<PAGE> 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)
<TABLE>
<S> <C> <C>
Incorporated in New York 1-4315 13-1727729
(State or Other (Commission (IRS Employer
Jurisdiction of File Number) Identification
Incorporation) Number)
</TABLE>
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
<PAGE> 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-
<PAGE> 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
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<PAGE> 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.
<PAGE> 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
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<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> Per-Book
<TOTAL-NET-UTILITY-PLANT> 951,570
<OTHER-PROPERTY-AND-INVEST> 7,528
<TOTAL-CURRENT-ASSETS> 194,848
<TOTAL-DEFERRED-CHARGES> 154,194
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,308,140
<COMMON> 67,599
<CAPITAL-SURPLUS-PAID-IN> 126,276
<RETAINED-EARNINGS> 186,520
<TOTAL-COMMON-STOCKHOLDERS-EQ> 380,395
0
0
<LONG-TERM-DEBT-NET> 357,156
<SHORT-TERM-NOTES> 0
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<COMMERCIAL-PAPER-OBLIGATIONS> 149,050
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43,516
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<LEASES-CURRENT> 1,654
<OTHER-ITEMS-CAPITAL-AND-LIAB> 376,333
<TOT-CAPITALIZATION-AND-LIAB> 1,308,140
<GROSS-OPERATING-REVENUE> 626,104
<INCOME-TAX-EXPENSE> 22,513
<OTHER-OPERATING-EXPENSES> 527,601
<TOTAL-OPERATING-EXPENSES> 550,114
<OPERATING-INCOME-LOSS> 75,990
<OTHER-INCOME-NET> 2,561
<INCOME-BEFORE-INTEREST-EXPEN> 78,551
<TOTAL-INTEREST-EXPENSE> 33,584
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2,797
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<EPS-PRIMARY> 3.12
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<PAGE> 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
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7
<PAGE> 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
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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.
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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:
<TABLE>
<CAPTION>
1998 1997 1996
================================================================================
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 5
Orange and Rockland Utilities, Inc. and Subsidiaries
The changes in electric sales by class of customer from the prior year are
as follows:
<TABLE>
<CAPTION>
1998 1997
================================================================================
<S> <C> <C>
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%
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
1998 1997
================================================================================
<S> <C> <C>
Residential (16.7%) (4.4%)
Commercial and industrial (8.8%) 1.7%
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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.
</TABLE>
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:
<TABLE>
<CAPTION>
Increase (Decrease) from prior year 1998 1997
================================================================================
(Millions of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
1998 1997 1996
================================================================================
(Millions of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 9
Orange and Rockland Utilities, Inc. and Subsidiaries
Consolidated Statements of Income
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
=============================================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
- --------------------------------------------------------------------------------
15
<PAGE> 10
Orange and Rockland Utilities, Inc. and Subsidiaries
Consolidated Balance Sheets
<TABLE>
<CAPTION>
December 31,
1998 1997
=========================================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
=========================================================================================================
</TABLE>
The accompanying notes are an integral part of these statements.
- --------------------------------------------------------------------------------
16
<PAGE> 11
Orange and Rockland Utilities, Inc. and Subsidiaries
<TABLE>
<CAPTION>
December 31,
1998 1997
===============================================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
===============================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
17
<PAGE> 12
Orange and Rockland Utilities, Inc. and Subsidiaries
Consolidated Cash Flow Statements
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
=====================================================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
=====================================================================================================================
</TABLE>
The accompanying notes are an integral part of these statements.
- --------------------------------------------------------------------------------
18
<PAGE> 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:
<TABLE>
<CAPTION>
1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Plant Classification:
Electric 2.80% 3.03% 2.88%
Gas 2.86% 2.90% 2.91%
Common 7.78% 7.21% 5.93%
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
Electric Utility Plant in Service $103,776 $103,217
Construction Work in Progress $ 483 $ 739
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996
================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
The tax effect of temporary differences which gave rise to deferred tax
assets and liabilities is as follows:
<TABLE>
<CAPTION>
As of December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996
================================================================================
(% of Pre-tax Income)
<S> <C> <C> <C>
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%
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996
================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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.
<TABLE>
<CAPTION>
(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*
============================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C>
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)
</TABLE>
- --------------------------------------------------------------------------------
22
<PAGE> 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):
<TABLE>
<CAPTION>
Par Value
------------------- Callable
Shares December 31, Redemption
Series Outstanding 1996, 1997 and 1998 Price Per Share
================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
(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
<PAGE> 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:
<TABLE>
<CAPTION>
1998 1997 1996
================================================================================
(Millions of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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.
<TABLE>
<CAPTION>
1998 1997
===================================================================================
Carrying Fair Carrying Fair
Amount Amount Amount Amount
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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
- -----------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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.
<TABLE>
<CAPTION>
December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
The following table provides the amounts recognized in the Company's
Consolidated Balance Sheets for the years 1998 and 1997:
<TABLE>
<CAPTION>
December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
December 31, 1998 1997 1996
================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
Weighted average assumptions used in the accounting for these plans were
as follows:
<TABLE>
<CAPTION>
1998 1997 1996
================================================================================
<S> <C> <C> <C>
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%
- --------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
25
<PAGE> 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:
<TABLE>
<CAPTION>
December 31, 1998 1997
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
December 31, 1998 1997 1996
================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Assumptions as of December 31, 1998 1997
================================================================================
<S> <C> <C>
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%
- --------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
1% 1%
Increase Decrease
================================================================================
(Thousands of Dollars)
<S> <C> <C>
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)
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
Non-cancellable
Operating
Leases
================================================================================
(Thousands of Dollars)
<S> <C>
1999 $ 4,500
2000 4,300
2001 3,800
2002 2,600
2003 1,500
All years thereafter 28,300
- --------------------------------------------------------------------------------
Total $45,000
- --------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 24
Orange and Rockland Utilities, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996
===========================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------
</TABLE>
Note 15. Summary of Quarterly Results of Operations (Unaudited).
<TABLE>
<CAPTION>
Earnings Earnings
Applicable Per
Income To Average
Operating From Net Common Common
Revenues Operations Income Stock Share
===================================================================================
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
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
- -----------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 25
Orange and Rockland Utilities, Inc. and Subsidiaries
Operating Statistics
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996 1995 1994
================================================================================================================================
<S> <C> <C> <C> <C> <C>
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
================================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
31
<PAGE> 26
Orange and Rockland Utilities, Inc. and Subsidiaries
Financial Statistics
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996 1995 1994
================================================================================================================================
<S> <C> <C> <C> <C> <C>
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%
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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%
================================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Credit Ratings Duff & Phelps Moody's Standard &
Credit Rating Investors Poor's
Company Service Corp.
=================================================================================================================================
<S> <C> <C> <C>
Commercial paper D-1 P-2 A-2
Pollution control bonds A A3 A-
Unsecured debt A A3 A-
Preferred stock A- baa1 BBB+
=================================================================================================================================
</TABLE>
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