Operating expenses ........... $ 55 Net loss ..................... $ 55
9. SUBSEQUENT EVENT Borrowing Base Redetermination On November 1, 2001, the lenders under the senior revolving credit facility notified the Company that its borrowing base under this facility had been redetermined in the semiannual review from $195 million to $175 million effective November 1, 2001. On November 2, 2001, the Company received a notice of borrowing base deficiency because borrowings under this facility exceed the redetermined borrowing base by $20 million. Under the credit facility, the Company may remedy the borrowing base deficiency by providing additional collateral sufficient to eliminate the borrowing base deficiency or making a cash payment sufficient to eliminate the borrowing base deficiency. Currently, all of the Company's assets are pledged as collateral under the credit facility and, based on operating projections, the Company will not have sufficient working capital to make a cash payment that would eliminate the borrowing base deficiency. On November 6, 2001, the Company notified the lenders that it intends to sell a portion of its oil and gas assets and to make a cash payment sufficient to eliminate the borrowing base deficiency within the 90-day cure period provided under the facility. If the Company is unable to cure the borrowing base deficiency through the sale of a portion of its oil and gas assets, other alternatives available to the Company are: - working with the lenders to amend the credit facility to allow the Company to make cash payments over a longer period of time to cure the deficiency; - raising additional debt or equity; or - any combination of these alternatives. Although there is no assurance that the Company will be successful, it intends to aggressively pursue a sale of a portion of its assets to obtain the funds necessary to eliminate the borrowing base deficiency. If the Company is unsuccessful in resolving the borrowing base deficiency, through the alternatives discussed above, it may seek protection under Chapter 11 of the United States Bankruptcy Code while it pursues other financing and/or reorganization alternatives. 14 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) (UNAUDITED) Effective November 1, 2001, $20 million under the senior revolving credit facility will be classified as a current liability due to the borrowing base redetermination. The remaining outstanding balance of $175 million under the senior revolving credit facility will be classified as long term because the Company believes that a sale of a portion of its assets during the cure period is possible and, that under accounting rules, it is not virtually certain that the Company will be in default under the senior revolving credit facility. 15 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Some of this information with respect to our plans and strategy for our business contains forward-looking statements. These statements are based on certain assumptions and analyses made by our management in light of their perception of expected future developments and other factors they believe are appropriate. Such statements are not guarantees of future performance and our actual results may differ materially from those projected in the forward-looking statements. GENERAL We have a high level of indebtedness with total consolidated indebtedness of $315.5 million and a ratio of total consolidated indebtedness to total capitalization of 83% as of September 30, 2001. Our major borrowings are comprised of $195 million under a senior revolving bank credit facility and $93.5 million under senior subordinated notes due 2007 that were issued mainly to our majority shareholders and herein referred to as the standby loan. Interest owed under our standby loan is currently required to be "paid-in-kind" by increasing the amount of the principal outstanding through the issuance of additional standby notes. In April 2001, we entered into an agreement with JP Morgan, a division of Chase Securities, to act as our financial advisor in evaluating various strategic transactions including: - various potential recapitalization transactions, - the sale of a portion of our company to provide more available working capital for our remaining properties, or - the sale of all of our company. In September 2001, we announced that we had entered into a non-binding letter of intent for the sale of our Mississippi oil and gas assets to an undisclosed third party for $80 million. Although negotiations continue with the third party, this letter of intent expired in October 2001 and we have reinitiated discussions with other potential purchasers. Given our high level of indebtedness, if we elect to pursue any such transactions and are successful, there can be no assurance that, after giving effect to any required repayment or prepayment of our indebtedness, any significant amount will be available to provide additional working capital for our operations or, in the event of a sale of all of our assets, for distribution to our shareholders. On November 1, 2001, the lenders under our senior revolving bank credit facility notified us that our borrowing base under this facility had been reduced from $195 million to $175 million effective November 1, 2001. We have notified the lenders that we intend to sell a portion of our oil and gas assets and to make a cash payment sufficient to eliminate the $20 million borrowing base deficiency within the 90-day cure period. There can be no assurance that we will be successful in curing the borrowing base deficiency through the sale of a portion of our oil and gas assets. See "Liquidity and Capital Resources - Credit Facilities" for further discussion regarding other alternatives available to us and other issues related to our credit facilities. Average net daily barrel of oil equivalent ("BOE") production was 10,885 BOE for the nine months ended September 30, 2001 as compared to 10,675 BOE for the same period in 2000. For purposes of determining BOE herein, natural gas is converted to barrels ("Bbl") on a six thousand cubic feet ("Mcf") to one Bbl basis. Our crude oil production increased in the first nine months of 2001 due to overall production increases on our operated properties; however, this increase was partially offset by decreases in natural gas production on our operated properties, decreases in crude oil and natural gas production on our properties operated by third parties and losses of production due to power outages as discussed below under "Results of Operations - Operating Revenues." Based on our current cash flow projections and existing debt constraints, management does not believe the forecasted future capital expenditure levels will be adequate to materially improve our crude oil and natural gas production above current levels. 16 LIQUIDITY AND CAPITAL RESOURCES Cash Flow Provided by Operating Activities. For the nine months ended September 30, 2001, cash flow provided by operating activities was $17.3 million compared with cash flow provided by operating activities of $4.6 million for the same period in 2000. Operating revenues, net of lease operating expenses, production taxes and general and administrative expenses, decreased $7.5 million from $41.6 million in the first nine months of 2000 to $34.1 million in the first nine months of 2001, primarily due to: - realized crude oil price decreases of 15% between such comparable periods; - decreases in natural gas production; and - increases in production expenses. These decreases were partially offset by: - increases in crude oil production; - increases in the price received for natural gas; and - decreases in general and administrative expenses. Cash flow provided by operating activities also included $11.4 million in reorganization costs (excluding $1.1 million Tunisian impairment) in the first nine months of 2000 and $17.0 million in interest expense on our old and new bank credit facilities in the first nine months of 2000 as compared to a reduction of $2.2 million in reorganization costs and $11.8 million in interest expense on our new credit facility for the first nine months of 2001. Changes in operating assets and liabilities resulted in $5.9 million of cash used for operating activities for the nine months ended September 30, 2001, compared to $9.2 million of cash used for operating activities for the same period in 2000. See "Results of Operations" for a discussion of operating results. Working Capital. We had working capital of $3.4 million at September 30, 2001 compared to a working capital deficit of $2.6 million at December 31, 2000. The increase in working capital at September 30, 2001 is primarily due to several factors including: - an increase of $1.1 million in accrued unrealized gains on derivatives due to the adoption of SFAS. No. 133; - a decrease of $1.1 million in trade payables; - a decrease of $2.0 million in accrued reorganization costs; - a decrease of $2.1 million in accrued interest payable; - a decrease of $1.6 million in accrued operating costs; - a decrease of $1.5 million in various other accrued liabilities; - an increase of $662,000 in current long term debt related to environmental claims and priority tax claims; and - an increase of $2.7 million in accrued unrealized losses on derivatives due to the adoption of SFAS. No. 133. Credit Facilities. The senior revolving credit facility was obtained from a syndicate of lenders led by The Chase Manhattan Bank, as agent for the lenders, and has a maximum loan commitment amount of up to $250 million. The credit facility limits advances to the amount of the borrowing base, which is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on the Company's reserve reports. The April 1, 2001 redetermination resulted in a decrease in our borrowing base from $205 million to $195 million. At September 30, 17 2001, $195 million in advances were outstanding under the revolving credit facility. On November 1, 2001, the lenders under the senior revolving credit facility notified us that our borrowing base under this facility had been redetermined in the semiannual review from $195 million to $175 million effective November 1, 2001. On November 2, 2001, we received a notice of borrowing base deficiency because borrowings under the credit facility exceed the redetermined borrowing base by $20 million. Under the credit facility, we may remedy the borrowing base deficiency by providing additional collateral sufficient to eliminate the borrowing base deficiency or making a cash payment sufficient to eliminate the borrowing base deficiency. Currently, all of our assets are pledged as collateral under the credit facility and, based on operating projections, we will not have sufficient working capital to make a cash payment that would eliminate the borrowing base deficiency. On November 6, 2001, we notified the lenders that we intend to sell a portion of our oil and gas assets to avoid an event of default and to make a cash payment sufficient to eliminate the borrowing base deficiency within the 90-day cure period commencing on November 2, 2001, as provided under the facility. Failure to cure the borrowing base deficiency within such 90 day period would constitute an event of default under the credit facility. If we are unable to cure the borrowing base deficiency through the sale of a portion of our oil and gas assets, other alternatives available to us are: - working with the lenders to amend the credit facility to allow us to make cash payments over a longer period of time to cure the deficiency; - raising additional debt or equity; or - any combination of these alternatives. Although there is no assurance that we will be successful, we intend to aggressively pursue a sale of a portion of our assets to obtain the funds necessary to eliminate the borrowing base deficiency. If we are unsuccessful in resolving the borrowing base deficiency, through the alternatives discussed above, we may seek protection under Chapter 11 of the United States Bankruptcy Code while we pursue other financing and/or reorganization alternatives. Effective November 1, 2001, $20 million under the senior revolving credit facility will be classified as a current liability due to the borrowing base redetermination. The remaining outstanding balance of $175 million under the senior revolving credit facility will be classified as long term because we believe that a sale of a portion of our assets during the cure period is possible and, that under accounting rules, it is not virtually certain that we will be in default under the senior revolving credit facility. The credit agreement contains financial and other covenants including: - maintenance of required ratios of cash flow to interest expense paid or payable in cash (not less than 2.50 to 1 for the average of the last four consecutive quarters most recently ended September 30, 2001; 2.75 to 1 for the average of the last four consecutive quarters ending December 31, 2001; and 3.0 to 1 for the average of the last four quarters for any quarter ending after January 1, 2002), senior debt to cash flow required (not to exceed 4.25 to 1 for the average of the last four consecutive quarters most recently ended September 30, 2001; 3.75 to 1 for the average of the last four quarter ending December 31, 2001; and 3.5 to 1 for the average of the last four consecutive quarters for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be not less than 1 to 1 as of the end of each quarter); - restrictions on the payment of dividends; and - limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. Non-cash transactions resulting from the adoption and accounting treatment of SFAS No. 133 are excluded from the calculation of covenant ratios under the credit facility. We believe that we were in compliance with all covenants under the credit facility as of September 30, 2001. As of September 30, 2001, the covenant ratios of cash flow to interest expense, senior debt to cash flow, and current assets to current liabilities were 2.82 to 1, 4.24 to 1, and 1.34 to 1, respectively. However, based on current future cash flow projections, we will be unable to maintain the required 18 ratio of senior debt to cash flow, as required by the credit agreement, beginning in the fourth quarter of 2001 and in future periods, unless we reduce our borrowings under the facility as discussed above. If we are unable to maintain the senior debt to cash flow ratio, we would seek to obtain from the lender an amendment to the credit facility to revise the required ratio of senior debt to cash flow to a level which we could comply; however, there is no assurance that an amendment could be obtained. If we were unable to obtain an amendment from the lenders, we would be in default under the credit facility. On March 31, 2000, we issued, mainly to our majority shareholders, an aggregate principal amount of $72 million in senior subordinated notes, due March 31, 2007. These senior subordinated notes, herein referred to as the "standby loan," bear interest at a minimum annual rate of 15% plus additional interest, after March 31, 2001, in an amount equal to 1/2% for every $0.25 that the "actual price" for our crude oil and natural gas production exceeds $15 per barrel of oil equivalent up to a maximum of 10% additional interest per year. Any time the average realized price exceeds $20 per barrel of oil equivalent, we will have to pay the 10% maximum additional interest. See the notes to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2000 for a complete description of these additional interest calculations. The semiannual interest payments under the standby loan are required to be paid-in-kind subject to the requirements of the intercreditor arrangement between the standby lenders and the lenders under the new credit agreement unless we meet specified financial tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The semiannual standby loan interest payments in the amount of $5.8 million, due on March 30, 2001 were paid-in-kind and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $4.4 million and $1.4 million, respectively. The standby loan interest payments of $10.3 million, which were at the maximum rate of 25%, were paid-in-kind when due on September 28, 2001, and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $8.3 million and $1.9 million, respectively. Interest accruing on the standby loan, subsequent to the previous semiannual interest payment is reflected in long term debt until the next semiannual interest is paid in cash or paid-in-kind. We may prepay, or may be required to repay, under certain circumstances, the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1,000,000, plus a prepayment fee calculated in accordance with the prepayment provision of the standby loan agreement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" in our Annual Report on Form 10-K for the year ended December 31, 2000 for a description of the calculation of the prepayment fee. As of September 30, 2001, the prepayment fee for the then total outstanding principal amounts, using then current treasury rates, was approximately $33.9 million, bringing the total obligation under the standby loan, including the prepayment fee, to approximately $127.3 million. The standby loan agreement contains certain covenants and cross default provisions, including a cross default provision which will automatically cause us to be in default under the terms of the standby loan agreement in the event we are in default under the senior revolving credit facility. In the event such default occurs, the standby lenders may declare all amounts due under the standby loan agreement immediately due, including principal, accrued interest and the prepayment fee. Capital Expenditures. During the first nine months of 2001, we incurred capital expenditures of $29.3 million compared with $15.5 million for the first nine months of 2000. We spent approximately $15.9 million in our Mississippi fields and $13.2 million in our Oklahoma fields during the first nine months of 2001. During this nine-month period, we drilled 32 wells, as listed below, and continued our development efforts through recompletions and workovers on existing wells and initiation or expansion of waterflood projects within the fields. Following are the wells drilled during 2001: Mississippi Fields: Brookhaven - 1 dry hole Cranfield - 1 producing gas Martinville - 2 producing oil Soso - 2 producing oil 19 Oklahoma Fields: Tatums - 10 producing oil; 5 service wells; 1 dry hole East Fitts - 3 producing oil; 1 suspended drilling Jennings-Deese - 1 producing oil; 3 service wells Eola - 1 producing oil; 1 dry hole During the third quarter of 2001, we focused our development drilling activities in our Oklahoma fields due to capital constraints and the anticipated sale of our Mississippi properties. We continued the expansion of the existing waterflood project in the Tatums unit with the completion of five producing oil wells, three service wells and one dry hole during the third quarter. The average daily production for the Tatums field has increased from an average of 605 BOEPD in the fourth quarter of 2000 to 708 BOEPD in the third quarter of 2001 due to the expansion of the waterflood project in 2001. We also drilled a producing oil well, the Feagin #13, to complete the shallow Ponotoc waterflood project in the Jennings-Deese field that had been initiated in the first quarter of 2001 through the drilling of three water injection wells. In addition, we were able to deepen this well to the Hoxbar reservoir that had not been previously tested in this area. The Feagin #13 well is currently producing 102 BOEPD net to our interest from the Hoxbar and Pontotoc formations. We believe there are additional development locations in the Pontotoc and Hoxbar reservoirs, including one offset location that will be drilled in the fourth quarter of 2001. At September 30, 2001, we were in the process of completing the Story #4 well, a development well in the Eola field, and had initiated drilling of the Jarman #2 well late in September 2001, an exploratory well in the Eola field. These wells were selected because we own high working interests in both wells (98.9% and 95% working interests in the Story #4 and the Jarman #2, respectively) and both wells should produce in economically attractive quantities if completions are successful. The Story #4 well is a development well offsetting the Jones "E" #1 well. The Jones "E" #1 was completed as a producing well in March of this year in the Upper McLish reservoir in the Eola field and has been producing at approximately 232 BOPD net to our interest without any significant production decline since it began producing. The Story #4 was directionally drilled to 8,000 feet to develop the Upper McLish and Basal Bromide reservoirs but at a lateral extension of the reservoirs from the Jones "E" #1 well. The Story #4 penetrated these objective sections and log interpretations indicated that three separate intervals were oil productive. We are currently preparing to stimulate the productive intervals and to move in pumping equipment to place the well on production. The Jarman #2 well was chosen to develop a separate fault block of the Basal Oil Creek sand in the Eola field. The Basal Creek objective, at a target depth of 9,000 feet, is a potential oil reservoir with a natural waterdrive reservoir mechanism that is capable of high rates of production. Drilling was continuing on this well at the end of October 2001 with expected completion in mid-November if the well is successful. One of our key development projects is the infill-drilling program in our East Fitts field in Oklahoma. This field represents approximately 23% of our net proved reserves or 23.1 MMBOE based on December 31, 2000 reserve estimates. This infill-drilling program is designed to recover unswept oil reserves from areas of the reservoir by increasing the density of the drilling pattern from the historic ten-acre development to a five-acre drainage pattern. During the first six months of 2001, Coho drilled four wells on this project. Three of the wells are producing and one of the wells encountered a high-pressure water flow and was abandoned with the plan to re-enter the well at a later date with suitable drilling equipment and continue the completion. The average daily production for the East Fitts field has increased from an average of 1,166 BOEPD in the fourth quarter of 2000 to 1,241 BOEPD in the third quarter of 2001 due to the infill drilling in 2001. Production increases from the infill drilling are not initially significant but the production life of the reserves is expected to be long with a slow decline curve thereby offering an attractive return for this drilling program. We estimate that there are an additional 81 proved undeveloped locations remaining to be exploited in this manner. We did not drill any additional wells in the third quarter of 2001 and do not plan to drill any additional infill wells for the remainder of 2001 due to our capital constraints and resumption of this program in 2002 will be evaluated if capital is available. Another key development project is in our East Velma Middle Block unit in Oklahoma which represents approximately 12% of our net proved reserves or 11.6 MMBOE based on December 31, 2000 reserve estimates. The installation of the waterflood facilities to serve the Sims and Humphreys units in the East Velma Middle Block Unit was initiated in October of 2000. In 2001, we completed the installation of the west water injection facility with all related injection lines and have completed 14 injection wells and six water supply wells for these units. We began 20 work on the east water injection facility in the second quarter of 2001. We estimate the expenditure of an additional $550,000 for the remainder of 2001 for the east water injection facility. Approximately $1.7 million of additional work would be required to complete this project in 2002 if capital is available. Currently, we are injecting 15,000 barrels of water per day in East Velma Middle Block, and plan to ultimately increase injection to 50,000 barrels of water per day when all wells and facilities are fully operational. We have injected a total of 1.7 million barrels of water since we started the project and have seen production response. We are in the process of installing larger pumping equipment to handle the increased productivity brought about from individual wells responding to the water injection. The use of existing wells for water injection has reduced the amount of daily produced gas; nevertheless, we have been able to arrest the normal field production decline at this early stage of the project. Under the projections used for the project, we anticipate increased productivity in response to waterflooding from the entire unit beginning in 2002, with peak increase being achieved in 2006. In the Bumpass unit, we have identified several potential secondary recovery projects in the Flattop and Goodwin sands that were historically produced only by primary means. We have initiated a pilot waterflood project on one of these identified Flattop sands and converted two existing well bores to serve as injection service wells. We are currently injecting approximately 1,700 barrels of water per day into these two wells. We have recompleted a well as a producer in the waterflooded Flattop sand in June 2001 and the well is currently producing at 110 BOPD net to our interest. We are encouraged by these production results in this early stage of the waterflood. We do not plan to expand this project during the remainder of 2001, but plan to add additional wells in future periods to serve this project if we continue to be encouraged by the response and if capital is available. We have identified several other isolated Flattop and Goodwin sand reservoirs that exhibit good waterflood characteristics and we plan to move to initiate waterflood operations on some of these potential areas if capital becomes available in 2002. Our 2001 annual capital expenditures budget was decreased by our Board of Directors at mid-year from $40.0 million to $35.0 million, with $5.7 million remaining to be spent during the last three months of 2001. Due to the redetermination of our borrowing base effective November 1, 2001, capital spending during the remainder to 2001 will be funded from cash flow from operations and may be more limited than previously budgeted in an effort to conserve working capital while we evaluate the alternatives available to cure our borrowing base deficiency. We have no material capital commitments related to our United States operations and are consequently able to adjust the level of our expenditures based on available cash flow. General and administrative costs associated with our exploration and development activities of $510,000 were capitalized for the first nine months of 2000 compared with $720,000 of capitalized costs for the first nine months of 2001. Hedging Activities and Other Derivatives. Crude oil and natural gas prices are subject to significant seasonal, political and other variables which are beyond our control. In an effort to reduce the effect of the volatility of the prices received for crude oil and natural gas, we have entered, and expect to continue to enter, into crude oil and natural gas hedging transactions by entering into certain arrangements that fix a minimum and maximum price range per barrel. We entered into these arrangements to reduce the downside risk associated with potential crude oil and natural gas price declines by setting a floor price for our future production based on the NYMEX crude oil and natural gas prices. Due to working capital constraints, we entered into the "costless collar" type of transactions because they do not require upfront premiums. Any gain or loss on our crude oil hedging transactions is determined as the difference between the contract price and the average closing price for West Texas Intermediate crude oil on the New York Mercantile Exchange for the contract period. Any gain or loss on our natural gas hedging transactions is determined as the difference between the contract price and the New York Mercantile Henry Hub settlement price the next to last business day of the contract. Currently, we have no existing natural gas hedge arrangements. At September 30, 2001, our hedge arrangements are as follows: Minimum and Maximum Crude Oil Price Arrangements - 2,000 barrels per day for the period October 1, 2001 to December 31, 2001, with a minimum price of $26.00 and a maximum price of $30.70. - 6,250 barrels per day for the period October 1, 2001 to December 31, 2001, with a minimum price of $20.00 and a maximum price of $22.80. - 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $28.00. 21 - 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $29.60. - 500 barrels per day for the period of January 1, 2002 to December 31, 2002, with a minimum price of $24.00 and a maximum price of $28.60. - 500 barrels per day for the period of April 1, 2002 to December 31, 2002, with a minimum price of $22.50 and a maximum price of $25.50. - 500 barrels per day for the period of April 1, 2002 to December 31, 2002, with a minimum price of $22.50 and a maximum price of $26.45. Fixed Price Arrangements - 5,500 barrels per day for the period January 1, 2002 to March 31, 2002 with a fixed price of $20.40. As of October 1, 2001, based on our third quarter 2001 crude oil production level of 10,885 BOEPD, 76% and 33% of our future crude oil production is hedged for the last quarter of 2001 and the year ending December 31, 2002, respectively. We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement required us to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability. Tunisia Operations. We decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May 2001, Coho International entered into a settlement agreement with the other joint owners in the permit area. Under this agreement, Coho International assigned its interest in the Fejaj permit to the other joint owners in exchange for the assumption by the other joint owners of Coho International's existing obligations and existing payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a definitive agreement to sell all of its interest in the Anaguid permit to Pioneer Natural Resources Company and the other joint owners in the permit area for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's obligations under the permit totaling in excess of $7 million. These sales agreements have been approved by the United States Bankruptcy Court, but the sale of the Anaguid permit is still subject to approval by the Tunisian government. We intend to convert the bankruptcy proceedings for Coho Anaguid and Coho International from Chapter 11 reorganization proceedings to Chapter 7 liquidation proceedings during the fourth quarter of 2001 to wind down these proceedings. We have not recorded the liabilities subject to compromise for these subsidiaries in our consolidated balance sheet as of September 30, 2001 because these liabilities are solely obligations of the bankrupt subsidiaries and, furthermore, substantially all of the obligations of these subsidiaries will be assumed under the sales agreements. 22 RESULTS OF OPERATIONS
Nine Months Ended Three Months Ended September 30 September 30 --------------------- --------------------- 2000 2001 2000 2001 ---- ---- ---- ---- Selected Operating Data Production Crude Oil (Bbl/day) 9,698 10,152 9,795 10,316 Natural Gas (Mcf/day) 5,860 4,398 5,726 4,254 BOE (Bbl/day) 10,675 10,885 10,749 11,025 Average Crude Oil Sales Prices Actual Price Received per Bbl $ 25.53 $ 22.39 $ 27.16 $ 21.47 Hedging Loss per Bbl $ (1.85) $ (2.25) $ (5.27) $ (1.97) --------- --------- -------- -------- Net Price Received per Bbl $ 23.68 $ 20.14 $ 21.89 $ 19.50 ========= ======== ======= ======= Average Natural Gas Sales Prices Actual Price Received per Mcf $ 3.52 $ 5.10 $ 4.46 $ 3.00 Hedging Loss per Mcf $ (.09) $ (.93) $ (.23) $ (.00) -------- --------- -------- -------- Net Price Received per Mcf $ 3.43 $ 4.17 $ 4.23 $ 3.00 ======== ======== ======= ======= Other Production expenses $ 5.92 $ 6.35 $ 6.16 $ 6.72 Production taxes $ 1.41 $ 1.32 $ 1.53 $ 1.21 Depletion per BOE $ 3.82 $ 4.30 $ 3.82 $ 4.29 Production revenues (in thousands) Crude Oil $ 62,935 $ 55,823 $ 19,721 $18,507 Natural Gas 5,516 5,003 2,226 1,174 -------- --------- -------- -------- $ 68,451 $ 60,826 $ 21,947 $19,681 ======== ======== ======== =======
Operating Revenues. During the first nine months of 2001, production revenues decreased 11% to $60.8 million as compared to $68.5 million for the same period in 2000. This decrease was primarily due to a 15% decrease in the price received for crude oil (net of hedging losses discussed below) and a 25% decrease in daily natural gas production, partially offset by a 5% increase in daily crude oil production and a 22% increase in the price received for natural gas (net of hedging losses discussed below). For the three months ended September 30, 2001, production revenues decreased 10% to $19.7 million as compared to $21.9 million for the same period in 2000. This decrease was primarily due to a 11% decrease in the price received for crude oil (net of hedging losses discussed below), a 29% decrease in the price received for natural gas (net of hedging losses discussed below) and a 26% decrease in daily natural gas production, partially offset by a 5% increase in daily crude oil production. The 5% increase in daily crude oil production during the nine months ended September 30, 2001 is due to overall production increases in our operated Mississippi and Oklahoma properties due to: - returning previously shut-in wells to service; - recompleting inactive wells and marginal producers; - repairing wells that were previously uneconomical due to depressed crude oil prices; and - increasing drilling activity on our operated properties. These increases were partially offset by production decreases on our properties which are operated by third parties, partial losses of production on our Oklahoma crude oil and natural gas properties during 2001 due to a power outage during May and June resulting from a wind storm in southern Oklahoma and due to a power outage during January 2001 resulting from an ice storm in southern Oklahoma. We estimate the losses of production resulting from the power outages to be approximately 30,743 BOE or 112 BOEPD for the nine months ended September 30, 2001. 23 The 25% decrease in daily natural gas production during the first nine months of 2001 is due to production declines on our operated Oklahoma and Mississippi gas properties and non-operated Oklahoma gas properties. The decline between the comparable nine month periods is primarily due to: - several recompletions during late 1999 and early 2000 on our Oklahoma properties which experienced high initial production but subsequently experienced rapid production declines; - normal production declines on our Mississippi properties; and - losses of production caused by the power outages resulting from the ice storm and wind storm as discussed above. Average crude oil prices (net of hedging losses discussed below) for the comparable nine month and three month periods, decreased 15% and 11%, respectively. Of the 15% decrease for the comparable nine month periods, 11% was attributable to crude oil hedging losses and 89% was attributable to decreases in actual prices received from the sale of our crude oil. The 11% decrease for the comparable three month periods represents a decrease of $2.39 per Bbl. We experienced a $5.69 per Bbl decrease in the actual price received from the sale of our crude oil which was partially offset by a price increase of $3.30 per Bbl due to a reduction in crude oil hedging losses between the comparable periods. Substantially all of our Mississippi crude oil is sold under contracts which are based on posted crude oil prices and substantially all of our Oklahoma crude oil is sold under a contract which is based on the New York Mercantile Exchange price. The price per Bbl received is adjusted for the quality and gravity of the crude oil and is generally lower than the NYMEX price. Our overall average crude oil price received during the first nine months of 2001 was $22.39 per Bbl, before hedging losses of $2.25 per Bbl as discussed below, which represented a discount of 19% to the average NYMEX price for such period. The realized price for our natural gas (net of hedging losses discussed below) increased 22% from $3.43 per Mcf in the first nine months of 2000 to $4.17 per Mcf in the first nine months of 2001. Natural gas prices decreased 29% from $4.23 per Mcf in the third quarter of 2000 to $3.00 in the third quarter of 2001. The fluctuations in the prices for natural gas are due to market supply and demand and due to current events which influence market perceptions of supply and demand. Production revenues for the nine months ended September 30, 2001 included crude oil and natural gas hedging losses of $6.2 million ($2.25 per Bbl) and $1.1 million ($.93 per Mcf), respectively, as compared to crude oil and natural gas hedging losses for the nine months ended September 30, 2000 of $4.9 million ($1.85 per Bbl) and $144,000 ($.09 per Mcf), respectively. Production revenues for the three months ended September 30, 2001 included crude oil hedging losses of $1.8 million ($1.97 per Bbl) and no natural gas hedging gains or losses, as compared to crude oil and natural gas hedging losses for the three months ended September 30, 2000 of $4.8 million ($5.27 per Bbl) and $124,000 ($.23 per Mcf), respectively. Expenses. Production expenses were $18.9 million for the first nine months of 2001 compared to $17.3 million for the first nine months of 2000 and $6.8 million for the third quarter of 2001 compared to $6.1 million for the same period in 2000. The increase in expenses for the comparable nine month and three month periods is primarily due to: - increased electrical costs due to greater fluid movement and higher electrical rates; - increased crude oil production; and - increased costs between years to obtain labor, materials and rigs related to well repair activity. These increases were partially offset by a decrease in well repair costs for the nine month and three month periods ended September 30, 2001 as compared to the same periods in 2000 due to a greater number of well repair projects being performed during the comparable periods in 2000 to return shut in wells, inactive wells and marginal wells to production. On a BOE basis, production costs increased 7% to $6.35 per BOE in 2001 from $5.92 per BOE in 2000 for the comparable nine month periods and increased 9% to $6.72 per BOE in 2001 from $6.16 per BOE in 2000 for the comparable three month periods. On a BOE basis, the increases in production costs for the comparable nine month and three month periods primarily relate to increased electrical costs, partially offset by decreased well repair costs. 24 Production taxes decreased $190,000 or 5% for the first nine months of 2001 as compared to the first nine months of 2000 and decreased $290,000 or 19% for the third quarter of 2001 as compared to the same period in 2000. The 5% decrease for the first nine months of 2001 is due to: - lower crude oil prices; - decreases in natural gas production; and - reinstatement of certain severance tax exemptions due to lower prices on our Mississippi crude oil production. These decreases were partially offset by: - increases in crude oil production; - higher natural gas prices; and - the expiration of certain severance tax exemptions on our Mississippi crude oil production during 2001. The 19% decrease for the third quarter of 2001 is due to: - lower crude oil prices; - lower natural gas prices; - decreases in natural gas production; and - reinstatement of certain severance tax exemptions due to lower prices on our Mississippi crude oil production. These decreases were partially offset by increases in crude oil production. General and administrative costs decreased $1.4 million or 26% between the comparable nine month periods. These decreases are primarily due to: - reductions of $715,000 in employee-related costs primarily due to staff attrition and the termination of corporate office employees and officers in April 2000; - reductions of $499,000 in franchise taxes due to refunds for the year 2000 and reductions of over accrued amounts in 2001; - capitalization of $720,000 of salaries and salary related costs associated with exploration and development during the first nine months of 2001 as compared to $510,000 during the same period in 2000; and - increases in cost recoveries from working interest owners of $685,000 during the first nine months of 2001 as compared to the first nine months of 2000 due to an increase in well activity. These decreases were partially offset by increases of $750,000 in professional fees. General and Administrative costs decreased $560,000 or 33% between the comparable three month periods. These decreases are primarily due to: - reductions of $151,000 in employee-related costs due to staff attrition and the termination of corporate office employees and officers in April 2000; - reductions of $473,000 in franchise taxes due to refunds for the year 2000 and reductions of over accrued amounts in 2001; and 25 - increases in cost recoveries from working interest owners of $190,000 during the third quarter of 2001 as compared to the third quarter of 2000. These decreases were partially offset by increases of $261,000 in professional fees. Loss on derivatives for the nine month period and the three month period ended September 30, 2001 includes a loss of $77,000 and a gain of $56,000, respectively, related to the change in fair value of embedded derivatives included in certain lease agreements and $1.7 million and $255,000, respectively, related to the ineffectiveness of our crude oil and natural gas hedging arrangements. In addition, certain financial arrangements which previously qualified for hedge accounting treatment were disqualified for hedge accounting treatment during the third quarter of 2001, resulting in a gain of $80,000 for the nine month and three month periods ending September 30, 2001. Allowance for bad debt of $765,000 for the nine month period ended September 30, 2000 primarily represents an allowance for uncollectible accounts receivable from working interest owners. Depletion and depreciation expense increased 14% to $12.8 million for the nine months ended September 30, 2001 from $11.2 million for the comparable nine month period in 2000 and increased 15% to $4.4 million for the three months ended September 30, 2001 from $3.8 million for the comparable period in 2000. These increases are due to increased production and an increased depletion rate per BOE from $3.82 per BOE during 2000 to $4.30 per BOE during 2001. These increased depletion rates per BOE for the nine month and three month periods ending September 30, 2001 are due to an increase in depletable costs and due to a decline in total proved reserves. Interest expense for the nine month period ended September 30, 2001 increased to $26.9 million compared to $26.6 million for the same period in 2000 and for the three month period ended September 30, 2001 decreased to $8.7 million compared to $9.3 million for the same period in 2000. Following is a summary of interest expense between comparable periods:
Nine Months Ended Three Months Ended September 30 September 30 ----------------- ------------------ 2000 2001 2000 2001 ---- ---- ---- ---- (in thousands) (in thousands) Old bank group loan......................................... $ 7,983 $ -- $ -- $ -- New credit facility ......................................... 9,001 11,762 4,491 3,465 Standby loan ................................................ 6,523 9,155 3,255 3,133 Amortization of standby loan original issue discount .................................................. -- 1,150 -- 402 Amortization of debt issuance costs ......................... 3,048 4,703 1,533 1,571 Miscellaneous ............................................... 56 119 28 99 ------- ------- ------ ------ $26,611 $26,889 $9,307 $8,670 ======= ======= ====== ======
The increase for the comparable nine month periods is due to: - higher debt issuance amortization expense for the nine months ended September 30, 2001 resulting from $33.9 million in debt issuance costs on our new debt; - amortization costs of $1.2 million for the nine months ended September 30, 2001 related to the standby loan original issue discount which resulted from the adoption of SFAS 133; and - discontinuance of the accrual of interest on our old unsecured bonds during the first quarter of 2000 as a result of our bankruptcy filing. Approximately $3.5 million of additional interest expense would have been recognized during the first quarter of 2000 if not for the discontinuance of such interest expense accrual. These increases were partially offset by: - lower interest expense due to a reduction in our debt on March 31, 2000 resulting from the reorganization; 26 - higher interest rates on our old bank group loan during the first quarter of 2000 due to payment defaults and debt acceleration; - interest on past due interest payments on our old bank group loan during the first quarter of 2000; and - lower interest rates on our bank debt during 2001 resulting from overall lower market rates. The decrease for the comparable three month periods is primarily due to lower interest rates on amounts outstanding under the new credit facility during the third quarter of 2001 as compared to the same period during 2000, partially offset by: - an increase in interest on the new credit facility due to an increased amount of debt outstanding during 2001; - an increase in interest on the standby loan due to an increased amount of debt outstanding; and - amortization of the standby loan original issue discount during 2001 which resulted from the adoption of SFAS No. 133. Loss on standby loan embedded derivative for the nine month period ended September 30, 2001 was $1.8 million and gain on standby loan embedded derivative for the three month period ended September 30, 2001 was $1.1 million. The $1.8 million loss for the nine month period relates to the September 28, 2001 semiannual interest payment at the maximum additional rate of 10% per year under the semiannual interest payment feature of the standby loan agreement of $4.1 million, partially offset by a gain of $2.3 million related to the change in fair value of the semiannual interest payment feature of the standby loan agreement based on future projections of actual prices to be received for our oil and gas production. For the nine month period ended September 30, 2001, the fair value of this semiannual interest payment, which is considered an embedded derivative, increased by $1.1 million from $16.7 million at December 31, 2000 to $17.7 million at September 30, 2001. A $2.3 million decrease in fair value was included in the above mentioned loss on standby loan embedded derivative and the remaining change in fair value, an increase of $3.4 million, was due to the issuance of new notes under the standby loan agreement for payments-in-kind of interest on March 30, 2001 and September 28, 2001. For the three month period ended September 30, 2001, the $1.1 million gain relates to a $5.2 million gain resulting from the change in the fair value of the semiannual interest payment, partially offset by a loss of $4.1 million resulting from the September 28, 2001 semiannual interest payment, as discussed above. The fair value of the semiannual interest payment decreased by $3.3 million, from $21.0 million at June 30, 2001 to $17.7 million at September 30, 2001. A $5.2 million decrease in fair value was included in the above mentioned loss on standby loan embedded derivative and the remaining change in fair value, an increase of $1.9 million, was due to the issuance of a new note under the standby loan agreement for payment-in-kind of interest on September 28, 2001. Reorganization costs decreased $14.7 million for the comparable nine month periods from $12.5 million for the nine months ending September 30, 2000 to a gain of $2.2 million for the nine months ending September 30, 2001. During 2000, substantially all estimated reorganization expenses were accrued, which included: - professional fees for consultants and attorneys assisting in the negotiations associated with financing and reorganization alternatives and approval and implementation of our plan of reorganization; - termination benefits for severed employees; - payments and accrual of settlement amounts of officer employment agreements and officer severance agreements which were rejected in the plan of reorganization; - payments and accrual of amounts made under our retention bonus plan; and - provisions for settlements of disputed bankruptcy claims and other costs to effect the plan of reorganization. During 2001, settlements of disputed bankruptcy claims resulted in lower settlement amounts than originally estimated, resulting in a $1.3 million gain. In addition, our insurer agreed upon a claims settlement for reimbursement of litigation fees, resulting in a $950,000 gain. Reorganization costs decreased $322,000 for the 27 comparable three month periods from $277,000 for the three months ended September 30, 2000 to a gain of $45,000 for the three months ended September 30, 2001. The loss of $277,000 during the three months ended September 30, 2000 primarily relates to the accrual of amounts made under our retention bonus plan. During the third quarter of 2001, settlements of bankruptcy claims resulted in a $45,000 gain. Accumulated effect of an accounting change for the nine months ended September 30, 2001 relates to the adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 required us to record the fair value at January 1, 2001 of embedded derivatives contained in certain agreements on the balance sheet with an offsetting amount in accumulated effect of an accounting change. At January 1, 2001, we recorded the fair value of embedded derivatives for certain leases in Laurel, Mississippi and the standby loan resulting in a $300,000 loss and $9.5 million gain, respectively. The accumulated effect of the accounting change related to the standby loan embedded derivative was an increase in net income of $9.5 million because, under the previous accounting treatment, the changes in the estimated future additional interest due to changes in forecasted crude oil and natural gas prices were recorded on an undiscounted basis through earnings as compared to the fair market value basis under SFAS No. 133 that considers the time value of the future additional interest payments. Loss on extinguishment of debt of $4.4 million for the nine months ended September 30, 2000 resulted from the settlement of the old bank group and bondholders' claims. The loss on settlement of the old bank group claim was $303,000 and represents the difference in our carrying value of the debt and the cash settlement amount. The loss on settlement of the bondholders' claims was $4.1 million and represents the difference in our carrying value of the debt and the reorganization value of $10.52 per share for the common stock received by the bondholders. Due to the factors discussed above, our net earnings for the nine months ended September 30, 2001 were $2.4 million and our net loss for the three months ended September 30, 2001 was $1.4 million as compared to a net losses of $40.0 million and $23.0 million, respectively, for the same periods in 2000. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We use financial instruments which inherently have some degree of market risk. The primary sources of market risk include fluctuations in commodity prices and interest rate fluctuations. PRICE FLUCTUATIONS Effect of Price Fluctuations - Hedging Contracts. Our results of operations are highly dependent upon the prices received for crude oil and natural gas production. We have entered, and expect to continue to enter, into forward sale agreements or other arrangements for a portion of our crude oil and natural gas production to hedge our exposure to price fluctuations. At September 30, 2001, we have hedged a portion of our crude oil production through December 31, 2002. To calculate the potential effect of the hedging contracts on our revenues, we applied prices from September 30, 2001 future oil price curves for the remainder of 2001 and 2002 to the quantity of our oil production hedged for these periods. In addition, we applied September 30, 2001 future oil pricing from the price curves assuming a 10% increase in prices and assuming a 10% decrease in prices. The estimated changes in our revenue through December 31, 2002 resulting from the hedging contracts are as follows:
Remainder of Changes in Revenue 2001 2002 ------------------------------------------------------- ---- ---- Increase (decrease) based on current price curve $ 240,000 $(1,605,000) Increase (decrease) based on 10% decrease in price curve $ 954,000 $ 676,000 Increase (decrease) based on 10% increase in price curve $(1,413,000) $(2,914,000)
Effect of Price Fluctuations - Additional Interest. At September 30, 2001, a principal amount of $93.5 million was outstanding under our senior subordinated notes due 2007, which we also refer to as our standby loan agreement. The standby loan bears interest at a minimum rate of 15% payable semiannually plus additional interest, after March 31, 2001, in an amount equal to 1/2% for every $0.25 that the actual price, net of hedging costs, for our oil and gas production exceeds $15.00 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. At September 30, 2001, using then current future crude oil and natural gas curves, we calculated the estimated future additional interest payments due through September 30, 2002 based on the principal amount of $93.5 million outstanding at September 30, 2001. In addition, we calculated the estimated additional interest payments due through September 30, 2002 assuming a 10% decrease in prices and a 10% increase 28 in prices. The estimated additional interest due through September 30, 2002 relating to the additional interest under the standby loan is as follows:
Based on current price curve $6,541,000 Based on 10% decrease in price curve $4,439,000 Based on 10% increase in price curve $8,644,000
Interest payments under the standby loan agreement are required to be paid-in-kind subject to the intercreditor arrangement between the standby lenders and the lenders under the senior revolving credit facility unless we meet specified tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for discussion on interest payments to be paid-in-kind. INTEREST RATE RISK Total debt as of September 30, 2001, included $195 million of floating-rate debt attributed to bank credit facility borrowing. As a result, our annual interest cost in 2001 and 2002 will fluctuate based on short-term interest rates. The impact on annual cash flow of a ten percent change in the floating interest rate (approximately 71 basis points) would be approximately $1.4 million assuming outstanding debt of $195 million throughout the year. Currently, $185.0 million of outstanding debt under our bank credit facility is at a guaranteed libor rate of 7.0625% through November 13, 2001. 29 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS On May 27, 1999, we filed a lawsuit against five affiliates of Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998, (2) breach of the oral agreements reached with HM4 on the restructured transaction in February 1999 and (3) promissory estoppel. We reached a settlement of the litigation in May, 2001, subject to approval of the United States Bankruptcy Court (the "Bankruptcy Court") and resolution of certain disputes relating to a matter under seal by order of the Bankruptcy Court as discussed below. Final settlement documents were signed during October 2001 and we anticipate presenting the matter to the Bankruptcy Court for approval during the fourth quarter of 2001 or early in 2002. We do not expect the settlement to have a material impact on our financial position or results of operations. Pursuant to our plan of reorganization, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of the proceeds available from the Hicks Muse lawsuit settlement after fees and expenses. During 2001, we became involved in a matter in connection with the lawsuit filed by us against Hicks Muse. This matter is under seal by order of the Bankruptcy Court. The matter involves a termination issue and the plaintiff claims damages that are based on a percentage of the ultimate amount recovered, if any, in the lawsuit against Hicks Muse. These percentages would be calculated on a graduated scale decreasing from 30% to 10% as the amount recovered increases. Alternatively, the plaintiff claims damages on the basis of lost time. However, we do not believe that either of these methods represents an appropriate measure of damages. We believe the claim is without merit. At the order of the Bankruptcy Court, certain matters were arbitrated. The arbitration panel's sealed findings have been forwarded to the Bankruptcy Court for further proceedings and consideration in conjunction with the pending settlement discussed above. We do not expect this matter to have a material impact on our financial position or results of operations. Resolution of this matter may, however, impact the amount of proceeds available to us from the settlement of the Hicks Muse lawsuit. On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit against certain of our former officers alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by us. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. Subsequently, the plaintiff named Ryder Scott Company and Sproule Associates Inc., the independent petroleum consultants which evaluate our oil and gas reserves, as additional defendants. Pursuant to our bylaws, we may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by our directors' and officers' liability insurance policy. The settlement of our lawsuit against certain affiliates of Hicks, Muse, Tate & Furst, as described above, requires dismissal of the claims against the former officers. If the suit continues against Ryder Scott Company and Sproule Associates Inc., we may be required to indemnify these companies subject to their terms and conditions contained in certain agreements with them, however we do not expect this matter to have a material impact on our financial position or results of operations. ITEM 2. CHANGES IN SECURITIES None ITEM 3. DEFAULTS UPON SENIOR SECURITIES None ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None ITEM 5. OTHER INFORMATION 30 On August 10, 2001, James E. Bolin and Ronald Goldstein advised us that they were resigning, effective immediately, as directors of Coho Energy, Inc. On August 15, 2001, John G. Graham also advised us that he was resigning, effective immediately, as a director of Coho Energy, Inc. The board vacancies created by these director resignations have not been filled at this time. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) EXHIBITS None (b) REPORTS ON FORM 8-K None 31 COHO ENERGY, INC. 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. COHO ENERGY, INC. (Registrant) Date: November 13, 2001 By: /s/ Gary L. Pittman ------------------------------------ Gary L. Pittman (Vice President and Chief Financial Officer) By: /s/ Susan J. McAden ------------------------------------ Susan J. McAden (Chief Accounting Officer and Controller) 32