-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PynbxUZB+apdeBcEn2SaFD1WAN29/OsJOVFexZZ0WXxO0xVYHnV5OFRct9fFhqI+ KeSrMolhUFii6qZbL6FpsQ== 0000795182-99-000001.txt : 19990219 0000795182-99-000001.hdr.sgml : 19990219 ACCESSION NUMBER: 0000795182-99-000001 CONFORMED SUBMISSION TYPE: 8-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19981031 ITEM INFORMATION: FILED AS OF DATE: 19990218 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BONNEVILLE PACIFIC CORP CENTRAL INDEX KEY: 0000795182 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 870363215 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K/A SEC ACT: SEC FILE NUMBER: 000-14846 FILM NUMBER: 99545236 BUSINESS ADDRESS: STREET 1: 50 W 300 SOUTH STREET 2: SUITE 300 CITY: SALT LAKE CITY STATE: UT ZIP: 84101 BUSINESS PHONE: 8013632520 MAIL ADDRESS: STREET 1: 50 WEST 300 SOUTH STREET 2: SUITE 300 CITY: SALT LAKE CITY STATE: UT ZIP: 84101 8-K/A 1 1098 AUDIT/FIN ITEM 7 Financial Statements and Exhibits As required by SEC Staff Legal Bulletin No. 2 reporting companies emerging from Bankruptcy are required to file, under cover of Form 8-K, an audited balance sheet. As of November 4, 1998, the date of the original filing of the Form 8-K, it was not practical for the Company to provide the audited balance sheet as required. This filing is an amendment to the original Form 8-K, which now includes the audited balance sheet. This amendment was done as soon as this audited balance sheet became available. INDEPENDENT AUDITOR'S REPORT To the Board of Directors and Chapter 11 Trustee of Bonneville Pacific Corporation Salt Lake City, Utah We have audited the accompanying consolidated balance sheet of Bonneville Pacific Corporation (Chapter 11 Debtor) and subsidiaries as of October 31, 1998. This balance sheet is the responsibility of the Company's management. Our responsibility is to express an opinion on this consolidated balance sheet based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Bonneville Pacific Corporation (Chapter 11 Debtor) and subsidiaries as of October 31, 1998 in conformity with generally accepted accounting principles. HEIN + ASSOCIATES LLP Denver, Colorado January 5, 1999, except for paragraph 16 of Note 5, as to which the date is February 11, 1999 BONNEVILLE PACIFIC CORPORATION (CHAPTER 11 DEBTOR) AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET OCTOBER 31, 1998 ($ In Thousands, Except Per Share Information) c> PRO FORMA (unaudited) BALANCE AFTER AFTER ACTUAL PLAN PLAN OCTOBER 31, DEBT DEBT 1998 DISCHARGE DISCHARGE ASSETS CURRENT ASSETS: Cash and cash equivalents $ 163,991 $(156,578) $ 7,413 Restricted Cash 462 - 462 Receivables 4,124 - 4,124 Other Current Assets 231 - 231 Total Current Assets 168,808 (156,578) 12,230 PROPERTY, PLANT AND EQUIPMENT Oil and gas properties, at cost, under the successful efforts method 32,859 - 32,859 Other property, plant and equipment 10,042 - 10,042 Accumulated depreciation, depletion, amortization and impairment (28,490) - (28,490) Total Property, Plant and Equipment 14,411 - 14,411 INVESTMENT AND OTHER ASSETS Investments in and advances to affiliated companies, at cost plus equity in undistributed earnings 9,744 - 9,744 Other assets 383 - 383 Total Other Assets 10,127 - 10,127 TOTAL ASSETS $193,346 $(156,578) $ 36,768 See accompanying notes to this consolidated balance sheet.
PRO FORMA (UNAUDITED) BALANCE AFTER ACTUAL PLAN PLAN OCTOBER 31, DEBT DEBT 1998 DISCHARGE DISCHARGE LIABILITIES AND STOCKHOLDERS' DEFICIENCY LIABILITIES NOT SUBJECT TO COMPROMISE: Current liabilities: Post-petition accounts payable $ 3,134 $ - $ 3,134 Accrued professional fees 4,281 (4,281) - Other current liabilities 1,139 - 1,139 Total Current liabilities 8,554 (4,281) 4,273 Bank debt 3,900 - 3,900 TOTAL LIABILITIES NOT SUBJECT TO COMPROMISE 12,454 (4,281) 8,173 SENIOR LIABILITIES SUBJECT TO COMPROMISE: Pre-petition accounts payable 3,750 ( 3,750) - Convertible debentures and pre-petition accrued interest 64,750 (64,750) - Bank debt and pre-petition accrued interest 31,512 (31,512) - Accrued interest 51,556 (51,556) - Priority claims 7 (7) - Total senior liabilities subject to compromise 151,575 (151,575) - SUBORDINATED LIABILITIES SUBJECT TO COMPROMISE: Pre-petition selling debentures claims (Class 5) 5,333 ( 5,333) - Post-petition selling debentures claims (Class 6) 6,901 ( 6,901) - Limited partner claims (Class 7) 721 ( 721) - Deeply subordinated claims (Class 8) 8,945 ( 8,945) - Selling stockholders 510(b) claims (Class 9) 30,852 ( 30,852) - Cigna claim (Class 10) 11,000 ( 11,000) - Total subordinated liabilities subject to compromise 63,752 ( 63,752) - TOTAL LIABILITIES SUBJECT TO COMPROMISE 215,327 (215,327) - Total liabilities 227,781 (219,608) 8,173 See accompanying notes to this consolidated balance sheet.
PRO FORMA (UNAUDITED) BALANCE AFTER ACTUAL PLAN PLAN OCTOBER 31, DEBT DEBT 1998 DISCHARGE DISCHARGE MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY COMPANY - - - COMMITMENTS AND CONTINGENCIES (Notes 5, 7, and 12) STOCKHOLDERS' (DEFICIENCY) EQUITY: Preferred stock - $.01 par value; cumulative; 5,000,000 shares authorized with $.01 per share liquidation value; no shares issued and outstanding - - - Common stock - $.01 par value; 50,000,000 shares authorized; 21,375,000 shares issued, pro forma 7,227,000 (post reverse split) issued 214 ( 142) 72 Additional Paid-in Capital 127,602 33,131 160,733 Accumulated deficit (154,183) 22,402 (131,781) Cumulative translation adjustment (429) - (429) (26,796) 55,391 28,595 Treasury stock - 9,688,000 shares (-0- pro forma), at cost ( 7,639) 7,639 - Total Stockholders' (deficiency) equity (Note 10) ( 34,435) 63,030 28,595 TOTAL LIABILITIES AND STOCKHOLDERS' (DEFICIENCY) EQUITY $193,346 $ (156,578) $ 36,768 See accompanying notes to this consolidated balance sheet.
[S] NOTES TO CONSOLIDATED BALANCE SHEET NOTE 1 - REORGANIZATION AND LEGAL MATTERS: Bonneville Pacific Corporation ("BPC"), but none of its partially- or wholly- owned subsidiaries, filed a voluntary petition for relief under Chapter 11 of Title 11 of the Federal Bankruptcy Code (the "Code") on December 5, 1991 (the "petition date"). From the petition date to June 12, 1992, BPC operated as a Chapter 11 Debtor-in-Possession subject to the jurisdiction of the United States Bankruptcy Court for the District of Utah, Central Division (the "Court"). On June 12, 1992, the Court ordered the appointment of a Chapter 11 Trustee (the "Trustee"). Certain executory contracts and leases existing at the petition date have been rejected or assumed with the approval of the Court. On June 19, 1998, the Trustee filed with the Court the "Trustee's Amended Chapter 11 Plan for the Estate of Bonneville Pacific Corporation dated April 22, 1998" (the "Plan"). This Plan was confirmed on August 27, 1998 and was effective on November 2, 1998 (the "Effective Date"). See Note 2 for further discussion of the Plan. The accompanying consolidated balance sheet has been prepared in accordance with the American Institute of Certified Public Accountants Statement of Position 90-7 (SOP 90-7) for reporting bankruptcy related items. SOP 90-7 requires BPC to record claims at the amount allowed or the amount estimated to be allowed as opposed to the amount for which the liabilities are expected to be settled. SOP 90-7 also requires separate balance sheet classification for liabilities subject to compromise, and requires disclosure of certain bankruptcy related items. The accompanying consolidated pro forma balance sheet reflects adjustments necessary to record the reorganization of BPC and the issuance of securities in connection with implementation of the Plan, as if these transactions had occurred as of October 31, 1998. NOTE - 2 CHAPTER 11 PLAN: The Plan classifies all claims into 11 classes plus administrative claims and standardizes the way certain claims are calculated. The classes and treatments, in general are as follows: Allowed Amount Amount of of Class Type of Claim Claim Settlement Treatment (in 000's) (1) Priority Claims $ 7 $ 7 Allowed claim paid in full in cash at distribution date. (2) Bank Debt Claims 31,512 31,512 Allowed claim paid in full in cash at distribution date; post-petition simple interest at 8.03% per annum through December 5, 1997 and 8.10% thereafter. (3) Trade and Other 3,750 3,750 Allowed claim paid in full in cash General Unsecured at distribution date; post-petition Claims simple interest at 5.5% per annum. (4) Current Debenture 64,750 64,750 Allowed claim paid in full in cash Claims at distribution date; post-petition simple interest at 7.32% per annum. (5) Pre-petition Sell- 5,333 5,333 Claim amount as uniformly calculated ing debenture Claims by the Trustee allowed and paid in Plan common stock. (6) Post-petition Sell- 6,901 6,901 Claim amount as uniformly calculated ing debenture Claims by the Trustee allowed and paid in Plan common stock. (7) Limited Partner 721 721 Claim amount as uniformly calculated Claims by the Trustee allowed and paid in Plan common stock. (8) Deeply Subordinated 8,945 895 10% of allowed claim paid in Plan Claims common stock. (9) Equity Claims 30,852 20,202 Allowed claim as uniformly calculated (For Loss of Value by the Trustee paid in Plan common on Equity, also known stock with a value estimated to be as 510(b) equity claims) approximately 65% of the allowed claim. (10) CIGNA Claim 11,000 7,203 Allowed as an $11 million 510(b) equity claim; claimant to receive Plan common stock with a value estimated to be approximately 65% of such claim. (11) Equity Interests Existing common stock was retained (Existing common stock) by the interestholders and their rights in the reorganized debtor were unaltered.
The Plan also provides for a one for four reverse stock split. The split was effective on November 2, 1998. The above claim amounts do not include accrued administrative claims in the amount of $4,281,000. These administrative claims were paid subsequent to October 31, 1998 as allowed by the bankruptcy court on January 5, 1999. Subsequent to October 31, 1998, BPC paid cash and issued stock in satisfaction of the above claims as provided for in the Plan. Pursuant to the Plan, claimants who were to receive less than 100 shares of Plan common stock (taking into account the reverse stock split) received cash in lieu of such stock. These cash payments totaled approximately $625,000. The value of BPC as set forth in the Plan (reorganization value) as of the date immediately preceding the effective date was greater than the sum of post-petition liabilities and allowed claims, therefore, the Company did not qualify for fresh start accounting and it will continue to report its assets and liabilities at historical cost amounts. NOTE 3 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Principles of Consolidation - The consolidated balance sheet includes the accounts of BPC and its majority-owned subsidiaries (collectively referred to as "the Company"). All significant intercompany balances and transactions have been eliminated in consolidation. The following majority-owned subsidiaries had activities during 1998: Bonneville Fuels Corporation ("BFC"), Bonneville Pacific Services Company, Inc. ("BPSC"), and Bonneville Nevada Corporation ("BNC"). Organization and Nature of Operations - The entity which ultimately became BPC was initially incorporated in the State of Utah in March 1980, and changed its state of incorporation to the State of Delaware in June 1986. The Company's current operations include the ownership of one operational cogeneration facility, a 50% interest in another cogeneration facility, a cogeneration operations and management company and an oil and gas company engaged in the exploration and production of oil and natural gas and in the gathering and marketing of natural gas and other forms of energy. At October 31, 1998, BPSC also had an interest in an additional cogeneration facility in the start-up phase in Mexico. Cash and Cash Equivalents - The Company considers all highly-liquid investments with an original maturity of three months or less to be cash equivalents. From time to time, BPC has had cash and cash equivalents which exceeded the Federal Deposit Insurance Corporation's insurance limit of $100,000, however, during the pendency of the reorganization proceedings, the banks have pledged United States Treasury notes to the US Bankruptcy Trustee, or have obtained a performance bond to guarantee the liquidity of the deposits. Use of Estimates in the Preparation of Financial Statements - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Investment in Partnership - BPC through a wholly-owned subsidiary, BNC, is a 50% general partner in Nevada Cogeneration Associates #1 ("NCA #1"). The investment in NCA #1, accounted for under the equity method, is recorded at cost, as adjusted for BNC's share of earnings and distributions received. Oil and Gas Properties - BFC follows the "successful efforts" method of accounting for its oil and gas properties, all of which are located in the continental United States. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Depreciation and depletion of capitalized costs for producing oil and gas properties is provided for using the units-of-production method based upon proved reserves for each field. In 1997, BFC began to accrue for future plugging, abandonment, and remediation using the negative salvage value method whereby costs are expensed through additional depletion expense over the remaining economic lives of the wells. Management's estimate of the total future costs to plug, abandon, and remediate BFC's share of all existing wells, including those currently shut-in, is approximately $3,800,000, net of salvage values. The cumulative total accrued, as additional accumulated depletion, was $367,000 as of October 31, 1998. Gains and losses are generally recognized upon the sale of interests in proved oil and gas properties based on the portion of the property sold. For sales of partial interests in unproved properties, BFC reflects the proceeds as a recovery of costs with no gain recognized until all costs have been recovered. Other Property and Equipment - Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 25 years) of the respective assets. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. When properties are sold, or otherwise disposed of, the cost of the property and the related accumulated depreciation or amortization are removed from the accounts, and any gains or losses are reflected in current operations. Impairment of Assets - The Company follows Statement of Financial Accounting Standards No. 121, Accounting for Impairment of Long-Lived Assets. When facts and circumstances indicate that the carrying value of an asset is impaired, the Company estimates the future undiscounted cash flows from that asset and compares that amount to the carrying value. If it is determined that an impairment is required, the asset is written down to its fair market value. Net capitalized costs of oil and gas properties are limited to the aggregate undiscounted future net revenues related to each field. If the net capitalized costs exceed the limitation, impairment is provided to reduce the carrying value of the oil and gas properties to fair market value. Income Taxes - The Company accounts for income taxes under the liability method of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Accounting for Hedged Transactions - In order to mitigate the risk of market price fluctuations, BFC enters into futures, swaps, and term gas sales contracts as hedges of commodity prices associated with its oil and gas production and the purchase and sale of natural gas. Changes in the market value of futures, swaps, and term gas contracts are deferred until the gain or loss is recognized on the hedged production or transactions. Segment Reporting - The Company has adopted FAS 131 Disclosures About Segments of an Enterprise and Related Information. FAS 131 replaces FAS 14 and utilizes the "management approach" whereby external financial reporting is aligned with internal reporting. FAS 131 defines an operating segment as a component of an enterprise that engages in business activity for which it may earn revenues and incur expenses, whose operating results are regularly reviewed by the entity's chief operating decision maker to allocate resources and assess performance, and for which discrete financial information is available. The Company has identified the following reportable operating segments: Bonneville Fuels Corporation, Bonneville Pacific Services Company Inc., and Bonneville Nevada Corporation. Impact of Recently Issued Accounting Pronouncements - In June 1998, the Financial Accounting Standards Board issued No. 133, (SFAS 133), Accounting for Derivative Instruments and Hedging Activities. This statement is effective for fiscal years beginning after June 15, 1999. Earlier application is encouraged; however, the Company does not anticipate adopting SFAS 133 until the fiscal year beginning January 1, 2000. SFAS 133 requires that an entity recognize all derivatives as assets or liabilities in the statement of financial position and measure those instruments at fair value. Although the Company is currently evaluating SFAS 133, it is not expected to have a material impact on the financial condition or results of operations of the Company. NOTE 4 - Impairment of Long-Lived Assets - The analysis of future cash flows of the Company's oil and gas properties and the related fair value of those properties by BFC resulted in an impairment charge of $1,600,000 as of October 31, 1998. After the effective date of the Plan, the Company's newly appointed Board of Directors determined that it would not renew the contract related to a small cogeneration plant which will now expire pursuant to its terms in April 1999. The Company also reviewed the carrying value of the small cogeneration plant in Mexico that is in the start-up phase and determined that it should be impaired. Consquently, the Company took impairment charges for the cogeneration assets of approximately $2,541,000 as of October 31, 1998, to reduce the net book value of these assets to their fair value. The Company also reviewed the carrying value of a certain parcel of undeveloped real estate and recorded approximately $150,000 impairment. NOTE 5 - Investment in NCA#1 Partnership - BPC, through BNC, is a 50% general partner in the NCA#1 partnership. The remaining 50% is owned by Texaco Clark County Cogeneration Company ("TCCCC"). The NCA#1 partnership owns and operates an 85 megawatt electric generating facility (the "Facility") in Clark County, Nevada. BNC receives a 50% allocation of income (loss), depreciation expense and other tax benefits from the operations of NCA#1. In accordance with the partnership agreement, BNC initially received a 66 2/3% share of net cash distributions until such net cash distributions equaled approximately $18,800,000 (September 1997) at which time BNC's share of net cash distributions changed to 50%. The NCA#1 partnership will terminate, unless terminated earlier by partner agreement, on the latter of April 30, 2023, or the date that NCA#1 elects to cease operations. Summary condensed balance sheet data and significant accounting disclosures for NCA #1 as of October 31, 1998 are as follows: 1998 (in 000's) Assets: Cash and cash equivalents $ 10,958 Other current assets 4,340 Operating facility and equipment, net 80,093 Other assets 11,510 Total assets $ 106,901 Liabilities and partners'equity: Project financing loan payable and bonds payable $ 74,892 Notes and other payables to affiliates 1,473 Other liabilities 5,226 Partners' equity: Bonneville Nevada 9,744 TCCCC 15,566 Total liabilities and partners' equity $106,901
The Facility was completed during 1992 and commercial operation began on June 18, 1992. All costs, including interest and field overhead expenses, incurred prior to commercial operations were capitalized as part of the Facility. The Facility is being depreciated on a straight-line basis over 30 years. Expenditures for maintenance, repairs and minor renewals are charged to expense as incurred, and expenditures for additions and improvements are capitalized. The facility requires significant maintenance every 25,000 and 50,000 operating hours. The expected cost of this maintenance is accrued using a straight-line method over the respective periods. Due to fluctuations in the extent of repairs, prices and changes in the timing of the scheduled events, the estimated costs of these events can differ from actual costs incurred. All legal and financing fees associated with NCA #1's project financing loan and bonds payable including the cost of subsequent amendments were deferred and are being amortized over the terms of the financing. In July 1991, NCA #1 entered into a Construction Loan, Term Loan and Reimbursement Agreement (the "Agreement") with several banks to finance the majority of the construction costs of the Facility. In April 1993, the loan was converted to a term loan of $63,938,000. The debt is scheduled to be reduced on dates and by amounts as specified in the Agreement through October 2007, unless terminated earlier as provided for in the Agreement. The Agreement places certain restrictions on cash accounts, capital distributions and permitted investments. The Agreement is collateralized by substantially all of the assets of NCA #1, as well as BNC's interest in the NCA #1 partnership. The amount outstanding under the Agreement bears interest at a market rate plus a margin. NCA #1 has entered into interest rate swap agreements with commercial banks to reduce the exposure to higher interest rates. If the variable interest exceeds the fixed rate established by the swap agreements, NCA #1 could be exposed to the risk of higher interest costs in the event of nonperformance by the commercial banks. The weighted average interest rate, inclusive of the effect of the swap agreements, on the outstanding loan balance was approximately 7.18% at October 31, 1998. The bankruptcy of BPC was an event of default, prior to 1996, under a covenant in the Agreement. This event of default gave the lenders the right to call the loan and to require redemption of the tax-exempt bonds at any time. During 1996, the Partnership amended the Loan and Reimbursement Agreement which became effective October 30, 1996, therein waiving the event of default regarding BPC's bankrupt status. The amendment also reduced the lender's margin by 1/4%, reduced the restricted cash accounts required, and changed the reporting requirements for the project. The future minimum payments on the debt outstanding and the letters of credit supporting the tax-exempt bonds at October 31, 1998, are as follows: November and December 1998 - $1,124,000; 1999 - $5,138,000; 2000 - $5,689,000; 2001 - $6,239,000; 2002 - $6,881,000; 2003 - $7,798,812, and for the years thereafter a total of $14,622,000. NCA #1 also obtained $27,400,000 of long-term project financing in the form of variable rate industrial development revenue bonds. BPC and the parent of TCCCC have guaranteed repayment of these bonds. The bonds are due and payable on November 1, 2020 and November 1, 2021. The interest rate on the bonds was approximately 4.42% at October 31, 1998. As set forth in the Plan, BPC has guaranteed repayment of the industrial revenue bonds. NCA #1 is considering refinancing these bonds. NCA #1 has an agreement for long-term power purchases of energy and capacity by Nevada Power Company (NPC) that terminates on April 30, 2023. NCA #1 is paid for energy delivered based upon fixed rates, as defined in the agreement, adjusted annually at 120% of the change in the CPI. NPC also pays NCA #1 for firm capacity based upon fixed rates, as defined, increased annually by 2%. During 1997, NCA #1 negotiated an amendment to the agreement severely limiting NPC's curtailment rights in exchange for a price discount of $.25 per megawatt hour. The amendment was signed on October 3, 1997 and was approved by Nevada Public Utility Commission subsequent to December 31, 1997. Pursuant to the amended agreement, upon mutual consent, NCA #1 has the right to release NPC from its purchase obligation for an agreed upon payment per released megawatt. NCA #1 also has a long-term process heat sales agreement with Georgia-Pacific Corporation which terminates on April 30, 2023, or earlier, as defined in the agreement. NCA #1 has a number of long-term fuel-gas purchase contracts and transportation contracts with various parties including affiliates of TCCCC. NCA #1 also has an equipment lease agreement which requires monthly payments of $24,000 plus sales tax over a 10-year term ending December 31, 2002. The Facility is operated and maintained by BPSC. BPSC is paid for all costs incurred in connection with the operation and maintenance of the Facility including an annual operating fee of $260,000, adjusted annually by the Consumer Price Index. BPSC also may earn a performance bonus upon meeting specified operating goals, as defined in the agreement. NCA #1, under agreements, pays for certain engineering and administrative expenses and other costs to TCCCC and its subsidiaries. TCCCC may earn a performance bonus based upon the plant achieving certain operational goals, as defined in the agreement. In 1997, the Nevada Legislature passed legislation to restructure the Nevada electric utility industry. The legislation (AB366) calls for competition to commence by January 1, 2000. The eventual outcome of these activities and their potential impact, if any, upon NCA #1 is not known. Income taxes are not recorded by NCA #1 since the net income or loss allocated to the partners is included in each partner's respective income tax return. Under the terms of the NCA #1 Partnership Agreement, at TCCCC's one-time option, BNC will be required to purchase or cause to be purchased, TCCCC's ownership interest in NCA #1 at fair market value as determined by an independent appraisal. TCCCC's one-time option becomes effective on June 18, 2012. NCA #1 has been in negotiations with the United States Environmental Protection Agency (the "EPA") regarding emissions from its gas turbine engines. Subsequent to October 31, 1998, the EPA filed a lawsuit against NCA #1, BNC and TCCCC, seeking damages of $25,000 per day from a unspecified point in time and the installation of custom emission controlling equipment. NCA #1, BNC and TCCCC, the partners to NCA #1, have signed a consent decree prepared by the U.S. Department of Justice that resolves the above mentioned lawsuit and requires NCA #1 to pay a $100,000 fine and install the emission controlling equipment. The decree still requires the signature of the other parties to the action. The cost of purchasing and installing the equipment and the proposed fine have been accrued by NCA #1 and are being held in a control account. NCA#1 believes that it will have no additional liability for the violations alleged in the above mentioned lawsuit after the consent decree has been executed and entered in the court. Subsequent to October 31, 1998, the Nevada Public Utilities Commission gave tentative approval for the merger of the Company's main customer with another utility company in Nevada. The ultimate impact, if this merger proceeds, on NCA #1 is not known at this time. NOTE 6 - LONG-TERM DEBT: BFC has an asset-based line-of-credit with a bank which provides for borrowing up to the borrowing base (as defined). The borrowing base was $11,500,000 at October 31, 1998. At October 31, 1998, outstanding borrowings amounted to $3,900,000, with interest at a variable rate that approximated 7.25% at October 31, 1998. BFC has issued letters of credit totaling $3,325,000 which further reduces the amount available for borrowing under the base. This facility is collateralized by certain oil and gas properties of BFC and is scheduled to convert to a term note on July 1, 2001. This term loan is scheduled to have a maturity of either the economic half life of BFC's remaining reserves on the date of conversion, or July 1, 2006, whichever is earlier. The borrowing base is based upon the lender's evaluation of BFC's proved oil and gas reserves, generally determined semi-annually. The future minimum principal payments under the term note will be dependent upon the bank's evaluation of BFC's reserves at that time. BFC also has an accounts receivable-based credit facility which includes a revolving line-of-credit with the bank which provides for borrowings up to $1,500,000. There were no outstanding borrowings under this facility at October 1998. This facility bears interest at prime (8% at October 31, 1998). This facility is collateralized by certain trade receivables of BFC and has a maturity date of July 1, 1999. The credit agreement contains various covenants which prohibit or limit the subsidiary's ability to pay dividends, purchase treasury shares, incur indebtedness, repay debt to BPC, sell properties or merge with another entity. Additionally, BFC is required to maintain certain financial ratios. BPC's pre-petition debt agreements contain various financial and operational covenants. While covenants in substantially all of these agreements have been breached, the related debt was settled as part of the Plan. See Note 5 for a discussion of long-term debt of NCA #1. NOTE 7 - COMMITMENTS: Office Lease - The Company leases office space under noncancellable operating leases. The total minimum rental commitments at October 31, 1998 are as follows: ($ in 000's) Remaining 1998 $ 40 1999 161 2000 124 2001 129 2002 88 $ 542
NOTE 8 - INCOME TAXES: Long-term deferred tax assets and liabilities are comprised of the following as of October 31, 1998: ($ in 000's) Deferred tax assets: Net operating loss carryforward $ 7,829 Depreciation, depletion, amortization and impairment 1,590 Liabilities recognized for book purposes prior to realization for tax purposes 14,033 Gross deferred tax assets 23,452 Deferred tax liabilities: Investment in NCA #1, primarily depreciation, depletion and amortization 1,787 Net deferred tax asset, before valuation allowance 21,665 Valuation allowance (21,665) Net deferred tax asset, after valuation allowance $ - At October 31, 1998, the Company had Federal income tax net operating loss carryforwards of approximately $22,369,000 which expire from 2010 through 2014.
Under Section 382 of the Internal Revenue Code of 1986, as amended, if certain significant ownership changes occur, there could be an annual limitation on the amount of net operating loss carryforwards which may be utilized. The Company may have experienced a change in ownership under these rules prior to December 31, 1997. Consequently, certain net operating loss carryforwards may be limited. There may be additional limitations due to the confirmation of the Plan. NOTE 9 - EMPLOYEE BENEFITS: Employee Stock Ownership Plan - On April 28, 1989, BPC adopted the Bonneville Pacific Corporation Employee Stock Ownership Plan (the "ESOP"). The ESOP had an allowed claim against BPC of $984,000 which claim was distributed to the ESOP participants and was satisfied by the Plan. The ESOP was terminated in 1997. Employee Qualified 401(k) Retirement Plan - Effective January 1, 1990, BPC adopted a qualified retirement plan under Sections 401(a) and 401(k) of the Internal Revenue Code. The Company may match employees' contributions at the Company's discretion. No company contributions were made in 1998 through October 31. Management Retention Program - In 1997, the Court approved a management retention program in order to retain certain key employees of the subsidiary companies. The retention program provides for the payment of certain cash severance benefits upon (a) an employee's termination without cause absent a change in control, or (b) termination from a change in control. Additionally, the retention programs provide benefits upon (a) the death of the employee or (b) the successful confirmation of the Plan. BFC and BPSC accrued $600,000 for the retention program in 1997. Subsequent to October 31, 1998, the Board of Directors expanded the program to include benefits to some additional Company employees. Stock Options - Subsequent to October 31, 1998, the Company's Board of Directors approved the issuance of a total of 45,000 options to its outside directors to purchase common stock at $9.44 per share exercisable over a 10-year period (which share price takes into account the reverse stock split which was effective on November 2, 1998). NOTE 10 - STOCKHOLDERS' EQUITY: Treasury Stock - At the effective date of the Plan, the treasury stock held by the Company and the Company stock held by the Trustee was cancelled with the Company now holding such stock as authorized but not issued common stock. Reverse Stock Split - The Plan provided for a one for four reverse stock split. This reverse stock split was effective on November 2, 1998. Shares Issued - Pursuant to the Plan, the Company issued stock in satisfaction of certain claims. See Note 2 for a discussion of the shares issued. After the effective date of the Plan and taking into account the reverse stock split, there were a total of 7,227,000 shares of the Company's stock issued and outstanding. NOTE 11 - CONCENTRATIONS OF CREDIT RISK: Approximately 77% of the Company's accounts receivable at October 31, 1998 result from BFC's crude oil and natural gas sales and/or joint interest billings to companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, since these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on trade receivables by the Company have been insignificant. The nature of the power generation business is such that each facility generally relies on one power or thermal sales agreement with a single electric customer for substantially all, if not all, of such facility's revenue over the life of the project. The power and thermal sales agreements are generally long-term agreements, covering the sale of electricity or thermal energy for initial terms of 20 or 30 years. However, the loss of any one major power or thermal sales agreement with any of these customers could have a material adverse effect on cash flow and, as a result, on results of operations. Furthermore, each power generation facility may depend on a single or limited number of entities to purchase thermal energy, or to supply or transport natural gas to such facility. The failure of any one customer, thermal host, gas supplier or gas transporter to fulfill its contractual obligations could have a material adverse effect on a power project's qualifying status under regulations and on the Company's business and results of operations. NOTE 12 - FINANCIAL INSTRUMENTS: Statement of Financial Accounting Standards No. 107 and 127 requires certain entities to disclose the fair value of certain financial instruments in their financial statements. Accordingly, management's best estimate is that the carrying amount of cash, receivables, notes payable, accounts payable, undistributed revenue, and accrued expenses approximates fair value of these instruments, other than liabilities subject to compromise, for which the estimated fair value equals the amount of settlement as discussed in Note 2. Energy Financial Instruments - BFC uses energy financial instruments and long- term gas sales contracts to minimize its risk of price changes in the natural gas and crude oil markets. Energy risk management products used include commodity futures and options, long-term gas sales contracts, fixed-price swaps, and basis swaps. Pursuant to company guidelines BFC is to engage in these activities only as a hedging mechanism against price volatility associated with pre-existing or anticipated gas or crude oil sales in order to protect profit margins. As of October 31, 1998, BFC has financial and physical contracts which hedge 5,835,000 MMbtu's of production through October 2001. The current market value of the hedging contracts was $(35,000) as of October 31, 1998. This amount is not reflected in the accompanying balance sheet. In the event energy financial instruments do not qualify for hedge accounting, the difference between the current market value and the original contract value would be currently recognized in the statement of operations. In the event that the energy financial instruments are terminated prior to the delivery of the item being hedged, the gains and losses at the time of the termination are deferred until the period of physical delivery. Such deferrals were immaterial as of October 31, 1998. NOTE 13 - SEGMENT INFORMATION: The Company has identified the following segments: BFC, BNC, and BPSC. BFC is primarily engaged in oil and gas production and energy marketing. BNC owns a 50% interest in NCA #1 which is engaged in cogeneration activities. BPSC is primarily engaged in providing operational and maintenance services to cogeneration plants. At October 31, 1998, BPSC also had an interest in an additional cogeneration facility in the start-up phase in Mexico. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from operations before reorganization items and income taxes. BFC BNC BPSC Corporate Total ($in 000's) October 31, 1998 Segment assets actual as of October 31 $17,358 $13,125 $ 2,464 $160,399 $193,346
NOTE 14 - OIL AND GAS PRODUCING ACTIVITIES AS OF OCTOBER 31, 1998: BFC's oil and gas producing activities are all located in the United States. The following is certain information with respect to the activities. October 31, 1998 ($ in 000's) Capitalized Costs Relating to Oil and Gas Properties Unproved oil and gas properties $ 2,155 Proved oil and gas properties 30,546 Gas gathering system 158 32,859 Accumulated depreciation, depletion, amortization and impairment (20,031) Net capitalized costs $ 12,828 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Acquisition of properties: Proved $ - Unproved 202 202 Exploration costs 1,027 Development Costs 3,078 $ 4,307
NOTE 15 -OIL AND GAS RESERVE INFORMATION AS OF DECEMBER 31, 1997 (UNAUDITED): The following quantity and value information is based on prices as of December 31, 1997. No price escalations were assumed. Subsequent to December 31, 1997, however, there have been substantial price declines in oil and gas. As the Company only performs detailed independent oil and gas reserve evaluations on an annual basis at year-end (December 31), the information included in this note does not consider the subsequent price declines nor other factors, including discoveries and revisions of previous quantity estimates, which have occurred subsequent to December 31, 1997. The Company did consider these factors when analyzing the impairment recognized as of October 31, 1998, as described in Note 4. Operating costs and production taxes were deducted in determining the quantity and value information. Such costs were estimated based on current costs and were not adjusted to anticipate increases due to inflation or other factors. No deductions were made for general overhead, depreciation and interest. The determination of oil and gas reserves is based on estimates and is highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available and an accurate determination of the reserves may not be possible for several years after discovery. Reserve information presented herein (as of December 31, 1997) is based on reports prepared by an independent petroleum engineer. Estimated Quantities of Proved Oil and Gas Reserves - The following is a reconciliation of BFC's interest in net quantities of proved oil and gas reserves. Proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimated reserves of oil (barrels) and natural gas (thousands of cubic feet) as of December 31, 1997 are as follows: For the Year Ended December 31, 1997 Gas Oil Proved developed and undeveloped reserves 23,140 298 Proved developed reserves 22,623 298
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves Estimated discounted future net cash flows and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying year-end prices of oil and gas relating to BFC's proved reserves to the year-end quantities of those reserves. The assumptions used to compute the proved reserve valuation do not necessarily reflect BFC's expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to subjectivity inherent in predicting the future, variations from the expected production rate also could result directly or indirectly from factors outside BFC's control, such as unintentional delays in development, environmental concerns and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expense has not been provided based on the availability of net operating loss carryforwards and other deductions. The usage of these carryforwards may be limited based upon a past change in ownership of BPC. There may be additional limitations on the availability of net operating loss carryforwards due to the confirmation of the Plan. A discount rate of 10% per year was used to reflect the timing of the future net cash flows. December 31 1997 ($ in 000's) Future cash inflows $ 46,859 Future production and development costs 18,155 28,704 10% annual discount for estimated timing of cash (9,075) flows Standardized measure of discounted future net cash 19,629 flows
SIGNATURES Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Dated: November 2, 1998 BONNEVILLE PACIFIC CORPORATION BY: /s/ Clark M. Mower Clark M. Mower President Bonneville Pacific Corporation (Chapter 11 Debtor) and Subsidiaries Consolidated Balance Sheet October 31, 1998 -----END PRIVACY-ENHANCED MESSAGE-----