-----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, BBToYfrlAk+3FNhYPy1PvlqEDkG6522cP6W5reJF/cqnqoPXEnFoJ6EfQteEXr2W dKB+aisSFb/KYz9DEH4JBA== 0000950123-99-001637.txt : 19990301 0000950123-99-001637.hdr.sgml : 19990301 ACCESSION NUMBER: 0000950123-99-001637 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19981231 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 19990226 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ORANGE & ROCKLAND UTILITIES INC CENTRAL INDEX KEY: 0000074778 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 131727729 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-04315 FILM NUMBER: 99550746 BUSINESS ADDRESS: STREET 1: ONE BLUE HILL PLZ CITY: PEARL RIVER STATE: NY ZIP: 10965 BUSINESS PHONE: 9143526000 MAIL ADDRESS: STREET 1: ONE BLUE HILL PLAZA CITY: PEARL RIVER STATE: NY ZIP: 10965 FORMER COMPANY: FORMER CONFORMED NAME: ROCKLAND LIGHT & POWER CO DATE OF NAME CHANGE: 19681202 8-K 1 ORANGE AND RECOKLAND UTILITIES, INC. 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): December 31, 1998 ORANGE AND ROCKLAND UTILITIES, INC. (Exact name of Registrant as specified in its charter) Incorporated in New York 1-4315 13-1727729 (State or Other (Commission (IRS Employer Jurisdiction of File Number) Identification Incorporation) Number)
One Blue Hill Plaza, Pearl River, New York 10965 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: (914)352-6000 2 Items 1.-4. Not Applicable. Item 5. Other Events. Orange and Rockland Utilities, Inc. (the "Company") reports audited consolidated financial statements for the year ended December 31, 1998, together with management's review of the Company's results of operations and financial condition, which information is included as Exhibit 99.17 to this Form 8-K. Item 6. Not Applicable. Item 7. Exhibits. Exhibit 23 - Consent of Arthur Andersen, LLP Exhibit 27 - Financial Data Schedule Exhibit 99.17 - Audited Consolidated Financial Statements of the Company and its Subsidiaries for the year ended December 31, 1998, together with Management's Review of the Company's Results of Operations and Financial Condition. Item 8. Not Applicable. Item 9. Not Applicable. -2- 3 SIGNATURE 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 hereunto duly authorized. ORANGE AND ROCKLAND UTILITIES, INC. By: /s/Robert J. McBennett Robert J. McBennett, Treasurer Dated: February 26, 1999 -3- 4 EXHIBIT INDEX ------------- Exhibit Number Description ------- ----------- Exhibit 23 Consent of Arthur Andersen LLP Exhibit 27 Financial Data Schedule Exhibit 99.17 Audited Consolidated Financial Statements of the Company and its Subsidiaries for the year ended December 31, 1998, together with Management's Review of the Company's Results of Operations and Financial Condition. EX-23 2 CONSENT OR ARTHUR ANDERSEN LLP 1 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report on the consolidated financial statements of Orange and Rockland Utilities, Inc., dated February 4, 1999 and included in this Current Report on Form 8-K into the Company's previously filed Registration Statements, on Form S-8 (File Nos. 33-25358, 33-25359 and 33-22129) and on Form S-3 (File No. 333-72289 and 333-26337). ARTHUR ANDERSEN LLP New York, N.Y. February 26, 1999 EX-27 3 FINANCIAL DATA SCHEDULE
UT 12-MOS DEC-31-1998 DEC-31-1998 Per-Book 951,570 7,528 194,848 154,194 0 1,308,140 67,599 126,276 186,520 380,395 0 0 357,156 0 0 149,050 36 43,516 0 1,654 376,333 1,308,140 626,104 22,513 527,601 550,114 75,990 2,561 78,551 33,584 44,967 2,797 42,170 34,899 23,867 76,192 3.12 0
EX-99.17 4 AUDITED CONSOLIDATED FINANCIAL STATEMENTS 1 Review of the Company's Results of Operations and Financial Condition Major Developments -- 1998 Merger On May 10, 1998, the Company, Consolidated Edison Inc. (CEI) and C Acquisition Corp., a wholly owned subsidiary of CEI (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement) providing for a merger transaction among the Company, CEI and the Merger Sub. Pursuant to the Merger Agreement, Merger Sub will merge with and into the Company (the Merger), with the Company being the surviving corporation and becoming a wholly owned subsidiary of CEI. On June 22, 1998, the Company and CEI and Consolidated Edison Company of New York, Inc. (Con Edison) filed a Joint Petition (Joint Petition) with the New York Public Service Commission (NYPSC) requesting approval of the Merger. The Parties have requested regulatory reviews and approvals prior to March 31, 1999. In this Joint Petition, the Company reaffirmed its commitment to honor the provisions of its NYPSC-approved Electric Rate and Restructuring Plan, dated November 26, 1997 (Restructuring Plan). Accordingly, the Company has proceeded with its efforts to divest all of its generating assets and to implement full retail access for all customers by May 1, 1999. Since both the Company and Con Edison have agreed to implement full retail access and have committed to comprehensive generation divestiture programs, the Company and Con Edison, in their filing described below with the Federal Energy Regulatory Commission (FERC), took the position that the Merger will not have an adverse impact on competition in the electric industry. The Merger is anticipated to result in cost savings, net of transaction costs and costs to achieve, of approximately $468 million over the first 10 years following the closing of the transaction. Transaction costs and costs to achieve are the incremental legal, financial, employee and organizational costs incurred and to be incurred to effectuate and implement the Merger and related costs savings activities. The Parties have proposed in the Joint Petition that these cost savings be allocated between customers and shareholders on a 50/50 basis. In addition, the Parties have proposed a cost allocation methodology and accounting procedure which would govern them and their various affiliates. On July 2, 1998, Rockland Electric Company (RECO) and Pike County Light & Power Company (Pike), wholly owned utility subsidiaries of the Company, filed similar petitions with the New Jersey Board of Public Utilities (NJBPU) and the Pennsylvania Public Utility Commission (PPUC), respectively, for approval of the Merger. The proceedings before the NYPSC, the NJBPU and the PPUC have established schedules that provide for final decisions by March 31, 1999. The Company can give no assurance that any of the Commissions will issue orders by that date or what, if any, conditions may be imposed by such Commissions to such orders. On January 14, 1999, Pike, the Office of the Consumer Advocate and the Office of the Small Business Advocate executed a settlement agreement which allows Pike to retain all merger savings, net of costs to achieve, until its next electric and gas base rate case. An Administrative Law Judge (ALJ) issued a Recommended Decision to the PPUC on February 3, 1999 recommending approval of the settlement in its entirety. A final PPUC order is expected prior to March 31, 1999. Orange and Rockland Utilities, Inc. and Subsidiaries On September 9, 1998, the Company and Con Edison filed an Application for Approval of Merger and Related Authorizations with the FERC. On January 27, 1999, FERC issued an order approving the merger consistent with the terms of said application. On February 3, 1999, the Company and CEI filed an application with the Securities and Exchange Commission seeking approval of the Merger under the Public Utility Holding Company Act of 1935. On January 26, 1999, the Company and CEI each filed a Notification and Report Form under the Hart-Scott-Rodino Act of 1976, as amended, (HSR Act) with the Department of Justice and the Federal Trade Commission. Under the provisions of the HSR Act, consummation of the Merger is subject to the expiration or earlier termination of the applicable waiting period. At a Special Meeting of the Common Shareholders of the Company held on August 20, 1998, the Merger Agreement was approved by a vote of approximately 74% of the common shares entitled to vote. The Merger is expected to occur shortly after all of the conditions to the consummation of the Merger, including the receipt of all regulatory approvals, are met or waived. Divestiture In accordance with the schedule in the Restructuring Plan, the Company filed its final divestiture plan (Divestiture Plan) with the NYPSC on February 4, 1998. The Divestiture Plan, which provides for a two-phase auction process, was approved by the NYPSC in orders issued April 16, 1998 and May 26, 1998. The Company retained Donaldson, Lufkin & Jenrette Securities Corporation to act as its financial advisor in connection with the divestiture of the generating assets. Following the review of final bids and negotiations with the winning bidder, on November 24, 1998, the Company entered into four separate Asset Sales Agreements (ASAs) with subsidiaries of Southern Energy, Inc. (Southern Energy), a subsidiary of Southern Company. The sales price for all generating facilities, including the two-thirds interest in Bowline Point Generating Plant (Bowline) owned by Con Edison, is approximately $480 million, plus certain fuel inventory and other adjustments. The Company's share of the sales price is approximately $345 million. The sale is subject to federal and state regulatory review and approval. The ASAs provide for the closing of the sale to occur on April 30, 1999, which date may be adjusted depending on the receipt of regulatory approvals. Under the terms of the ASAs, if approval by FERC of the establishment of the Independent System Operator, as described below, has not been obtained by the time all other regulatory approvals have been obtained, the parties have agreed to defer the closing of the sale, but in no event to a date later than August 31, 1999. The Restructuring Plan provides that the New York share of any net book gains from the divestiture of the generating assets will be shared between the Company's New York customers and shareholders, with shareholders receiving 25 percent of the gain, up to $20 million. The terms of the Restructuring Plan also permit the Company to defer and recover up to $7.5 million (New York electric share) of prudent and verifiable non-officer employee costs associated with the divestiture, such as retraining, outplacement, severance, early retirement and employee retention programs. Under the terms of the Restructuring Plan, the Company will be authorized to petition the NYPSC for recovery of employee costs in excess of $7.5 million. In addition, the Restructuring Plan provides for the recovery of all prudent and verifiable costs of the sale. The NJBPU has not yet decided how RECO's share of any gain will be allocated between ratepayers and shareholders. Pike's settlement will allow shareholders to retain $55,000 of any gain. Competition Regulatory agencies at the federal level, as well as in the three states in which the Company has retail electric franchises, are currently implementing changes in regulatory and rate-making practices, as described below, designed to promote increased competition consistent with safety, reliability and affordability standards. Depending on ongoing developments in this area, the Company's market share and profit margins will become subject to competitive pressures in addition to regulatory constraints. Federal Initiative On April 24, 1996, the FERC issued its final order (FERC Order 888) requiring electric utilities to file non-discriminatory open access transmission tariffs that would be available to wholesale sellers and buyers of electric energy. The order also provided for the recovery of related legitimate and verifiable strandable costs subject to the FERC's jurisdiction. The Company's open access transmission tariff, as originally filed with the FERC on July 9, 1996 and amended through October 1997, offers transmission service and certain ancillary services to wholesale customers on a basis that is comparable to that which it provides itself. The Company is operating under the filed tariff, subject to refund, pending final FERC approval of the Company's filing. The Company participates in the wholesale electric market primarily as a buyer of energy and, as a result, Order 888 is not expected to materially impact the Company's financial condition or results of operations. On January 31, 1997, the Company, in conjunction with the other members of the New York Power Pool (NYPP), filed tariffs with the FERC seeking permission to restructure the NYPP into an Independent System Operator (ISO). On December 19, 1997, the Company and the other members of the NYPP made a supplemental filing with the FERC which provides for a revised ISO governance structure. In an Order dated January 27, 1999, the FERC conditionally accepted the proposed ISO Tariff and the proposed market rules of the ISO. The Order requires substantial modifications to the proposed ISO Tariff including separation of the transmission tariff from the rate schedules that govern non-transmission functions. The NYPP members must submit a revised monitoring program to identify both the exercise of market power and market design flaws. The FERC also set a hearing to consider certain rate issues and noted that an application pursuant to Section 203 of the Federal Power Act requesting transfer of control of all necessary facilities from the NYPP members to the ISO must be submitted to and approved by the FERC. The NYPP members filed such Section 203 applications with the FERC on February 5, 1999. The Company is unable to predict when the ISO will become operational. New York Competitive Opportunities Proceeding Electric The Restructuring Plan, in addition to providing for the divestiture of the electric generating facilities discussed above, provides that full retail access to a competitive energy and capacity market will be available for all customers by May 1, 1999. The Restructuring Plan also provides for electric price reductions of approximately $32.4 million over its four-year term and for recovery, through a Competitive Transition Charge (CTC), of above-market generation costs should the transfer of title to the Company's generating assets not occur before May 1, 1999. Should a CTC be required, the Company would be authorized to recover the difference between its non-variable costs of generation, including 75% of fixed production labor expenses and property taxes, and the revenues, net of fuel and variable operating and maintenance expenses, derived from the operation of the Company's generating assets in a deregulated competitive market. If title to the generating assets has not transferred as of May 1, 2000, the CTC would be modified so as to allow a maximum recovery of 65% of fixed production labor expenses and property taxes. The modified CTC would remain effective until the earlier of the date title to the generating assets is - -------------------------------------------------------------------------------- 7 2 Orange and Rockland Utilities, Inc. and Subsidiaries transferred or October 31, 2000. In the event title to the generating assets is not to be transferred by October 31, 2000, the Company would be authorized to petition the NYPSC for permission to continue a CTC until the date title to the generating assets is transferred. The CTC does not allow for the recovery of inflationary increases in non-fuel operating and maintenance production costs, property tax increases, wage rate increases, or increased costs associated with capital additions or changes in the costs of capital applicable to production costs. The Restructuring Plan also provides a schedule for the submission of comments by the Company, the staff of the New York State Department of Public Service (the Staff) and other interested parties to the NYPSC on the degree and timing of introducing competition in metering and billing services. The NYPSC initiated proceedings in these areas during 1998. The Company cannot predict at this time the ultimate outcome of the proceedings or their effect, if any, on the Company's consolidated financial position or results of operations. Settlement agreements, providing for the implementation of unbundled rates, effective May 1, 1999, which separate the components of existing tariffs into production, transmission, distribution and customer cost categories, were reached on August 13 and September 18, 1998 between the Company, the Staff and other interested parties. By Orders dated February 4, 1999, the NYPSC approved the settlement agreements with minor modifications. Gas In 1996, the NYPSC approved utility restructuring plans designed to open up the local natural gas market to competition and allow residential and small commercial users the ability to purchase gas supplies from a variety of sources, other than the franchised local distribution utility. On November 3, 1998, the NYPSC issued a Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Case 97-G-1380). The Policy Statement envisions a three- to seven-year transition for gas utilities to exit the gas merchant function. To further this process and increase gas competition in the state, the NYPSC has directed that gas utilities no longer require customers migrating from sales to transportation service to continue utilizing upstream pipeline capacity contracted for by the utility, except where specific operational or reliability requirements warrant. According to the Order, utilities will be provided a reasonable opportunity to recover strandable costs. The Company ceased requiring transportation customers to utilize its upstream capacity as of October 1, 1998. As of December 31, 1998, the Company has not incurred any stranded costs related to its upstream pipeline capacity. As the Company moves to a competitive market, traditional cost recovery mechanisms may be replaced by market-based methods. It is not possible to predict the outcome of this proceeding or its effect on the Company's consolidated financial position or results of operations. New Jersey -- Energy Master Plan On April 30, 1997, the NJBPU issued an order "Adopting and Releasing Final Report in its Energy Master Plan Phase II Proceeding to Investigate the Future Structure of the Electric Power Industry (Docket No. EX 94120585Y)." The Order required RECO and other New Jersey investor-owned electric utilities each to file unbundled rates, a stranded cost proposal and a restructuring plan by July 15, 1997. As part of its stranded cost proposal, the NJBPU recommended that each utility provide a 5-10% rate reduction. RECO's filing was made on July 15, 1997. The filing includes a Restructuring Plan, a Stranded Costs Filing and an Unbundled Rates Filing. On December 8, 1997, RECO submitted an Amended and Restated Restructuring Plan and Stranded Costs Filing with the NJBPU to reflect the fact that the Company has committed to divest all of its electric generating assets by auction. The Restructuring Plan calls for RECO to remain a regulated transmission and distribution company. Standards of Conduct and Affiliate Rules have been proposed in order to promote effective competition and ensure that regulated operations do not subsidize unregulated operations. RECO has proposed to implement full retail competition (energy and capacity) for all customers by May 1, 1999, the same date approved for retail access in New York. As discussed below, the recently approved New Jersey restructuring legislation would delay the implementation of full retail access until June 1, 1999. Under this schedule, full retail access will be achieved 13 months ahead of the NJBPU's proposed phase-in schedule. In its Stranded Costs Filing, RECO has identified two categories of potential stranded costs: generation investment and power purchase contracts with non-utility generators (NUG). Divestiture of the Company's generating assets will determine their market value and the related stranded costs, if any. RECO proposes to recover its share of stranded generation investment, if any, through regulated delivery rates by means of a Market Transition Charge (MTC). The MTC would be in effect over a period of up to eight years, commencing May 1, 1999. Stranded NUG contract payments are proposed to be recovered over the remaining life of the contracts through a non-bypassable wires charge also assessed by the regulated delivery company. RECO proposed to reduce its annual net revenue (revenue net of fuel, purchased power and applicable taxes) by $4.3 million, or 5.1%, effective with the implementation of retail competition. RECO also made an Unbundled Rates Filing, which was updated on January 30, 1998, and would serve as the basis to segregate the costs of the generation function from rates in order to facilitate customer choice. In addition, the MTC mechanism would be added to the existing rate structure to allow for recovery of stranded costs, and a non-bypassable societal benefits charge would be created as a billing mechanism for mandated public policy programs. Hearings with respect to RECO's filings were held in the spring of 1998 and a decision is pending. The NJBPU has indicated that it will consider RECO's filings as required by the recently enacted utility legislation discussed below. On January 28, 1999, the New Jersey Assembly and Senate approved restructuring legislation. The Governor signed this legislation into law on February 9, 1999. The legislation provides for the implementation of full retail access by no earlier than June 1, 1999 and no later than August 1, 1999. In addition, the legislation requires rate reductions of at least 5% at the start of retail access from the level of aggregate rates in effect on April 30, 1997 and of at least an additional 5% within thirty-six months of the start of retail access. Further, these reductions must be sustained for a total of four years from the start of retail access. In addition, the legislation authorizes the NJBPU to establish "shopping credits" for those customers choosing an alternative supplier of electricity. Given the results of the sale of the Company's generation facilities, it is likely that RECO's stranded costs will be limited to uneconomic NUG contracts, for which the legislation provides recovery over the life of the contract. As discussed above, RECO has proposed to reduce its revenues net of fuel and taxes by 5.1%. Until a procedural schedule is established by the NJBPU to address RECO-specific issues, the Company is unable to predict the outcome of this proceeding or its effect, if any, on the Company's consolidated financial position or results of operations. Pennsylvania -- Competition Legislation On December 3, 1996, the Electricity Generation Customer Choice and Competition Act (Act) was signed into law by the Governor of the Commonwealth of Pennsylvania. The Act provides for a transition of the Pennsylvania electric industry from a vertically integrated structure to a functionally separated model that permits direct access by customers to a competitive electric generation market while retaining the existing - -------------------------------------------------------------------------------- 8 3 Orange and Rockland Utilities, Inc. and Subsidiaries regulation and customer protections in the transmission and distribution systems. The transition plan of the Act calls for a three-year phase-in of retail access beginning January 1, 1999, and concluding January 1, 2001. The Act also provides for the opportunity for recovery of prudent and verifiable costs resulting from the restructuring through the implementation of a Competitive Transition Charge (CTC) for a period of up to nine years and the imposition of rate caps designed to prevent a customer's total electric costs from increasing above current levels during the transition period. In addition, the Act permits the refinancing of certain approved transition costs through the issuance of bonds secured by revenue streams, the continuation of which are guaranteed by the PPUC. The savings associated with this financing mechanism will be used to reduce strandable costs. On September 30, 1997, in accordance with the requirements of the Act, Pike submitted its electric restructuring filing to the PPUC. On December 15, 1997, Pike submitted an Amended and Restated Electric Restructuring Filing with the PPUC to reflect the fact that the Company has committed to divest all of its electric generating assets by auction. In this amended and restated filing, Pike proposed that full retail competition be implemented for all customers by May 1, 1999. With the implementation of retail competition, Pike proposed to continue to serve as the "provider of last resort" for those consumers who do not choose an alternate provider, or whose alternate provider defaults. Pike proposed to remain a regulated transmission and distribution company. On September 30, 1997, Pike also submitted proposed unbundled rates which separate the components of existing tariffs into production, transmission, distribution and customer cost categories. This filing was updated on January 30, 1998. On May 15, 1998, Pike reached a settlement agreement which resolved all issues in the restructuring and rate unbundling proceeding. On July 23, 1998, the PPUC approved Pike's electric restructuring settlement agreement. The agreement calls for implementation of full retail access by May 1, 1999, provides for unbundled electric rates, including a CTC which allows full recovery of all stranded costs and a Basic Generation Service charge for customers who remain with Pike for generation services. In addition, the settlement allows shareholders to retain $55,000 of Pike's pro rata share of any gain on the sale of the Company's generating facilities. Rate Activities New York -- Gas On December 30, 1998, the Company filed a gas base rate case with the NYPSC, the Company's first such filing since 1991. The Company's rate year cost of service justifies an increase in gas revenue of $13 million, or 8.2%. This increase is due primarily to gas construction expenditures necessary to maintain a safe and reliable infrastructure, property tax increases and expenditures for environmental investigation and remediation. In order to avoid a sudden and relatively large rate increase, the Company is limiting its rate year request to an increase of $3.9 million, or 2.5%. The Company's proposal to limit the increase to $3.9 million is conditioned on the approval of several provisions. The Company has requested that it be allowed to: (1) continue to defer environmental investigation and remediation costs associated with its former manufactured gas plant sites and its West Nyack, New York facility; (2) defer prospective increases in gas property tax expense; (3) amortize deferred credits associated with pension and management audit costs over a two-year period; and (4) amortize, over a two-year period, a $4 million depreciation reserve credit which represents the difference between book and theoretical reserve as well as the remaining balance from a previous depreciation study. The Company also has proposed a second stage adjustment to gas rates to take effect October 1, 2000 and a third stage adjustment to take effect October 1, 2001. These adjustments would include the following: (1) inflation on all operation and maintenance expenses other than fixed amortizations and taxes other than income taxes; (2) recovery of any deferred property tax expense; (3) recovery of carrying costs and depreciation on the forecasted increases in rate base for the ensuing rate year due to increases in plant in service, less depreciation reserves and deferred income taxes related to gas plant and the gas portion of common plant; and (4) recovery of previously deferred environmental investigation or remediation costs. An ALJ will establish the procedural schedule for the proceeding. New York -- Electric On May 3, 1996, the NYPSC approved, subject to modifications required by the NYPSC decision in the New York Competitive Opportunities Proceeding (as previously discussed), a Settlement Agreement (1996 Agreement) among the Company, Staff and other parties which resolved all remaining revenue requirement issues in the proceeding for a three-year period commencing May 1, 1996, and concluding April 30, 1999. Under the 1996 Agreement, the Company reduced its annual electric retail revenues in New York by $7.75 million, or 2.3%, effective May 1, 1996. The settlement provided for several performance mechanisms related to service reliability and customer service, and the elimination of all revenue and most expense reconciliation provisions contained in the Revenue Decoupling Mechanism then in effect. The 1996 Agreement provided the Company with the opportunity to retain all New York electric earnings up to a 10.9% return on equity annually for each of the next three years. Earnings in excess of 10.9% would be shared equally between customers and shareholders. By orders dated November 26 and December 31, 1997, the Company, on December 1, 1997, as part of the approved Restructuring Plan, implemented the first year of the electric rate reduction in the amount of $5.9 million. An incremental rate reduction of $2.9 million was implemented as part of this agreement on December 1, 1998. In addition, the Restructuring Plan permits the Company to retain all earnings up to an 11.4% return on equity and provides that earnings in excess of 11.4% are to be shared, with 75% to be used to offset NYPSC approved deferrals or otherwise inure to the Company's customers, and 25% to be retained by the Company's shareholders. (This supersedes the 10.9% contained in the 1996 Agreement). Additional information on New York electric rate activities is contained in the previous discussion of the New York Competitive Opportunities Proceeding. New Jersey The NJBPU on January 8, 1997 approved a stipulation among New Jersey utilities, NJBPU Staff and NJ Division of Ratepayer Advocate which provides a recovery plan for costs associated with the change in accounting required by Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The approved plan provides several alternative recovery mechanisms. RECO received approval from the NJBPU on December 17, 1997 to begin amortizing these costs effective January 1, 1998. On January 23, 1997, a residential customer of RECO filed a petition with the NJBPU requesting a lowering of RECO's rates by $21.2 million, or 16%, based on financial data for the twelve months ended December 31, 1995, as adjusted. A central issue raised by the petition is whether RECO's continued purchase of all of its power supply requirement from the Company continues to be appropriate when alleged lower cost energy is available from other sources. In an Order dated January 23, 1998, the NJBPU did not approve petitioner's request to reduce RECO's rates. - -------------------------------------------------------------------------------- 9 4 Orange and Rockland Utilities, Inc. and Subsidiaries The Order held the petition in abeyance pending the outcome of the unbundling, stranded costs and restructuring filings by RECO. In addition, the NJBPU granted petitioner intervenor status in RECO's restructuring proceedings to raise issues related to the continued purchase by RECO of its power supply requirements from the Company. The Company does not expect the petition to have a material effect on the Company's consolidated financial position or results of operations. Discontinued Operations In August 1997, Norstar Management, Inc. (NMI), a wholly owned indirect subsidiary of the Company, sold certain of the assets of NORSTAR Energy Limited Partnership (NORSTAR), a natural gas services and marketing company of which NMI is the general partner. The assets sold consisted primarily of customer contracts and accounts receivable. The Company believes all liabilities related to NORSTAR were fully provided for in 1997 and that the Company's future results of operations are not expected to be materially affected thereby. In accordance with Accounting Principles Board Opinion No. 30, the financial results for this segment are reported as "Discontinued Operations." The total losses related to discontinued operations were $(15,432,000), or $(1.13) per share, for 1997 and $(1,844,000), or $(0.13) per share, for 1996. Financial Performance Earnings per share from continuing operations were $3.12 for 1998, compared to $3.09 in 1997 and $3.30 in 1996. The increase in continuing operations earnings between 1998 and 1997 was primarily the result of increased electric retail sales, higher other income, the conclusion of the incurrence of investigation and litigation costs during 1997 and the lower number of shares outstanding. Partially offsetting the increase were lower gas sales and higher operating and maintenance expenses. The decrease between 1997 and 1996 was primarily the result of decreased electric and gas net revenues, increased investigation and litigation costs and increased interest charges, partially offset by lower operating and maintenance expenses. Consolidated earnings per share were $3.12, $1.96 and $3.17 for the years 1998, 1997 and 1996, respectively. The increase in consolidated earnings per share in 1998 is primarily the result of the costs associated with discontinuing the Company's gas marketing subsidiary during 1997. Earnings per average common share are summarized as follows:
1998 1997 1996 ================================================================================ Utility operations $ 3.18 $ 3.25 $ 3.39 Events affecting the Company: Investigation & litigation costs -- (0.13) (0.09) Diversified activities (0.06) (0.03) -- - -------------------------------------------------------------------------------- Earnings per share from continuing operations 3.12 3.09 3.30 Loss per share from discontinued operations -- (1.13) (0.13) - -------------------------------------------------------------------------------- Consolidated earnings per share $ 3.12 $ 1.96 $ 3.17 - --------------------------------------------------------------------------------
The earned return on common equity was 11.3% in 1998, compared to 7.1% in 1997 and 11.3% in 1996. If the effect of the Company's discontinued operations were excluded, the earned return on common equity would have been 11.2% and 12.2% in 1997 and 1996, respectively. Book value per share at year-end 1998 was $28.14, compared to $27.69 in 1997 and $28.41 in 1996. The dividends paid on common stock were $2.58 per share in 1998, 1997 and 1996. Under the terms of the Merger Agreement, the Company has agreed not to pay dividends in any quarter in excess of the dividend amount paid for the same period of the prior fiscal year. The Company has maintained the following capital structure: 46% long-term debt, 6% preferred stock and 48% common equity. Results of Operations The discussion which follows identifies the principal causes of the significant changes in the amounts of revenues and expenses affecting income available for common stock by comparing 1998 to 1997 and 1997 to 1996. This discussion should be read in conjunction with the Notes to Consolidated Financial Statements and other financial and statistical information contained elsewhere in this report. The following is a summary of the changes in earnings available for common stock:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Utility operations: Operating revenues $ (22.4) $ (5.6) Energy and gas costs (18.3) 3.8 - -------------------------------------------------------------------------------- Net revenues from utility operations (4.1) (9.4) Other utility operating expenses and taxes (3.0) (5.7) - -------------------------------------------------------------------------------- Operating income from utility operations (1.1) (3.7) Diversified revenues (0.2) (0.5) Diversified operating expenses and taxes (0.3) 1.5 - -------------------------------------------------------------------------------- Income from operations (1.0) (5.7) Other income and deductions 3.1 3.2 Interest charges 2.0 0.7 - -------------------------------------------------------------------------------- Income from continuing operations 0.1 (3.2) Discontinued operations 15.4 (13.6) - -------------------------------------------------------------------------------- Net income 15.5 (16.8) Preferred dividends -- (0.2) - -------------------------------------------------------------------------------- Earnings applicable to common stock $ 15.5 $ (16.6) - --------------------------------------------------------------------------------
Electric Operating Results Electric operating revenues, net of fuel and purchased power costs, increased by 0.3%, or $1.1 million, in 1998 after decreasing by 1.0%, or $3.7 million, in 1997. These changes are attributable to the following factors:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Retail sales: Price changes $(5.2) $(5.7) Sales volume changes 11.8 6.5 - -------------------------------------------------------------------------------- Subtotal 6.6 0.8 Sales for resale 6.8 4.0 Other operating revenues (3.0) (2.4) - -------------------------------------------------------------------------------- Total electric revenues 10.4 2.4 Electric energy costs 9.3 6.1 - -------------------------------------------------------------------------------- Net electric revenues $ 1.1 $(3.7) - --------------------------------------------------------------------------------
Electric Sales and Revenues Total sales of electric energy to retail customers during 1998 were 4,865,286 Mwh (megawatt hours), compared with 4,691,935 Mwh during 1997 and 4,605,262 Mwh in 1996. Revenues associated with these sales were $472.4 million, $465.8 million and $465.0 million in 1998, 1997 and 1996, respectively. Electric revenues were reduced by $8.0 million during the year due to the change necessitated by the New Jersey Uniform Transitional Utilities Assessment Act. This act, although it resulted in a change in the method of recording the tax by lowering revenue and correspondingly lowering taxes other than income taxes, did not affect the Company's tax liability or the Company's net income for the period. Electric sales to customers for the last five years are shown in the accompanying chart: Electric Sales to Customers Mwh (Millions) [GRAPHIC OMITTED] [The following table was depicted as a bar chart in the printed material.] '94 '95 '96 '97 '98 4.46 4.53 4.61 4.69 4.87 - -------------------------------------------------------------------------------- 10 5 Orange and Rockland Utilities, Inc. and Subsidiaries The changes in electric sales by class of customer from the prior year are as follows:
1998 1997 ================================================================================ Residential 2.5% 3.5% Commercial 7.4% (4.2%) Industrial (2.9%) 12.2% Public street lighting 6.7% (8.9%) Sales to public authorities 7.0% 43.3% - --------------------------------------------------------------------------------
Customer usage increased as a result of an increase in the average kilowatt hours (Kwh) used per customer and an increase in the average number of customers. Electric sales increased 3.7%, 1.9% and 1.7% in 1998, 1997 and 1996, respectively. Under its Restructuring Plans, the Company and its utility subsidiaries will remain regulated transmission and distribution companies that will deliver electricity to its customers and maintain reliable service. All New York and Pennsylvania customers will be provided the opportunity to choose an alternative electric supplier effective May 1, 1999. Under legislation recently adopted in New Jersey, customers there will be provided full retail access by no earlier than June 1, 1999 and no later than August 1, 1999. The Company and its utility subsidiaries will remain the "provider of last resort" for those of its customers who do not purchase electricity from other sources. The Company will continue to introduce programs which are designed to reduce peak load and encourage efficient energy usage. The Company's future electric earnings will be affected by changes in sales volumes resulting from the strength of the economy, weather conditions and conservation efforts of customers. Sales for resale increased by $6.8 million to $14.0 million in 1998 when compared to 1997, after increasing $4.0 million in 1997. Revenues from these sales are primarily a recovery of costs, under the applicable tariff regulations, and have a minimal impact on the Company's earnings. Electric Energy Costs The cost of fuel used in electric generation and purchased power increased 6.9%, or $9.3 million, in 1998, after increasing 4.7%, or $6.1 million, in 1997. The components of these changes in electric energy costs are as follows:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Prices paid for fuel and purchased power $(7.6) $ -- Changes in Kwh generated or purchased 11.6 6.3 Deferred fuel charges 5.3 (0.2) - -------------------------------------------------------------------------------- Total $ 9.3 $ 6.1 - --------------------------------------------------------------------------------
The increase in electric energy costs in both 1998 and 1997 is primarily the result of increased sales. Cost Per KwH Cents [GRAPHIC OMITTED] [The following table was depicted as a bar chart in the printed material.] '94 '95 '96 '97 '98 2.51 2.46 2.48 2.49 2.36 The price paid for fuel and purchased power per kilowatt hour over the last five years is shown in the accompanying chart: The Company maintains an aggressive program of managing its sources of fuel and energy purchases to provide its customers with the lowest cost of energy available at any given time. Energy is purchased whenever available at a price lower than the cost of production at the Company's generating plants. The Company continues to use the least costly fuel available for generating electricity. Once the sale of the Company's generating assets is completed, electric energy costs will consist of purchased power costs necessary to meet the needs of customers under the "provider of last resort" clause contained in the restructuring plans. Gas Operating Results Gas operating revenues, net of gas purchased for resale, decreased by 7.5%, or $5.2 million, in 1998 when compared to 1997, after decreasing by 7.6%, or $5.7 million in 1997. These changes are attributable to the following factors:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Sales to firm customers: Price changes (including gas recoveries) $(20.3) $(2.0) Sales volume changes (8.8) (1.8) - -------------------------------------------------------------------------------- Subtotal (29.1) (3.8) Sales to interruptible customers (3.7) (1.2) Sales for resale -- -- Other operating revenues -- (3.0) - -------------------------------------------------------------------------------- Total gas revenues (32.8) (8.0) Gas energy costs (27.6) (2.3) - -------------------------------------------------------------------------------- Net gas revenues $ (5.2) $(5.7) - --------------------------------------------------------------------------------
Gas Sales and Revenues Firm gas sales amounted to 17,342 million cubic feet (Mmcf) in 1998, a decrease of 14.7% from the 20,321 Mmcf recorded in 1997. The decrease in sales in 1997 was 2.9% from the 1996 level of 20,918 Mmcf. Gas revenues from firm customers were $121.0 million, $150.1 million and $153.9 million in 1998, 1997 and 1996, respectively. Firm Gas Sales Mmcf (thousands) [GRAPHIC OMITTED] [The following table was depicted as a bar chart in the printed material.] '94 '95 '96 '97 '98 20.4 19.8 20.9 20.3 17.3 Gas sales to firm customers for the last five years are shown in the accompanying chart: The changes in firm gas sales by class of customer from the prior year are as follows:
1998 1997 ================================================================================ Residential (16.7%) (4.4%) Commercial and industrial (8.8%) 1.7% - --------------------------------------------------------------------------------
The decrease in 1998 was primarily the result of the warmest winter weather in the last thirty years. Annual heating degree days were 21% below normal. This decrease was somewhat offset by an increase in the average number of customers. The decrease in 1997 was primarily the result of milder weather conditions offset somewhat by an increase in the average number of customers. Under the terms of the current gas rate agreement in New York, the level of firm sales is subject to a weather normalization adjustment. The Company adjusts firm gas sales revenues to the extent actual degree days vary more than plus or minus 2.2% from the degree days utilized to project sales during a heating season. Therefore, severe weather conditions will not have an impact on gas operating results. The FERC's Order 636 required pipeline supply companies to separate or unbundle their charges for providing natural gas to the local distribution companies. Subsequent to unbundling under FERC's Order 636, the Company implemented tariffs which, as approved by the NYPSC, granted the Company permission to retain 15% of all revenues derived from the release of upstream pipeline capacity beginning in 1996. Additionally, as part of the Company's rate agreement in Case 92-G-0050, the Company is allowed to retain 25% of net revenues derived from the FERC's Order 63 off-system transactions. Revenues retained from Order 636 and Order 63 transactions in 1998 amounted to $0.3 million. - -------------------------------------------------------------------------------- 11 6 Orange and Rockland Utilities, Inc. and Subsidiaries Revenues from interruptible gas customers (customers with alternative fuel sources) decreased by 26.3% in 1998 after decreasing by 7.9% in 1997 when compared to the previous year. These sales are dependent upon the availability and price competitiveness of alternative fuel sources. As a result of applicable tariff regulations, these interruptible sales do not have a substantial impact on earnings. Gas Energy Costs Utility gas energy costs decreased by 27.9%, or $27.6 million, in 1998 after a decrease of 2.3%, or $2.3 million, in 1997. The changes in utility gas energy costs for the years 1998 and 1997 are a result of the following:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Prices paid to gas suppliers* $ (5.2) $ 0.5 Firm and interruptible Mcf sendout (14.7) (5.8) Deferred fuel charges (7.7) 3.0 - -------------------------------------------------------------------------------- Total $(27.6) $(2.3) - -------------------------------------------------------------------------------- *Net of refunds received from gas suppliers.
The Company continues its policy of the aggressive use of spot market purchases in order to provide price flexibility, while assuring an adequate supply of gas through a variety of long-term and short-term gas contracts. In addition, to stabilize gas prices during the winter heating season as directed by the NYPSC, the Company establishes fixed gas prices on a monthly basis under its gas purchase agreements for a percentage of its gas purchases at New York Mercantile Exchange prices. The price paid for purchased gas per thousand cubic feet (Mcf) over the last five years is shown in the accompanying chart: Cost Per Mcf Dollars [GRAPHIC OMITTED] [The following table was depicted as a bar chart in the printed material.] '94 '95 '96 '97 '98 3.52 3.43 4.05 4.07 3.82 The NYPSC, in its effort to promote competition, has required the Company to provide firm transportation service for those customers who elect to purchase their gas supply from a marketer rather than the Company. Marketers are permitted to aggregate customers. On November 3, 1998, the NYPSC issued a Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Case 97-G-1380). The Policy Statement envisions a three- to seven-year transition for gas utilities to exit the gas merchant function. To further this process and increase gas competition in the State, the NYPSC has directed that gas utilities no longer require customers migrating from sales to transportation service to continue utilizing upstream capacity contracted for by the utility, except where specific operational or reliability requirements warrant. According to the Order, utilities will be provided a reasonable opportunity to recover strandable costs. The Company ceased requiring transportation customers to utilize its upstream capacity as of October 1, 1998. As of December 31, 1998, the Company has not incurred any stranded costs related to its upstream pipeline capacity. As the transition to a competitive retail market continues, the Company will determine what supply capacity and storage contracts it maintains. As the Company moves to a competitive market, traditional cost recovery mechanisms may be replaced by market-based methods. Other Utility Operating Expenses and Taxes A comparison of other operating expenses and taxes for utility operations is presented in the following table:
Increase (Decrease) from prior year 1998 1997 ================================================================================ (Millions of Dollars) Other operating expenses $ 5.6 $(5.8) Maintenance 1.5 (1.4) Depreciation and amortization (0.1) 3.7 Taxes (10.0) (2.2) - -------------------------------------------------------------------------------- Total $ (3.0) $(5.7) - --------------------------------------------------------------------------------
The primary reason for the increase in utility other operating expenses for 1998 is increased customer accounting and service costs primarily related to the Company's new Customer Information Management System, increased uncollectible accounts and higher transmission expenses, partially offset by reduced administrative and general expenses. The costs of Demand Side Management (DSM) programs, which were $6.0 million, $5.2 million and $4.7 million in 1998, 1997 and 1996, respectively, also caused utility operating expense to increase. However, the DSM costs are recovered in rates on a current basis and therefore have no impact on earnings. The remaining increase between 1997 and 1996 was the amortization of independent power producer costs of $9.8 million in 1997 compared to the $16.2 million amortized in 1996. Maintenance costs increased 4.1% in 1998 after decreasing by 3.7% in 1997. The increase in 1998 is primarily the result of increased plant and transmission system maintenance partially offset by decreased distribution system maintenance. In 1997, the decrease is primarily the result of lower scheduled plant maintenance costs when compared to 1996. Depreciation and amortization expenses decreased by $0.1 million in 1998, after increasing by $3.7 million in 1997 as a result of plant additions. After eliminating the regulatory adjustments approved in the New York Electric Restructuring Case, 1998 depreciation expense increased by $2.3 million due to normal plant additions and the amortization of the Company's new customer accounting system. Taxes other than income taxes decreased $8.7 million in 1998, after decreasing by $0.1 million in 1997. The decrease in 1998 is primarily due to the change necessitated by the New Jersey Uniform Transitional Utilities Assessment Act. This act, effective January 1, 1998, resulted in a change in the method of recording the tax by lowering revenue and correspondingly lowering taxes other than income taxes. After eliminating regulatory adjustments approved in the New York Electric Restructuring Case, property taxes increased by $2.1 million. Federal income tax decreased by $1.3 million in 1998, after decreasing $2.1 million in 1997. The changes in both years are the result of changes in pre-tax book income. For a detailed analysis of income tax components, see Note 2 of Notes to Consolidated Financial Statements. Diversified Activities The Company's diversified activities, at year end, excluding the discontinued gas marketing operations, consisted of energy services and land development businesses conducted by wholly owned non-utility subsidiaries. Revenues from diversified activities decreased by $0.2 million in 1998, after decreasing by $0.5 million in 1997. Operating expenses incurred by the non-utility subsidiaries decreased by $0.3 million in 1998, after increasing by $1.5 million in 1997. Earnings from diversified activities decreased by $0.3 million in 1998, after decreasing by $0.6 million in 1997. The reduction in 1998 earnings is primarily the result of the decrease in rental income resulting from sales of these properties in prior years. The reduction in 1997 earnings is primarily related to the start-up costs for Palisades Energy Services, Inc., an indirect subsidiary of the Company. - -------------------------------------------------------------------------------- 12 7 Orange and Rockland Utilities, Inc. and Subsidiaries As mentioned previously, the Company has discontinued its gas marketing operations. Diversified operations in the future will focus on promoting energy services-related operations. Other Income and Deductions and Interest Charges Other income and deductions increased by $3.1 million in 1998 after increasing by $3.2 million in 1997. The increase in 1998 was the result of the absence of investigation and litigation costs which was concluded in 1997, increased interest income, gain on the sale of securities and the recognition of other income as a result of marking securities to market (see Note 10 of Notes to Consolidated Financial Statements). The increase in 1997 was the result of the 1996 New York rate decision offset by increased investigation charges. Interest charges increased $2.0 million in 1998 when compared to 1997, after increasing $0.7 million in 1997. The increases in 1998 and 1997 are the result of increased short-term debt. Liquidity and Capital Resources The Company's construction program is designed to maintain reliable electric and gas service, meet future customer service requirements and improve the Company's competitive position. The cash expenditures related to the construction program and other capital requirements for the years 1996-1998 were as follows:
1998 1997 1996 ================================================================================ (Millions of Dollars) Construction expenditures $55.4 $73.1 $60.9 Retirement of long-term debt & equity -- net 2.9 5.8 1.8 - -------------------------------------------------------------------------------- Total $58.3 $78.9 $62.7 - --------------------------------------------------------------------------------
At December 31, 1998, the Company estimated the cost of its construction program in 1999 to be $41.0 million. This estimate includes four months of construction expenditures related to the Company's generating facilities. It is expected that the Company's capital requirements for 1999 will be met primarily with funds from operations, supplemented by short-term borrowings. The financing activities of the Company and its utility subsidiaries during 1998 consisted of a debt refinancing and the repurchase of common stock. With regard to long-term debt refinancing, on November 10, 1998, Pike issued $3.2 million of First Mortgage Bonds Series C, 7.07% due October 1, 2018 (the Series C Bonds). The proceeds from the sale of the Series C Bonds were used primarily to redeem the two series of Pike First Mortgage Bonds then outstanding; the Series A Bonds, 9% due 2001 and the Series B Bonds, 9.95% due 2020, with the remaining proceeds being used to finance capital spending. With regard to common stock, the Company, pursuant to an order of the NYPSC, initiated a Common Stock Repurchase Program (the Repurchase Program) during December 1997. Funds were provided for the Repurchase Program through a Credit Agreement between the Company and Mellon Bank, N. A. During 1998, the Company repurchased 70,400 shares of its Common Stock at an average price of $45.81 per share. The Repurchase Program was suspended in the first quarter of 1998. The total number of shares of common stock repurchased under the Repurchase Program was 136,300 shares at an average price of $45.75 per share. Both the Repurchase Program and the Credit Agreement were canceled during the second quarter of 1998. The Company's Dividend Reinvestment Plan (DRP) and its Employee Stock Purchase and Dividend Reinvestment Plan (ESPP) provide that, at the option of the Company, the common stock requirements of the plans may be satisfied by either the original issue of common stock or open market purchases. Since November 1, 1994, the requirements of both plans have been satisfied by open market purchases. The Company has outstanding 428,443 shares of Non-Redeemable Cumulative Preferred Stock and 10,684 shares of Non-Redeemable Preference Stock (the Preferred and Preference Stock) in various series, which together amount to $43.5 million. Both the Preferred Stock and the Preference Stock are redeemable at the option of the Company. The 10,684 shares of Non-Redeemable Preference Stock are convertible into shares of the Company's common stock, prior to redemption, at a ratio of 1.47 shares of common stock for each share of Preference Stock. The Merger Agreement calls for the redemption of all of the Company's Preferred and Preference Stock prior to the effective date of the Merger. On October 7, 1998, the Company filed a petition with the NYPSC for permission to issue up to $45 million aggregate principal amount of unsecured debentures and to use the proceeds from the sale of the unsecured debentures to redeem all of the Company's outstanding Preferred Stock and Preference Stock. The NYPSC approved the Company's petition on January 13, 1999. The Company intends to redeem all of the outstanding Preferred and Preference Stock as soon as practicable. Neither the Company nor its utility subsidiaries have any plans at the present time for additional external financing other than debt securities proposed to be issued in connection with the redemption of the Company's Preferred and Preference Stock as described above. Pursuant to an order of the FERC, the Company has authority to issue up to $200 million of short-term debt through September 30, 1999 and RECO has authority to issue up to $15 million of short-term debt through December 31, 1999. At December 31, 1998, the Company and its utility subsidiaries had unsecured bank lines of credit totaling $160 million. At January 1, 1999, the Company reduced such lines of credit to $155 million. The Company may borrow under the lines of credit through the issuance of promissory notes to the banks. The Company, however, primarily utilizes such lines of credit to fully support commercial paper borrowings. The aggregate amount of borrowings through the issuance of promissory notes and commercial paper cannot exceed the aggregate lines of credit. The non-utility subsidiaries of the Company and of RECO had no bank lines of credit at December 31, 1998. As a result of the planned divestiture of the Company's generating facilities, it is expected that the Company will have approximately $225 million of cash proceeds available when the sale is complete. Other Developments Year 2000 Compliance Since 1996, the Company has been working to address Year 2000 (Y2K) issues. Y2K issues arise as a result of a computer programming standard that traditionally recorded a year as two digits (e.g., 98) rather than four digits (e.g., 1998). With the change in the century, software and embedded chip technology that use a two-digit field for the year may malfunction or provide inaccurate results. Overall responsibility for the Company's Y2K efforts resides with an Executive Sponsorship Committee which is responsible for ensuring that appropriate plans are implemented and adequate resources are available and for monitoring the Company's Y2K progress. The Committee consists of several members of senior management. The Chairperson of the Committee is responsible for reporting to the Company's Board of Directors on Y2K issues on a periodic basis. The Company's Y2K Plan includes the following phases: (1) awareness (i.e., the communication of Y2K issues and their importance); (2) assessment, including the development of a detailed inventory of all information technology and embedded chip technology and the assessment of the inventory for Year 2000 vulnerability; (3) remediation (i.e., repair, replacement, retirement) of affected systems; (4) validation of the individual application or device once it has been repaired followed by testing of integrated systems; and (5) contingency planning in the event problems arise in connection with critical systems or devices. - -------------------------------------------------------------------------------- 13 8 Orange and Rockland Utilities, Inc. and Subsidiaries The Company has completed an inventory and assessment of its information and embedded technology and prioritized the inventoried technology as either Mission Critical or Business Critical. Pursuant to the definitions adopted by the Company, the misoperation of a Mission Critical system or device could directly contribute to the interruption of electric or gas service or could adversely affect the safety of the general population and/or employees. Similarly, the misoperation of a Business Critical system or device could directly contribute to the loss of a department's capability to perform its function (e.g., customer service, accounting). Consistent with the target date established for the energy industry, all Mission Critical systems/devices will be Y2K ready by July 1, 1999, and all Business Critical systems/devices will be Y2K ready by October 1, 1999. Over the past several years, the Company has been evaluating and replacing various computer applications, including its Customer Information Management System, Fixed Asset System and other core accounting and management systems. This effort was undertaken to provide additional functionality, automated processing, improved access to information, as well as to address Y2K issues. The Company's remaining computer applications and hardware have been substantially remediated and this effort is targeted for completion by March 31, 1999. In addition, inventory and assessment of embedded chips throughout the Company, including the power generation, transmission and distribution and telecommunications areas, have been completed. Remediation and testing of non-compliant embedded chips have begun and the Company expects to meet the targeted completion dates of July 1, 1999 and October 1, 1999 for Mission and Business Critical systems, respectively. The Company's systems may be vulnerable to its critical suppliers should such suppliers themselves not be Y2K ready. The Company has identified its critical suppliers, including those which supply telecommunication services, coal, oil or natural gas and electricity. Assessment of the critical suppliers' Y2K readiness has begun and will be completed in February 1999. The Company is working with the NYPP and the North American Electric Reliability Council to ensure that appropriate steps are being taken to address the reliability of the power grid. The Company has procedures in place should a system failure occur. The Company is developing contingency plans based on the results of its testing and critical supplier assessments and is reviewing existing emergency plans and procedures which will be modified as appropriate to address Y2K-specific issues. Contingency plans for Mission Critical systems and suppliers will be completed by July 1, 1999, and for Business Critical systems by October 1, 1999. The total estimated cost to execute the Company's Y2K Plan is approximately $8.5 million, of which approximately $4.9 million has been incurred through December 31, 1998. These expenditures include core accounting systems which provide both enhanced functionality and address Y2K issues, but do not include other systems that were replaced in the normal course of business for operating reasons, which also address Y2K issues. The Company has and will continue to fund these costs from the operations of the Company. The Company has developed a Y2K Plan which details the steps the Company must take to mitigate the impact of the century change. The Company believes that with the full implementation of its Y2K Plan, the possibility of significant Y2K problems will be greatly reduced, if not eliminated. However, the failure of the Company, or one or more of the Company's key suppliers or vendors, to correct a material Y2K problem could result in the interruption of service to its customers or the failure of certain normal business operations. Accordingly, the Company is unable to determine at this time whether the consequences of Y2K will have a material adverse effect on the Company's results of operations, liquidity or financial condition. Termination Benefits Relating to the Divestiture The proposed sale of the Company's generating assets will result in workforce reductions. The Company plans to provide, where appropriate, termination benefits that include pension protection, severance and outplacement services to affected employees. Statement of Financial Accounting Standards No. 88 (SFAS No. 88), "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," applies to any employer that offers benefits to employees in connection with their termination of employment. The divestiture will trigger curtailment, settlement and special termination benefits accounting. Due to the demographic uncertainty, a reasonable estimate of the obligation cannot be made at this time, but will be made when acceptances of employment and involuntary terminations become known. Since the Restructuring Plan includes provisions to recover such costs, they are not expected to have a material impact on the Company's results of operations. Termination Benefits Relating to the Merger The Merger may also result in liabilities for contractual termination benefits, workforce reductions and curtailment losses under employee benefit plans triggered by the consummation of the business combination. In accordance with Emerging Issues Task Force 96-5, "Recognition of Liabilities for Contractual Termination Benefits or Changing Benefit Plan Assumptions in Anticipation of a Business Combination," the Company will recognize any SFAS No. 88 costs when the Merger is consummated. New Financial Accounting Standards During 1997 and 1998, the Financial Accounting Standards Board issued the following accounting standards: Statement of Financial Accounting Standards No. 130 (SFAS No. 130), "Reporting Comprehensive Income;" Statement of Financial Accounting Standards No. 131 (SFAS No. 131), "Disclosures about Segments of an Enterprise and Related Income;" Statement of Financial Accounting Standards No. 132 (SFAS No. 132), "Employers' Disclosures about Pension and Other Postretirement Benefits;" and Statement of Financial Accounting Standards No. 133 (SFAS No. 133), "Accounting for Derivative Instruments and Hedging Activities." The Company has adopted these standards for the year ended December 31, 1998. Adoption of these standards had no effect on the results of operations of the Company. Effects of Inflation The Company's utility revenues are based on rate regulation, which provides for recovery of operating costs and a return on rate base. Inflation affects the Company's construction costs, operating expenses and interest charges and can impact the Company's financial performance if rate relief is not granted on a timely basis. Financial statements, which are prepared in accordance with generally accepted accounting principles, report operating results in terms of historical costs and do not generally recognize the impact of inflation. Cautionary Statement Regarding Forward-Looking Information This document contains forward-looking statements with respect to the financial condition, results of operations and business of the Company in the future, which involve certain risks and uncertainties. Actual results or developments might differ materially from those included in the forward-looking statements because of factors such as competition and industry restructuring, changes in economic conditions, changes in laws, regulations or regulatory policies, uncertainties relating to the ultimate outcome of the Merger and the sale of the Company's generating assets, the outcome of certain assumptions made in regard to Y2K issues and other uncertainties. For all of those statements, the Company claims the protections of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. - -------------------------------------------------------------------------------- 14 9 Orange and Rockland Utilities, Inc. and Subsidiaries Consolidated Statements of Income
Year Ended December 31, 1998 1997 1996 ============================================================================================================= (Thousands of Dollars) Operating Revenues: Electric (Note 1) $ 475,922 $ 472,364 $ 473,936 Gas (Note 1) 135,619 168,450 176,442 Electric sales to other utilities 13,956 7,109 3,106 - ------------------------------------------------------------------------------------------------------------- Total Utility Revenues 625,497 647,923 653,484 Diversified activities 607 851 1,405 - ------------------------------------------------------------------------------------------------------------- Total Operating Revenues 626,104 648,774 654,889 - ------------------------------------------------------------------------------------------------------------- Operating Expenses: Operations: Fuel used in electric production (Note 1) 94,503 69,261 54,917 Electricity purchased for resale (Note 1) 49,588 65,500 73,776 Gas purchased for resale (Note 1) 71,649 99,321 101,614 Other expenses of operation 149,141 143,675 147,819 Maintenance 36,735 35,285 36,652 Depreciation and amortization (Note 1) 35,735 35,861 32,272 Taxes other than income taxes 90,250 98,996 98,829 Federal income taxes (Notes 1 and 2) 22,513 23,878 26,366 - ------------------------------------------------------------------------------------------------------------- Total Operating Expenses 550,114 571,777 572,245 - ------------------------------------------------------------------------------------------------------------- Income from Operations 75,990 76,997 82,644 - ------------------------------------------------------------------------------------------------------------- Other Income and Deductions: Allowance for other funds used during construction 4 40 20 Investigation and litigation costs -- (2,761) (1,800) Other -- net 2,826 949 (2,268) Taxes other than income taxes (280) (270) (246) Federal income taxes (Notes 1 and 2) 11 1,562 662 - ------------------------------------------------------------------------------------------------------------- Total Other Income and Deductions 2,561 (480) (3,632) - ------------------------------------------------------------------------------------------------------------- Income Before Interest Charges 78,551 76,517 79,012 - ------------------------------------------------------------------------------------------------------------- Interest Charges: Interest on long-term debt 23,867 23,215 24,221 Other interest 9,449 8,233 5,748 Amortization of debt premium and expense -- net 1,137 1,521 1,462 Allowance for borrowed funds used during construction (869) (1,390) (566) - ------------------------------------------------------------------------------------------------------------- Total Interest Charges 33,584 31,579 30,865 - ------------------------------------------------------------------------------------------------------------- Income from Continuing Operations 44,967 44,938 48,147 - ------------------------------------------------------------------------------------------------------------- Discontinued Operations: (Note 3) Operating loss -- net of taxes -- (6,738) (1,844) Estimated loss on disposal -- (8,694) -- - ------------------------------------------------------------------------------------------------------------- Loss from Discontinued Operations -- (15,432) (1,844) - ------------------------------------------------------------------------------------------------------------- Net Income 44,967 29,506 46,303 Dividends on preferred and preference stock, at required rates 2,797 2,800 3,024 - ------------------------------------------------------------------------------------------------------------- Earnings applicable to common stock $ 42,170 $ 26,706 $ 43,279 ============================================================================================================= Average number of common shares outstanding (000's) 13,520 13,649 13,654 - ------------------------------------------------------------------------------------------------------------- Earnings per average common share outstanding: Continuing operations $ 3.12 $ 3.09 $ 3.30 Discontinued operations -- (0.49) (0.13) Estimated loss on disposal -- (0.64) -- - ------------------------------------------------------------------------------------------------------------- Total earnings per average common share outstanding $ 3.12 $ 1.96 $ 3.17 - -------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements. - -------------------------------------------------------------------------------- 15 10 Orange and Rockland Utilities, Inc. and Subsidiaries Consolidated Balance Sheets
December 31, 1998 1997 ========================================================================================================= (Thousands of Dollars) Assets: Utility Plant: Electric $1,065,912 $1,047,857 Gas 246,845 232,206 Common 103,064 64,570 - --------------------------------------------------------------------------------------------------------- Utility Plant in Service 1,415,821 1,344,633 Less accumulated depreciation 498,652 471,865 - --------------------------------------------------------------------------------------------------------- Net Utility Plant in Service 917,169 872,768 Construction work in progress 34,401 63,445 - --------------------------------------------------------------------------------------------------------- Net Utility Plant (Notes 1, 5, 8 and 13) 951,570 936,213 - --------------------------------------------------------------------------------------------------------- Non-utility Property: Non-utility property 7,780 11,651 Less accumulated depreciation and amortization 252 1,109 - --------------------------------------------------------------------------------------------------------- Net Non-utility Property (Notes 1 and 8) 7,528 10,542 - --------------------------------------------------------------------------------------------------------- Current Assets: Cash and cash equivalents (Notes 9 and 10) 5,643 3,513 Temporary cash investments (Note 10) 500 518 Customer accounts receivable, less allowance for uncollectible accounts of $3,686 and $2,530, respectively 57,095 61,817 Accrued utility revenue (Note 1) 28,489 22,869 Other accounts receivable, less allowance for uncollectible accounts of $286 and $258, respectively 16,173 20,450 Materials and supplies (at average cost): Fuel for electric generation 7,255 8,875 Gas in storage 12,097 11,103 Construction and other supplies 14,809 15,291 Prepaid property taxes 22,768 21,575 Prepayments and other current assets 30,019 21,469 - --------------------------------------------------------------------------------------------------------- Total Current Assets 194,848 187,480 - --------------------------------------------------------------------------------------------------------- Deferred Debits: Income tax recoverable in future rates (Notes 1 and 2) 74,330 74,731 Deferred Order 636 transition costs (Note 1) 1,478 1,476 Deferred revenue taxes (Note 1) 11,915 10,923 Deferred pension and other postretirement benefits (Notes 1 and 11) 4,097 9,334 IPP settlement agreements 5,330 14,238 Unamortized debt expense (amortized over term of securities) 10,840 11,153 Other deferred debits 46,204 31,919 - --------------------------------------------------------------------------------------------------------- Total Deferred Debits 154,194 153,774 - --------------------------------------------------------------------------------------------------------- Total Assets $1,308,140 $1,288,009 =========================================================================================================
The accompanying notes are an integral part of these statements. - -------------------------------------------------------------------------------- 16 11 Orange and Rockland Utilities, Inc. and Subsidiaries
December 31, 1998 1997 =============================================================================================================== (Thousands of Dollars) Capitalization and Liabilities: Capitalization: Common stock (Notes 4 and 7) $ 67,599 $ 67,945 Premium on capital stock (Note 7) 132,321 132,985 Capital stock expense (6,045) (6,084) Retained earnings (Note 6) 186,520 181,473 - --------------------------------------------------------------------------------------------------------------- Total Common Stock Equity 380,395 376,319 - --------------------------------------------------------------------------------------------------------------- Non-redeemable preferred stock -- 42,844 Non-redeemable cumulative preference stock -- 379 - --------------------------------------------------------------------------------------------------------------- Total Non-Redeemable Stock (Note 7) -- 43,223 - --------------------------------------------------------------------------------------------------------------- Long-term debt (Notes 8 and 10) 357,156 356,637 - --------------------------------------------------------------------------------------------------------------- Total Capitalization 737,551 776,179 - --------------------------------------------------------------------------------------------------------------- Non-current Liabilities: Reserve for claims and damages (Note 1) 4,078 4,591 Postretirement benefits (Note 11) 9,759 15,334 Pension costs (Note 11) 47,481 43,618 Obligations under capital leases (Note 12) -- 1,646 - --------------------------------------------------------------------------------------------------------------- Total Non-current Liabilities 61,318 65,189 - --------------------------------------------------------------------------------------------------------------- Current Liabilities: Long-term debt and capital lease obligations due within one year (Notes 8 and 12) 1,690 209 Preferred and Preference stock to be redeemed within one year (Note 7) 43,516 -- Commercial paper (Notes 9 and 10) 149,050 130,400 Accounts payable 60,573 57,630 Dividends payable 637 637 Customer deposits 3,427 4,639 Accrued Federal income and other taxes 516 2,929 Accrued interest 6,500 6,011 Refundable gas costs (Note 1) 7,816 5,893 Refunds to customers 1,223 986 Other current liabilities 11,938 19,391 - --------------------------------------------------------------------------------------------------------------- Total Current Liabilities 286,886 228,725 - --------------------------------------------------------------------------------------------------------------- Deferred Taxes and Other: Deferred Federal income taxes (Notes 1 and 2) 197,698 192,514 Deferred investment tax credits (Notes 1 and 2) 13,654 14,482 Accrued Order 636 transition costs 1,340 1,340 Other deferred credits 9,693 9,580 - --------------------------------------------------------------------------------------------------------------- Total Deferred Taxes and Other 222,385 217,916 - --------------------------------------------------------------------------------------------------------------- Commitments and Contingencies (Note 13): -- -- - --------------------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $ 1,308,140 $ 1,288,009 ===============================================================================================================
- -------------------------------------------------------------------------------- 17 12 Orange and Rockland Utilities, Inc. and Subsidiaries Consolidated Cash Flow Statements
Year Ended December 31, 1998 1997 1996 ===================================================================================================================== (Thousands of Dollars) Cash Flow from Operations: Net income $ 44,967 $ 29,506 $ 46,303 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 35,286 35,415 33,765 Deferred Federal income taxes 5,612 7,280 5,353 Amortization of investment tax credit (828) (810) (925) Deferred and refundable fuel and gas costs 423 (1,096) (6,371) Allowance for funds used during construction (873) (1,430) (586) Other non-cash changes (1) 5,021 3,759 Changes in certain current assets and liabilities: Accounts receivable, net and accrued utility revenue 3,379 (13,723) (26) Materials and supplies 1,108 326 (2,927) Prepaid property taxes (1,193) (1,524) 636 Prepayments and other current assets (8,550) 71 2,708 Accounts payable 2,943 (9,819) 5,367 Accrued Federal income and other taxes (2,413) 1,905 (800) Accrued interest 489 (1,028) (213) Refunds to customers 237 (830) (12,087) Other current liabilities (8,665) (4,066) 1,478 Other -- net 4,271 22,565 1,888 - --------------------------------------------------------------------------------------------------------------------- Net Cash Provided by Operations 76,192 67,763 77,322 - --------------------------------------------------------------------------------------------------------------------- Cash Flow from Investing Activities: Additions to plant (53,037) (73,986) (58,834) Temporary cash investments 18 771 46 Allowance for funds used during construction 873 1,430 586 - --------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (52,146) (71,785) (58,202) - --------------------------------------------------------------------------------------------------------------------- Cash Flow from Financing Activities: Proceeds from: Issuance of long-term debt 3,200 100,088 26 Issuance of capital lease obligation -- 2,020 -- Retirement of: Common stock (3,225) (3,012) -- Preference and preferred stock -- (1,390) (1,384) Long-term debt (2,684) (103,261) (195) Capital lease obligations (161) (204) (275) Net borrowings (repayments) under short-term debt arrangements 18,650 48,030 21,120 Dividends on preferred and common stock (37,696) (38,057) (38,280) - --------------------------------------------------------------------------------------------------------------------- Net Cash Used in Financing Activities (21,916) 4,214 (18,988) - --------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents 2,130 192 132 Cash and Cash Equivalents at Beginning of Year 3,513 3,321 3,189 - --------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 5,643 $ 3,513 $ 3,321 - --------------------------------------------------------------------------------------------------------------------- Supplemental Disclosure of Cash Flow Information Cash paid during the year for: Interest, net of amounts capitalized $ 32,139 $ 32,313 $ 29,209 Federal income taxes $ 21,011 $ 10,000 $ 17,982 =====================================================================================================================
The accompanying notes are an integral part of these statements. - -------------------------------------------------------------------------------- 18 13 Orange and Rockland Utilities, Inc. and Subsidiaries Notes to Consolidated Financial Statements Note 1. Summary of Significant Accounting Policies. General Orange and Rockland Utilities, Inc. (the Company) and its wholly owned utility subsidiaries, Rockland Electric Company (RECO) and Pike County Light & Power Company (Pike), are subject to regulation by the Federal Energy Regulatory Commission (FERC) and various state regulatory authorities with respect to their rates and accounting. Accounting policies conform to generally accepted accounting principles, as applied in the case of regulated public utilities, and are in accordance with the accounting requirements and rate-making practices of the regulatory authority having jurisdiction. 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 revenues and expenses during the reporting period. Actual results could differ from those estimates. A description of the significant accounting policies follows. Principles of Consolidation The consolidated financial statements include the accounts of the Company, all subsidiaries and the Company's pro rata share of an unincorporated joint venture. All intercompany balances and transactions have been eliminated. The Company's ongoing diversified activities, at year end, consisted of energy services and land development businesses conducted by its wholly owned non-utility subsidiaries. Rate Regulation The Company, RECO and Pike are subject to rate regulation by the New York Public Service Commission (NYPSC), the New Jersey Board of Public Utilities (NJBPU), and the Pennsylvania Public Utility Commission (PPUC), respectively, and the FERC. The consolidated financial statements of the Company are based on generally accepted accounting principles, including the provisions of Statement of Financial Accounting Standards No. 71 (SFAS No. 71), "Accounting for the Effects of Certain Types of Regulation," which gives recognition to the rate-making and accounting practices of the regulatory agencies. The principal effect of the rate-making process on the Company's consolidated financial statements is that of the timing of the recognition of incurred costs. If rate regulation provides assurance that an incurred cost will be recovered in a future period by inclusion of that cost in rates, SFAS No. 71 requires the capitalization of the cost. Regulatory assets represent probable future revenue associated with certain incurred costs, as these costs are recovered through the rate-making process. The following regulatory assets were reflected in the Consolidated Balance Sheets as of December 31, 1998 and 1997:
1998 1997 ================================================================================ (Thousands of Dollars) Deferred Income Taxes (Note 1) $ 74,330 $ 74,731 FERC Order 636 Costs 1,478 1,476 Deferred Revenue Taxes (Note 1) 11,915 10,923 Deferred Pension and Other Postretirement Benefits (Note 11) 4,097 9,334 Gas Take-or-Pay Costs 298 1,473 Deferred Plant Maintenance Costs (Note 1) 4,231 4,251 Demand Side Management Costs 3,756 3,047 Deferred Fuel and Gas Costs (Note 1) (4,269) (3,848) IPP Settlement Agreements 5,330 14,238 Merger Costs (Note 4) 10,535 -- Divestiture Costs (Note 5) 3,290 -- Other 7,783 7,663 - -------------------------------------------------------------------------------- Total $ 122,774 $ 123,288 - --------------------------------------------------------------------------------
The Company's Electric Rate and Restructuring Plan (Restructuring Plan), as approved by the NYPSC, provides for full recovery of all regulatory assets. The Company will continue application of SFAS No. 71 for the generation portion of the business until the divestiture is complete (see Note 5). Utility Revenues Utility revenues are recorded on the basis of cycle billings rendered to customers monthly. Unbilled revenues are accrued at the end of each month for estimated energy usage since the last meter reading. The level of revenues from gas sales in New York is subject to a weather normalization clause that requires recovery from or refund to firm customers of a portion of the shortfalls or excesses of firm net revenues which result from variations of more than plus or minus 2.2% in actual degree days from the number of degree days used to project heating season sales. Fuel Costs The tariff schedules for electric and gas services in New York include adjustment clauses under which fuel, purchased gas and certain purchased power costs, above or below levels allowed in approved rate schedules, are billed or credited to customers up to approximately 60 days after the costs are incurred. In accordance with regulatory commission policy, such costs, along with the related income tax effects, are deferred until billed or credited to customers. A reconciliation of New York recoverable gas costs with billed gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from customers during a subsequent twelve-month period. The NYPSC provides for a modified electric fuel adjustment clause requiring an 80%/20% sharing between customers and shareholders of variations between actual and forecasted fuel costs annually. The 20% portion of fluctuations from forecasted costs is limited to a maximum of $1,762,000 annually. The fuel costs targets are approved by the NYPSC for each calendar year following the Company's filing of forecasted fuel costs. Tariffs for electric and gas service in Pennsylvania and electric service in New Jersey contain adjustment clauses which utilize estimated prospective energy costs on an annual basis. The recovery of such estimated costs is made - -------------------------------------------------------------------------------- 19 14 Orange and Rockland Utilities, Inc. and Subsidiaries through equal monthly charges over the year of projection. Any over- or under-recoveries are deferred and refunded or charged to customers during the subsequent twelve-month period. Utility Plant Utility plant is stated at original cost. The cost of additions to, and replacements of, utility plant include contracted work, direct labor and material, allocable overheads, allowance for funds used during construction and indirect charges for engineering and supervision. Replacement of minor items of property and the cost of repairs are charged to maintenance expense. At the time depreciable plant is retired or otherwise disposed of, the original cost, together with removal cost less salvage, is charged to the accumulated provision for depreciation. Depreciation For financial reporting purposes, depreciation is computed on the straight-line method based on the estimated useful lives of the various classes of property. Provisions for depreciation are equivalent to the following composite rates based on the average depreciable plant balances at the beginning and end of the year:
Year Ended December 31, 1998 1997 1996 - -------------------------------------------------------------------------------- Plant Classification: Electric 2.80% 3.03% 2.88% Gas 2.86% 2.90% 2.91% Common 7.78% 7.21% 5.93% - --------------------------------------------------------------------------------
The composite gas depreciation rate excludes the effects of adjustments provided for in a 1996 gas rate agreement with the NYPSC. Jointly Owned Utility Plant The Company has a one-third interest in the 1,200 megawatt Bowline Point generating facility (Bowline), which it owns jointly with Consolidated Edison Company of New York, Inc. (Con Edison). The Company is the operator of the joint venture. Energy is allocated to the participants based on an agreement dated May 31, 1996. This agreement entitles each company to a certain amount of energy at different periods during the year. The operation and maintenance expenses of the facility are allocated to the Company on a one-third basis, except for major maintenance which is allocated based on the energy received from the plant by the partners. Under this agreement, each co-owner has an undivided interest in the facility and is responsible for its own financing. The Company's interest in this jointly owned plant consists primarily of the following:
Year Ended December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Electric Utility Plant in Service $103,776 $103,217 Construction Work in Progress $ 483 $ 739 - --------------------------------------------------------------------------------
Federal Income Taxes The Company and its subsidiaries file a consolidated federal income tax return, and income taxes are allocated based on the taxable income or loss of each company. Investment tax credits, which were available prior to the Tax Reform Act of 1986, have been fully normalized and are being amortized over the remaining useful life of the related property for financial reporting purposes. The consolidated financial statements of the Company are prepared pursuant to the provisions of Statement of Financial Accounting Standards No. 109 (SFAS No. 109), "Accounting for Income Taxes," which requires the asset and liability method of accounting for income taxes. SFAS No. 109 requires the recording of deferred income taxes for temporary differences that are reported in different years for financial reporting and tax purposes. The statement also requires that deferred tax liabilities or assets be adjusted for the future effects of any changes in tax laws or rates and that regulated enterprises recognize an offsetting regulatory asset or liability, as appropriate. Deferred Revenue Taxes Deferred revenue taxes represent the unamortized balance of an accelerated payment of New Jersey Gross Receipts and Franchise Tax (NJGRFT) required by legislation enacted effective June 1, 1991, as well as certain New York State revenue taxes which are deferred and amortized over a twelve-month period following payment, in accordance with the requirements of the NYPSC. In accordance with an order by the NJBPU, the NJGRFT has been deferred and is being recovered in rates, with a carrying charge of 7.5% on the unamortized balance. This amortization, originally being amortized over a ten-year period, was extended by an NJBPU Order dated February 9, 1998 as part of RECO's approval of recovery of the Postretirement Benefits Other Than Pensions. Deferred Plant Maintenance Costs The Company utilizes a silicone injection procedure as part of its maintenance program for residential underground electric cable in order to prevent premature failures and ensure the realization of the expected useful life of the facilities. In 1992, the FERC issued an accounting order that required the cost of this procedure to be treated as maintenance expense rather than as a plant addition. The Company requested deferred accounting for these expenditures from the NYPSC and NJBPU in order to properly match the cost of the procedure with the periods benefited. In 1994, the NYPSC approved the deferred accounting request and authorized a ten-year amortization for rate purposes. On January 12, 1996, the NJBPU authorized RECO to capitalize these costs until the next base rate case. Reserve for Claims and Damages Costs arising from workers' compensation claims, property damage, general liability and unusual production plant repair costs are partially self-funded. Provisions for the reserves are based on experience, risk of loss and the rate-making practices of regulatory authorities. Reclassifications Certain amounts from prior years have been reclassified to conform with the current year presentation. - -------------------------------------------------------------------------------- 20 15 Orange and Rockland Utilities, Inc. and Subsidiaries Note 2. Federal Income Taxes. The Internal Revenue Service (IRS) has completed its examination of the Company's tax returns for 1995 and 1996. The Company and the IRS have agreed to a refund of tax and interest, which had a minimal effect on the operating results of the Company. The components of federal income taxes are as follows:
Year Ended December 31, 1998 1997 1996 ================================================================================ (Thousands of Dollars) Charged to operations: Current $17,449 $17,517 $21,120 Deferred-net 5,186 6,482 5,374 Amortization of investment tax credit (122) (121) (128) - -------------------------------------------------------------------------------- Total charged to operations 22,513 23,878 26,366 - -------------------------------------------------------------------------------- Charged to other income: Current 268 (1,671) 155 Deferred-net 426 798 (21) Amortization of investment tax credit (705) (689) (796) - -------------------------------------------------------------------------------- Total charged to other income (11) (1,562) (662) - -------------------------------------------------------------------------------- Total $22,502 $22,316 $25,704 - --------------------------------------------------------------------------------
The tax effect of temporary differences which gave rise to deferred tax assets and liabilities is as follows:
As of December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Liabilities: Accelerated depreciation $ 193,756 $ 191,438 Other 39,369 39,305 - -------------------------------------------------------------------------------- Total liabilities 233,125 230,743 - -------------------------------------------------------------------------------- Assets: Employee benefits (17,480) (19,650) Other (17,947) (18,579) - -------------------------------------------------------------------------------- Total assets (35,427) (38,229) - -------------------------------------------------------------------------------- Net Liability $ 197,698 $ 192,514 - --------------------------------------------------------------------------------
Reconciliation of the difference between federal income tax expenses and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:
Year Ended December 31, 1998 1997 1996 ================================================================================ (% of Pre-tax Income) Statutory tax rate 35% 35% 35% Changes in computed taxes resulting from: Amortization of investment tax credits (1%) (1%) (1%) Cost of removal (2%) (1%) (1%) Additional depreciation deducted for book purposes 2% 3% 4% Other (1%) (3%) (3%) - -------------------------------------------------------------------------------- Effective Tax Rate 33% 33% 34% - --------------------------------------------------------------------------------
Note 3. Discontinued Operations. In August 1997, Norstar Management, Inc. (NMI), a wholly owned indirect subsidiary of the Company, sold certain of the assets of NORSTAR Energy Limited Partnership (NORSTAR), a natural gas services and marketing company of which NMI is the general partner. The assets sold consisted primarily of customer contracts and accounts receivable. In accordance with Accounting Principles Board Opinion No. 30, the financial results for this segment are reported as "Discontinued Operations." Discontinued operations had no material effect on the 1998 results of operations. The total losses related to discontinued operations were $(15,432,000), or $ (1.13) per share, for 1997 and $(1,844,000), or $ (0.13) per share, for 1996. The net assets of these operations at December 31, 1998 consist of cash of $0.9 million, net accounts receivable of $0.1 million and other current assets of $0.1 million partially offset by accounts payable of $0.1 million. Note 4. Proposed Merger with Consolidated Edison, Inc. On May 10, 1998, the Company, Consolidated Edison, Inc. (CEI) and C Acquisition Corp., a wholly owned subsidiary of CEI (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement) providing for a merger transaction among the Company, CEI and the Merger Sub. Pursuant to the Merger Agreement, Merger Sub will merge with and into the Company (the Merger), with the Company being the surviving corporation and becoming a wholly owned subsidiary of CEI. On June 22, 1998, the Company and CEI and Con Edison filed a Joint Petition (Joint Petition) with the NYPSC requesting approval of the Merger. The Parties have requested regulatory reviews and approvals prior to March 31, 1999. The Merger is anticipated to result in cost savings, net of transaction costs and costs to achieve, of approximately $468 million over the first 10 years following the closing of the transaction. Transaction costs and costs to achieve are the incremental legal, financial, employee and organizational costs incurred and to be incurred to effectuate and implement the Merger and related cost savings activities. The Parties have proposed in the Joint Petition that these cost savings be allocated between customers and shareholders on a 50/50 basis. In addition, the Parties have proposed a cost allocation methodology and accounting procedure which would govern them and their various affiliates. On July 2, 1998, RECO and Pike filed similar petitions with the NJBPU and the PPUC, respectively, for approval of the Merger. The proceedings before the NYPSC, the NJBPU and the PPUC have established schedules that provided for final decisions by March 31, 1999. The Company can give no assurance that any of the Commissions will issue orders by that date or what, if any, conditions may be imposed by such Commissions to such orders. On January 14, 1999, Pike, the Office of the Consumer Advocate and the Office of the Small Business Advocate executed a settlement agreement which allows Pike to retain all merger savings, net of costs to achieve, until its next electric and gas base rate case. An Administrative Law Judge issued a Recommended Decision to the PPUC on February 3, 1999 recommending approval of the settlement in its entirety. A final PPUC order is expected prior to March 31, 1999. - -------------------------------------------------------------------------------- 21 16 Orange and Rockland Utilities, Inc. and Subsidiaries On September 9, 1998, the Company and Con Edison filed an Application for Approval of Merger and Related Authorizations with the FERC. On January 27, 1999, the FERC issued an order approving the merger consistent with the terms of said application. On February 3, 1999, the Company and CEI filed an application with the Securities and Exchange Commission seeking approval of the Merger under the Public Utility Holding Company Act of 1935. On January 26, 1999, the Company and CEI each filed a Notification and Report Form under the Hart-Scott-Rodino Act of 1976, as amended, (HSR Act) with the Department of Justice and the Federal Trade Commission. Under the provisions of the HSR Act, consummation of the Merger is subject to the expiration or earlier termination of the applicable waiting period. At a Special Meeting of the Common Shareholders of the Company held on August 20, 1998, the Merger Agreement was approved by a vote of approximately 74% of the common shares entitled to vote. The Merger is expected to occur shortly after all of the conditions to the consummation of the Merger, including the receipt of all regulatory approvals, are met or waived. Note 5. Divestiture of Power Plants. In accordance with the schedule in the Restructuring Plan, the Company filed its Final Divestiture Plan (Divestiture Plan) on February 4, 1998. The Divestiture Plan which provides for a two-phase auction process, was approved by the NYPSC in orders issued April 16, 1998 and May 26, 1998. The Company retained Donaldson, Lufkin & Jenrette Securities Corporation to act as its financial advisor in connection with the divestiture of the generating assets. Following the review of final bids and negotiations with the winning bidder, on November 24, 1998, the Company entered into four separate Asset Sales Agreements (ASAs) with subsidiaries of Southern Energy, Inc. (Southern Energy), a subsidiary of Southern Company. The sales price for all generating facilities, including the two-thirds interest in Bowline owned by Con Edison, is approximately $480 million, plus certain fuel inventory and other adjustments. The Company's share of the sales price is approximately $345 million. The total net book value of the plant assets at December 31, 1998 is approximately $264 million. In addition, fuel and material and supplies inventories, with a carrying value of $17.5 million at December 31, 1998, will be included in the sale. The sale is subject to federal and state regulatory review and approval. The ASAs provide for the closing of the sale to occur on April 30, 1999, which date may be adjusted depending on the receipt of regulatory approvals. The New York Power Pool is currently in the process of restructuring itself into an Independent System Operator (ISO) which requires FERC approval. In an order dated January 27, 1999 the FERC conditionally accepted the proposed ISO Tariff subject to certain modifications. Under the terms of the ASAs, if approval by FERC of the establishment of the ISO has not been obtained by the time all other regulatory approvals have been obtained, the parties have agreed to defer the closing of the sale, but in no event to a date later than August 31, 1999. The Restructuring Plan provides that the New York share of any net book gains from the divestiture of the generating assets will be shared between the Company's New York customers and shareholders, with shareholders receiving 25 percent of the gain, up to $20 million. The terms of the Restructuring Plan also permit the Company to defer and recover up to $7.5 million (New York electric share) of prudent and verifiable non-officer employee costs associated with the divestiture, such as retraining, outplacement, severance, early retirement and employee retention programs. Under the terms of the Restructuring Plan, the Company will be authorized to petition the NYPSC for recovery of employee costs in excess of $7.5 million. In addition, the Restructuring Plan provides for the recovery of all prudent and verifiable costs of the sale. The NJBPU has not yet decided how RECO's share of any gain will be allocated between ratepayers and shareholders. Pike's settlement will allow shareholders to retain $55,000 of any gain. Note 6. Retained Earnings. Consolidated Statements of Retained Earnings:
Year Ended December 31, 1998 1997 1996 ================================================================================ (Thousands of Dollars) Balance at beginning of year $ 181,473 $ 192,060 $184,008 Net income 44,967 29,506 46,303 - -------------------------------------------------------------------------------- 226,440 221,566 230,311 - -------------------------------------------------------------------------------- Less: Dividends Preferred stock 2,797 2,800 3,024 Common stock 34,899 35,229 35,227 - -------------------------------------------------------------------------------- 37,696 38,029 38,251 - -------------------------------------------------------------------------------- Capital stock repurchase (2,213) (2,064) -- - -------------------------------------------------------------------------------- Capital stock expense (11) -- -- - -------------------------------------------------------------------------------- Balance at end of year $ 186,520 $ 181,473 $192,060 - --------------------------------------------------------------------------------
Various restrictions on the availability of retained earnings of RECO for cash dividends are contained in, or result from, covenants in indentures supplemental to that company's Mortgage Trust Indenture. Approximately $7,501,600 at December 31, 1998 and 1997 were so restricted. Note 7. Capital Stock. The table below summarizes the changes in Capital Stock, issued and outstanding, for the years 1996, 1997 and 1998.
(B) (C) Non-Redeemable Non-Redeemable (A) Cumulative Cumulative Common Preferred Preference Capital Stock Stock Stock Stock ($5 par value) ($100 par value) (no par value) Premium ============================================================================================================================ Shares Amount* Shares Amount* Shares Amount* Amount* ============================================================================================================================ Balance 12/31/95: 13,653,613 $ 68,268 428,443 $ 42,844 12,539 $409 $133,607 Conversions 508 3 (359) (12) 9 - ---------------------------------------------------------------------------------------------------------------------------- Balance 12/31/96: 13,654,121 68,271 428,443 42,844 12,180 397 133,616 Reacquired Stock (65,900) (330) -- -- (644) Conversions 790 4 (541) (18) 13 - ---------------------------------------------------------------------------------------------------------------------------- Balance 12/31/97: 13,589,011 67,945 428,443 42,844 11,639 379 132,985 Reacquired Stock (70,400) (352) -- -- (688) Conversions 1,377 6 (955) (31) 24 Accretion of call premium 324 - ---------------------------------------------------------------------------------------------------------------------------- Balance 12/31/98: 13,519,988 $ 67,599 428,443 $ 43,168 10,684 $348 $132,321 - ---------------------------------------------------------------------------------------------------------------------------- Shares Authorized 50,000,000 820,000 1,500,000 - ---------------------------------------------------------------------------------------------------------------------------- *(in thousands)
- -------------------------------------------------------------------------------- 22 17 Orange and Rockland Utilities, Inc. and Subsidiaries (A) Pursuant to a December 1997 Order of the NYPSC, the Company had authority to repurchase up to 700,000 shares of its common stock and to issue up to $25 million of long- term debt to provide funds for the common stock repurchase. During 1998 the Company repurchased 70,400 shares of its Common Stock at an average price of $45.81 per share. The Repurchase Program was suspended in the first quarter of 1998. The total number of shares of common stock repurchased under the Repurchase Program was 136,300 shares at an average market price of $45.75 per share. The Repurchase Program was canceled during the second quarter of 1998. The Company then discharged the long-term debt associated with the program. At December 31, 1998, 15,705 shares of common stock were reserved for conversion of preference stock. (B) Non-Redeemable Preferred Stock (cumulative):
Par Value ------------------- Callable Shares December 31, Redemption Series Outstanding 1996, 1997 and 1998 Price Per Share ================================================================================ (Thousands of Dollars) A, 4.65% 50,000 $ 5,000 $104.25 B, 4.75% 40,000 4,000 $102.00 D, 4.00% 3,443 344 $100.00 F, 4.68% 75,000 7,500 $102.00 G, 7.10% 110,000 11,000 $101.00 H, 8.08% 150,000 15,000 $102.43 - -------------------------------------------------------------------------------- 428,443 $ 42,844 - --------------------------------------------------------------------------------
This stock is subject to redemption, at any time, solely at the option of the Company on 30 days minimum notice upon payment of the redemption price, plus accrued and unpaid dividends to the date fixed for redemption. Furthermore, the preferred stock is superior to cumulative preference stock and common stock with respect to dividends and liquidation rights. (See discussion below of the Company's intention to redeem these securities). (C) The Non-Redeemable $1.52 Convertible Cumulative Preference Stock, Series A, is redeemable at the option of the Company on 30 days minimum notice upon payment of the redemption price, plus accrued and unpaid dividends. The redemption price per share is $32.50 plus accrued and unpaid dividends to the date fixed for redemption. This stock ranks junior to cumulative preferred stock and superior to common stock as to dividends and liquidation rights. Furthermore, this stock is convertible, at the option of the shareholder, into common stock at the ratio of 1.47 shares of common stock for each share of preference stock, subject to adjustment. (See discussion below of the Company's intention to redeem these securities). As a result of the Merger Agreement, and contingent upon regulatory approvals of the Merger Agreement, it is expected that the Company's common stock will be acquired by CEI during the second quarter of 1999. The price, as stated in the Merger Agreement, will be $58.50 per share. In addition, the Merger Agreement requires that the Company's Preferred Stock and Preference Stock be called for redemption prior to the effective date of the Merger. The Company intends to redeem all of the outstanding Preferred Stock and Preference Stock as soon as practicable. These issues of stock are reflected on the Consolidated Balance Sheet at December 31, 1998 as Current Liabilities. Effective July 1, 1998, the Company began accreting the estimated call price over the carrying amount for the Preferred and Preference Stock to be redeemed. On October 7, 1998, the Company filed a petition with the NYPSC for permission to issue $45 million of long-term debt, the proceeds of which will be used to call for redemption of all of the Company's outstanding Preferred and Preference Stock. The NYPSC approved the Company's petition on January 13, 1999. Note 8. Long-Term Debt. During 1997, the final series of bonds outstanding under the Orange and Rockland Utilities, Inc. First Mortgage Indenture was redeemed at maturity, and the Company has canceled its First Mortgage and discharged the lien thereof. The indenture under which the Company's debentures are issued contains a covenant restricting the issuance by the Company of secured indebtedness while any securities are outstanding under the debenture indenture. Pike was required, pursuant to its First Mortgage Indenture, to make annual sinking fund payments in the amount of $9,500 on July 15 of each year, with respect to its Series "A" Bonds. The sinking fund requirements of Pike for 1997 were satisfied by the allocation of an amount of additional property. Pike is not required to make annual sinking fund payments with respect to its Series "C" Bonds. Details of long-term debt at December 31, 1998 and 1997 are as follows:
December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Orange and Rockland Utilities, Inc.: Promissory Notes (unsecured): 6.9% - 7.0% due through April 15, 2001 $ 67 $ 106 6.09% due Oct. 1, 2014 (a) 55,000 55,000 Variable due Aug. 1, 2015 (b) 44,000 44,000 Debentures: Series A, 93/8% due Mar. 15, 2000 80,000 80,000 Series C, 6.14% due Mar. 1, 2000 20,000 20,000 Series D, 6.56% due Mar. 1, 2003 35,000 35,000 Series F, 61/2% due Dec. 1, 2027 (c) 80,000 80,000 Rockland Electric Company: First Mortgage Bonds: Series I, 6% due July 1, 2000 20,000 20,000 Series J, 71/8% due Feb. 1, 2007 20,000 20,000 Pike County Light & Power Company: First Mortgage Bonds Series A, 9% due July 15, 2001 -- 884 Series B, 9.95% due Aug. 15, 2020 -- 1,800 Series C, 7.07% due Oct. 1, 2018 (d) 3,200 -- - -------------------------------------------------------------------------------- 357,267 356,790 Less: Amount due within one year 35 39 - -------------------------------------------------------------------------------- 357,232 356,751 Unamortized discount on long-term debt (76) (114) - -------------------------------------------------------------------------------- Total Long-Term Debt $ 357,156 $ 356,637 - --------------------------------------------------------------------------------
(a) The Company's $55 million Promissory Note was issued in connection with the New York State Energy Research and Development Authority (NYSERDA) variable rate Pollution Control Refunding Revenue Bonds (Orange and Rockland Utilities, Inc. Projects), 1994 Series A (1994 Bonds). Pursuant to an interest rate swap agreement, the Company pays interest at a fixed rate of 6.09% to a swap counterparty and receives a variable rate of interest in return which is identical to the variable rate on the 1994 Bonds. The result is to effectively establish a fixed rate of interest on the 1994 Bonds of 6.09%. - -------------------------------------------------------------------------------- 23 18 Orange and Rockland Utilities, Inc. and Subsidiaries (b) The Company's $44 million Promissory Note was issued in connection with the NYSERDA's $44 million variable rate Pollution Control Refunding Bonds due August 1, 2015 (the 1995 Bonds). The average interest rate on the 1995 Bonds was 3.20% in 1998 and 3.54% in 1997. The interest rate is adjusted weekly, unless converted to another interest rate mode. (c) The Series F Debentures are not redeemable prior to their stated maturity. However, the holders may elect to have their Series F Debentures repaid on December 1, 2004 at 100% of the principal amount of such debentures. (d) On November 10, 1998, Pike issued $3.2 million of First Mortgage Bonds Series C, 7.07% due October 1, 2018 (the Series C Bonds). The proceeds from the sale of the Series C Bonds were used primarily to redeem Pike's First Mortgage Bonds Series A and Series B. The Series C Bonds are redeemable at the option of Pike on or after October 1, 2008 at varying rates. In January 1998, the Company entered into a Credit Agreement with Mellon Bank, N.A., the proceeds of which were used to provide funds for the Company's Common Stock Repurchase Program. The Common Stock Repurchase Program was suspended in the first quarter of 1998 and was canceled during the second quarter of 1998 and the amounts outstanding under the Credit Agreement were subsequently paid and the Credit Agreement was canceled. The aggregate amount of debt maturities, all of which will be satisfied by cash payments for each of the five years following 1998 is as follows: 1999-$35,000; 2000-$120,028,000; 2001-$4,000; 2002-$-0-; 2003-$35,000,000. Substantially all of the utility plant and other physical property of the Company's utility subsidiaries, RECO and Pike, are subject to the liens of the respective indentures securing the First Mortgage Bonds of each company. Note 9. Cash and Short-Term Debt. The Company considers all cash and highly liquid debt instruments purchased with a maturity date of three months or less to be cash and cash equivalents for the purposes of the Consolidated Financial Statements. At December 31, 1998, the Company and its utility subsidiaries had unsecured bank lines of credit totaling $160 million. Effective January 1, 1999, such lines of credit were reduced to $155 million. The Company may borrow under the lines of credit through the issuance of promissory notes to the banks at their prevailing interest rate for prime commercial borrowers. The Company, however, primarily utilizes such lines of credit to fully support commercial paper borrowings, which are issued through dealers at the prevailing interest rate for prime commercial paper. The aggregate amount of borrowings through the issuance of promissory notes and commercial paper cannot exceed the aggregate lines of credit. All borrowings for 1998, 1997 and 1996 had maturity dates of three months or less. Information regarding short-term borrowings during the past three years is as follows:
1998 1997 1996 ================================================================================ (Millions of Dollars) Weighted average interest rate at year-end 6.3% 7.0% 6.5% Amount outstanding at year-end $149.1 $130.4 $82.4 Average amount outstanding for the year $130.7 $119.9 $66.6 Daily weighted average interest rate during the year 5.8% 5.9% 5.7% Maximum amount outstanding at any month-end $154.2 $204.5 $97.5 - --------------------------------------------------------------------------------
As a result of the planned divestiture of the Company's generating facilities, it is expected that the Company will have approximately $225 million of cash proceeds available when the sale is complete. Note 10. Fair Value of Financial Instruments. Financial Assets and Liabilities For the Company, financial assets and liabilities consist principally of cash and cash equivalents, temporary cash investments, short-term debt, commercial paper, long-term debt and funds held in benefit trust. The methods and assumptions used to estimate the fair value of each class of financial assets and liabilities for which it is practicable to estimate that value are as follows: Cash equivalents and temporary cash investments: The carrying amount reasonably approximates fair value because of the short maturity of those instruments. Long-term debt: The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues. Commercial paper: The carrying amount reasonably approximates fair value because of the short maturity of those instruments. Funds held in benefit trust: The fair value of the funds held in benefit trust consisting of fixed income securities, insurance contracts and temporary cash investments are based on quoted market prices of the fixed income securities, the stated cash surrender values of the insurance contracts and the carrying amount of the temporary cash investments which approximate their fair value.
1998 1997 =================================================================================== Carrying Fair Carrying Fair Amount Amount Amount Amount - ----------------------------------------------------------------------------------- (Thousands of Dollars) Cash and cash equivalents $ 5,643 $ 5,643 $ 3,513 $ 3,513 Temporary cash investments 500 500 518 518 Long-term debt 357,267 367,149 356,790 362,908 Commercial paper 149,050 149,050 130,400 130,400 Funds held in benefit trust 16,343 16,343 10,647 12,414 - -----------------------------------------------------------------------------------
Off Balance Sheet and Derivative Financial Instruments The Company utilizes an interest rate swap derivative financial instrument. At this time, no energy derivatives for its electric and natural gas operations are in use. Information regarding the interest rate swap agreement is as follows: Swap Agreement -- In connection with the issuance of the 1994 Bonds, the Company entered into a single interest rate swap agreement during 1992. Under the terms of the interest rate swap - -------------------------------------------------------------------------------- 24 19 Orange and Rockland Utilities, Inc. and Subsidiaries agreement, the Company pays interest at a fixed rate of 6.09% to a swap counterparty and receives a variable rate of interest in return. The variable rate is identical to the variable rate on the 1994 Bonds. The result is to effectively fix the interest rate on the 1994 Bonds at 6.09%. There were no gains or losses due to the execution of the swap agreement. The terms and conditions of the swap agreement are specific to the financing described. As a result, no market price is available. Under certain circumstances, although none are anticipated, the agreement may be terminated. The fair value of the agreement is the amount which one counterparty may be required to pay the other upon early termination. If the agreement had been terminated on December 31, 1998, it is estimated that the Company would have been required to make a payment of approximately $8.4 million to the swap counterparty. Note 11. Pension and Postretirement Benefits. During 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 132 (SFAS No. 132), "Employers' Disclosures About Pensions and Other Postretirement Benefits." This standard revises the disclosure requirements of Statement of Financial Accounting Standards No. 87 (SFAS No. 87), "Employers' Accounting for Pensions," Statement of Financial Accounting Standards No. 88 (SFAS No. 88), "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," and Statement of Financial Accounting Standards No. 106 (SFAS No. 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS No. 132 revises employers' disclosures about pension and other postretirement benefit plans. It does not change the measurement or recognition of those plans. Pension Benefits The Company maintains a qualified, non-contributory defined benefit retirement plan, covering substantially all employees and non-qualified, non-contributory supplemental retirement plans covering certain management employees. The plans call for benefits, based primarily on years of service and average compensation, to be paid to eligible employees at retirement. The Plans were last amended in 1997 to update the benefit formula to a January 1, 1993 pivot date (from January 1, 1988), provide unreduced early retirement benefits to employees meeting the Rule of 85 (age and years of service total to 85 or more, with a minimum age of 55), and to change the definition of compensation to include awards paid to management employees under the Company's annual team incentive plan. The following table sets forth the plans' funded status and amounts recognized in the Consolidated Balance Sheets at December 31, 1998 and 1997. Plan assets are stated at fair market value and are composed primarily of common stocks and investment grade debt securities. The information presented in the following tables does not include the effect of the proposed divestiture of the Company's generating assets, which is expected to take place during 1999. Due to the uncertainties concerning employee issues and the inability to determine which employees or how many employees will be impacted by the divestiture, the costs to the retirement plan cannot be determined at this time.
December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Change in benefit obligation: Benefit obligation at beginning of year $ 260,306 $ 232,990 Service cost 6,868 6,535 Interest cost 19,194 17,993 Amendments -- 12,852 Benefits paid (14,978) (12,451) Actuarial (gain)/loss 18,375 2,387 - -------------------------------------------------------------------------------- Benefit Obligation at End of Year $ 289,765 $ 260,306 - -------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of year $ 247,523 $ 225,997 Actual return on plan assets 33,119 33,163 Benefits paid (14,131) (11,637) - -------------------------------------------------------------------------------- Fair Value of Plan Assets at End of Year $ 266,511 $ 247,523 - -------------------------------------------------------------------------------- Funded status $ (23,254) $ (12,783) Unamortized net transition asset (3,026) (4,034) Unrecognized prior service costs 35,830 40,081 Unrecognized (net gain)/loss (57,031) (66,108) - -------------------------------------------------------------------------------- Accrued Pension Cost $ (47,481) $ (42,844) - --------------------------------------------------------------------------------
The following table provides the amounts recognized in the Company's Consolidated Balance Sheets for the years 1998 and 1997:
December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Accrued benefit liability $(52,118) $(46,795) Intangible asset 1,503 1,920 Accumulated other comprehensive income 3,134 2,031 - -------------------------------------------------------------------------------- Net Amount Recognized $(47,481) $(42,844) - --------------------------------------------------------------------------------
The Company's non-qualified plans, which are included in the tables above, were the only plans with an accumulated benefit obligation in excess of plan assets. The non-qualified plans accumulated benefit obligations at December 31, 1998 and 1997 were $20.6 million and $17.6 million, respectively. The plans have segregated assets held in a separate benefit trust for the payment of benefits, the fair market value of which were $16.3 million and $12.4 million at December 31, 1998 and December 31, 1997, respectively. The plans' net periodic pension cost for the years 1998, 1997 and 1996 were $3.2 million, $2.8 million and $2.3 million, respectively. Net periodic pension expense for the Company's qualified plan for the years 1998, 1997 and 1996 includes the following components:
December 31, 1998 1997 1996 ================================================================================ (Thousands of Dollars) Service cost $ 5,849 $ 5,695 $ 5,456 Interest cost 17,836 16,686 15,135 Expected return on plan assets (17,480) (15,838) (14,746) Amortization of: Unrecognized net transition asset (1,114) (1,114) (1,114) Unrecognized prior service costs 3,939 3,509 2,970 Unrecognized net gain (6,714) (4,968) (4,824) - -------------------------------------------------------------------------------- Net Pension Expense $ 2,316 $ 3,970 $ 2,877 - --------------------------------------------------------------------------------
Weighted average assumptions used in the accounting for these plans were as follows:
1998 1997 1996 ================================================================================ Discount rate 6.75% 7.5% 7.5% Expected return on plan assets 8.0% 8.0% 8.0% Rate of compensation increase: Hourly 3.0% 3.0% 3.0% Management 1.0% 1.0% 2.0% Rate of consumer price increase 2.1% 2.6% 2.8% - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- 25 20 Orange and Rockland Utilities, Inc. and Subsidiaries Postretirement Benefits In addition to providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for retired employees. Employees retiring from the Company on or after having attained age 55 and who have rendered at least 10 years of service are entitled to postretirement health care coverage. The NYPSC, NJBPU and PPUC currently allow the Company to recover in rates the SFAS No. 106 costs applicable to electric and gas operations. Under the provisions of SFAS No. 71, the Company adopted deferred accounting for any difference between the expense charge required under SFAS No. 106 and the current rate allowance authorized by each jurisdiction. As permitted by SFAS No. 106, the Company elected to amortize the accumulated postretirement benefit obligation at the date of adoption of the accounting standard, January 1, 1993, over a 20-year period. This transition obligation totaled $57.2 million. At December 31, 1998, $34.6 million remains. In order to provide funding for postretirement benefit payments to retirees, the Company established Voluntary Employees' Beneficiary Association (VEBA) trusts. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code. The Company's policy is to fund postretirement health and life insurance costs to the extent recoveries are realized for these costs through rates. The following table provides a reconciliation of the changes in the plans' benefit obligations and the fair value of the VEBA trusts assets over the two-year period ending December 31, 1998, a statement of the changes in funded status as of December 31 of both years, and the net accrued liability recognized in the Company's Consolidated Financial Statements:
December 31, 1998 1997 ================================================================================ (Thousands of Dollars) Change in benefit obligation: Benefit obligation at beginning of year $ 80,625 $ 82,999 Service cost 1,463 1,863 Interest cost 5,326 6,013 Plan participants' contributions 101 -- Amendments 98 (6,898) Actual gain/(loss) (1,802) 1,230 Benefits paid (5,334) (4,582) - -------------------------------------------------------------------------------- Benefit Obligation at End of Year $ 80,477 $ 80,625 - -------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of year $ 22,238 $ 14,822 Actual return on plan assets 2,086 735 Employer contribution 12,089 11,263 Plan participants' contributions 101 -- Benefits paid (5,334) (4,582) - -------------------------------------------------------------------------------- Fair Value of Plan Assets at End of Year $ 31,180 $ 22,238 - -------------------------------------------------------------------------------- Excess of projected benefit obligation over plan assets $ 49,297 $ 58,387 Unrecognized transition obligation (34,601) (37,027) Unrecognized prior service cost (89) -- Unrecognized actuarial (gain)/loss (5,016) (6,393) - -------------------------------------------------------------------------------- Accrued Postretirement Benefit Cost $ 9,591 $ 14,967 - --------------------------------------------------------------------------------
The following table provides the components of net periodic benefit cost for the postretirement plans for the years ended December 31, 1998, 1997 and 1996:
December 31, 1998 1997 1996 ================================================================================ (Thousands of Dollars) Service cost $ 1,463 $ 1,863 $ 2,050 Interest cost 5,326 6,013 5,925 Return on plan assets (1,654) (907) (546) Amortization of transition obligation 2,427 2,572 2,776 Prior service cost 9 84 202 Net losses 21 1,011 855 Amortized/(deferred and capitalized) 3,169 (1,009) (2,400) - -------------------------------------------------------------------------------- Net Expense $ 10,761 $ 9,627 $ 8,862 - --------------------------------------------------------------------------------
The Company's postretirement plans provide for health care and life insurance benefits. The health care plan became contributory starting in 1995, with participants contributing toward their medical coverage; the life insurance plan is non-contributory. Written agreements dictate the calculation of premiums to be paid by retirees. The accounting for the health care plans reflects future cost-sharing changes consistent with the Company's expressed intent that retirees share in the overall cost of benefits each year. The assumptions used in the measurement of the Company's benefit obligation are shown in the following table:
Assumptions as of December 31, 1998 1997 ================================================================================ Discount rate 6.75% 7.5% Expected return on plan assets 6.25% 6.25% Medical cost rate of increase 7.0% 7.5% Prescription drug cost rate increase 9.0% 10.0% - --------------------------------------------------------------------------------
For measurement purposes the health care and prescription drug trend rates shown above are assumed to decrease by 0.5% and 1.0%, respectively, each year to a rate of 5.0% in 2002 and thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1.0% change in assumed health care cost trend rates would have the following effects:
1% 1% Increase Decrease ================================================================================ (Thousands of Dollars) Effect on total service and interest cost components of net periodic postretirement health care benefit cost $ 817 $ (651) Effect on health care component of the accumulated postretirement obligation $7,983 $(6,454) - --------------------------------------------------------------------------------
Note 12. Leases. The Company maintains leases for certain property and equipment which meet the accounting criteria for capitalization. As required by SFAS No. 71, the Company has recorded such leases on its balance sheets. The amount of net assets under capital leases included in the accompanying Consolidated Balance Sheets is $1.7 million and $1.8 million, at December 31, 1998 and 1997, respectively. Although current rate-making practices treat all leases as operating leases, SFAS No. 71 provides that regulated utilities shall recognize as a charge against income an amount equal to the rental expense allowed for rate-making purposes. Therefore, the rental payments on these leases have no impact on the Company's financial results. - -------------------------------------------------------------------------------- 26 21 Orange and Rockland Utilities, Inc. and Subsidiaries In accordance with the terms of sale agreements with Southern Energy (see Note 5), the Company purchased the two leased gas turbines on February 1, 1999 for $1.7 million. These assets will be sold to a subsidiary of Southern Energy when the sale is completed. The lease is reflected as a current liability on the Consolidated Balance Sheet at December 31, 1998. The future minimum rental commitments under the Company's non-cancellable operating leases are as follows:
Non-cancellable Operating Leases ================================================================================ (Thousands of Dollars) 1999 $ 4,500 2000 4,300 2001 3,800 2002 2,600 2003 1,500 All years thereafter 28,300 - -------------------------------------------------------------------------------- Total $45,000 - --------------------------------------------------------------------------------
Rental expense for 1998, 1997 and 1996 was $6.0 million, $5.8 million and $6.2 million, respectively. Note 13. Commitments and Contingencies. Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk, as defined by Statement of Financial Accounting Standards No. 105 "Financial Instruments with Concentrations of Credit Risk," consist principally of temporary cash investments and accounts receivable. The Company places its temporary cash investments with highly rated financial institutions. Concentrations of credit risk with respect to accounts receivable are limited due to the Company's large, diverse customer base within its service territory. Therefore, as of December 31, 1998, the Company had no significant concentrations of credit risk. Construction Program Under the construction program of the Company and its subsidiaries, it is estimated that expenditures (excluding allowance for funds used during construction) of approximately $41.0 million will be incurred during 1999. This estimate includes four months of construction expenditures related to the Company's generating facilities. Construction expenditures, including cost of removal and salvage, amounted to $55.4 million for 1998. Gas Supply and Storage Contracts The Company has long-term and short-term contracts for firm supply, transportation and storage of gas. The contracts contain provisions that permit the Company to extend the contracts beyond their primary term if they are still required to serve firm customers. Approximately 90 percent of the Company's existing contracts will expire between 2000 and 2004. The Company's obligations under these contracts for the five years following 1998 are as follows: 1999-$60,100,000; 2000-$56,200,000; 2001-$42,400,000; 2002-$39,700,000 and 2003-$25,400,000. The NYPSC, in its effort to promote competition, has required the Company to provide firm transportation service for those customers that elect to purchase their gas supply from a marketer rather than the Company. Marketers are permitted to aggregate customers. As the transition to a competitive retail market develops, the Company will determine what supply capacity and storage contracts it maintains. As the Company moves to a competitive market, traditional cost recovery mechanisms may be replaced by market-based methods. Coal Supply Contracts The Company has one long-term contract for the supply of coal and two long-term contracts and a letter of intent for the transportation of coal. The Company has the right under the long-term coal purchase contract to suspend the purchase of coal if an alternative fuel source becomes less expensive. As part of the divestiture, the coal contracts will be assigned to various subsidiaries of Southern Energy. The aggregate contract obligations for the supply and transportation of coal for each of the five years following 1998 are as follows: 1999-$30,300,000; 2000-$29,600,000; 2001-$29,000,000; 2002-$29,000,000; 2003-$29,100,000. Power Purchase Agreements The Company has two long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2000 and 2015, respectively. The Company's aggregate contract obligations for the purchase of electric capacity and energy for each of the five years following 1998 are as follows: 1999-$3,100,000; 2000-$3,300,000; 2001-$700,000; 2002-$700,000; 2003-$700,000. Legal Proceedings Restructuring Litigation The Company, the six other New York State investor-owned electric utilities and the Energy Association of New York State filed a petition in New York State Supreme Court on September 18, 1996, challenging the NYPSC's May 20, 1996 Order in the Competitive Opportunities Proceeding (Case 94-E-0952) under Article 78 of the New York Civil Practice Law and Rules. In their Article 78 petition, the petitioners alleged that the Order is vague, ambiguous and procedurally defective, that the May 20, 1996 Order fails to assure the utilities a reasonable opportunity to recover strandable costs and that the NYPSC lacks the authority to order retail wheeling or divestiture. On November 26, 1996, the Supreme Court issued a ruling denying the Article 78 petition. In its ruling, the Court determined that because the NYPSC had not yet directed retail wheeling, generation deregulation and asset divestiture, there was no justiciable controversy regarding these issues. Despite this finding, the Court proceeded to opine that the NYPSC is not precluded by state or federal law from ordering retail wheeling or generation divestiture. The Court also determined that the utilities are not entitled, as a matter of law, to recover from customers the full amount of the utilities' strandable costs. On December 24, 1996, the Energy Association and the New York utilities appealed to the Appellate Division of the Supreme Court for the Third Judicial Department from the Supreme Court's November 26, 1996 decision. The Supreme Court of the State of New York, Appellate Division, Third Department, has granted several motions by the petitioners for an extension of time to - -------------------------------------------------------------------------------- 27 22 Orange and Rockland Utilities, Inc. and Subsidiaries perfect the appeal. By Decision and Order on Motion dated October 28, 1998, the Appellate Division has granted a motion to extend the time to perfect appeals to February 25, 1999. The Company's Restructuring Plan approved by the NYPSC's Orders of November 26 and December 31, 1997 requires the Company to petition the Appellate Division to withdraw its appeal. This petition must be filed "following final Commission approval of this agreement" (i.e., when any appeals from such approval are exhausted or the time to appeal has expired). On April 30, 1998, the Public Utility Law Project of New York, Inc. (PULP) instituted litigation in New York State Supreme Court against the NYPSC and the Company challenging the Company's Restructuring Plan. The NYPSC and the Company each filed a Motion to Dismiss this litigation on May 26, 1998. The Court denied these Motions on September 1, 1998 and ordered that PULP's action be converted into an Article 78 proceeding. The Company is unable to predict the final result of this litigation. Environmental Litigation On March 29, 1989, the New Jersey Department of Environmental Protection (NJDEP) issued a directive under the New Jersey Spill and Control Act to various potentially responsible parties (PRPs), including the Company, with respect to a site formerly owned and operated by Borne Chemical Company in Elizabeth, Union County, New Jersey, ordering certain interim actions directed at both site security and the off-site removal of certain hazardous substances. The Company and other PRPs are currently conducting a remedial investigation to determine what, if any, subsurface remediation at the Borne site is required. The Company does not believe that this matter will have a material effect on the financial condition of the Company. On August 2, 1994, the Company entered into a Consent Order with the New York State Department of Environmental Conservation (DEC) in which the Company agreed to conduct a remedial investigation of certain property it owns in West Nyack, New York. Polychlorinated biphenyls (PCBs) have been discovered at the West Nyack site. Petroleum contamination related to a leaking underground storage tank was found as well. The Company has completed this remedial investigation. The Company and the DEC have executed a second Consent Order to implement a Record of Decision (ROD), dated October 20, 1997 issued by the DEC. The ROD provides for the removal and off-site disposal of soils contaminated with PCBs and other petroleum-related contaminants and the post-remedial monitoring of groundwater. The Company completed all remediation at the West Nyack site in April 1998 except for the ongoing groundwater monitoring which will continue through March 2000. The Company anticipates that the DEC will determine whether any additional groundwater remediation will be required once such monitoring is completed. Deferred accounting treatment has been approved by the NYPSC and these costs are expected to be recovered in rates. The Company has identified seven former Manufactured Gas Plant (MGP) sites which were owned and operated by the Company or its predecessors. The Company may be named as a PRP for these sites under relevant environmental laws, which may require the Company to clean up these sites. To date, no claims have been asserted against the Company. The Company and the DEC have executed a Consent Order dated as of January 8, 1996, which provides for preliminary site assessments of these seven MGP sites. Preliminary Site Assessment (PSA) reports for four sites were submitted to the DEC on September 1, 1997. These reports showed varying degrees of contamination at each of the sites which necessitates further investigation. The Company entered into a Consent Order dated September 29, 1998 to conduct a Remedial Investigation and Feasibility Study (RIFS) at each of these sites. Field investigations began in October 1998 and are ongoing. The Company anticipates that final reports will be submitted to DEC in the third quarter of 1999. In addition, the Company has completed PSAs at two of its other MGP sites and submitted PSA reports to DEC in September 1998. Since MGP contamination was found at each of these two sites, the Company expects that a RIFS will need to be performed at these sites. Due to difficulties in obtaining access, the Company has not commenced a PSA for its MGP site located in Nyack, New York. The Company currently is negotiating a separate consent order with DEC for this MGP site, as well as an access agreement with the current site owner. Although the Company is unable at this time to estimate the total costs to be incurred at the seven MGP sites, deferred accounting treatment has been approved by the NYPSC and these costs are expected to be recovered in rates. On May 29, 1991, a group of ten electric utilities (Metal Bank Group) entered into an Administrative Consent Order with the United States Environmental Protection Agency (EPA) to perform a RIFS at the Cottman Avenue/Metal Bank Superfund site in Philadelphia, Pennsylvania. PCBs have been discharged at the Cottman Avenue site from an underground storage tank and the handling of transformers and other electrical equipment. On December 31, 1997, the EPA executed a ROD which presents the final remedial action selected for the site, which EPA estimates will cost approximately $17.2 million. On July 6, 1998, the EPA issued an administrative order to the Company and the members of the Metal Bank Group ordering them to commence remediation of the site. On July 28, 1998, the Metal Bank Group and the Company notified the EPA of their intent to proceed with the work required by the July 6, 1998 order. By letter dated September 22, 1998, EPA selected the Metal Bank Group's consultant to perform the remedial design for the site. This consultant has developed and the Metal Bank Group has submitted a draft remedial design work plan to EPA for comment. On November 23, 1998, the Company executed a settlement agreement with the Metal Bank Group wherein they agreed that the Company would become a member of the Metal Bank Group and that the Company would pay the Metal Bank Group $350,000, which represents the Company's share of costs incurred by the Metal Bank Group at the Cottman Avenue site through July 20, 1998. On November 30, 1998, the Company executed the Cottman Avenue PRP Group amended agreement, thereby becoming a member of the Metal Bank Group. This agreement allocated to the Company 4.57% of shared costs. The consolidated financial results include the Company's share of costs to join the Metal Bank Group as well as a provision for the Company's share of the projected liability. - -------------------------------------------------------------------------------- 28 23 Orange and Rockland Utilities, Inc. and Subsidiaries Other Litigation On November 19, 1996, the Company was served with a Summons and Complaint (Summons and Complaint) in a litigation entitled Crossroads Cogeneration Corporation v. Orange and Rockland Utilities, Inc., filed in the United States District Court for the District of New Jersey. The litigation relates to a certain Power Sales Agreement between the Company and Crossroads Cogeneration Corporation (Crossroads), which requires the Company to purchase electric capacity and associated energy from a cogeneration facility in Mahwah, New Jersey. The Complaint alleges damage claims for breach of contract, breach of the implied covenant of good faith and fair dealing and violations of the Federal Antitrust laws and seeks a declaration of Crossroads' rights under the Agreement. By Opinion and Order dated June 30, 1997 (Order), the Court dismissed Crossroads' Complaint in its entirety with prejudice, whereupon Crossroads appealed to the United States Court of Appeals for the Third Circuit. On October 27, 1998, the United States Court of Appeals for the Third Circuit issued its decision in this case. The Third Circuit confirmed the trial court's dismissal with prejudice of Crossroads federal antitrust claims but rejected the trial court's determination that the NYPSC's November 29, 1996 decision was determinative of Crossroads' state contract claims. This case has been remanded to the United States District Court for the District of New Jersey. The Company cannot predict the ultimate outcome of this proceeding. On March 9, 1998, three shareholders of the Company filed a purported derivative action on behalf of the Company alleging various claims against its directors, several current officers and one former officer, certain other defendants and nominally against the Company. Plaintiffs filed the action, entitled Virgilio Ciullo, et al. v. Orange and Rockland Utilities, Inc. et al. in the Supreme Court of the State of New York, County of New York. The complaint was subsequently amended several times to assert additional purported derivative and class action claims. By order dated January 8, 1999 and entered on January 12, 1999, the State Supreme Court granted defendants' motion to dismiss the complaint in its entirety and denied plaintiffs' motion to further amend their complaint to add additional causes of actions. On February 10, 1999, plaintiffs filed a notice of appeal from the trial court's decision to the Appellate Division. Environmental The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and certain similar state statutes authorize various governmental authorities to issue orders compelling responsible parties to take cleanup action at sites determined to present an imminent and substantial danger to the public and to the environment because of an actual or threatened release of hazardous substances. As discussed above, the Company is a party to a number of administrative and litigation proceedings involving potential impact on the environment. Such proceedings arise out of, without limitation, the operation and maintenance of facilities for the generation, transmission and distribution of electricity and natural gas. As noted above, the Company does not believe that certain proceedings will have a material effect on the Company, while as to others, the Company is unable at this time to estimate what, if any, costs it will incur. Pursuant to the Clean Air Act Amendments of 1990, which became law on November 15, 1990, a permanent nationwide reduction of 10 million tons in sulfur dioxide emissions from 1980 levels, as well as a permanent nationwide reduction of 2 million tons of nitrogen oxide emissions from 1980 levels, must be achieved by January 1, 2000. In addition, continuous emission monitoring systems were required at all affected facilities effective January 1, 1995. Pursuant to New York State attainment of ozone standards, nitrogen oxide (NOx) reductions were achieved effective May 31, 1995. Additional NOx reductions will be required effective May 1999 for the annual ozone season (May - September). The Company has two base load generating stations that burn fossil fuels that are affected by this legislation. These generating facilities already burn low sulfur fuels, so additional capital costs are not anticipated for compliance with the sulfur dioxide emission requirements. The Company installed low nitrogen oxide burners at the Lovett Plant and made operational modifications at Bowline Plant to meet NOx reduction levels for ozone attainment. Additional emission monitoring systems were installed at both facilities. In compliance with DEC proposed regulations, effective May 1, 1999, the Company will be allocated NOx emission allowances for the annual ozone season. The Company does not anticipate incurring additional capital costs to comply with these proposed regulations. Beginning with calendar year 1994, Title V sources (Bowline and Lovett) are required to pay an emission fee. Each facility's fees are based upon actual air emissions reported to the DEC for the preceding calendar year. For 1998, the Company paid an emission rate of approximately $32.64 per ton based upon 1997 emissions. The emission fee will be reevaluated by New York State annually. The EPA finalized in July 1997 new national ambient air quality standards for ozone particulate matter. By agreements dated November 24, 1998, the Company agreed to sell all of its electric generating facilities to subsidiaries of Southern Energy. Pending the closing, the Company will continue to assess the impact of the Clean Air Act Amendments of 1990 and new ozone and particulate standards on its power generating operations as additional regulations implementing these Amendments and standards are promulgated. Note 14. Segments of Business. In accordance with the requirements of Statement of Financial Accounting Standards No. 131 (SFAS No. 131), "Disclosures about Segments of an Enterprise and Related Information," the Company defines its principal business segments as utility (electric and gas) and diversified activities. The diversified segment, at year end, included energy services and land development. Total utility revenue as reported in the Consolidated Statements of Income include both sales to unaffiliated customers and intersegment sales which are billed at tariff rates. Income from operations is total revenue less operating expenses. General corporate expenses were allocated in the manner used in the rate-making process. Identifiable assets by segment are those assets that are used in the production, distribution and sales operations in each segment. Allocations were made in a manner consistent with the rate-making process. Corporate assets are principally property, cash, sundry receivables and unamortized debt expense. - -------------------------------------------------------------------------------- 29 24 Orange and Rockland Utilities, Inc. and Subsidiaries
Year Ended December 31, 1998 1997 1996 =========================================================================================== (Thousands of Dollars) Operating Information: Operating revenues: Sales to unaffiliated customers: Electric $ 489,869 $ 479,463 $ 477,032 Gas 135,605 168,421 176,400 Intersegment sales: Electric 9 10 10 Gas 14 29 42 - ------------------------------------------------------------------------------------------- Total Utility Operating Revenues 625,497 647,923 653,484 Diversified activities 607 851 1,405 - ------------------------------------------------------------------------------------------- Total Operating Revenues $ 626,104 $ 648,774 $ 654,889 - ------------------------------------------------------------------------------------------- Operating income before income taxes: Electric $ 89,160 $ 87,430 $ 86,161 Gas 11,352 15,382 22,447 Diversified activities (2,009) (1,937) 402 - ------------------------------------------------------------------------------------------- Total Operating Income Before Income Taxes 98,503 100,875 109,010 - ------------------------------------------------------------------------------------------- Income Taxes: Electric 21,770 21,837 21,585 Gas 1,301 2,491 4,879 Diversified activities (558) (450) (98) - ------------------------------------------------------------------------------------------- Total Income Taxes 22,513 23,878 26,366 - ------------------------------------------------------------------------------------------- Total Income From Operations $ 75,990 $ 76,997 $ 82,644 - ------------------------------------------------------------------------------------------- Other Information: Identifiable assets: Electric $ 1,004,102 $ 996,647 $ 978,952 Gas 260,754 241,656 240,471 Diversified activities 11,913 13,162 24,220 - ------------------------------------------------------------------------------------------- Total Identifiable Assets 1,276,769 1,251,465 1,243,643 Corporate assets 31,371 36,544 22,489 - ------------------------------------------------------------------------------------------- Total Assets $ 1,308,140 $ 1,288,009 $ 1,266,132 - ------------------------------------------------------------------------------------------- Depreciation expense: Electric $ 29,919 $ 30,597 $ 29,430 Gas 5,688 5,091 2,578 Diversified activities 128 173 264 - ------------------------------------------------------------------------------------------- Total Depreciation Expense $ 35,735 $ 35,861 $ 32,272 - ------------------------------------------------------------------------------------------- Additions to plants: Electric $ 33,910 $ 48,555 $ 41,932 Gas 19,109 25,257 16,766 Diversified activities 18 174 136 - ------------------------------------------------------------------------------------------- Total Additions $ 53,037 $ 73,986 $ 58,834 - -------------------------------------------------------------------------------------------
Note 15. Summary of Quarterly Results of Operations (Unaudited).
Earnings Earnings Applicable Per Income To Average Operating From Net Common Common Revenues Operations Income Stock Share =================================================================================== (Thousands of Dollars) Quarter Ended 1998 March 31 $165,081 $21,482 $ 13,804 $ 13,104 $ 0.97 June 30 139,549 12,712 5,076 4,377 0.32 September 30 172,118 26,902 18,449 17,588 1.30 December 31 149,356 14,894 7,638 7,101 0.53 - ----------------------------------------------------------------------------------- 1997 March 31 $185,318 $21,395 $ 6,916 $ 6,216 $ 0.46 June 30 137,195 13,068 (994) (1,693) (0.13) September 30 159,728 23,741 12,568 11,868 0.87 December 31 166,533 18,793 11,016 10,315 0.76 - -----------------------------------------------------------------------------------
Quarterly results reflect the seasonal effect of electric and gas sales as well as the results of the NORSTAR discontinued operations. Report of Independent Public Accountants ARTHUR ANDERSEN LLP To the Board of Directors and Shareholders of Orange and Rockland Utilities, Inc.: We have audited the accompanying consolidated balance sheets of Orange and Rockland Utilities, Inc. (a New York Corporation) and Subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income and retained earnings and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Orange and Rockland Utilities, Inc. and Subsidiaries as of December 31, 1998 and 1997, and the consolidated results of their operations and their cash flows for the three years ended December 31, 1998, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP New York, New York February 4, 1999 - -------------------------------------------------------------------------------- 30 25 Orange and Rockland Utilities, Inc. and Subsidiaries Operating Statistics
Year Ended December 31, 1998 1997 1996 1995 1994 ================================================================================================================================ Electric: Sales (Mwh): Residential 1,836,916 1,791,676 1,731,105 1,685,110 1,660,755 Commercial 2,105,741 1,959,862 2,044,759 2,056,185 2,049,265 Industrial 815,089 839,851 748,484 680,678 657,142 Public Street Lighting 28,713 26,899 29,522 28,107 27,836 Public Authorities 78,827 73,647 51,392 75,506 68,972 - -------------------------------------------------------------------------------------------------------------------------------- Total Sales to Customers 4,865,286 4,691,935 4,605,262 4,525,586 4,463,970 Other Utilities for Resale 556,679 305,445 190,394 118,730 265,311 - -------------------------------------------------------------------------------------------------------------------------------- Total Sales of Electricity 5,421,965 4,997,380 4,795,656 4,644,316 4,729,281 - -------------------------------------------------------------------------------------------------------------------------------- Revenues (000's): Residential $ 219,170 $ 218,974 $ 209,706 $ 208,862 $ 214,439 Commercial 202,054 194,102 200,281 204,240 212,214 Industrial 42,818 44,936 46,663 50,205 51,316 Public Street Lighting 4,945 5,040 4,903 4,930 4,939 Public Authorities 3,402 2,754 3,453 4,257 4,051 - -------------------------------------------------------------------------------------------------------------------------------- Total Revenues from Sales to Customers 472,389 465,806 465,006 472,494 486,959 Other Utilities for Resale 13,956 7,109 3,106 2,150 6,636 - -------------------------------------------------------------------------------------------------------------------------------- Total Revenues from Sales of Electricity 486,345 472,915 468,112 474,644 493,595 Other Electric Operating Revenues 3,533 6,558 8,930 (14,661) (14,566) - -------------------------------------------------------------------------------------------------------------------------------- Total Electric Operating Revenues $ 489,878 $ 479,473 $ 477,042 $ 459,983 $ 479,029 ================================================================================================================================ Gas: Sales (Mmcf): Residential 12,489 14,997 15,685 14,759 15,164 Commercial and Industrial 4,853 5,324 5,233 5,066 5,257 - -------------------------------------------------------------------------------------------------------------------------------- Total Firm Sales 17,342 20,321 20,918 19,825 20,421 Interruptible 3,114 3,527 3,996 2,327 1,023 Other Utilities for Resale 7 3 4 4 27 - -------------------------------------------------------------------------------------------------------------------------------- Total Sales of Gas 20,463 23,851 24,918 22,156 21,471 - -------------------------------------------------------------------------------------------------------------------------------- Revenues (000's): Residential $ 93,630 $ 115,335 $ 116,981 $ 96,737 $ 112,759 Commercial and Industrial 27,412 34,771 36,954 31,226 36,676 - -------------------------------------------------------------------------------------------------------------------------------- Total Revenues from Firm Sales 121,042 150,106 153,935 127,963 149,435 Interruptible 10,256 13,915 15,101 6,725 3,996 Other Utilities for Resale 69 75 94 59 203 - -------------------------------------------------------------------------------------------------------------------------------- Total Revenues from Sales of Gas 131,367 164,096 169,130 134,747 153,634 Other Gas Revenues 4,252 4,354 7,312 5,477 3,534 - -------------------------------------------------------------------------------------------------------------------------------- Total Gas Operating Revenues $ 135,619 $ 168,450 $ 176,442 $ 140,224 $ 157,168 ================================================================================================================================
- -------------------------------------------------------------------------------- 31 26 Orange and Rockland Utilities, Inc. and Subsidiaries Financial Statistics
Year Ended December 31, 1998 1997 1996 1995 1994 ================================================================================================================================ Common Stock Data: Earnings Per Average Common Share: Continuing Operations $ 3.12 $ 3.09 $ 3.30 $ 2.54 $ 2.45 Discontinued Operations $ -- $ (1.13) $ (0.13) $ 0.06 $ 0.05 - -------------------------------------------------------------------------------------------------------------------------------- Consolidated Earnings Per Average Common Share $ 3.12 $ 1.96 $ 3.17 $ 2.60 $ 2.50 - -------------------------------------------------------------------------------------------------------------------------------- Dividends Declared Per Share $ 2.58 $ 2.58 $ 2.58 $ 2.57 $ 2.54 Book Value Per Share (Year End) $ 28.14 $ 27.69 $ 28.41 $ 27.82 $ 27.79 Market Price Range Per Share: High $ 57 1/16 $ 48 5/8 $ 37 1/8 $ 37 3/8 $ 41 1/4 Low $ 40 $ 30 1/8 $ 33 3/8 $ 30 7/8 $ 28 3/8 Year End $ 57 $ 46 9/16 $ 35 7/8 $ 35 3/4 $ 32 1/2 Price Earnings Ratio 18.27 23.76 11.32 13.75 13.00 Dividend Payout Ratio 82.69% 131.63% 81.39% 98.85% 101.60% Common Shareholders at Year End 17,650 19,682 21,322 22,916 23,299 Average Number of Common Shares Outstanding (000's) 13,520 13,649 13,654 13,653 13,594 Total Common Shares Outstanding at Year End (000's) 13,520 13,589 13,654 13,654 13,653 Return on Average Common Equity 11.29% 7.09% 11.33% 9.35% 9.01% - -------------------------------------------------------------------------------------------------------------------------------- Capitalization Data (000's): Common Stock Equity $ 380,395 $ 376,319 $ 387,850 $ 379,776 $ 379,403 Non-Redeemable Preferred and Preference Stock 43,516 43,223 43,241 43,253 43,268 Redeemable Preferred Stock -- -- -- 1,390 2,774 Long-Term Debt (includes current portion) 357,192 356,676 359,825 359,928 379,014 - -------------------------------------------------------------------------------------------------------------------------------- Total Capitalization $ 781,103 $ 776,218 $ 790,916 $ 784,347 $ 804,459 - -------------------------------------------------------------------------------------------------------------------------------- Capitalization Ratios: Common Stock Equity 48.70% 48.48% 49.04% 48.42% 47.16% Non-Redeemable Preferred Stock 5.57% 5.57% 5.47% 5.51% 5.38% Redeemable Preferred Stock -- -- -- 0.18% 0.35% Long-Term Debt (includes current portion) 45.73% 45.95% 45.49% 45.89% 47.11% - -------------------------------------------------------------------------------------------------------------------------------- Selected Financial Data (000's): Operating Revenues $ 626,104 $ 648,774 $ 654,889 $ 602,310 $ 638,404 Operating Expenses $ 550,114 $ 571,777 $ 572,245 $ 526,741 $ 562,810 Operating Income $ 75,990 $ 76,997 $ 82,644 $ 75,569 $ 75,594 Net Income $ 44,967 $ 29,506 $ 46,303 $ 38,573 $ 37,217 Earnings Applicable to Common Stock $ 42,170 $ 26,706 $ 43,279 $ 35,438 $ 33,966 Net Utility Plant $ 951,570 $ 936,213 $ 899,643 $ 873,668 $ 856,289 Total Assets $1,308,140 $1,288,009 $1,266,132 $1,251,541 $1,230,726 Long-Term Debt Including Redeemable Preferred Stock $ 357,192 $ 356,676 $ 359,825 $ 361,318 $ 381,788 Ratio of Long-Term Debt to Net Plant 37.7% 38.1% 40.0% 41.2% 44.3% Ratio of Accumulated Depreciation to Utility Plant in Service 35.2% 35.1% 33.8% 33.3% 33.1% ================================================================================================================================
Credit Ratings Duff & Phelps Moody's Standard & Credit Rating Investors Poor's Company Service Corp. ================================================================================================================================= Commercial paper D-1 P-2 A-2 Pollution control bonds A A3 A- Unsecured debt A A3 A- Preferred stock A- baa1 BBB+ =================================================================================================================================
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