REVIEW OF THE COMPANY'S RESULTS OF OPERATIONS AND FINANCIAL CONDITION
FINANCIAL PERFORMANCE
Consolidated earnings per share were $2.50 for 1994, compared to $3.06 in 1993
and $3.15 in 1992. The decline in earnings in 1994, and to a lesser degree in
1993, reflects the impact of the costs associated with the investigation and
litigation involving former officers and others, the establishment of a
provision for the refunding of misappropriated funds to customers, and adverse
regulatory actions related to these events, as well as a decline in non-utility
subsidiary operating results. The investigation and related matters are more
fully described below under "Events Affecting the Company." Despite this adverse
effect on earnings for 1994 and 1993, the core utility business produced strong
operating results. Electric revenues from retail customers increased in 1994 and
1993. Firm gas revenues remained stable in 1994 after increasing 15% in 1993. In
addition, Orange and Rockland Utilities, Inc.'s (Company's) cost containment
program reduced operating expenses. The decline in non-utility earnings is
primarily a result of continuing competitive pressure in the gas marketing
business, which substantially limited the subsidiary's gross profit margin.
Consolidated earnings available for common stock were $34.0 million in 1994,
$41.5 million in 1993 and $42.3 million in 1992. Earnings per average common
share are summarized as follows:
1994 1993 1992
===========================================================================
Utility operations $ 3.14 $ 3.37 $ 3.12
Events Affecting the Company:
Investigation & litigation costs (.42) (.29) --
Refunds of misappropriated funds (.20) -- --
Diversified activities (.02) (.02) .03
- ---------------------------------------------------------------------------
Consolidated earnings per share $ 2.50 $ 3.06 $ 3.15
- ---------------------------------------------------------------------------
The earned return on common equity was 9.0% in 1994, compared to 11.2% in
1993, and 11.9% in 1992. Book value per share at year-end 1994 and 1993 was
$27.79, compared to $27.22 in 1992.
The Company continued to provide a fair and equitable return on shareholders'
investments by increasing the dividend paid on common stock to $2.54 per share
from the $2.49 paid in 1993 and the $2.43 paid in 1992. The Company has
maintained a strong capital structure of 46% long-term debt, 6% preferred stock
and 48% common equity.
8
Orange and Rockland Utilities, Inc. and Subsidiaries
EVENTS AFFECTING THE COMPANY
Following the arrest in August 1993 of a Company Vice President on charges of
grand larceny, commercial bribery and making illegal campaign contributions, the
Company's Board of Directors appointed a Special Committee of outside directors
(Special Committee) on August 20, 1993, giving it a broad mandate to investigate
all wrongdoing at the Company. In turn, the Special Committee retained counsel
specializing in investigations of utility corporations.
On August 23, 1994, the investigative firm completed its inquiries and issued
a report documenting its findings. The Report of the Special Committee, which
was made available to all shareholders, found a pattern of misconduct by James
F. Smith, the Company's former Chief Executive Officer, including a subversion
of the Company's system of internal controls to mask payment by the Company of
personal expenses.
As a result of the investigation, the Company has taken steps to correct the
problems which were found, uncover any remaining problems, and reduce the
likelihood of similar improprieties in the future.
The investigation resulted in the dismissal of the Chairman of the Board and
Chief Executive Officer, as well as the termination of three Vice Presidents,
two of whom had been controllers during the period covered in the investigation,
and the Manager of Internal Auditing. On May 11, 1994 the Company appointed
Arthur Andersen LLP as its new outside auditors. The Company also has entered
into a Joint Cooperation Agreement with the Rockland County (NY) District
Attorney's Office, pursuant to which the Company has, among other things,
appointed an independent Inspector General for a period of up to seven years,
and discontinued for five years all political contributions and the activities
of all political action committees.
The New York Public Service Commission (NYPSC) and the New Jersey Board of
Public Utilities (NJBPU) have undertaken investigations to determine the impact
of these events on the Company's ratepayers. The Company is cooperating fully in
the inquiries and has pledged to return to customers any funds that are
determined to have been misappropriated. To date, the Company has refunded a
total of $369,000 to New York ratepayers, $93,000 to New Jersey ratepayers and
approximately $2,600 to Pennsylvania ratepayers, and has submitted plans to the
NYPSC and NJBPU to refund an additional $4.1 million to ratepayers based on the
findings of the Company's investigation. A similar refund proposal for
approximately $26,000 has been accepted by the Pennsylvania Public Utility
Commission (PPUC). The NYPSC and NJBPU have completed their investigations and
have submitted reports to the Company for comment prior to final adoption and
publication. Neither the NYPSC nor the NJBPU has yet quantified what it
believes to be the impact of the wrongdoing and related investigation on
ratepayers.
The Company is pursuing lawsuits and an arbitration proceeding against certain
former officers and employees to recover misappropriated funds and other costs
attributable to the wrongdoing and related investigation.
Four lawsuits were brought against the Company or its officers and directors,
purportedly on behalf of shareholders or ratepayers, seeking damages resulting
from these events. The ratepayer case has been dismissed, and the three
shareholder suits have been settled, although one of these settlements still
requires court approval. For more information on these legal proceedings, refer
to Note 12 of Notes to Consolidated Financial Statements.
NEW MANAGEMENT TEAM
The Company has engaged in a major corporate restructuring. In addition to the
appointment of D. Louis Peoples as Vice Chairman and Chief Executive Officer, R.
Lee Haney has been appointed Vice President and Chief Financial Officer (CFO).
With these key appointments, the Company's management has been reorganized to
broaden spans of control in order to maximize performance and flexibility in a
competitive environment. The Electric Production Department has been
restructured as a newly-created Division to provide for the segregation of the
Company's electric generation function, and the marketing function has been
strengthened to take advantage of the Company's energy services expertise and
opportunities in new markets. The Company has upgraded the organizational
position of the Internal Auditing function to report directly to the Audit
Committee of the Board of Directors and, in January 1995, appointed a new
Director of Internal Auditing. Also reporting to the Audit Committee of the
Board of Directors and the Chief Executive Officer is an Ethics Officer. The
Ethics Officer, appointed in February 1995, is responsible for administering a
strict set of ethical standards and creating an effective procedure for
employees to report suspected violations of the Company's new comprehensive Code
of Business Conduct. In order to complete its organizational restructuring, the
Company is currently in the process of hiring a Vice President of Human
Resources and a General Counsel.
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 1994 to 1993 and 1993 to 1992. This
discussion should be read in conjunction with the Notes to Consolidated
Financial Statements and other financial and statistical information contained
elsewhere
9
1994 Annual Report
in this report. The following is a summary of the changes in earnings
available for common stock:
Increase (Decrease) From Prior Year 1994 1993
==================================================================================
(Millions of Dollars)
Utility Operations:
Operating revenues $ (8.0) $ 39.8
Energy costs (4.9) 15.5
- ----------------------------------------------------------------------------------
Net revenues from utility operations (3.1) 24.3
Other utility operating expenses and taxes 3.6 20.4
Diversified revenues 57.8 87.3
Diversified operating expenses and taxes 58.1 88.1
- ----------------------------------------------------------------------------------
Income from operations (7.0) 3.1
Other income and deductions (.8) (5.4)
Interest charges (.2) (1.3)
- ----------------------------------------------------------------------------------
Net income (7.6) (1.0)
Preferred dividends (.1) (.1)
- ----------------------------------------------------------------------------------
Earnings available for common stock $ (7.5) $ (.9)
- ----------------------------------------------------------------------------------
ELECTRIC OPERATING REVENUES AND SALES
Electric operating revenues, net of fuel and purchased power costs, decreased
by 1.4% or $4.7 million in 1994 after increasing by 6.1% or $20.0 million in
1993.
The components of these changes are attributable to the following factors:
Increase (Decrease) From Prior Year 1994 1993
=================================================================================
(Millions of Dollars)
Retail sales:
Base rates including misc. surcharges
and revenue tax recoveries $ (2.2) $ 17.7
Fuel cost recoveries (3.1) 2.0
Sales volume changes 8.7 12.0
- ---------------------------------------------------------------------------------
Subtotal 3.4 31.7
Sales for resale 0.2 (.6)
Other operating revenues:
RDM revenue reconciliation and DSM incentives (8.2) (6.1)
Other (3.3) (1.8)
- ---------------------------------------------------------------------------------
Total electric revenues (7.9) 23.2
Electric energy costs (3.2) 3.2
- ---------------------------------------------------------------------------------
Net electric revenues $ (4.7) $ 20.0
- ---------------------------------------------------------------------------------
Actual total sales of electric energy to retail customers during 1994 were
4,464 Mmwh, compared with 4,358 Mmwh during 1993 and 4,212 Mmwh in 1992. Before
reflecting the effects of the Revenue Decoupling Mechanism (RDM) in the
Company's New York jurisdiction,electric revenues associated with these sales
were $487.0 million, $483.6 million and $451.9 million in 1994, 1993 and 1992,
respectively.
Electric sales to customers for the last five years are shown in the
accompanying table. [Graphics Chart, see Appendix A of Exhibit 13]
The changes in electric sales by class of customer from the prior year are as
follows:
1994 1993
=============================================================================
Residential 3.0% 5.1%
Commercial 1.5% 1.6%
Industrial 4.6% 5.6%
Public street lighting .5% .6%
Sales to public authorities (4.3%) 2.5%
- -----------------------------------------------------------------------------
An increase in the number of customers compared to the previous year was the
primary reason electric retail sales increased 2.4% and 3.5% in 1994 and 1993,
respectively.
The Company continues to meet the needs of its customers by pursuing
least-cost strategies. Demand-Side Management (DSM) programs, which are designed
to reduce peak load, encourage efficient energy usage and reduce the need for
costly investments in new generating capacity, continue to be an integral
component of the Company's resource plan. These efforts resulted in the Company
achieving an energy-efficiency savings of approximately 193,864 Mwh in 1994,
166,697 Mwh in 1993 and 113,315 Mwh in 1992. Based on the energy efficiency
savings in New York, the Company earned and filed to recover the maximum
allowable incentives provided by the NYPSC approved rate agreement for the 1993
and 1992 calendar years. For 1994, the NYPSC significantly reduced the amount of
DSM incentive available to the Company. However, as a result of greater than
projected acquired demand and energy savings, the Company was able to earn an
incentive of approximately $600,000 in 1994. In addition to DSM, the Company
continues to actively seek cost-effective energy supply options, such as
purchased power agreements with other utilities.
An innovative rate-making procedure called RDM, which became effective January
1, 1991, requires among other things, the reconciliation of actual electric
sales revenue based on usage in the Company's New York franchise territory to
the level allowed in rates, thereby minimizing the impact of sales volume
changes on earnings. The Company's earnings from New York electric operations
under the RDM agreement are dependent on its success in achieving its DSM goals,
as well as controlling operating and maintenance costs within levels provided
for in rates. Under the agreement, New York electric revenue targets, net of
fuel and taxes, amounted to $224.8 and $223.2 million, compared to actual sales
revenues based upon usage of $237.1 and $230.1 million in 1994 and 1993,
respectively, requiring the Company to record revenue reductions of $12.3
million in 1994 and $6.9 million in 1993. The Company's success in achieving its
DSM and customer service goals allowed it to earn incentives amounting to
$600,000 for DSM in 1994 and $3.4 million in 1993. Customer service incentives
in 1994 were discontinued by the NYPSC's July 10, 1994 order terminating the
Company's electric rate request. The Customer Service incentives provided $.5
million of additional earnings in 1993.
Although the RDM agreement was scheduled to expire on December 31, 1993, the
NYPSC's June 10, 1994 decision extended the provisions of the agreement with
certain modifications more
10
Orange and Rockland Utilities, Inc. and Subsidiaries
fully described under "Rate Activities." The RDM agreement will continue to
affect future electric earnings from the Company's New York operations. Electric
earnings from the Company's New Jersey and Pennsylvania operations will continue
to be affected by changes in sales volumes resulting from the strength of the
economy, weather conditions and the conservation efforts of customers.
Sales for resale increased by 13.0% in 1994 after decreasing by 7.3% in 1993.
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 decreased
2.3% or $3.2 million in 1994 after increasing 2.4% or $3.2 million in 1993. The
components of these changes in electric energy costs are as follows:
Increase (Decrease) From Prior Year 1994 1993
==========================================================================
(Millions of Dollars)
Prices paid for fuel and purchased power $ (8.3) $ (1.8)
Changes in Kwh generated or purchased 3.1 4.7
Deferred fuel charges 2.0 .3
- --------------------------------------------------------------------------
Total $ (3.2) $ 3.2
- --------------------------------------------------------------------------
The decrease in electric energy costs in 1994 is primarily a reflection of
reduced prices paid for coal and natural gas used as boiler fuel, partially
offset by an increase in kilowatt hour demand. The increase in 1993 was
primarily due to the increase in kilowatt hour demand and coal prices, offset by
decreased purchased power cost and cost of natural gas used as boiler fuel.
The price paid for fuel and purchased power per kilowatt hour over the last
five years is shown in the accompanying table.[Graphics Chart, see Appendix A
of Exhibit 13]
The Company's tariff schedules include adjustment clauses under which fuel and
certain purchased power costs are recovered. In New York, an incentive-based
mechanism associated with the electric fuel adjustment clause provides for the
sharing of up to a 20% variation between actual costs and forecast fuel targets,
to a maximum of $1,762,000. In 1994, 1993 and 1992, pre-tax earnings were
enhanced by $1,241,000, $755,000 and $800,000, respectively, as a result of this
mechanism. 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. The Company's ability to burn coal and
natural gas has enabled it to reduce its use of fuel oil significantly. Energy
is purchased from other utilities whenever available, generally 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.
The sources of electricity available for sale during the last three years are
as follows:
1994 1993 1992
========================================================
Source of Electricity Sold:
Company generation:
Oil 6% 5% 10%
Natural gas 23 16 21
Coal 36 33 33
Hydro 3 4 3
Other supply:
Purchased power 32 42 33
- --------------------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------
GAS OPERATING REVENUES AND SALES
Gas operating revenues, net of gas purchased for resale, increased by 2.4%, or
$1.6 million, and 6.8%, or $4.3 million, for 1994 and 1993, respectively.
These changes are attributable to the following factors:
Increase (Decrease) From Prior Year 1994 1993
======================================================
(Millions of Dollars)
Sales to firm customers:
Base rates including misc. surcharges
and revenue tax recoveries $ .2 $ 5.7
Gas cost recoveries (.2) 13.8
Sales volume changes (.4) .1
- ------------------------------------------------------
Subtotal (.4) 19.6
Sales to interruptible customers 1.4 (.8)
Sales for resale .1 (1.8)
Other operating revenues (1.2) (.4)
- ------------------------------------------------------
Total gas revenues (.1) 16.6
Gas energy costs (1.7) 12.3
- ------------------------------------------------------
Net gas revenues $ 1.6 $ 4.3
- ------------------------------------------------------
Firm gas sales amounted to 20,421 million cubic feet (Mmcf) during 1994, a
decrease of .7% from the 1993 level of 20,556 Mmcf. Firm gas sales for 1992 were
20,507 Mmcf. Gas revenues from firm customers were $149.4 million, $149.8
million and $130.2 million in 1994, 1993 and 1992, respectively.
Gas sales to firm customers for the last five years are shown in the
accompanying table.[Graphics Chart, see Appendix A of Exhibit 13]
The changes in firm gas sales by class of customer from the prior year are as
follows:
1994 1993
======================================================
Residential (1.0%) .7%
Commercial and industrial .5% (2.2%)
- ------------------------------------------------------
Sales in 1994 were adversely affected by weather conditions in the fourth
quarter of 1994. The increase in the number of customers in 1994 and 1993
somewhat offset the decrease in sales in 1994, and was the primary reason for
the slight increase in sales in 1993.
Effective December 15, 1992, under the terms of a multi-year gas rate
agreement, the level of firm sales in New York is subject to a weather
normalization adjustment. The Company adjusts firm
11
1994 Annual Report
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. Therefore, weather
conditions will have a minimal impact on gas revenues.
Revenues from interruptible gas customers (customers with alternative fuel
sources) increased by 53.4% in 1994, after decreasing by 23.7% in 1993. These
sales are dependent upon the availability and price competitiveness of
alternative fuel sources. As a result of applicable tariff regulations, these
sales do not have a substantial impact on earnings.
GAS ENERGY COSTS
Utility gas energy costs decreased by 1.9%, or $1.7 million in 1994, after
increasing 15.8% or $12.3 million in 1993.
The changes in utility gas energy costs for the years 1994 and 1993 are a
result of the following:
Increase (Decrease) From Prior Year 1994 1993
===========================================================
(Millions of Dollars)
Prices paid to gas suppliers* $(2.7) $ 2.7
Firm and interruptible Mcf sendout 3.2 (2.1)
Deferred fuel charges (2.2) 11.7
- -----------------------------------------------------------
Total $(1.7) $12.3
- -----------------------------------------------------------
*Net of refunds received from gas suppliers.
The Company continues its policy of the aggressive use of market purchases in
order to provide price flexibility, while assuring an adequate supply of gas
through a variety of long-term contracts with pipeline suppliers.
The price paid for purchased gas per thousand cubic feet (Mcf) over the last
five years is shown in the accompanying table.[Graphics Chart, see Appendix A
of Exhibit 13]
Gas costs from 1990-1993 were adversely affected by the actions of the Federal
Energy Regulatory Commission (FERC), which had authorized pipeline suppliers to
pass through take-or-pay costs. As required by the NYPSC in Case 88-G-062, the
Company has deferred a portion of these costs. As of December 31, 1994, $2.8
million of deferred take-or-pay charges and accrued interest remain on the books
of the Company. The Company is negotiating with the staff of the NYPSC to
recover the remainder of its incurred take-or-pay costs. The Company's gas costs
were not materially affected by take-or-pay charges in 1994.
As a result of the FERC's objective to restructure the gas transportation
industry to promote competition among gas suppliers and to ensure supply at the
lowest reasonable costs, the FERC, pursuant to Order No. 636, has authorized
pipelines to recover from their customers certain transition costs. The Company
currently estimates that its obligations for Order No. 636 transition costs will
total approximately $24.6 million. Approximately $11.1 million of these
transition costs have been billed to the Company. The Company is presently in
the process of recovering these costs from its customers.
On December 20, 1994, the NYPSC issued an order establishing the regulatory
and rate-making policies applicable to New York gas distribution utilities
resulting from the restructuring of the interstate natural gas industry under
FERC Order No. 636. The order provides mechanisms for recovery of transition
costs which the Company believes will allow it to fully recover the costs
imposed on it by the FERC's actions.
OTHER UTILITY OPERATING EXPENSES AND TAXES
A comparison of other operating expenses and taxes for utility operations is
presented in the following table:
Increase (Decrease) From Prior Year 1994 1993
======================================================
(Millions of Dollars)
Other operating expenses $ (.2) $12.5
Maintenance 1.1 .4
Depreciation & amortization 1.7 (.1)
Taxes 1.0 7.6
- ------------------------------------------------------
Total $ 3.6 $20.4
- ------------------------------------------------------
The costs of DSM programs, which decreased by $7.4 million in 1994, after
increasing by $8.0 million in 1993, were the primary causes of the changes in
other operating expenses in 1994 and 1993. These costs are recovered in revenues
on a current basis. Additionally, 1994, as well as 1993, was impacted by higher
operating expenses associated with increases in the cost of labor, materials and
services.
Maintenance costs increased 2.6% and 1.0% in 1994 and 1993, respectively. The
1994 increase was the result of increased maintenance of distribution plant,
while the 1993 increase was the result of slightly higher maintenance costs in
the production plants.
Depreciation and amortization expenses increased $1.7 million in 1994 after
decreasing $.1 million in 1993. The increase in 1994 was the result of normal
plant additions. The prior year's decrease was the result of the amortization of
certain excess depreciation reserves provided in the 1992 gas rate agreement.
Taxes other than income taxes increased $2.6 million and $3.5 million in 1994
and 1993, respectively. The increase in each year was primarily the result of
taxes associated with revenues and property taxes. Federal income tax expense
decreased $1.6 million in 1994, after increasing $4.1 million in 1993. 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 consist of gas marketing, gas production
and land development businesses conducted by its wholly owned non-utility
subsidiaries.
Revenues from diversified activities increased $57.8 million and $87.3 million
in 1994 and 1993, respectively. The increases in revenues over the last two
years are primarily the result of gas marketing revenues, which were favorably
impacted by increases in the number of customers and higher sales volumes.
Operating expenses, incurred by the non-utility subsidiaries, increased $58.1
million and $88.1 million in 1994 and 1993, respectively. These increases are
directly related to gas marketing
12
Orange and Rockland Utilities, Inc. and Subsidiaries
purchases which were $55.5 and $85.9 million higher in 1994 and 1993,
respectively. Other expenses of operation, maintenance, depreciation and taxes
increased $2.6 million and $2.2 million in 1994 and 1993, respectively.
Operating income from diversified activities decreased by $.3 million and $1.0
million in 1994 and 1993, respectively. The declines were primarily a result of
lower gross profit margins realized by the gas marketing subsidiary.
On January 23, 1995, the Company's wholly owned gas marketing subsidiary, O&R
Energy, Inc., signed a Letter of Intent with a wholly owned subsidiary of Shell
Gas Trading Company (Shell) to create a new full service natural gas services
and marketing company--NORSTAR Energy Limited Partnership--contingent upon
certain governmental approvals. Under the terms of the agreement, Shell will
contribute substantial firm gas supplies and other assets in exchange for
approximately a 27 percent limited partnership interest. O&R Energy, Inc. will
transfer its natural gas marketing business to the new venture in exchange for
approximately a 73 percent general partnership interest. The alliance of O&R
Energy, Inc.'s gas marketing and operations expertise with the commitment of
firm gas supplies from Shell will assure NORSTAR a strong capital structure and
increase the range of services available to support an aggressive expansion into
new markets.
In September 1994, the Company sharpened its focus on its core energy services
business by adopting a plan to sell the six radio broadcast properties operated
by one of its non-utility subsidiaries. The assets to be sold consist primarily
of radio broadcast licenses and operating plant and equipment. A contract for
the sale of two of the six broadcasting properties held by the subsidiary was
signed in January 1995. Non-binding offers on the remaining stations have been
received and are being evaluated. The sale of these assets is expected to be
completed by June 1, 1995. Although the final gain or loss which will result
from the sale of the properties cannot be determined at this time, the Company
does not believe, based on the sales and offers received to date, that the
disposition will have any material effect, either positive or negative, on the
Company's financial statements. For more information on this sale, refer to Note
1 of Notes to Consolidated Financial Statements.
OTHER INCOME AND DEDUCTIONS AND INTEREST CHARGES
Other Income and Deductions and Interest Charges decreased by $.6 and $ 5.6
million in 1994 and 1993, respectively. The decrease in 1994 resulted from
higher investigation and litigation expenses described under "Events Affecting
the Company" which reduced Other Income by $1.7 million net of taxes as compared
to the previous year. This decrease in income was somewhat offset by $.7 million
reduction in political expenditures and charitable contributions and a $.4
million improvement in the operating results from the Company's radio
broadcasting subsidiary. The decrease in Other Income in 1993 was primarily due
to the cost of the investigation incurred in that year.
Interest charges decreased $.2 million, or .7% in 1994, after decreasing $1.3
million, or 3.6%, in 1993. The 1994 and 1993 decreases are the result of
refinancing certain of the Company's long-term debt issues, taking advantage of
the lower interest rates available, somewhat offset by an increase in the cost
of short-term debt in 1994, after a decrease in such costs in 1993.
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 cost of the construction program and other
capital requirements for the years 1992-1994 are as follows:
1994 1993 1992
======================================================
(Millions of Dollars)
Construction expenditures $60.0 $54.0 $56.0
Retirement of long-term debt &
preferred stock-- net 4.1 1.5 (2.5)
- ------------------------------------------------------
Total $64.1 $55.5 $53.5
- ------------------------------------------------------
At December 31, 1994, the Company estimated the cost of its construction
program in 1995 to be $61.5 million and retirement of long-term debt and
preferred stock to be $20.8 million. The Company's capital requirements for 1995
will be met primarily with funds from operations, supplemented by the issuance
of short-term borrowings.
On August 31, 1994, the New York State Energy Research and Development
Authority (NYSERDA) issued, on behalf of the Company, $55 million of variable
rate Pollution Control Refunding Revenue Bonds (Orange and Rockland Utilities,
Inc. Projects), 1994 Series A due October 1, 2014 (1994 Bonds). The proceeds
from the issuance of the 1994 Bonds were used to refund, on October 1, 1994, the
$55 million NYSERDA 10 1/4% Pollution Control Revenue Bonds (Orange and Rockland
Utilities, Inc. Projects), 1984 Series. In anticipation of issuing the 1994
Bonds, the Company entered into an interest rate swap agreement in 1992.
Pursuant to the swap agreement, the Company will pay interest at a fixed rate of
6.09% to a swap counter party and will receive 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%.
Effective May 1, 1994 through October 31, 1994, all shares of common stock
purchased, under the Company's Dividend Reinvestment and Stock Purchase Plan
(DRP) and the Employee Stock Purchase and Dividend Reinvestment Plan (ESPP),
were original issue shares purchased from the Company. During that time, $3.9
million of common equity was generated through the issuance of approximately
120,000 shares of common stock under
13
1994 Annual Report
the Company's DRP and ESPP. Effective November 1, 1994, common stock acquired
under the DRP and ESPP is again being purchased on the open market. The Company
has been authorized by the NYPSC to issue through December 31, 1995, up to
750,000 shares original issue common stock under the DRP and ESPP, of which
692,798 shares were unissued at year-end.
The Company and its utility subsidiaries have available bank lines of credit
of $59 million and O&R Energy, Inc., a non-utility subsidiary of RECO, has a $15
million line of credit. Information regarding short-term borrowings during the
past three years is as follows:
1994 1993 1992
========================================================================
(Millions of Dollars)
Weighted average interest rate at year-end 6.4% 3.6% 3.7%
Amount outstanding at year-end $29.4 $46.2 $41.5
Average amount outstanding for year $31.3 $35.3 $23.9
Daily weighted average interest rate during year 4.5% 3.3% 3.8%
Maximum amount outstanding
at any month-end $42.9 $46.2 $41.5
- ------------------------------------------------------------------------
The current credit ratings of the Company's principal securities and its
commercial paper are as follows:
Duff & Phelps Fitch Moody's Standard &
Credit Rating Investors Investors Poor's
Company Service, Inc. Service Corp.
===========================================================================
Commercial paper D-1 F-2 P-2 A-2
First mortgage bonds A+ A- A3 A-
Unsecured debt A A- Baa1 A-
Preferred stock A- A- baa1 BBB+
- ---------------------------------------------------------------------------
During June 1994, Standard & Poor's Corporation, Moody's Investors Service,
and Fitch Investors Service, Inc. lowered their ratings on the Company's
securities. The major reasons cited for the downgrades included uncertainties
resulting from the ongoing investigations surrounding alleged financial
improprieties and the termination by the NYPSC of the Company's electric rate
proceeding which included a reduction in the targeted return on equity to 10.6%.
RATE ACTIVITIES
NEW YORK
On September 30, 1992, the NYPSC approved a four-year settlement agreement
(Settlement Agreement) in the Company's gas rate case (Case 92-G-0050). The
Settlement Agreement contained a weather normalization clause which
automatically adjusts rates to offset the effects of variations in gas sales
volumes resulting from weather from the level assumed for setting rates. The
Settlement Agreement provided for an overall rate of return of 10.26%, with a
return on common equity of 12.15%, including incentives of 50 basis points. On
September 1, 1993, the Company filed with the NYPSC the second stage adjustment
to gas rates pursuant to the Settlement Agreement. The requested increase in
annual gas revenues as a result of the second-stage adjustment was $3.8 million,
or 2.5%. Although the Settlement Agreement provided for an effective date for
this adjustment of January 1, 1994, the Company agreed to extend the effective
date until June 30, 1994, in connection with the ongoing investigations of
alleged financial improprieties. The effective date of this adjustment was
further extended until December 30, 1994 by NYPSC Order issued June 3, 1994.
On September 1, 1994, the Company filed a plan to implement the second-stage
rate adjustment on January 1, 1995 and to postpone the next adjustment to gas
rates to January 1, 1996. On September 19, 1994, the Company subsequently
requested the further postponement of the second-stage gas rate adjustment until
the Commission's investigation of alleged financial improprieties is concluded.
The purpose of the request was to combine the results of the investigation and
staged filings into a single rate change. On November 4, 1994, the NYPSC issued
an Order terminating the Settlement Agreement effective December 31, 1994. The
Order denied the Company the opportunity for rate adjustments in the third and
fourth years (1995 and 1996) of the Settlement Agreement. However, the Order
authorized the Company to continue to defer certain items under the second-stage
rate adjustment until the adjustment becomes effective and to defer all
previously authorized reconciliations through the end of 1994, pending review
and audit by the NYPSC Staff and the conclusion of the NYPSC's investigation of
alleged financial improprieties.
On January 29, 1993, the Company filed, with the NYPSC, for an increase in
electric rates of $17.1 million (4.8%) to be effective January 1, 1994.
The NYPSC accepted the Company's proposal for a two-month (November and
December 1993) temporary rate reduction of approximately $115,000 per month
related to any misappropriation of funds identified as a result of the
investigation. The Company voluntarily extended the temporary rate reduction
for a third month, through January 1994.
As a result of the ongoing investigation of alleged financial improprieties,
the NYPSC issued an Order on December 21, 1993 which resulted in the
postponement of the effective date of new electric rates from January 1, 1994
until June 30, 1994.
By Order issued June 10, 1994 (June Order), the electric rate application was
terminated by the NYPSC. The June Order provided for the continuation of the RDM
revenue reconciliation and operating cost adjustment procedures and the
continuation of other provisions of the December 16, 1993 Order, including up to
$3.0 million of revenue made subject to refund, a 5% net resource savings DSM
incentive, and elimination of a customer service incentive. The June Order also
provided for a reduction in the RDM adjustment factor effective July 1, 1994,
reflecting the new recovery level required for 1993 net RDM deferrals. Finally,
the June Order reduced the return on equity threshold for measuring excess
earnings from 12.0% to 10.6%, effective retroactively to January 1, 1994. All
earnings in excess of 10.6% are to be deferred for future disposition pending
the conclusion of the ongoing investigation.
14
Orange and Rockland Utilities, Inc. and Subsidiaries
On September 19, 1994, the Company filed an appeal with the Supreme Court of
New York challenging the legality of the June Order. The appeal argues that by
changing the targeted return on common equity from 11.45% to 10.6% for the first
six months of 1994, the Commission engaged in retroactive rate-making. The
appeal also argues that there is no evidence in the record to support a
determination that the cost of equity is 10.6%. The Company and the NYPSC have
agreed to stay the briefings in this appeal until after the NYPSC has issued its
final report on its investigation of the Company.
On November 10, 1994, the Company filed, with the NYPSC, a quantification of
the rate-making effects of its ongoing investigation into prior financial
improprieties. The Company requested the NYPSC approve an additional refund of
approximately $3.4 million to its New York electric and gas customers. Although
the NYPSC has not acted on this request, this amount was charged to operations
in the fourth quarter of 1994. The NYPSC has instituted a proceeding (Case
93-17-0849) to provide the opportunity for other parties, including NYPSC Staff
who are conducting an independent investigation, to be heard on this matter. On
November 18, 1994, NYPSC Staff submitted to the Company a draft report of its
investigation of the Company for factual verification. This draft report does
not include the NYPSC Staff's estimate of the inappropriate costs that have been
borne by the Company's ratepayers. Such an estimate will be included in the
final versions of the report. On January 11, 1995, the Company submitted its
response to this draft report. The Company is unable to predict the final
results of this proceeding and what modifications, if any, will be made to the
amount proposed to be refunded.
NEW JERSEY
In January 1992, in response to RECO's March 18, 1991 petition requesting a
$12.9 million increase in base rates, an increase in electric rates of $5.1
million was granted by the New Jersey Board of Regulatory Commissioners (NJBRC).
The NJBRC was renamed effective July 5, 1994 and is now the New Jersey Board of
Public Utilities (NJBPU). This increase included a 12% rate of return on common
equity. In addition, the NJBRC initiated a Phase II proceeding in this case to
address the effect of the State of New Jersey's June 1, 1991 tax legislation.
That legislation changed the procedure under which certain taxes are collected
from the State's utilities. Previously, utilities had been subject to a 12.5%
gross receipts and franchise tax, which the utilities paid in lieu of property
taxes. The new tax is based upon the number of units of energy (kwh or therms)
delivered by a utility rather than revenues. The legislation also required that
utilities accelerate payment to the State of the taxes collected. As a result,
RECO was required to make additional tax payments of approximately $16 million
during the period 1993-1994. On November 12, 1992, the NJBRC issued a Decision
and Order approving the recovery of the additional tax over a ten-year period. A
carrying charge of 7.5% on the unamortized balance was also approved. The amount
of unamortized accelerated payments is included in Deferred Revenue Taxes.
On February 26, 1993, the New Jersey Department of Public Advocate, Division
of Rate Counsel (Rate Counsel) filed a Notice of Appeal from the NJBRC Decision
and Order with the Superior Court of New Jersey, Appellate Division, stating as
grounds for the appeal that the Decision is arbitrary and capricious and would
result in unjust and unreasonable rates. On March 21, 1994, the Superior Court
of New Jersey, Appellate Division, upheld the NJBRC Decision, stating the NJBRC
used proper rate-making principles.
Under an agreement with the NJBPU to return to customers any funds found to be
misappropriated as a result of an ongoing investigation of certain former
officers and employees, RECO has refunded to New Jersey ratepayers $93,000
through reductions in the applicable fuel adjustment charges in February and
March 1994. In December 1994, RECO submitted a proposal to the NJBPU to refund
an additional $.7 million. By order dated January 27, 1995, the NJBPU approved
this proposal ordering the refund to be made in February 1995. The NJBPU
investigation into these matters is continuing and the Company is unable to
predict what modifications, if any, will be made to the amount to be refunded.
On November 3, 1993, the NJBRC (now the NJBPU), commenced its periodic
management audit of RECO. As a result of the events and investigations described
above, the NJBPU audit included, in addition to a standard review of operating
procedures, policies and practices, a review of the posture of RECO management
regarding business ethics and a determination regarding the effect of such
events on RECO ratepayers. The NJBPU's draft findings are contained in its
"Final Report on An Ethics Review of Rockland Electric Company" (Docket No. EA
90030248) dated December 1, 1994, a copy of which was provided to the Company
for comment. On January 11, 1995, the Company submitted its comments to this
audit report to the NJBPU. The NJBPU has not yet issued its final report.
PENNSYLVANIA
On November 19, 1992, Pike County Light & Power Company (Pike) filed, with the
PPUC, for a $497,000 increase in electric rates and a $36,300 increase in gas
rates. During April 1993, Pike and the other parties involved in this proceeding
signed a stipulated agreement providing for an increase of $270,000, or 6.6% for
electric rates and $12,000, or 1.5% for gas rates. On June 10, 1993, the PPUC
approved the electric rate settlement with rates effective June 11, 1993. On
June 24, 1993, the PPUC approved the gas rate settlement with rates effective
June 25, 1993. With regard to the ongoing investigation into the alleged
financial improprieties, Pike has pledged to return to ratepayers any funds
discovered to have been misappropriated due to the financial improprieties of
certain former officers and employees who are the subject of an ongoing
investigation.
15
1994 Annual Report
COMPETITION
The Company is operating in an increasingly competitive environment. In the
electric industry, the Energy Policy Act of 1992 (Act) permitted unregulated
non-utility generating companies to sell wholesale electric power in competition
with regulated utilities. The Act also required utilities to provide access to
others, under certain conditions, to the utilities' electric transmission
systems. Although the Act does not require utilities to deliver their
competitors' power directly to retail customers, state regulators retain the
right to allow retail competition. Regulatory agencies in the three states in
which the Company has retail electric franchises are currently evaluating
possible changes in regulatory and ratemaking practices designed to promote
increased competition consistent with safety, reliability and affordability
standards. Depending on future developments in this area, the Company's market
share and profit margins could become subject to competitive pressures in
addition to traditional regulatory constraints.
The Company recognizes that the regulated utility environment is changing and
is committed to remaining competitive in its core energy services business and
to capitalizing on new market opportunities. The Company's strategy for meeting
the challenges of increased competition focuses on improving service while
reducing costs. The Company has adopted an aggressive cost reduction program and
is currently evaluating the pricing of services provided to customers. In
addition, the Company's marketing function has been restructured to identify
growth opportunities and strengthen customer relations by improving the value of
energy services offered. Another component of the strategy is to actively
participate, with regulators and others, in developing a transition to a more
competitive environment which provides for an equitable sharing of
environmental, social, regulatory and taxation obligations among all parties, as
well as a reasonable opportunity for utilities to recover past investments and
expenditures made pursuant to their obligation to provide service to the public.
Competition in the Company's gas business has existed for several years, with
interruptible customers and customers with alternative fuel usage capacity
having the option to obtain their own gas supply and transport it through the
Company's distribution system. In addition, FERC Order No. 636, which
deregulated much of the interstate pipeline industry, has enabled the Company to
contract directly with gas producers for supplies of natural gas. The Company is
successfully meeting the challenge of competition in the gas business by taking
advantage of the opportunities provided in this rapidly changing business
environment to obtain greater access to reasonably priced natural gas supplies
and storage. The Company has developed customized supply and flexible pricing
arrangements to provide value-added service to its gas customers and is actively
seeking new marketing opportunities.
OTHER DEVELOPMENTS
SFAS NO. 119
In October 1994, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 119 "Disclosure About Derivative
Financial Instruments and Fair Value of Financial Instruments (SFAS No. 119),
which requires various disclosures about financial instruments and related
transactions. This statement revises previously issued statements related to
disclosure of financial instruments, namely SFAS No. 105 and SFAS No. 107, to
include disclosure of derivatives. For the Company, financial instruments
consist principally of cash and cash equivalents, short-term debt, commercial
paper, long-term debt and redeemable preferred stock. The disclosures required
by SFAS No. 119 are contained in Note 9 of the Notes to Consolidated Financial
Statements.
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
historic costs and do not recognize the impact of inflation.
16
Orange and Rockland Utilities, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF
INCOME AND RETAINED EARNINGS
Year Ended December 31,
1994 1993 1992
==================================================================================================
(Thousands of Dollars)
OPERATING REVENUES:
Electric (Note 1) $ 472,393 $480,553 $456,768
Gas (Note 1) 157,168 157,257 140,679
Electric sales to other utilities 6,636 6,414 6,965
- --------------------------------------------------------------------------------------------------
Total Utility Revenues 636,197 644,224 604,412
Diversified activities (Note 1) 380,705 322,925 235,660
- --------------------------------------------------------------------------------------------------
Total Operating Revenues 1,016,902 967,149 840,072
- --------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Operations:
Fuel used in electric production (Note 1) 84,860 74,480 85,005
Electricity purchased for resale (Note 1) 49,391 62,969 49,245
Gas purchased for resale (Note 1) 88,305 89,984 77,700
Non-utility gas marketing purchases 365,917 310,467 224,579
Other expenses of operation 152,200 149,604 134,253
Maintenance 44,011 42,861 42,474
Depreciation and amortization (Note 1) 35,862 34,056 34,014
Taxes other than income taxes 95,964 93,610 90,371
Federal income taxes (Notes 1 and 2) 24,540 26,225 22,679
- --------------------------------------------------------------------------------------------------
Total Operating Expenses 941,050 884,256 760,320
- --------------------------------------------------------------------------------------------------
INCOME FROM OPERATIONS 75,852 82,893 79,752
- --------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Investigation and litigation costs (Note 12) (8,795) (6,139) --
Other-- net (Note 1) (530) (1,703) 200
Taxes other than income taxes (123) (94) (97)
Federal income taxes (Notes 1 and 2) 4,250 3,525 895
- --------------------------------------------------------------------------------------------------
Total Other Income and Deductions (5,198) (4,411) 998
- --------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES 70,654 78,482 80,750
- --------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt 29,105 30,147 32,158
Other interest 3,088 2,404 2,416
Amortization of debt premium and expense -- net 1,244 1,116 364
- --------------------------------------------------------------------------------------------------
Total Interest Charges 33,437 33,667 34,938
- --------------------------------------------------------------------------------------------------
NET INCOME 37,217 44,815 45,812
Dividends on preferred and preference stock, at required rates 3,251 3,364 3,478
- --------------------------------------------------------------------------------------------------
Earnings applicable to common stock 33,966 41,451 42,334
Cash dividends on common stock: $2.54, $2.49 and $2.43 34,486 33,694 32,589
- --------------------------------------------------------------------------------------------------
Balance to retained earnings (520) 7,757 9,745
Retained earnings, beginning of year 184,179 176,422 166,677
- --------------------------------------------------------------------------------------------------
Retained earnings, end of year $ 183,659 $184,179 $176,422
==================================================================================================
Average number of common shares outstanding (000's) 13,594 13,532 13,438
- --------------------------------------------------------------------------------------------------
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING $ 2.50 $ 3.06 $ 3.15
==================================================================================================
The accompanying notes are an integral part of these statements.
17
1994 Annual Report
CONSOLIDATED BALANCE SHEETS
December 31,
1994 1993
=========================================================================================================
(Thousands of Dollars)
ASSETS:
UTILITY PLANT:
Electric $ 951,019 $ 931,827
Gas 198,755 189,000
Common 55,445 52,525
- ---------------------------------------------------------------------------------------------------------
Utility Plant in Service 1,205,219 1,173,352
Less accumulated depreciation 398,584 372,279
- ---------------------------------------------------------------------------------------------------------
Net Utility Plant in Service 806,635 801,073
Construction work in progress 49,654 30,907
- ---------------------------------------------------------------------------------------------------------
Net Utility Plant (Notes 1, 7, 11 and 12) 856,289 831,980
- ---------------------------------------------------------------------------------------------------------
NON-UTILITY PROPERTY:
Non-utility property 34,585 35,049
Less accumulated depreciation, depletion and amortization 13,977 13,041
- ---------------------------------------------------------------------------------------------------------
Net Non-utility Property (Notes 1 and 7) 20,608 22,008
- ---------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents (Notes 8 and 9) 16,081 14,256
Temporary cash investments (Note 9) 1,839 1,447
Customer accounts receivable, less allowance for uncollectible
accounts of $2,200 and $2,026 44,105 60,289
Accrued utility revenue (Note 1) 27,273 23,017
Other accounts receivable, less allowance for uncollectible
accounts of $209 and $102 17,384 11,577
Gas marketing accounts receivable, less allowance for
uncollectible accounts of $327 and $471 58,470 49,248
Materials and supplies (at average cost):
Fuel for electric generation 9,309 8,951
Gas in storage 11,544 13,413
Construction and other supplies 16,983 16,698
Prepaid property taxes 19,327 18,414
Prepayments and other current assets 28,877 22,212
- ---------------------------------------------------------------------------------------------------------
Total Current Assets 251,192 239,522
- ---------------------------------------------------------------------------------------------------------
DEFERRED DEBITS:
Income tax recoverable in future rates (Notes 1 and 2) 73,261 75,468
Extraordinary property loss - Sterling Nuclear Project (Notes 1 and 3) 10,139 15,481
Deferred Order No. 636 transition costs (Notes 1 and 12) 13,480 21,500
Deferred revenue taxes (Note 1) 16,888 17,588
Deferred pension and other postretirement benefits (Notes 1 and 10) 10,505 7,277
IPPsettlement agreements (Notes 1 and 12) 17,821 4,300
Unamortized debt expense (amortized over term of securities) 10,493 8,565
Other deferred debits 32,328 37,284
- ---------------------------------------------------------------------------------------------------------
Total Deferred Debits 184,915 187,463
- ---------------------------------------------------------------------------------------------------------
TOTAL $1,313,004 $1,280,973
=========================================================================================================
18
Orange and Rockland Utilities, Inc. and Subsidiaries
December 31,
1994 1993
=========================================================================================================
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES:
CAPITALIZATION:
Common stock (Note 5) $ 68,265 $ 67,660
Premium on capital stock (Note 5) 133,595 130,313
Capital stock expense (6,116) (6,108)
Retained earnings (Note 4) 183,659 184,179
- ---------------------------------------------------------------------------------------------------------
Total Common Stock Equity 379,403 376,044
- ---------------------------------------------------------------------------------------------------------
Non-redeemable preferred stock 42,844 42,844
Non-redeemable cumulative preference stock 424 443
- ---------------------------------------------------------------------------------------------------------
Total Non-redeemable Stock (Note 5) 43,268 43,287
- ---------------------------------------------------------------------------------------------------------
Redeemable preferred stock (Note 6) 2,774 4,158
- ---------------------------------------------------------------------------------------------------------
Long-term debt (Notes 7 and 9) 359,622 380,266
- ---------------------------------------------------------------------------------------------------------
Total Capitalization 785,067 803,755
- ---------------------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES:
Reserve for claims and damages (Note 1) 4,713 3,830
Postretirement benefits (Note 10) 15,625 6,719
Pension costs (Note 10) 39,854 34,275
Obligation under capital leases (Note 11) 275 793
- ---------------------------------------------------------------------------------------------------------
Total Non-current Liabilities 60,467 45,617
- ---------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Long-term debt and lease obligation due within one year(Notes 7, 9 and 11) 19,910 1,463
Preferred stock to be redeemed within one year (Note 6) 1,384 1,384
Notes payable (Notes 8 and 9) -- 1,200
Commercial paper (Notes 8 and 9) 29,400 45,000
Accounts payable 63,855 57,359
Gas marketing accounts payable 71,913 54,247
Dividends payable 725 752
Customer deposits 5,669 5,807
Accrued Federal income and other taxes 5,949 9,586
Accrued interest 8,608 9,877
Refundable gas costs 7,554 8,967
Refunds to customers 10,265 793
Other current liabilities 16,127 16,321
- ---------------------------------------------------------------------------------------------------------
Total Current Liabilities 241,359 212,756
- ---------------------------------------------------------------------------------------------------------
DEFERRED TAXES AND OTHER:
Deferred Federal income taxes (Notes 1 and 2) 173,317 172,672
Deferred investment tax credits (Notes 1 and 2) 17,109 18,004
Accrued Order No. 636 transition costs (Note 12) 13,480 21,500
Accrued IPP settlement agreements (Notes 1 and 12) 8,000 --
Refundable fuel costs (Note 1) 10,366 4,405
Other deferred credits 3,839 2,264
- ---------------------------------------------------------------------------------------------------------
Total Deferred Taxes and Other 226,111 218,845
- ---------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 12) -- --
- ---------------------------------------------------------------------------------------------------------
TOTAL $1,313,004 $1,280,973
=========================================================================================================
The accompanying notes are an integral part of these statements.
19
1994 Annual Report
CONSOLIDATED CASH FLOW STATEMENTS
Year Ended December 31,
1994 1993 1992
==================================================================================================
(Thousands of Dollars)
CASH FLOW FROM OPERATIONS:
Net Income $37,217 $44,815 $45,812
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 35,938 34,571 34,317
Deferred Federal income taxes (Note 2) (188) (39) 6,593
Deferred investment tax credit (Note 2) (895) (963) (1,132)
Deferred and refundable fuel and gas costs 4,548 7,802 (6,388)
Allowance for funds used during construction (517) (276) (430)
Other non-cash changes 6,042 (8,055) 3,855
Changes in certain current assets and liabilities:
Accounts and gas marketing receivables, net
and accrued utility revenue (3,101) (17,286) (14,509)
Materials and supplies 1,226 (737) 743
Prepaid property taxes (913) (1,066) (1,085)
Prepayments and other current assets (6,665) (3,983) 2,453
Operating and gas marketing accounts payable 24,162 19,407 2,210
Accrued Federal income and other taxes (3,637) 4,911 1,506
Accrued interest (1,269) 779 (1,108)
Refunds to customers 9,472 753 (114)
Other current liabilities (332) 2,336 1,712
Other-- net 16,402 4,814 (5,687)
- --------------------------------------------------------------------------------------------------
Net Cash Provided by Operations 117,490 87,783 68,748
- --------------------------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES:
Additions to plant (60,542) (54,308) (56,438)
Temporary cash investments (392) (569) (878)
Allowance for funds used during construction 517 276 430
- --------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (60,417) (54,601) (56,886)
- --------------------------------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from:
Issuance of common stock (Note 5) 3,868 -- 7,589
Issuance of long-term debt (Note 7) 55,000 75,000 55,000
Retirement of:
Preference and preferred stock (Note 6) (1,384) (1,384) (1,384)
Long-term debt (57,688) (75,091) (51,159)
Capital lease obligations-- net (Note 11) (479) (443) (410)
Net borrowings (repayments) under short-term debt
arrangements (Note 8) (16,800) 4,700 11,500
Dividends on preferred and common stock (37,765) (37,086) (36,093)
- --------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (55,248) (34,304) (14,957)
- --------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 1,825 (1,122) (3,095)
Cash and Cash Equivalents at Beginning of Year 14,256 15,378 18,473
- --------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $16,081 $14,256 $15,378
- --------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest, net of amounts capitalized $33,134 $32,012 $35,497
Federal income taxes $21,558 $27,020 $14,450
==================================================================================================
The accompanying notes are an integral part of these statements.
20
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. (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. 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 non-utility subsidiaries are wholly owned land development, gas
marketing and gas production companies.
RATE REGULATION
The Company's utility operations are subject to rate regulation by the New
York Public Service Commission (NYPSC), the New Jersey Board of Public Utilities
(NJBPU), the Pennsylvania Public Utility Commission (PPUC) and the FERC. The
financial statements of the Company are based on generally accepted accounting
principles, including the provisions of Statement of Financial Accounting
Standards 71 (SFAS 71), "Accounting for the Effects of Certain Types of
Regulation," which give recognition to the rate-making and accounting practices
of these agencies. The principal effect of the rate-making process on the
Company's financial statements is that of the timing of the recognition of
incurred costs. If rate regulation provides reasonable assurance that an
incurred cost will be recovered in a future period by inclusion of that cost in
rates, SFAS 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, 1994 and 1993:
1994 1993
===============================================================================
(Thousands of Dollars)
Deferred Income Taxes (Note 2) $ 73,261 $ 75,468
Extraordinary Property Loss (Note 3) 10,139 15,481
FERC Order No. 636 Costs (Note 12) 13,480 21,500
Deferred Revenue Taxes (Note 1) 16,888 17,588
Deferred Pension and Other
Postretirement Benefits (Note 10) 10,505 7,277
Gas Take-or-Pay Costs (Note 12) 2,837 3,635
Revenue Decoupling Mechanism (Note 1) 1,295 10,293
Deferred Plant Maintenance Costs (Note 1) 4,699 3,488
Demand-Side Management Costs (Note 1) (96) 1,544
Deferred Fuel Costs (Note 1) (10,366) (4,405)
IPP Settlement Agreements (Note 1) 17,821 4,300
Other 7,255 4,400
- -------------------------------------------------------------------------------
Total $147,718 $160,569
- -------------------------------------------------------------------------------
UTILITY REVENUES
Utility revenues are recorded on the basis of cycle billings rendered to
certain customers monthly and others bi-monthly. Unbilled revenues are accrued
at the end of each month for estimated energy usage since the last meter
reading.
Under the Company's Revenue Decoupling Mechanism agreement (RDM), New York's
electric revenues are recognized in the accompanying financial statements based
on established targets. The RDM also provides for the reconciliation of
Demand-Side Management (DSM) expenditures and the adjustment of certain
operating costs. Any variation between actual results and the established
targets are deferred and recovered from or returned to customers over a
subsequent twelve-month period. Customer service performance incentives or
penalties which were discontinued by the NYPSC in 1994 and demand-side
management incentives, as detailed in the Agreement, are recognized as earned.
Effective December 1, 1992, 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 shortfalls or excesses of firm net revenues during a
heating season due to variation from normal weather, which is the basis for
projecting base tariff requirements.
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 to customers.
A reconciliation of 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 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 overhead, 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.
21
1994 Annual Report
DEPRECIATION
For financial reporting purposes, depreciation is computed on the
straight-line method based on the estimated useful lives of the various classes
of property. Provisions for depreciation are equivalent to the following
composite rates based on the average depreciable plant balances at the beginning
and end of the year:
Year Ended December 31, 1994 1993 1992
=====================================================
Plant Classification:
Electric 3.05% 3.04% 3.04%
Gas 2.80% 2.68% 3.59%
Common 6.37% 6.07% 5.88%
- -----------------------------------------------------
The composite gas depreciation rate, excluding the effect of adjustments
provided for in a 1992 gas rate agreement with the NYPSC, amounted to 3.10% in
1994 and 3.01% in 1993.
JOINTLY-OWNED UTILITY PLANT
The Company has a one-third interest in the 1,200 megawatt Bowline Point
generating facility, which it owns jointly with Consolidated Edison Company of
New York, Inc. The Company is the operator of the joint venture. Each
participant is entitled to its proportionate share of the energy produced. The
operating and maintenance expenses of the facility are shared proportionately,
based on the energy received from the plant by the partners.
Under this agreement, each co-owner has an undivided interest in the facility
and is responsible for its own financing. The Company's interest in this
jointly-owned plant consists primarily of the following:
Year Ended December 31, 1994 1993
===========================================================
(Thousands of Dollars)
Electric Utility Plant in Service $98,171 $97,753
Construction Work in Progress $ 2,984 $ 1,124
- -----------------------------------------------------------
FEDERAL INCOME TAXES
The Company and its subsidiaries file a consolidated Federal income tax
return, and income taxes are allocated to its subsidiaries based on the taxable
income or loss of each.
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 Company adopted Statement of Financial Accounting Standards No. 109 (SFAS
No. 109) "Accounting for Income Taxes" on January 1, 1993, which requires a
change from the deferred method to the asset and liability method of accounting
for income taxes. SFAS No. 109 retains the requirement to record 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 representing the probable future rate recoveries for additional
deferred tax liabilities. The probable future rate recoveries (revenues) to be
recorded take into consideration the additional future taxes which will be
generated by that revenue. Deferred taxes are also provided on temporary
differences of the Company's non-regulated subsidiaries, which are charged to
expense rather than offset by regulatory assets. The balance of deferred tax
assets and liabilities as of January 1, 1993, the date of implementation of SFAS
No. 109, was $69.6 million. The components of deferred tax assets and
liabilities as of January 1, 1993, are as follows; Liabilities: Accelerated
Depreciation -- $63.5 million, Other Liabilities -- $12.1 million; Assets:
Employee Benefits -- $(6.4) million, and Deferred Fuel Costs -- $.4 million.
DEFERRED REVENUE TAXES
Deferred revenue taxes represent the unamortized balance of an accelerated
payment of New Jersey Gross Receipts and Franchise Tax required by legislation
enacted effective June 1, 1991. In accordance with an order by the NJBPU, the
expenditure has been deferred and is being recovered in rates, with a carrying
charge of 7.5% on the unamortized balance, over a ten-year period. In addition,
certain New York State revenue taxes included in rate base are deferred and
amortized over a twelve-month period following payment in accordance with the
requirements of the NYPSC.
IPP SETTLEMENT AGREEMENTS
During 1994, the Company negotiated termination agreements with two of the
three Independent Power Producers (IPP) scheduled to provide electric generating
capacity and energy services to the Company in the late 1990's. The Company is
presently negotiating for a similar arrangement with the remaining IPP, Wallkill
Generating Company, L.P. (Wallkill Generating). As of December 31, 1994, $17.8
million of contract termination charges have been deferred in accordance with
regulatory accounting orders pending a determination of the recoverability of
the costs in rates. On January 24, 1995, the NJBPU authorized the recovery of
$.9 million over a period of twelve months for the portion of one of the
settlement agreements applicable to the Company's New Jersey electric
operations. A decision on the recovery of the remaining $16.9 million, as well
as any additional charges associated with the ongoing negotiation, will be
addressed in future rate proceedings before the NYPSCand NJBPU. Management
believes that these $16.9 million of termination costs were prudently incurred
and therefore should be fully recoverable in rates.
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 period. The NJBPU has not as yet
acted on the Company's petition.
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.
22
Orange and Rockland Utilities, Inc. and Subsidiaries
SALE OF BROADCAST PROPERTIES
On September 8, 1994, the Company adopted a formal plan to sell the six radio
broadcast properties operated by a wholly owned indirect subsidiary, Atlantic
Morris Broadcasting, Inc. In January 1995, a contract was signed for the sale of
two of the six broadcasting properties. Non-binding offers have been received
for the remaining stations. The sale of the properties is anticipated to be
completed on or before June 1, 1995. Although the final gain or loss which will
result from the sale of the properties cannot be determined at this time, the
Company does not believe, based on the sales and offers received to date, that
the disposition will have any material effect on the Company's financial
statements. Operating results of $(484,000), $(804,000) and $(960,000) for the
years ended December 31, 1994, 1993, and 1992, respectively, for the radio
broadcast properties are included in Other Income and Deductions in the
accompanying Consolidated Statements of Income and Retained Earnings. Net assets
of $6.9 million consisting principally of radio broadcast licenses and operating
plant and equipment are included at book value in the accompanying Consolidated
Balance Sheets.
RECLASSIFICATIONS
Certain amounts from prior years have been reclassified to conform with the
current year presentation.
NOTE 2. FEDERAL INCOME TAXES.
The Internal Revenue Service (IRS) concluded its audits of the Company's tax
returns through 1989. All issues have been resolved, resulting in an immaterial
effect on the Company's results of operations. Presently, the IRS is examining
tax returns for 1990, 1991 and 1992; notification of their findings for these
years has not yet been received.
The components of Federal income taxes are as follows:
Year Ended December 31, 1994 1993 1992
==========================================================================================
(Thousands of Dollars)
Charged to operations:
Current $ 24,415 $26,332 $16,567
Deferred-net 262 86 6,384
Amortization of investment tax credit (137) (193) (272)
- ------------------------------------------------------------------------------------------
24,540 26,225 22,679
- ------------------------------------------------------------------------------------------
Charged to other income:
Current (3,042) (2,630) (244)
Deferred-net (450) (125) 209
Amortization of investment tax credit (758) (770) (860)
- ------------------------------------------------------------------------------------------
(4,250) (3,525) (895)
- ------------------------------------------------------------------------------------------
Total $ 20,290 $ 22,700 $ 21,784
- ------------------------------------------------------------------------------------------
Effective January 1, 1993, the Company adopted the provisions of SFAS No.
109. The adoption of SFAS No. 109 did not have a significant impact on the
results of current operations because of the recording of offsetting regulatory
assets for utility operations and the relatively minor impact from diversified
operations. The resulting cumulative effect of the change in accounting
principle of $(.1) million is included in 1993's results of operations. Fiscal
year 1992 was not restated to apply the provisions of SFAS No. 109. The deferred
tax expense for 1992 was the result of the following:
Pollution Control Facilities -- $1.5 million, Abandonment Loss --
Sterling -- $(1.5 million), Accelerated Tax Depreciation --$6.4 million,
Deferred Employee Benefits -- $(2.0 million), Deferred Fuel Costs -- $2.0
million and Other -- $.2 million.
The tax effect of temporary differences which gave rise to deferred tax
assets and liabilities are as follows:
As of December 31, 1994 1993
===============================================================
(Thousands of Dollars)
Liabilities:
Accelerated depreciation $177,362 $172,815
Other 30,111 30,216
- ---------------------------------------------------------------
Total liabilities 207,473 203,031
- ---------------------------------------------------------------
Assets:
Employee benefits (15,269) (14,417)
Deferred fuel costs (4,784) (2,707)
Other (14,103) (13,235)
- ---------------------------------------------------------------
Total assets (34,156) (30,359)
- ---------------------------------------------------------------
Net Liability $173,317 $172,672
- ---------------------------------------------------------------
Reconciliation of the difference between Federal income tax expenses and the
amount computed by applying the prevailing statutory income tax rate to income
before income taxes is as follows:
Year Ended December 31, 1994 1993 1992
=====================================================================================
(% of Pre-tax Income)
Statutory tax rate 35% 35% 34%
Reduction in computed taxes resulting from:
Amortization of investment tax credits (2) (1) (2)
Cost of removal (1) (2) (3)
Additional depreciation deducted for
book purposes 5 4 3
Other (2) (3) --
- ------------------------------------------------------------------------------------
Effective Tax Rate 35% 33% 32%
- ------------------------------------------------------------------------------------
On August 10, 1993, the Budget Reconciliation Act of 1993 was signed into
law. Among other things, the Act increased the corporate Federal income tax rate
to 35% from 34%, retroactive to January 1, 1993. Pursuant to the provisions of
SFAS No. 109, the Company adjusted its deferred tax and regulatory asset
balances during 1993 to reflect the higher rate. The impact of this rate change
was to increase the deferred tax liability by $7.6 million; however, because of
the recording of offsetting regulatory assets, the increase in income tax
expense was $.1 million.
NOTE 3. STERLING NUCLEAR PROJECT.
Costs associated with the Sterling Nuclear Project, which was abandoned in
1980, and in which the Company was a 33% participant, are recorded in Deferred
Debits -- Extraordinary Property Loss.
The Company has been authorized by the NYPSC to recover all costs associated
with the Sterling Nuclear Project. An annual amortization has been approved
which includes a return on investment equal to the Company's current overall
rate of return. Amortization of project costs applicable to New York operations
will be completed in approximately 15 months. The NJBPU had approved a
twenty-year amortization, which commenced June 23, 1982, of costs (excluding a
return on the unamortized balance) attributable to the Company's subsidiary,
RECO.
At December 31, 1994 and 1993, the unamortized Sterling Project costs which
have been approved for amortization and recovery, before reduction for deferred
taxes, amounted to $10.8 million and $16.5 million, respectively. Approximately
$4.7 million and $5.6 million of such recoverable costs at December 31, 1994 and
December 31, 1993, respectively, are attributable to RECO and are not subject to
an earned return on the unamortized balance.
23
1994 Annual Report
NOTE 4. RETAINED EARNINGS.
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, 1994 and 1993 was so restricted.
NOTE 5. CAPITAL STOCK OTHER THAN REDEEMABLE PREFERRED STOCK.
The table below summarizes the changes in Capital Stock, issued and
outstanding, for the years 1992, 1993 and 1994.
(B) (C)
Non-Redeemable Non-Redeemable
(A) Cumulative Cumulative
Common Preferred Preference Capital
Stock Stock Stock Stock
($5 par value) ($100 par value) (no par value) Premium
=====================================================================================================
Shares Amount* Shares Amount* Shares Amount* Amount*
- -----------------------------------------------------------------------------------------------------
Balance 1/1/92: 13,327,470 $66,637 428,443 $ 42,844 15,041 $490 $123,701
Sales 202,488 1,013 6,575
Conversions 1,233 6 (852) (28) 22
- -----------------------------------------------------------------------------------------------------
Balance 1/1/93: 13,531,191 67,656 428,443 42,844 14,189 462 130,298
Conversions 864 4 (599) (19) 15
- -----------------------------------------------------------------------------------------------------
Balance 1/1/94: 13,532,055 67,660 428,443 42,844 13,590 443 130,313
Sales 120,041 601 3,268
Conversions 817 4 (565) (19) 14
- -----------------------------------------------------------------------------------------------------
Balance 12/31/94: 13,652,913 $68,265 428,443 $ 42,844 13,025 $424 $133,595
- -----------------------------------------------------------------------------------------------------
Shares
Authorized 15,000,000 820,000 1,500,000
- -----------------------------------------------------------------------------------------------------
*(in thousands)
(A) At December 31, 1994, 19,147 shares of common stock were reserved for
conversion of preference stock.
(B) Non-Redeemable Preferred Stock (cumulative):
Par Value
------------------- Callable
Shares December 31, Redemption
Series Outstanding 1992, 1993 and 1994 Price Per Share
===================================================================
(Thousands of Dollars)
A,4.65% 50,000 $ 5,000 $104.25 at any time.
B,4.75% 40,000 4,000 $102.00 at any time.
D,4.00% 3,443 344 $100.00 at any time.
F,4.68% 75,000 7,500 $102.00 at any time.
G,7.10% 110,000 11,000 $101.00 at any time.
H,8.08% 150,000 15,000 $102.43 at any time.
- -------------------------------------------------------------------
428,443 $ 42,844
- -------------------------------------------------------------------
This stock is not subject to mandatory redemption, but rather is subject to
redemption 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.
(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.
NOTE 6. REDEEMABLE PREFERRED STOCK.
The table below summarizes the changes in Redeemable Cumulative Preferred
Stock, issued and outstanding, for the years 1992, 1993 and 1994.
($100 par value)
- ---------------------------------------------------------------
Shares Amount*
- ---------------------------------------------------------------
Balance 12/31/91: 83,106 $ 8,310
Redemptions (13,842) (1,384)
- ---------------------------------------------------------------
Balance 12/31/92: 69,264 6,926
Redemptions (13,842) (1,384)
- ---------------------------------------------------------------
Balance 12/31/93: 55,422 5,542
Redemptions (13,842) (1,384)
- ---------------------------------------------------------------
Balance 12/31/94: 41,580 $ 4,158
- ---------------------------------------------------------------
Shares Authorized 180,000
- ----------------------------------------------------
*(in thousands)
The Redeemable Cumulative Preferred Stock, Series I, 8 1/8%, is redeemable in
whole or in part at the option of the Company on 30 days' minimum notice at the
redemption price plus accrued and unpaid dividends to the date fixed for
redemption. The redemption price per share is $101 through January 1, 1997, and
$100 thereafter.
The preferred stock is superior to the cumulative preference stock and common
stock with respect to dividends and liquidation rights. A sinking fund provision
requires that the Company, on each December 31, call for the redemption and
retirement of 13,842 shares at $100 per share, provided, however, that the
Company will call for redemption and retire on December 31, 1997, the remaining
shares outstanding at the redemption price of $100 per share plus accrued and
unpaid dividends to the date fixed for redemption. The redemption requirement
for each of the three years following 1994 is as follows: $1,384,200 annually in
1995 and 1996 and $1,389,600 at maturity in 1997.
NOTE 7. LONG-TERM DEBT.
Under the terms of the Company's First Mortgage Indenture and the indentures
supplemental thereto, and relative to all series of First Mortgage Bonds, Orange
and Rockland Utilities (ORU) on May 1 of each year is required to make annual
sinking fund payments equal to 1% of the maximum amount of bonds outstanding
during the preceding calendar year. ORU has satisfied such requirements through
the year 1994 by allocating an amount of additional property and expects to
continue such practice in succeeding years. Pike is 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 1994 were satisfied by the allocation of
an amount of additional property and Pike expects to continue such practice in
succeeding years.
On August 31, 1994, the New York State Energy Research and Development
Authority (NYSERDA) issued, on behalf of the Company, $55 million of variable
rate Pollution Control Refunding Revenue Bonds (Orange and Rockland Utilities,
Inc. Projects), 1994 Series A due October 1, 2014 (1994 Bonds). The proceeds
from the issuance of the 1994 Bonds were used to refund, on October 1, 1994, the
$55 million NYSERDA 10 1/4% Pollution Control Revenue Bonds (Orange and Rockland
Utilities, Inc. Projects), 1984 Series issued on behalf of the Company. In
anticipation of
24
Orange and Rockland Utilities, Inc. and Subsidiaries
issuing the 1994 Bonds, the Company entered into an interest rate swap agreement
in 1992. Pursuant to the swap agreement, the Company will pay interest at a
fixed rate of 6.09% to a swap counter party and will receive a variable rate of
interest in return which is identical to the variable rate payment made on the
1994 Bonds. The result is to effectively establish a fixed rate of interest on
the 1994 Bonds of 6.09%.
Details of long-term debt at December 31, 1994 and 1993 are as follows:
December 31, 1994 1993
===============================================================================
(Thousands of Dollars)
Orange and Rockland Utilities, Inc.:
First Mortgage Bonds:
Series H, 4 7/8% due Aug. 15, 1995 $ 17,000 $ 17,000
Series I, 6 1/2% due Oct. 1, 1997 23,000 23,000
Promissory Notes (unsecured)
12.9% due through Feb. 15, 1996 25 42
10 1/4% due Oct. 1, 2014 -- 55,000
9% due Aug. 1, 2015 44,000 44,000
6.09% due Oct. 1, 2014 55,000 --
Debentures:
Series A, 9 3/8% due Mar. 15, 2000 80,000 80,000
Series B, 6 1/2% due Oct. 15, 1997 55,000 55,000
Series C, 6.14% due Mar. 1, 2000 20,000 20,000
Series D, 6.56% due Mar. 1, 2003 35,000 35,000
Rockland Electric Company:
First Mortgage Bonds:
Series C, 4 5/8% due Aug. 15, 1995 2,000 2,000
Series H, 9.59 % due July 1, 2020 20,000 20,000
Series I, 6% due July 1, 2000 20,000 20,000
Pike County Light & Power Company:
First Mortgage Bonds:
Series A, 9% due July 15, 2001 884 884
Series B, 9.95% due Aug. 15, 2020 1,800 1,800
Diversified Operations:
Mortgage (secured)
8 1/2% due through June 18, 1999 5,575 5,654
Secured Notes 8 1/2% due through Aug. 31, 1998 277 2,868
- -------------------------------------------------------------------------------
379,561 382,248
Less: Amount due within one year 19,392 984
- -------------------------------------------------------------------------------
360,169 381,264
Unamortized discount on long-term debt (547) (998)
- -------------------------------------------------------------------------------
Total Long-Term Debt $359,622 $380,266
- -------------------------------------------------------------------------------
The aggregate amount of debt maturities--all of which will be satisfied by
cash payments--and sinking fund requirements -- all of which will be satisfied
by the allocation of additional property -- for each of the five years
following 1994 is as follows:
1995 -- $19,631,200; 1996 -- $531,800; 1997 -- $78,194,500;
1998 -- $120,100; 1999--$4,905,500.
Substantially all of the utility plant and other physical property is subject
to the liens of the respective indentures securing the First Mortgage Bonds of
the Company and its utility subsidiaries.
Investments in the Company's wholly owned utility subsidiaries, costing
$11,828,700, which have been eliminated from the consolidated balance sheet,
are pledged under the Second Supplemental Indenture to the Company's First
Mortgage Indenture.
NOTE 8. 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, 1994, the Company and its utility subsidiaries had unsecured
bank lines of credit with ten commercial banks aggregating $59.0 million. In
most cases the annual fees equal to one-eighth of 1% are paid to the banks for
such lines of credit. 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, 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. In addition, O&R
Energy, Inc., a non-utility subsidiary of RECO, maintains a $15.0 million line
of credit with one commercial bank under which there were no borrowings
outstanding at December 31, 1994 and 1992. At December 31, 1993, there was $1.2
million outstanding under the O&R Energy, Inc. line of credit. There are no fees
associated with this line, and borrowings, made under the line are at a rate of
prime plus one-half percent.
All borrowings for 1994, 1993 and 1992 had maturity dates of three months or
less.
Information regarding short-term borrowings during the past three years is as
follows:
1994 1993 1992
=====================================================================
(Millions of Dollars)
Weighted average interest rate at year-end 6.4% 3.6% 3.7%
Amount outstanding at year-end $29.4 $46.2 $41.5
Average amount outstanding for the year $31.3 $35.3 $23.9
Daily weighted average interest rate
during the year 4.5% 3.3% 3.8%
Maximum amount outstanding at
any month-end $42.9 $46.2 $41.5
- ---------------------------------------------------------------------
NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS.
FINANCIAL ASSETS AND LIABILITIES
For the Company, financial assets and liabilities consist principally of cash
and cash equivalents, short-term debt, commercial paper, long-term debt and
redeemable preferred stock. 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 is as follows:
Cash and 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.
25
1994 Annual Report
Notes payable and Commercial paper--The carrying amount reasonably
approximates fair value because of the short maturity of those instruments.
Redeemable preferred stock--The fair value of the Company's redeemable
preferred stock is estimated based on the quoted market prices for the same or
similar issues.
1994 1993
=====================================================================
Carrying Fair Carrying Fair
Amount Amount Amount Amount
- ---------------------------------------------------------------------
(Thousands of Dollars)
Cash and cash equivalents $ 16,081 $ 16,081 $ 14,256 $ 14,256
Temporary cash investments 1,839 1,839 1,447 1,447
Long-term debt 379,561 371,730 382,248 408,497
Notes payable and commercial
paper 29,400 29,400 46,200 46,200
Redeemable preferred stock 4,158 4,136 5,542 5,732
- ---------------------------------------------------------------------
OFF BALANCE SHEET AND DERIVATIVE FINANCIAL INSTRUMENTS
In addition, the Company utilizes certain off balance sheet, derivative
financial instruments. Information regarding such instruments 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. The
purpose of the swap agreement, which became effective on October 1, 1994, was to
take advantage of the favorable interest rates which existed during 1992. Under
the terms of the 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 payment on the 1994
Bonds made pursuant to an indenture of trust dated August 15, 1994. 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,
1994, the Company would have been required to make a payment of approximately
$1,900,000 to the Swap counterparty.
Gas Futures Contracts--The Company's natural gas marketing subsidiary, O&R
Energy, Inc., enters into futures contracts and commodity price swap agreements
and purchases options to reduce exposure to changes in the price of natural gas.
These transactions are accounted for as hedges in accordance with SFAS No. 80
"Accounting for Futures Contracts." Gains and losses on futures contracts and
purchased options, and payments or receipts under swap agreements, are included
as part of revenue and recognized when the underlying gas is delivered to
customers.
Net futures contracts purchased and outstanding at December 31, 1994,
amounted to 257 contracts and the related margin deposits with brokers amounted
to $678,000. The underlying futures contracts are of varying durations, none of
which extend beyond November 1995. The Company would be required to pay
approximately $30,000 to settle these contracts at December 31, 1994. Deferred
losses at December 31, 1994, were not significant.
Swap transactions were entered into in order to eliminate the commodity price
risk relating to long-term fixed price sales commitments and variable price
purchase commitments. The swap agreements require payments to (or receipt from)
the broker based on the differential between a fixed and variable price for
natural gas. The swap agreements hedge 4.7 BCF of natural gas to be purchased
and delivered over the five years ended October 1999. The related margin
deposits at December 31, 1994, amounted to $1,600,000. Margin deposits consist
of cash and letters of credit. The Company would be required to pay
approximately $1,194,000 to settle these contracts at December 31, 1994.
NOTE 10. PENSION AND POSTRETIREMENT BENEFITS.
PENSION BENEFITS
The Company maintains a non-contributory defined benefit retirement plan,
covering substantially all employees. The plan calls for benefits, based
primarily on years of service and average career compensation, to be paid to
eligible employees at retirement. For financial reporting purposes, pension
costs are accounted for in accordance with the requirements of Statement of
Financial Accounting Standards No. 87 (SFAS No. 87), "Employers' Accounting for
Pensions."
SFAS No. 87 results in a difference in the method of determining pension
costs for financial reporting and funding purposes. Plan valuation for funding
and income tax purposes is prepared on the unit credit cost method, which makes
no assumptions as to future compensation levels. In contrast, the projected unit
credit cost method required for accounting purposes by SFAS No. 87 reflects
assumptions as to future compensation levels. The Company's policy is to fund
the pension costs determined by the unit credit cost method subject to the IRS
funding limitation rules. For rate-making purposes, pension expense determined
under SFAS No. 87 is reconciled with the amount provided in rates for pensions.
Any difference is deferred for subsequent recovery or refund.
Net periodic pension expense calculated pursuant to the requirements of SFAS
No. 87 for the years 1994, 1993 and 1992 includes the following components:
December 31, 1994 1993 1992
==================================================================
(Thousands of Dollars)
Service cost-benefits earned
during year $ 6,250 $ 5,690 $ 5,896
Interest cost on projected
benefit obligation 14,132 12,915 10,301
Actual return on plan assets 2,634 (19,383) (15,135)
Net deferral and capitalized (18,426) 5,014 4,397
- ------------------------------------------------------------------
Net Pension Expense $ 4,590 $ 4,236 $ 5,459
- ------------------------------------------------------------------
The following table sets forth, pursuant to the requirements of SFAS No. 87,
the plan's funded status and amounts recognized in the Consolidated Balance
Sheets at December 31, 1994 and 1993. Plan assets are stated at fair market
value and are composed primarily of common stocks and investment grade debt
securities.
26
Orange And Rockland Utilities, Inc. And Subsidiaries
December 31, 1994 1993
==============================================================================
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested $(154,980) $(153,730)
Nonvested (13,644) (9,758)
- ------------------------------------------------------------------------------
Accumulated benefit obligation $(168,624) $(163,488)
- ------------------------------------------------------------------------------
Projected benefit obligation $(181,625) $(180,176)
Plan assets at fair market value 172,835 182,810
- ------------------------------------------------------------------------------
Excess of plan assets over projected
benefit obligation (8,790) 2,634
Unamortized net transition asset at
adoption of SFAS No. 87 being amortized
over 15 years (7,795) (8,909)
Unrecognized prior service costs 35,425 28,528
Unrecognized net gain (49,137) (47,960)
- ------------------------------------------------------------------------------
Accrued Pension Cost $ (30,297) $ (25,707)
- ------------------------------------------------------------------------------
The expected long-term rate of return on plan assets, the weighted average
discount rate and the annual rate of increase in future compensation assumed in
determining the projected benefit obligation were 8%, 8.5% and 3.5%,
respectively for 1994. For the year 1993, the expected long-term rate of return
on plan assets, the discount rate and the annual rate of increase in future
compensation assumed in determining the projected benefit obligation were 8%,
7.75% and 4%, respectively.
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 who have
rendered at least 10 years of service are entitled to postretirement health care
coverage.
Effective January 1, 1994, the Company adopted the provisions of SFAS No. 112
"Employers' Accounting for Postretirement Benefits" which requires the
recognition, on an accrual basis of disability benefits provided to former or
inactive employees after employment, but before retirement. As a result, the
Company recorded a liability and regulatory asset of $.9 million during 1994.
Effective January 1, 1993, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 (SFAS No. 106), "Employers' Accounting
for Postretirement Benefits Other Than Pensions," which established the
accounting and financial reporting standards for postretirement benefits other
than pensions. SFAS No. 106 requires the Company to accrue the estimated future
cost of postretirement health and non-pension benefits during the years that the
employee renders the necessary service, rather than recognizing the cost of such
benefits after the employee has retired and when the benefits are actually paid.
Deferred accounting for any difference between the expense charge required under
SFAS No. 106 and the current rate allowance has been authorized by the NYPSC for
the Company's New York electric and gas operations. A similar procedure has been
adopted by the NJBPU for the operations in that state.
In December 1994, the NYPSC allowed the Company to start recovering SFAS No.
106 costs applicable to New York electric operations. Rate recovery of SFAS No.
106 costs applicable to the Company's New York gas and New Jersey electric
operations will be addressed in future rate filings.
In order to provide funding for active employees' postretirement benefits,
the Company has established Voluntary Employees' Beneficiary Association (VEBA)
trusts for collectively bargained employees and management employees.
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. In 1994, rate recoveries amounted to $3.5 million and
billings to others totaled $.5 million. The Company will begin funding the VEBA
trusts in 1995.
As permitted by SFAS No. 106, the Company has 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. The following table sets forth the plan's
funded status, reconciled with amounts recognized in the Company's financial
statements at December 31, 1994 and December 31, 1993:
1994 1993
==============================================================================
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Fully eligible active employees $(19,574) $(18,386)
Other active employees (25,248) (27,073)
Retirees (20,677) (20,337)
- ------------------------------------------------------------------------------
Total benefit obligation (65,499) (65,796)
Plan assets at fair value -0- -0-
- ------------------------------------------------------------------------------
Accumulated postretirement obligation in
excess of plan assets (65,499) (65,796)
Unrecognized experience net (gain) loss (736) 4,694
Unrecognized transition obligation 51,522 54,383
- ------------------------------------------------------------------------------
Accrued Postretirement Benefit Cost $(14,713) $ (6,719)
- ------------------------------------------------------------------------------
The components of net periodic postretirement benefit cost for the years
ended December 31, 1994 and 1993 are as follows:
1994 1993
==============================================================================
(Thousands of Dollars)
Service cost $ 1,817 $ 1,535
Interest cost 5,198 4,598
Return on plan assets -0- -0-
Amortization of transition obligation 2,861 2,861
Net losses/(gains) 553 -0-
Deferred and capitalized (4,480) (6,719)
- ------------------------------------------------------------------------------
Net Expense $ 5,949 $ 2,275
- ------------------------------------------------------------------------------
The calculation of the actuarial present value of benefit obligations at
December 31, 1994 assumes a discount rate of 8.5% and health care cost trend
rates of 8.5% for medical costs and 12% for prescription drugs in 1995,
decreasing through 2002 to a rate of 5.0%. If the health care trend rate
assumptions were increased by 1 percent, the accumulated postretirement benefit
obligation would be increased by approximately $6.6 million. The effect of this
change on the sum of the service cost and interest cost would be an increase of
$.9 million. 1993 assumed a discount rate of 7.75% and health care cost trend
rates of 9.0% for medical costs and 14% for prescription drugs in 1994,
decreasing through 2002 to a rate of 5.0%.
27
1994 Annual Report
OTHER
The Company and two of its wholly owned non-utility subsidiaries have
established a Subsidiary Equity Incentive Plan in which plan participants are
entitled to certain rights measured as Performance Units. Each Performance Unit
gives the plan participant the opportunity to receive an incentive award of 3-5%
of the net increase, subject to certain restrictions, in the value of the
Company's investment in the participating subsidiaries over its initial
investment.
Incentive awards granted during 1994 amounted to $.6 million. No incentive
awards were granted in 1993. As of December 31, 1994 and 1993, $1.1 million and
$1.5 million was reserved for future award grants.
NOTE 11. LEASES.
The Company maintains leases for certain property and equipment which meet
the accounting criteria for capitalization. As required by Statement of
Financial Accounting Standards No. 71 (SFAS No. 71), "Accounting for the Effects
of Certain Types of Regulation," the Company has recorded such leases on its
balance sheets. The amount of leased property included in the accompanying
Consolidated Balance Sheets, and the obligation associated with such leases at
December 31, 1994 and 1993 are as follows:
DECEMBER 31, 1994 1993
===============================================================================
(Thousands of Dollars)
Utility Plant--Electric $4,245 $4,245
Less accumulated amortization 3,452 2,973
- -------------------------------------------------------------------------------
Net Assets Under Capital Lease $ 793 $1,272
- -------------------------------------------------------------------------------
Noncurrent Liabilities $ 275 $ 793
Current Liabilities 518 479
- -------------------------------------------------------------------------------
Total Liabilities $ 793 $1,272
- -------------------------------------------------------------------------------
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 Consolidated Statements of Income and Retained Earnings.
The future minimum rental commitments under the Company's capital leases and
noncancellable operating leases are as follows:
NONCANCELLABLE
CAPITAL OPERATING
LEASES LEASES
===============================================================================
(Thousands of Dollars)
1995 $ 571 $ 6,238
1996 286 4,311
1997 -- 3,742
1998 -- 3,489
1999 -- 3,264
All years thereafter -- 28,841
- -------------------------------------------------------------------------------
Total 857 $ 49,885
--------------
Less amount representing interest 64
- -----------------------------------------------------------
Present value of net
minimum lease payments $ 793
- -----------------------------------------------------------
Rental expense for 1994, 1993 and 1992 was $5.3 million, $6.0 million and
$6.3 million, respectively.
NOTE 12. 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, accounts receivables, gas marketing
accounts receivables and an interest rate swap agreement. The Company places its
temporary cash investments with high quality 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.
With respect to gas marketing operations, the customer base consists of a large
diverse group of users of natural gas across the United States, with the
Company's credit risk being dependent on overall economic conditions. Regarding
the interest rate swap agreement, the Company does not use derivative financial
instruments for speculative purposes and is a counterparty in one swap agreement
related to the refinancing of $55 million of pollution control bonds. Therefore,
as of December 31, 1994, 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 AFUDC) of approximately $61.5 million
will be incurred during 1995. As a requirement of the Clean Air Act of 1990,
capital expenditures of $13.5 million are included in the above amount.
GAS SUPPLY AND STORAGE CONTRACTS
The Company has long-term contracts for firm supply, transportation and
storage of gas. The Company's gas purchase obligation under these contracts for
the five years following 1994 is as follows: 1995--$70,272,600;
1996--$72,406,800; 1997--$59,428,300; 1998--$61,193,200 and 1999--$63,043,300.
On August 7, 1987, the FERC issued an order authorizing pipeline suppliers to
pass through to local distribution companies (LDC's) take-or-pay costs resulting
from contract renegotiations with gas producers. The Company's total take-or-pay
liability is approximately $14.7 million. The Company has received refunds from
pipeline suppliers of approximately $2.4 million which it has applied against
this take-or-pay liability. The Company has been allowed by the NYPSC to pass
through 65% of these costs to customers while deferring the remaining amount
until the NYPSC concludes its review of each company in its jurisdiction. As of
December 31, 1994, the Company has deferred $2.8 million of these costs.
On April 8, 1992, the FERC issued Order No. 636. The Order required
significant changes to the structure of the natural gas industry, and more
specifically, to the manner in which pipelines provide service. Order No. 636
changed the manner in which the Company obtains its gas supplies by unbundling
the transportation, storage and supply services offered by interstate gas
pipelines into separate components. During 1993, the Company successfully
completed the process of acquiring its own gas supply and assumed direct
responsibility for its gas acquisition and transportation. While the FERC's
objective is to restructure the industry to promote competition among gas
suppliers to ensure supply at the lowest reasonable cost, there are significant
initial costs associated with the implementation of the
28
Orange And Rockland Utilities, Inc. and Subsidiaries
restructuring rule. Specifically, Order No. 636 authorizes pipelines to recover
from their customers certain transition costs resulting from implementation of
the rulemaking. The Company's four principal pipeline suppliers made filings
with the FERC during 1993 for approval of a portion of their restructuring
transition costs and allocation procedures to flow the approved costs through to
their customers. Through December 31, 1994, the Company has paid $11.1 million
of transition costs. The Company currently estimates that its remaining
obligation for Order No. 636 transition costs will be approximately $13.5
million. This estimate was determined from information provided in Order No. 636
FERC compliance filings by the Company's pipeline suppliers and from subsequent
transition cost filings. This estimate is subject to adjustment by the FERC in
its deliberations on these filings and any future filings by the suppliers and
the outcome of bankruptcy proceedings involving one of the Company's suppliers.
The Company has provided for the unpaid liability as of December 31, 1994 with
an offsetting charge to Deferred Transition Costs. On October 28, 1993, the
NYPSC instituted a generic proceeding to review the issues associated with Order
No. 636 restructuring. On December 20, 1994, the NYPSC issued Opinion No. 94-26
in this Proceeding. As a result, any transition costs resulting from FERC Order
No. 636 will be fully recoverable in gas rates to the extent such costs were
prudently incurred.
COAL SUPPLY CONTRACTS
The Company has one long-term contract and one short-term contract for the
supply of coal and two long-term contracts 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.
The Company's aggregate contract obligations for the supply and
transportation of coal, for each of the five years following 1994 is as follows:
1995--$33,132,900; 1996--$31,942,400; 1997--$31,495,300; 1998--$32,406,400;
1999--$32,716,600.
POWER PURCHASE AGREEMENTS
The Company has three long-term contracts with other utilities for the
purchase of electric generating capacity and energy. The contracts expire in
1995, 1998 and 2015. Total payments under these contracts were $5.0 million,
$4.6 million and $3.2 million during 1994, 1993 and 1992, respectively. At
December 31, 1994, the estimated future payments for capacity that the Company
is obligated to buy under these contracts for the five years following 1994 are
as follows:
Capacity
Year (Mw) Amount
=============================================================================
1995 260 $4,152,500
1996 300 4,452,700
1997 325 5,048,000
1998 300 1,031,000
1999 25 690,000
- -----------------------------------------------------------------------------
The purchase capacities shown in the above table are based on contracts
currently in effect and are exclusive of applicable energy charges.
The Company has a power sales agreement with an independent power producer,
(IPP) Wallkill Generating Company, L.P. (Wallkill Generating), to purchase 95 Mw
of capacity and associated energy. Under the terms of this agreement, purchases
were to commence by no later than January 1, 1997. In November 1994, the Company
notified Wallkill Generating to stop work on the proposed generating facility
and commenced buyout negotiations.
Wallkill Generating has threatened to file a lawsuit against the Company,
arguing that the Company had breached an implied duty of good faith and fair
dealing in connection with the development and permitting of the Wallkill
project. In support of this claim, Wallkill Generating cited, among other
things, an alleged conflict of interest involving a former Company officer who
prior to his retirement in October 1994 had directed the Company's activities
with respect to the Wallkill project. Wallkill Generating alleged that this
former officer had a financial and management interest in another IPP project.
Based on investigations to date, the Company believes that this interest on his
part had no effect on the Company's actions or decisions with respect to the
Wallkill project which the Company has independently determined is an uneconomic
source of power compared with other alternatives.
LEGAL PROCEEDINGS
INVESTIGATION AND RELATED LITIGATION
On February 7, 1994, the Company commenced an action entitled Orange and
Rockland Utilities, Inc. v. James F. Smith (Smith), in New York State Supreme
Court against its former Chief Executive Officer and Chairman of the Board of
Directors, who was terminated for cause by the Company's independent Directors
in October 1993. The action asserts claims against Mr. Smith for breach of his
fiduciary duties of loyalty and care, waste, conversion, fraud and unjust
enrichment based on misuse of Company assets and personnel and misappropriation
of Company funds for his own benefit or for other improper purposes, and failure
to maintain proper management controls or to properly supervise corporate
affairs and subordinate employees. Mr. Smith counterclaimed for benefits and
filed a motion demanding arbitration under his employment agreement with the
Company. On June 17, 1994, the court issued an Order granting Mr. Smith's motion
to compel arbitration. Under a second order dated August 10, 1994, the parties
have filed demands for arbitration of the claims asserted by the Company and by
Mr. Smith with the American Arbitration Association. Hearings are scheduled to
begin on May 15, 1995.
On August 26, 1993 the Company filed an action entitled Orange and Rockland
Utilities, Inc. v. Winikow et al., under the Federal Racketeer Influenced and
Corrupt Organizations Act (RICO), in the United States District Court, Southern
District of New York. The Company alleges that the defendants -- a former
Company Vice President, three other former Company employees and two vendors --
engaged in a conspiracy to divert monies from the Company through the submission
of false and fraudulent invoices in order to pay personal expenses of and/or to
provide personal services to the defendants. In addition, the Company alleges
that the defendants made various contributions to political candidates
consisting of money and services diverted from the Company. Accordingly, the
Company seeks treble damages as called for by the RICO statute, punitive
damages, attorneys' fees, interest and court costs. On December 19, 1994, the
Company filed a notice dismissing the action against three former Company
employees, two of whom had paid restitution to the Company, and one vendor. The
Company is continuing to pursue its claims against the former Vice President and
one vendor.
29
1994 Annual Report
On August 18, 1993, Feiner v. Orange and Rockland Utilities, Inc., a
purported ratepayer class action complaint against the Company, RECO, a former
Company Vice President and others, was filed in the United States District
Court, Southern District of New York. Plaintiffs alleged that the defendants
violated the Federal Racketeer Influenced and Corrupt Organizations Act (RICO)
and New York common law by using false and misleading information to obtain rate
increases from the NYPSC and used funds obtained from ratepayers in furtherance
of an alleged scheme to make illegal campaign contributions and other illegal
payments. On February 18, 1994, the Company filed a motion to dismiss this case,
which motion was granted on September 8, 1994, and the case was dismissed.
Plaintiff then filed a Notice of Appeal with the United States Court of Appeals
for the Second Circuit (the Second Circuit) appealing the District Court's
decision. Thereafter, the parties signed a Stipulation of Settlement dismissing
the appeal, which was approved by the Second Circuit on December 7, 1994. The
settlement recognizes the remedial measures already taken by the Company, pays
$75,000 towards the plaintiffs' attorneys fees and leaves the District Court
decision dismissing the case in effect.
On November 23, 1993, Gross v. Orange and Rockland Utilities, Inc. (Gross), a
purported shareholder class action complaint, was filed in the United States
District Court, Southern District of New York, and, on March 31, 1994, Bernstein
v. Orange and Rockland Utilities, Inc. and James F. Smith (Bernstein), also a
purported shareholder class action complaint, was filed in the same Court.
Plaintiffs in both actions alleged that various Securities and Exchange
Commission filings of the Company during certain periods in 1993 contained false
and misleading information, and thereby violated certain sections of the
Securities Act of 1933 (Gross) or the Securities Exchange Act of 1934
(Bernstein) by failing to disclose what the plaintiffs alleged was a "scheme" by
the Company to make illegal political payments and campaign contributions. On
November 3, 1994, the Company signed a settlement agreement in the Gross and
Bernstein actions, which settlement was subject to Court approval. On November
21, 1994, the Court consolidated the two cases, approved a notice, and
conditionally certified a class action for settlement purposes only. Notice to
the class was mailed and published at the end of November. The settlement was
approved by the Court on January 27, 1995. Pursuant to the settlement agreement,
the Company will create a settlement fund of $1.85 million, to be distributed on
a pro rata basis to members of the settlement class, and all claims of the
plaintiffs in both cases will be deemed resolved. The cross-claims of the
Company and James F. Smith in the Bernstein action were dismissed without
prejudice.
On August 31, 1993, Patents Management Corp. v. Orange and Rockland
Utilities, Inc., et al., a purported shareholder derivative complaint, was filed
in the Supreme Court of the State of New York, County of New York, against the
Company, most of the Company's Directors and several other named defendants by
an alleged shareholder of the Company. Plaintiff initially claimed that the
named Directors breached their fiduciary duties by condoning the alleged
wrongful acts of a former Vice President or failing to exercise appropriate
supervisory control over such former Vice President and later amended the
complaint to complain of other matters described in the Report of the Special
Committee (see "Events Affecting the Company"). Plaintiff requested that the
Court require the Directors to indemnify the Company against all losses
sustained by the Company as a result of the alleged wrongful acts. A Stipulation
of Settlement with regard to this case has been signed by the Company and the
plaintiff. Under its terms, the Company agrees to implement remedial measures
and provision is made for payment of plaintiff's attorneys fees. A hearing on
the proposed settlement is scheduled before the Court on February 23, 1995. If
approved by the Court, the Settlement will resolve all issues in this case.
On November 10, 1994, the Company filed with the NYPSC a quantification of
the rate-making effects of its ongoing investigation into prior financial
improprieties. The Company requested the NYPSC approve an additional refund of
approximately $3.4 million to its New York electric and gas customers. In
December 1994, a filing was made with the NJBPU proposing to refund
approximately $.7 million to the Company's New Jersey customers. By order dated
January 27, 1995, the NJBPU approved this refund. These amounts were charged to
operations in the fourth quarter of 1994. The NYPSC may conduct a proceeding to
provide the opportunity for other parties, including NYPSC Staff, which is
conducting an independent investigation, to be heard on this matter. The NJBPU
also is conducting an investigation. The Company is unable to predict the final
results of these proceedings and what modifications, if any, will be made to the
amount proposed to be refunded in New York and New Jersey.
OTHER LEGAL PROCEEDINGS
On May 11, 1993, an action was commenced against the Company by Hudson
Riverkeeper Fund, Inc. (Riverkeeper) in the United States District Court for the
Southern District of New York. In its complaint, Riverkeeper alleged that the
Company violated and continues to violate its SPDES Permit for its Lovett
Generating Station (Lovett) by failing to maintain cooling water intake
structures that reflect the best technology available for minimizing adverse
environmental impact. In addition, the complaint alleged that the Company failed
to submit a scope of work for entrainment studies required by its SPDES permit
(entrainment studies). The original complaint requested that the Court assess
civil penalties aggregating $22 million and order the Company to take steps to
insure that the cooling water intake structures at Lovett reflect the best
technology available for minimizing adverse environmental impact. On May 18,
1993, Riverkeeper amended its complaint against the Company by withdrawing its
entrainment studies allegation and reducing the amount of civil penalties sought
to approximately $11 million. On June 30, 1993, the Company filed its answer to
Riverkeeper's allegations. Thereafter, reflecting the Company's belief that
Riverkeeper's allegations have no legal merit, the Company filed a Motion for
Summary Judgment seeking the dismissal of this action. On October 21, 1993, the
Court issued a Memorandum and Order denying the Company's Motion for Summary
Judgment and ruling that the New York State Department of Environmental
Conservation (DEC) should be included as a party to this action. On January 14,
1994, a conference was held before Judge Brieant during which the DEC intervened
in this litigation as a designated plaintiff. On April 8, 1994, the parties
agreed to have engineers enter into discussions regarding modifications to the
Lovett plant's cooling water intake structures. These discussions continued
throughout 1994.
On January 15, 1993, the Company was served with a complaint naming the
Company as one of several defendants in Warwick Administrative Group, et al. v.
Avon Products, Inc. et al., which case was filed in the United States District
Court for the Southern District of New York. The allegations in this case stem
from an
30
Orange And Rockland Utilities, Inc. and Subsidiaries
Administrative Order for Remedial Design and Remedial Action issued on February
28, 1992 by the United States Environmental Protection Agency pursuant to
Superfund laws which impose liability upon entities who are identified as having
contributed hazardous wastes to a particular site requiring cleanup, including
generators and transporters of such wastes. The Order directs certain members of
the Warwick plaintiff group to implement a plan for the cleanup of the Warwick
Landfill site in Greenwood Lake, New York. The Warwick plaintiff group now
alleges that some defendants, including the Company, arranged to have hazardous
substances disposed of at the Warwick site and thus seeks to recover from the
defendants costs incurred and damages suffered in connection with the cleanup of
the site. An answer to the complaint, as amended, was filed by the Company on
February 23, 1993, denying all of the allegations in the amended complaint and
setting forth a number of affirmative defenses.
On September 25, 1991, the Company was named as one of several hundred third
party defendants in the United States v. Kramer, et al. and State of New Jersey
Department of Environmental Protection v. Almo Anti-Pollution Services, et al.,
which cases have been consolidated in the United States District Court for the
District of New Jersey, Camden Vicinage. The allegations in this action concern
the Helen Kramer Landfill site in Mantua, New Jersey, which operated from 1963
to 1981. Suit in this case was brought under Superfund laws. It is presently
unclear if any hazardous waste generated by the Company was transported to the
Helen Kramer Landfill site. At this time the Company does not believe this
action will have a material effect on the business or financial condition of the
Company.
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. Certain PRPs,
including the Company, signed an administrative consent order with NJDEP
requiring them to perform a removal action at the Borne site, which was
completed on June 22, 1992. The PRPs have entered into negotiations with the
NJDEP regarding the terms of an additional administrative consent order which
will obligate the PRPs, including the Company, to perform a remedial
investigation and feasibility study (RIFS) at the site. The results of this
study will 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 (NYSDEC) 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. The results of this investigation will determine what, if any,
remediation at the West Nyack site will be required. The Company does not
believe that this matter will have a material effect on the financial condition
of the Company.
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 May 25, 1994, the Company
entered into a tolling agreement by which the Metal Bank Group reserved its
right to file suit against the Company, while the Metal Bank Group and the
Company entered into discussions to determine the Company's involvement with the
Cottman Avenue site. These discussions continue. The RIFS has been completed and
submitted to the EPA for determination of what remedial measures will be
required at the Cottman Avenue site. The Company is unable at this time to
estimate the Company's share, if any, of past or future costs at this site.
On January 17, 1995, the Company was served with a summons in Michael Payran
v. Orange and Rockland Utilities, Inc. and James Donnery, a purported personal
injury action commenced in the Supreme Court of the State of New York. Plaintiff
seeks compensatory and punitive damages of $50 million as a result of injuries
sustained at the Company's Lovett power plant. Since the Company has not been
served with the complaint in this action, it cannot evaluate plaintiff's claims.
ENVIRONMENTAL
The Federal Comprehensive Environmental Response, Compensation and Liability
Act of 1980 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. The Company is a party to a number of administrative
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. Such proceedings are not, in the aggregate, material to the financial
condition of the Company.
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 are
required at all affected facilities effective January 1, 1995. Pursuant to New
York State attainment of ozone standards, nitrogen oxide (NOx) reductions must
be achieved by May 31, 1995.
The Company has two base load generating stations that burn fossil fuels that
will be impacted 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. However, installation of low NOx
burners at Lovett plant and operational modifications at Bowline plant are
required to meet NOx reduction levels for ozone attainment. Additional emission
monitoring systems have
31
1994 Annual Report
been installed at both facilities. The Company's construction expenditures for
this work are estimated to be approximately $28.7 million through 1995.
Approximately $15.2 million has been expended through 1994. Beginning with
calendar year 1994, Title V sources (Bowline Point and Lovett) are required to
pay an emission fee. Each facility's fees are based upon actual air emissions
reported to NYSDEC at a rate of approximately $25 per ton of air emissions for
calendar year 1994. The emission fee will be reevaluated by New York State
annually. The Company will continue to assess the impact of the Clean Air Act
Amendments of 1990 on its power generating operations as additional regulations
implementing these Amendments are promulgated.
To date, the Company has identified six former manufactured gas plant sites
which were owned and operated by the Company or its predecessors. The Company
may be named as a potentially responsible party 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 or consent orders entered
into by the Company regarding these sites.
The NYPSC has commenced a proceeding to consider the most economical method
of compliance with the Clean Air Act Amendments of 1990 by electric utilities in
New York State.
NOTE 13. SEGMENTS OF BUSINESS.
The Company defines its principal business segments as utility (electric and
gas) and diversified activities. The diversified segment includes the gas
marketing, gas production and land development.
Total utility revenue as reported in the Consolidated Statements of Income
and Retained Earnings 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.
Segments of Business
Year Ended December 31, 1994 1993 1992
==============================================================================
Operating Information: (Thousands of Dollars)
Operating revenues:
Sales to unaffiliated customers:
Electric $ 478,909 $ 486,842 $ 463,601
Gas 157,045 157,185 140,630
Intersegment sales:
Electric 120 125 132
Gas 123 72 49
- ------------------------------------------------------------------------------
Total Utility
Operating Revenues 636,197 644,224 604,412
Diversified activities 380,705 322,925 235,660
- ------------------------------------------------------------------------------
Total Operating Revenues $1,016,902 $ 967,149 $ 840,072
- ------------------------------------------------------------------------------
Operating income before
income taxes:
Electric $ 80,355 $ 89,243 $ 83,824
Gas 19,724 19,147 16,539
Diversified activities 313 729 2,067
- ------------------------------------------------------------------------------
Total Operating Income
Before Income Taxes 100,392 109,119 102,430
- ------------------------------------------------------------------------------
Income Taxes:
Electric 19,894 21,380 18,596
Gas 4,644 4,679 3,403
Diversified activities 2 167 679
- ------------------------------------------------------------------------------
Total Income Taxes 24,540 26,226 22,678
- ------------------------------------------------------------------------------
Total Income From
Operations $ 75,852 $ 82,893 $ 79,752
- ------------------------------------------------------------------------------
Other Information:
Identifiable assets:
Electric $ 960,143 $ 944,903 $ 839,122
Gas 214,933 219,508 182,943
Diversified activities 95,846 84,401 73,275
- ------------------------------------------------------------------------------
Total Identifiable Assets 1,270,922 1,248,812 1,095,340
Corporate assets 42,082 32,161 32,161
- ------------------------------------------------------------------------------
Total Assets $1,313,004 $1,280,973 $1,127,501
- ------------------------------------------------------------------------------
Depreciation expense:
Electric $ 29,161 $ 28,049 $ 27,076
Gas 5,940 5,349 6,404
Diversified activities 761 658 534
- ------------------------------------------------------------------------------
Total $ 35,862 $ 34,056 $ 34,014
- ------------------------------------------------------------------------------
Capital expenditures:
Electric $ 44,832 $ 39,441 $ 42,133
Gas 15,242 13,955 13,799
Diversified activities 468 912 506
- ------------------------------------------------------------------------------
Total $ 60,542 $ 54,308 $ 56,438
- ------------------------------------------------------------------------------
NOTE 14. SUMMARY OF QUARTERLY RESULTS OF OPERATIONS (UNAUDITED).
Earnings Earnings
Applicable Per
Income To Average
Operating From Net Common Common
Revenues Operations Income Stock Share
==============================================================================
QUARTER ENDED (Thousands of Dollars)
1994
March 31 $292,675 $24,165 $14,068 $13,255 $ .98
June 30 229,735 13,380 3,380 2,567 .19
September 30 239,214 25,615 16,382 15,570 1.14
December 31 255,278 12,692 3,387 2,574 .19
- ------------------------------------------------------------------------------
1993
March 31 $263,189 $23,958 $15,084 $14,243 $1.05
June 30 213,988 15,044 6,601 5,760 .43
September 30 236,402 26,391 17,312 16,471 1.22
December 31 253,570 17,500 5,818 4,977 .36
- ------------------------------------------------------------------------------
32
Orange and Rockland Utilities, Inc. and Subsidiaries
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 sheet of Orange and
Rockland Utilities, Inc. and Subsidiaries (a New York corporation) as of
December 31, 1994, and the related consolidated statements of income and
retained earnings and cash flows for the year then ended. 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 audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the 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 audit provides 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, 1994, and the
consolidated results of their operations and their cash flows for the year then
ended, in conformity with generally accepted accounting principles.
As discussed in Note 12 to the Consolidated Financial Statements under the
subheading Investigation and Related Litigation, the New York Public Service
Commission (NYPSC) and the New Jersey Board of Public Utilities (NJBPU) are
currently investigating, among other things, misappropriations of Company funds
by certain former employees and the impact on ratepayers. Although the Company
has completed its own investigation and has requested the NYPSC and the NJBPU to
approve additional refunds of $3.4 million and $.7 million, respectively, the
Company is unable to predict the final results of this proceeding and what
modifications, if any, will be made to the amounts proposed to be refunded.
Accordingly, no provision for any additional liability that may result from
these investigations has been made in the accompanying consolidated financial
statements.
As discussed in Notes 2 and 10 of the Consolidated Financial Statements, the
Company changed its method of accounting for income taxes and postretirement
benefits in 1993.
/s/ Arthur Andersen LLP
New York, New York
February 2, 1995
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
GRANT THORNTON LLP
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF ORANGE AND ROCKLAND UTILITIES,
INC. AND SUBSIDIARIES
We have audited the accompanying consolidated balance sheets of Orange and
Rockland Utilities, Inc. and Subsidiaries as of December 31, 1993, and the
related consolidated statements of income and retained earnings and cash flows
for each of the two years in the period ended December 31, 1993. 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, 1993, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles.
As more fully discussed in Note 12 (Legal Proceedings) to the Consolidated
Financial Statements, the Company and various state regulatory authorities are
currently investigating misappropriations of Company funds by certain former
employees and the impact on ratepayers. As a result of these improprieties,
several class action and derivative complaints have been filed against the
Company and others. Although the Company has refunded certain amounts to
ratepayers as of December 31, 1993, the ultimate outcome of the investigations
and litigation cannot presently be determined. Accordingly, no provision for any
additional liability that may result from these matters has been made in the
accompanying 1993 financial statements.
As discussed in Notes 2 and 10 of the Consolidated Financial Statements, the
Company changed its method of accounting for income taxes and postretirement
benefits in 1993.
/s/ Grant Thornton LLP
New York, New York
February 16, 1994
33
1994 Annual Report
OPERATING STATISTICS -- ELECTRIC
Year Ended December 31,
1994 1993 1992
=================================================================================================================
SOURCE OF ELECTRICITY (Mwh):
Generation -- net
Steam 3,282,416 2,720,897 3,083,852
Hydro 168,149 164,378 143,871
Gas Turbine 10,448 7,557 3,938
- -----------------------------------------------------------------------------------------------------------------
Total Net Generation 3,461,013 2,892,832 3,231,661
Purchases 1,574,015 2,054,253 1,532,105
Company Use and Unaccounted For (305,747) (354,806) (298,806)
- -----------------------------------------------------------------------------------------------------------------
Net Energy Sold 4,729,281 4,592,279 4,464,960
- -----------------------------------------------------------------------------------------------------------------
SALES (Mwh):
Residential 1,660,755 1,611,602 1,532,915
Commercial 2,049,265 2,018,240 1,986,048
Industrial 657,142 627,944 594,912
Public Street Lighting 27,836 27,705 27,538
Public Authorities 68,972 72,037 70,257
- -----------------------------------------------------------------------------------------------------------------
Total Sales to Customers 4,463,970 4,357,528 4,211,670
Other Utilities for Resale 265,311 234,751 253,290
- -----------------------------------------------------------------------------------------------------------------
Total Sales of Electricity 4,729,281 4,592,279 4,464,960
- -----------------------------------------------------------------------------------------------------------------
REVENUES (000's):
Residential $ 214,439 $ 211,082 $ 193,124
Commercial 212,214 212,240 202,523
Industrial 51,316 50,983 47,128
Public Street Lighting 4,939 4,967 4,880
Public Authorities 4,051 4,344 4,212
- -----------------------------------------------------------------------------------------------------------------
Total Revenues from Sales to Customers 486,959 483,616 451,867
Other Utilities for Resale 6,636 6,414 6,965
- -----------------------------------------------------------------------------------------------------------------
Total Revenues from Sales of Electricity 493,595 490,030 458,832
Other Electric Operating Revenues (14,566) (3,063) 4,901
- -----------------------------------------------------------------------------------------------------------------
Total Electric Operating Revenues $ 479,029 $ 486,967 $ 463,733
- -----------------------------------------------------------------------------------------------------------------
SYSTEM NET CAPABILITY AND PEAK (Kw):
Net Installed Capability at Time of Peak 1,013,500 1,013,500 1,011,000
Firm Purchases-- net 275,000 250,000 200,000
- -----------------------------------------------------------------------------------------------------------------
Total System Net Capability 1,288,500 1,263,500 1,211,000
- -----------------------------------------------------------------------------------------------------------------
NET PEAK LOAD 1,022,000 1,037,000 943,000
LOAD FACTOR .52 .51 .53
HEAT RATE -- Btu of Fuel per
Kwh Generated 10,772 10,683 10,600
ELECTRIC CUSTOMERS -- Year End 259,708 256,897 254,192
RESIDENTIAL CUSTOMER STATISTICS:
Average Annual Kwh Use 7,357 7,214 6,928
Average Annual Revenue per Kwh 12.91(cents) 13.10(cents) 12.60(cents)
Average Annual Bill Including Fuel $ 949.89 $ 944.82 $ 872.77
Average Annual Fuel Cost Recovery $ 188.74 $ 194.90 $ 192.76
=================================================================================================================
Year Ended December 31,
1991 1990
==========================================================================================
SOURCE OF ELECTRICITY (Mwh):
Generation -- net
Steam 3,506,037 3,805,705
Hydro 172,752 201,115
Gas Turbine 15,217 23,446
- ------------------------------------------------------------------------------------------
Total Net Generation 3,694,006 4,030,266
Purchases 1,150,460 891,313
Company Use and Unaccounted For (316,748) (329,181)
- ------------------------------------------------------------------------------------------
Net Energy Sold 4,527,718 4,592,398
- ------------------------------------------------------------------------------------------
SALES (Mwh):
Residential 1,597,571 1,496,284
Commercial 1,955,851 1,885,221
Industrial 576,046 574,456
Public Street Lighting 26,780 26,488
Public Authorities 73,455 71,221
- ------------------------------------------------------------------------------------------
Total Sales to Customers 4,229,703 4,053,670
Other Utilities for Resale 298,015 538,728
- ------------------------------------------------------------------------------------------
Total Sales of Electricity 4,527,718 4,592,398
- ------------------------------------------------------------------------------------------
REVENUES (000's):
Residential $ 196,031 $ 179,554
Commercial 196,409 186,423
Industrial 44,724 44,834
Public Street Lighting 4,732 4,686
Public Authorities 4,419 4,242
- ------------------------------------------------------------------------------------------
Total Revenues from Sales to Customers 446,315 419,739
Other Utilities for Resale 9,575 19,292
- ------------------------------------------------------------------------------------------
Total Revenues from Sales of Electricity 455,890 439,031
Other Electric Operating Revenues 1,265 2,506
- ------------------------------------------------------------------------------------------
Total Electric Operating Revenues $ 457,155 $ 441,537
- ------------------------------------------------------------------------------------------
SYSTEM NET CAPABILITY AND PEAK (Kw):
Net Installed Capability at Time of Peak 1,008,700 1,005,000
Firm Purchases-- net 175,000 152,000
- ------------------------------------------------------------------------------------------
Total System Net Capability 1,183,700 1,157,000
- ------------------------------------------------------------------------------------------
NET PEAK LOAD 1,001,000 922,000
LOAD FACTOR .51 .54
HEAT RATE -- Btu of Fuel per
Kwh Generated 10,441 10,486
ELECTRIC CUSTOMERS -- Year End 251,724 248,758
RESIDENTIAL CUSTOMER STATISTICS:
Average Annual Kwh Use 7,286 6,893
Average Annual Revenue per Kwh 12.27(cents) 12.00(cents)
Average Annual Bill Including Fuel $ 894.11 $ 827.20
Average Annual Fuel Cost Recovery $ 207.01 $ 209.92
==========================================================================================
34
Orange And Rockland Utilities, Inc. and Subsidiaries
OPERATING STATISTICS -- GAS
Year Ended December 31,
1994 1993 1992 1991 1990
======================================================================================================================
SOURCE OF GAS (Mmcf):
Purchased 47,618 41,983 47,070 46,438 52,013
Manufactured 38 21 22 15 14
Storage--net (906) 1,077 (450) 1,490 (565)
Used in Electric Production (24,847) (21,234) (24,141) (26,444) (30,741)
Company Use and Unaccounted For (432) (630) (549) (1,176) (634)
- ----------------------------------------------------------------------------------------------------------------------
Net Energy Sold 21,471 21,217 21,952 20,323 20,087
- ----------------------------------------------------------------------------------------------------------------------
SALES (Mmcf):
Residential 15,164 15,323 15,212 13,564 13,555
Commercial and Industrial 5,257 5,233 5,295 4,766 4,807
- ----------------------------------------------------------------------------------------------------------------------
Total Firm Sales 20,421 20,556 20,507 18,330 18,362
Interruptible 1,023 653 889 1,325 889
Other Utilities for Resale 27 8 556 668 836
- ----------------------------------------------------------------------------------------------------------------------
Total Sales of Gas 21,471 21,217 21,952 20,323 20,087
- ----------------------------------------------------------------------------------------------------------------------
REVENUES (000's):
Residential $ 112,759 $ 113,116 $ 97,646 $ 82,198 $ 82,139
Commercial and Industrial 36,676 36,707 32,541 27,811 27,849
- ----------------------------------------------------------------------------------------------------------------------
Total Revenues from Firm Sales 149,435 149,823 130,187 110,009 109,988
Interruptible 3,996 2,605 3,414 5,536 3,683
Other Utilities for Resale 203 105 1,950 1,999 2,404
- ----------------------------------------------------------------------------------------------------------------------
Total Revenues from Sales of Gas 153,634 152,533 135,551 117,544 116,075
Other Gas Revenues 3,534 4,724 5,128 5,143 1,636
- ----------------------------------------------------------------------------------------------------------------------
Total Gas Operating Revenues $ 157,168 $ 157,257 $140,679 $122,687 $117,711
- ----------------------------------------------------------------------------------------------------------------------
MAXIMUM DAILY CAPACITY AT
DEC. 31 (Mmcf):
Pipeline Suppliers 195.2 194.6 195.9 195.9 194.7
Propane Plants 30.6 30.6 30.6 30.6 30.6
- ----------------------------------------------------------------------------------------------------------------------
Total Maximum Daily Capacity 225.8 225.2 226.5 226.5 225.3
- ----------------------------------------------------------------------------------------------------------------------
MAXIMUM 24-HOUR SENDOUT (Mmcf) 206.0 191.3 160.0 167.0 165.2
HEATING DEGREE DAYS 5,522 5,791 5,771 5,106 4,918
GAS CUSTOMERS -- YEAR END 110,631 109,464 108,168 106,854 105,528
RESIDENTIAL CUSTOMER STATISTICS:
Average Annual Mcf Use 151.0 145.2 145.4 131.0 131.9
Average Annual Revenue per Mcf $ 7.44 $ 7.41 $ 6.44 $ 6.08 $ 6.09
Average Annual Bill Including Fuel $1,122.89 $1,075.86 $ 936.63 $ 797.09 $ 802.61
Average Annual Fuel Cost Recovery $ 622.72 $ 595.94 $ 500.42 $ 446.11 $ 458.11
======================================================================================================================
35
1994 Annual Report
FINANCIAL STATISTICS
Year Ended December 31,
1994 1993 1992 1991 1990
============================================================================================================================
COMMON STOCK DATA:
Earnings Per Average Common Share $ 2.50 $ 3.06 $ 3.15 $ 3.12 $ 3.54*
Dividends Declared Per Share $ 2.54 $ 2.49 $ 2.43 $ 2.37 $ 2.32
Book Value Per Share (Year End) $ 27.79 $ 27.79 $ 27.22 $ 26.33 $ 25.46
Market Price Range Per Share:
High $ 41 1/4 $ 47 1/2 $ 41 7/8 $ 39 $ 32 3/8
Low $ 28 3/8 $ 38 5/8 $ 32 3/8 $ 30 7/8 26 1/8
Year End $ 32 1/2 $ 40 5/8 $ 41 5/8 $ 38 5/8 $ 31 3/8
Price Earnings Ratio 13.00 13.28 13.21 12.38 8.86
Dividend Payout Ratio 101.60% 81.37% 77.14% 75.96% 65.54%
Common Shareholders at Year-End 23,299 24,328 25,696 25,989 26,424
Average Number of Common Shares
Outstanding (000's) 13,594 13,532 13,438 13,238 13,040
Total Common Shares Outstanding at
Year-End (000's) 13,653 13,532 13,531 13,327 13,132
Return on Average Common Equity 9.01% 11.16% 11.88% 12.13% 14.49%
- ----------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION DATA (000'S):
Common Stock Equity $ 379,403 $ 376,044 $ 368,321 $ 350,947 $ 334,317
Non-Redeemable Preferred Stock 43,268 43,287 43,306 43,334 43,365
Redeemable Preferred Stock 2,774 4,158 5,542 6,926 8,311
Long-Term Debt 359,622 380,266 380,202 376,839 371,660
- ----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 785,067 $ 803,755 $ 797,371 $ 778,046 $ 757,653
- ----------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION RATIOS:
Common Equity 48.33% 46.79% 46.19% 45.11% 44.13%
Non-Redeemable Preferred Stock 5.51% 5.38% 5.43% 5.57% 5.72%
Redeemable Preferred Stock .35% .52% .70% .89% 1.10%
Long-Term Debt 45.81% 47.31% 47.68% 48.43% 49.05%
- ----------------------------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA (000'S):
Operating Revenues $1,016,902 $ 967,149 $ 840,072 $ 727,783 $ 652,892
Operating Expenses $ 941,050 $ 884,256 $ 760,320 $ 650,707 $ 571,191
Operating Income $ 75,852 $ 82,893 $ 79,752 $ 77,076 $ 81,701
Net Income $ 37,217 $ 44,815 $ 45,812 $ 44,868 $ 49,839
Earnings Applicable to Common Stock $ 33,966 $ 41,451 $ 42,334 $ 41,277 $ 46,133
Net Utility Plant $ 856,289 $ 831,980 $ 814,686 $ 792,413 $ 765,287
Total Assets $1,313,004 $1,280,973 $1,127,501 $1,087,846 $1,039,006
Long-Term Debt Including
Redeemable Preferred Stock $ 362,396 $ 384,424 $ 385,744 $ 383,765 $ 379,971
Ratio of Long-Term Debt to Net Plant 44.4% 46.0% 47.0% 48.0% 51.3%
Ratio of Accumulated Depreciation to
Utility Plant in Service 33.1% 31.7% 30.7% 30.0% 29.3%
============================================================================================================================
*Includes non-recurring gain on sale of non-utility land of $0.55 per share.
36
ORANGE AND ROCKLAND UTILITIES, INC.
APPENDIX A TO EXHIBIT 13
FORM 10-K DECEMBER 31, 1994
The Review of the Company's Results of Operations and Financial
Condition, which is included in the Company's Annual Report to Shareholders
and is incorporated by reference in this Annual Report on Form 10-K, contains
certain graphic presentations of financial data which are presented in tabular
format as follows:
1. - Graph entitled "Electric Sales to Customers"
Year Millions of Mwh
1990 405
1991 423
1992 421
1993 436
1994 446
2. - Graph entitled "Costs per Kwh" shows the price paid for fuel and
purchased power on a per-kwh basis as follows:
Cost per Kwh of Fuel
Year and Purchased Power
1990 2.87 cents
1991 2.74 cents
1992 2.70 cents
1993 2.67 cents
1994 2.51 cents
3. - Graph entitled "Firm Gas Sales" shows firm gas sales to customers
as follows:
Year Millions of Mcf's
1990 18.4
1991 18.3
1992 20.5
1993 20.6
1994 20.4
4. - Graph entitled "Cost per Mcf" shows the price paid for purchased
gas as follows:
Cost per Mcf of
Year Gas Purchased
1990 $3.17
1991 $2.90
1992 $3.52
1993 $3.63
1994 $3.52
02309.lfh