<PAGE> 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-8369
CONNECTICUT ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Connecticut 06-0869582
(State or other jurisdiction of (I.R.S Employer
incorporation or organization) Identification No.)
855 Main Street
Bridgeport, Connecticut 06604
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code
(203) 579-1732
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock ($1 par value) New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
(Title of Class)
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Aggregate market value of the voting stock held by non-affiliates of the
registrant based on the closing price of such stock as of November 25, 1994:
$169,800,891
Class Outstanding at November 25, 1994
- - ------------------------------ --------------------------------
Common Stock, $1 par value 8,707,738
An index of exhibits to this Annual Report on Form 10-K may be found on
Page 17 hereof.
<PAGE> 2
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Connecticut Energy Corporation's 1994 Annual Report to
Shareholders are incorporated into Part II.
2. Portions of Connecticut Energy Corporation's Definitive Proxy Statement
dated December 14, 1994 are incorporated into Part III.
PART I
------
CONNECTICUT ENERGY CORPORATION
------------------------------
Item 1. Business
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The Connecticut Energy Corporation ("Company") is a public utility holding
company primarily engaged in the retail distribution of natural gas for
residential, commercial and industrial uses through its wholly owned subsidiary,
The Southern Connecticut Gas Company ("Southern"), a Connecticut public service
company. Southern's predecessor companies, New Haven Gas Company and The
Bridgeport Gas Company, were originally incorporated in Connecticut in 1847 and
1849, respectively. The Company is exempt from registration under the Public
Utility Holding Company Act of 1935.
Southern serves approximately 153,000 customers in Connecticut, primarily
in 22 towns, including the urban communities of Bridgeport and New Haven, in an
area along the southern Connecticut coast from Westport to Old Saybrook.
Southern is also authorized to lay mains and sell gas in an additional ten towns
in its service area, but does not currently provide any service to these towns.
As of September 30, 1994, the Company, through its subsidiary, had 572
full-time employees all of whom were employees of Southern. A breakdown of
Southern's revenues for the twelve months ended September 30, 1994 was 60.6%
residential, 21.1% commercial, 8.9% industrial and 9.4% interruptible and
other. Southern is the sole distributor of natural gas, other than bottled
gas, in Southern's service area. Oil and electricity compete with gas in most
industrial and commercial markets and for residential space and water heating.
In general, Southern's firm rates currently are lower than electric rates for
heating and, on average, are generally competitive with fuel oil. Southern's
gas sales are affected by seasonal factors, and it experiences higher revenues
during the winter months.
Customers
General. Southern provides two types of gas sales service to its on-system
customers--firm and interruptible. Firm service is provided to residential,
commercial and industrial customers who require a continuous gas supply
throughout the year. Interruptible service is available to those commercial and
industrial customers and multi-family residential dwellings that can switch
between natural gas and an alternate fuel. Southern provides transportation
service to certain commercial and industrial customers, on an interruptible
basis. The gas transported is owned by those commercial and industrial
customers. From 1990 through 1994, the average number of on-system customers
served by Southern grew from approximately 151,100 to 152,600.
Southern now serves Connecticut Light and Power Company's Devon generating
station in accordance with a Special Contract for the Transportation of Gas
("Special Contract"). Additionally, Southern has the Connecticut Department of
Public Utility Control's ("DPUC") approval to participate in the off-system
sales market. If gas supply is available after meeting on-system loads,
<PAGE> 3
Southern sells this supply to customers within Connecticut or in out-of-state
markets. These sales are on an interruptible basis, and the customers to which
these sales are made are not permanent customers of Southern.
Firm Sales. In 1994, firm sales represented approximately 91% of operating
revenues and approximately 66% of total gas throughput. Firm sales to
industrial customers are likely to constitute a smaller percentage of
Southern's future total sales due to the changing character of the local economy
and continuing regulatory developments affecting the natural gas industry. See
section entitled "Rates and Regulation".
Southern concentrates on customer additions that are the most cost-
effective to achieve. During the mid-1980s, when many residential family
developments were being constructed, Southern extended mains to those
developments, thereby adding groups of customers for heating as well as
appliance loads at a relatively low capital cost per customer. Over the past
three years, new construction has slowed dramatically, and Southern has focused
on adding load along its existing mains, which generally requires a lower
capital outlay. Less than 50% of the residences along Southern's mains heat
with natural gas, and the conversion of these homes to natural gas heat has
been a major factor in increased load growth during the current economic
slowdown.
Interruptible Sales, Transportation and Special Contract Services. Inter-
ruptible sales and transportation services are priced flexibly and competitively
versus the price of alternate fuels being paid by larger commercial and
industrial customers. Southern's interruptible sales fluctuate depending
primarily upon the relative prices of alternate fuels and natural gas as well as
the availability of gas not needed to serve firm customers.
In addition to interruptible sales, Southern transports, on an
interruptible basis, gas for delivery to certain large commercial and
industrial users. Because of recent regulatory developments, end-users can
contract more easily than in the past for transportation service on interstate
pipelines to transport natural gas supplies purchased from producers/suppliers,
rather than purchase gas solely from the local distribution company. In
Southern's service areas, gas is transported to the customers' premises through
a combination of interstate pipeline transportation and Southern's distribution
system.
Interruptible transportation revenues are considerably less than revenues
from gas sales because customers pay only a fee for the transportation service,
whereas gas sales revenues include the cost of gas sold.
Southern provides service to Connecticut Light and Power Company's Devon
generating station in accordance with rates as specified in the Special
Contract. Off-system sales are priced based upon the market situation versus
the cost of the available supply.
In 1994, interruptible sales, transportation and special contract services
represented approximately 9% of operating revenues and approximately 31% of
total gas throughput.
Combined interruptible sales and transportation services have generally
increased since 1988 because of (a) higher alternate fuel prices, (b) Southern's
ability to negotiate its interruptible prices under flexible pricing
arrangements, (c) changes in the regulatory environment which encouraged such
sales and (d) customers' increased desire for cost containment. See section
entitled "Rates and Regulation" for further discussion of Southern's flexible
pricing and margin sharing mechanism for on-system interruptible service. To
the extent Southern negotiates its monthly prices for interruptible services
below its monthly standard offering price, lower margins may result.
<PAGE> 4
Southern's average margins on transportation service are less than its
average margins on firm sales and are usually equal to or slightly less than its
average margins on interruptible sales.
The Company does not believe that the loss of any single customer or a few
customers would have a long-term, material adverse effect upon Southern's
business.
Marketing. Southern focuses its marketing efforts on three objectives: (1) to
increase the number of residential households using natural gas for heating and
hot water, (2) to improve system load factor by promoting additional
interruptible sales and (3) to increase sales to commercial and industrial
customers through the use of both traditional and off peak applications for
natural gas. Marketing programs emphasize growth from within the existing
distribution system and the addition of high load factor usage of natural gas
such as water heating, air conditioning and electric power generation.
In the residential heating market, 2,504 customers were added in 1994
compared to 1,865 in 1993 and 3,006 in 1992. New customer additions in 1994
increased by 34% from 1993. This was due to increased additions in the new
housing construction market and other marketing programs designed to counter
continued low oil prices and the slowly recovering Connecticut economy.
Residential conversions to natural gas accounted for 61% of total new customer
additions in 1994, compared to 80% in 1993 and 68% in 1992.
Less than 50% of the single family homes along existing mains presently
heat with natural gas. Southern's residential marketing efforts are focused
primarily on this market segment. Residential marketing programs for this group
included: (1) a conversion burner program; (2) a high-efficiency heating
program; (3) a trade ally program and (4) service contracts for natural gas
heating equipment. These programs use incentives to promote conversion to
natural gas. Southern also utilizes an employee incentive program to promote
conversions and an incentive program for heating customers to assist in
increasing the number of conversions to natural gas heat.
In the commercial and industrial sectors, emphasis is placed on adding both
new firm and interruptible sales. During 1994 Southern added slightly more
than 861,500 Mcf of new sales, up 14% from 1993 additions of approximately
754,000 Mcf. Firm sales accounted for approximately 75% of this total.
Marketing programs for commercial and industrial customers include: (1) a
program to promote the use of high efficiency space conditioning equipment; (2)
an interruptible sales program offering customers the option of financing new
equipment through Southern and (3) a conversion burner leasing program which
provides customers with a low-cost opportunity to switch to natural gas.
Sales to the cooling and cogeneration markets represent the potential for
increasing off peak natural gas usage. Continuing advances in natural gas
cooling technology along with environmental and operational advantages have made
natural gas cooling more competitive with conventional cooling in large and
small commercial buildings and in industrial process applications.
During 1994, Southern added 1,173 tons of natural gas cooling. This
represents almost 46,500 Mcf of new off peak load. Since 1991, Southern has
added 8,475 tons of natural gas cooling. Southern's marketing programs for
natural gas cooling and cogeneration utilize customized rebates to encourage
customer conversions.
Natural gas vehicles ("NGV") represent an emerging market opportunity to
increase off peak natural gas usage. Recently passed Connecticut legislation
should encourage increased use of natural gas for vehicles. Incentives provided
in this legislation include a 50% Connecticut tax credit for installation of
<PAGE> 5
natural gas fueling equipment and/or conversion equipment for vehicles. There
is currently an exemption from Connecticut's motor fuels tax for qualifying
fleets. This tax is presently 31 cents per gallon.
The Company is aggressively pursuing the NGV market. Southern has entered
into three agreements with customers to provide natural gas for motor vehicle
use: Southern New England Telephone Company ("SNET") is fueling 11 natural gas
vehicles at a SNET site near its New Haven corporate headquarters; the United
States Postal Service have converted 62 of its postal vehicles at its East Haven
office to natural gas and R.R. Donnelley & Sons Company will initially convert
4 of its heavy duty lift trucks to natural gas with the potential of adding 18
additional lift trucks.
Gas Supply. Southern's current long-term supply sources include: (1) Canadian
supplies purchased from Alberta Northeast Gas Limited ("Alberta Northeast") with
transportation on Iroquois Gas Transmission System, L.P. ("Iroquois"); (2)
transportation and storage services from Tennessee Gas Pipeline Company
("Tennessee") with direct purchase of supply from producers and marketers; (3)
transportation and storage services from Texas Eastern Transmission Corporation
("Texas Eastern") with direct purchase of supply from producers and marketers;
(4) transportation service from Algonquin Gas Transmission Company ("Algonquin")
of natural gas purchased from producers and marketers; (5) transportation and
storage service from CNG Transmission Corporation ("CNG Transmission"); (6)
transportation service from Transcontinental Gas Pipeline Corporation
("Transco"); (7) storage and transportation service from National Fuel Gas
Supply Corporation ("National Fuel") and (8) liquid and vapor supplies from
Distrigas of Massachusetts Corporation ("Distrigas"). These arrangements
result in gas deliveries into Southern's franchise territory through
interconnections with three interstate pipelines -- Algonquin, Iroquois and
Tennessee.
In addition to Southern's long-term arrangements to acquire firm gas
supplies, Southern purchases spot supplies and utilizes interruptible
transportation services from interstate pipeline companies.
Southern's supply, transportation and storage agreements require Southern
to pay a fixed demand charge regardless of the amount of gas transported or
stored. The Federal Energy Regulatory Commission ("FERC") regulates interstate
pipeline companies in connection with the rates charged to Southern for
transportation and storage of natural gas.
The following table shows Southern's sources of gas supply for the periods
indicated.
<TABLE>
<CAPTION>
Fiscal Year
Ended
September 30,
---------------------------------------
1994 1993 1992 1991 1990
(Millions of cubic feet) ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Algonquin.............. 53 229 2,521 5,476 7,518
Tennessee.............. 24 --- 1,873 2,249 4,546
Texas Eastern.......... --- 372 1,539 1,649 ---
Intercompany........... --- --- --- --- 111
Alberta Northeast...... 12,631 12,446 4,863 --- ---
Other (including LNG
and producers/marketers 18,586 15,731 15,491 12,942 10,974
------ ------ ------ ------ ------
Total .............. 31,294 28,778 26,287 22,316 23,149
------ ------ ------ ------ ------
Propane.................. --- 33 --- 2 113
Net Inventory Changes.... (388) (1,362) (1,345) --- (6)
Transportation........... 3,396 1,653 4,859 5,999 4,688
------ ------ ------ ------ ------
Total Throughput.... 34,302 29,102 29,801 28,317 27,944
====== ====== ====== ====== ======
</TABLE>
<PAGE> 6
Domestic Supply. Prior to 1992, Southern purchased sales service from
Tennessee, Texas Eastern and Algonquin, combined with a small amount of storage
service with Penn-York Energy Corporation, as well as a storage service through
Algonquin delivered on a "best efforts" basis. With the implementation of FERC
Order No. 636, Southern has converted these supply arrangements from a fully
bundled sale and storage service provided by interstate pipelines to unbundled
storage and transportation services.
On July 1, 1992, Southern converted its long-term sales contract with
Tennessee to firm transportation and firm storage services. Under the
transportation contract, Southern has 13,336,000 Mcf of pipeline capacity
available on an annual basis. Southern's storage contract with Tennessee
provided winter storage of 1,174,000 Mcf annually. Due to FERC Order No. 636,
the storage contract was unbundled into a storage contract and a transportation
contract both effective September 1, 1992. These contracts expire in the year
2000. Another contract with Tennessee provides 516,000 Mcf of firm
transportation annually.
Southern has firm storage service from National Fuel. The gas which is
stored is later delivered under a firm transportation agreement with Tennessee
and provides 150,000 Mcf of winter season supply. The storage and
transportation contracts extend through 1995.
On June 1, 1993, Texas Eastern's former sales service was converted to a
firm transportation service. This service provides for 5,972,000 Mcf of
pipeline capacity on an annual basis. Additionally, Texas Eastern provides
1,383,000 Mcf of storage service and 12,108,000 Mcf of transportation service
on an annual basis formerly provided as sales service through Algonquin. The
majority of the storage gas was purchased in place in fiscal 1993. These
contracts expire in the year 2012.
Southern has a storage service contract with CNG Transmission under which
Southern has 100 days of storage service available, or 648,000 Mcf annually.
The storage gas is transported by Texas Eastern and Algonquin under firm
transportation contracts. The remaining contract term is 18 years. Under other
contracts, CNG Transmission provides 773,000 Mcf of annual firm storage service
and 1,028,000 Mcf of annual transportation service. This gas is stored by CNG
Transmission and is delivered to Southern under transportation contracts with
Texas Eastern and Algonquin.
Algonquin now furnishes only transportation services to Southern. The
deliveries which Algonquin makes to Southern are gas supplies transported by
other pipelines interconnected to Algonquin.
The increased natural gas storage capabilities acquired through the
restructuring process have impacted Southern's operations. Southern's storage
capacity is used to enhance security of supply and reduce dependence on the
production of liquefied natural gas ("LNG") and propane.
Additionally, much of the transportation and storage service through Texas
Eastern and Algonquin and a nominal amount of transportation service from
Tennessee is "no notice" transportation, which allows Southern to meet sudden
and dramatic shifts in demand and assures reliability to meet customer
requirements.
Southern also has multiple purchase agreements with producers and marketers
for firm supply behind its storage and transportation agreements. These
agreements range from 365 day availability of supply to 90 day peaking supply,
with terms ranging from one year to seven years. Southern pays a monthly
reservation charge, but has no monthly purchase obligation under these
agreements. Commodity prices are tied to pricing indices showing current prices
by supply areas.
Canadian Supply. In January 1992, Southern began receiving Canadian supply
under its long-term contracts with Alberta Northeast with firm transportation on
Iroquois. These firm supply contracts with Alberta Northeast provide Southern
with 12,775,000 Mcf of firm Canadian supply annually. These services were
largely unaffected by FERC Order No. 636, although Iroquois became an open
<PAGE> 7
access transporter effective September 1, 1993. Supply agreements with Alberta
Northeast have remaining terms of 9 to 13 years, and the transportation
agreement with Iroquois has a remaining term of 17 years.
Supplemental Supply. Southern has an agreement with Distrigas to purchase on
a firm basis 328,000 Mcf annually, effective November 1992. This contract
continues for eight years and includes provisions for either vapor or liquid
delivery, with an option to increase the maximum daily delivery over the term of
the contract. Additionally, Southern has an interruptible purchase contract
with Distrigas.
Southern uses gas from its LNG and propane facilities to meet peak winter
demand requirements, including the demands of a design year -- a year as cold as
the coldest in the past 30 years. Southern has additional offsite propane
storage and has contracts with Distrigas to obtain supplies to refill its LNG
storage tank.
FERC Order No. 636. FERC Order No. 636 compliance filings have been approved
for Algonquin and Texas Eastern, effective June 1, 1993, and for Tennessee and
Iroquois, effective September 1, 1993. Transition costs, i.e. those costs
incurred by pipelines as a result of implementing Order No. 636, are being
allowed by FERC to be recovered by the pipelines from their customers. Four
types of transition costs have been defined in the order: (1) unrecovered gas
costs remaining in the purchased gas adjustment account; (2) gas supply
realignment ("GSR") costs; (3) stranded costs and (4) new facilities costs.
Southern has incurred approximately $8,815,000 in transition costs as of
September 30, 1994. Of this total, $4,468,000 represent unrecovered gas costs
and $4,347,000 represent GSR costs and stranded investment costs. Hearings were
conducted by the DPUC in May 1994; and on July 8, 1994, the DPUC issued a
Decision regarding implementation of FERC Order No. 636 by the Connecticut local
gas distribution companies. The DPUC addressed, among other things, the
mechanism for the recovery of deferred transition costs. Under this mechanism,
the DPUC has allowed the recovery of the unrecovered gas cost balances from the
suspension of flow-through of purchased gas cost credits attributable to the
twelve month period ended August 31, 1993 and all future years ending August 31
as well as refunds received after October 1, 1993 from interstate pipelines.
Additionally, any subsequent refunds from interstate pipelines, as well as any
credits received by Southern for release of its capacity on interstate
pipelines, shall be used to offset Southern's payments of unrecovered gas costs
until fully recovered. As of September 30, 1994, Southern has recovered
approximately $4,468,000 in unrecovered gas costs through a combination of
these recovery mechanisms.
GSR costs as well as stranded investment costs are to be recovered by
Southern as follows: (1) retention of 50% of margins derived through off-system
sales; (2) retention of 50% of all interruptible margins earned above Southern's
target level; (3) retention of pipeline refunds or deferred gas costs credits
for the 1992/93 period and all subsequent annual deferred gas cost periods
that are in excess of the estimated unrecovered gas cost portion of transition
costs; (4) retention of any capacity release credits received from pipelines in
excess of those needed for unrecovered purchased gas costs and (5) if needed, a
per unit surcharge applied to firm customers' bills, which will be evaluated in
subsequent annual deferred gas cost proceedings. There is no hierarchy in the
use of the first four recovery measures, and any and all could be utilized as
available. All subsequent annual deferred gas cost credits will be applied on
an annual basis. All other transition cost credits will be immediately applied
on a monthly basis to offset transition costs which have been or will be
subsequently billed. As of September 30, 1994, Southern has recovered
approximately $3,020,000 in GSR costs as well as stranded investment costs
through a combination of these recovery mechanisms.
Straight-fixed-variable ("SFV") rates are now in effect on the pipelines
serving Southern as a result of FERC Order No. 636 and have replaced modified-
fixed-variable ("MFV") rates. Pipeline demand charges have increased under SFV
rate design due to shifting certain revenue requirements to the fixed portion of
pipeline rates. Pipeline usage charges, on the other hand, have decreased
correspondingly due to the same cost shifting out of the variable portion of the
<PAGE> 8
rate. The change in gas costs due to SFV rates, specifically, the adjustment
between pipeline demand and usage charges, has been incorporated in Southern's
new base cost of gas approved by the DPUC.
Capacity release programs are available on all pipelines serving Southern.
These programs permit Southern to release firm transportation capacity,
including underground storage, to "replacement shippers" on a basis which is
either prearranged or subject to bidding. All releases must be posted on the
electronic bulletin board of the pipeline on which the capacity is being
released. Bidding occurs on the posted releases except for prearranged
transportation arrangements of 29 days or less.
Southern has been an active participant in capacity release since June 1,
1993. Capacity release results in direct reductions to gas cost since pipeline
demand charges recouped from a replacement shipper flow back on the pipeline's
monthly bill as a credit to Southern.
Rates and Regulation
Connecticut Regulation. Southern is subject to the jurisdiction of the DPUC
as to accounting, rates, charges, operating matters and the issuance of
securities, both equity and debt, other than borrowings maturing in twelve
months or less. Southern's firm sales rates change monthly pursuant to a
DPUC approved Purchased Gas Adjustment clause ("PGA"), under which purchased
gas costs above or below a specified base cost are charged or credited to
customers.
In setting authorized rates for Southern, the DPUC allows prospective
adjustments to a historical test year. Forward-looking adjustments to the mid-
point of the rate year (the first year that rates will be in effect) for rate
base, revenues, expenses and capital structure are allowed. The DPUC has found
that these refinements provide for better synchronization of the ratemaking
components. Costs used by the DPUC in determining Southern's rates may not be
the same as actual costs incurred by Southern during the period rates are in
effect. The sales used in establishing rates are based on "normal" weather
patterns. Actual rates of return realized may not necessarily equal the
authorized rates of return.
On April 23, 1993, Southern filed an application with the DPUC for an
increase in rates designed to produce additional revenues of approximately
$27,900,000 or 13.67% over test year revenues. Southern's base rates had not
been increased since April 1990.
On December 1, 1993, the DPUC issued a final Decision on Southern's latest
rate request. This Decision incorporated the Partial Settlement of Certain
Issues ("Partial Settlement") which was previously approved by the DPUC in
September 1993 and resolved most of the significant financial aspects of
Southern's original rate request, including an increase in base rates of
$13,400,000 based upon Southern's sales forecast as originally filed, an allowed
return on equity of 11.45% and the implementation of a weather normalization
adjustment clause. In addition, Southern was permitted to recover previously
deferred costs over amortization periods from three to five years associated
with shortfalls in energy assistance, the certified hardship arrearage
forgiveness program, environmental remediation expenditures, economic
development programs and undepreciated gas holder costs.
The Partial Settlement also provides for current recovery of postretirement
health care expenses accrued under Statement of Financial Accounting Standards
No. 106 and the establishment of a target margin, net of gross receipts tax, of
$4,000,000 for on-system sales and transportation to Southern's interruptible
customers with excess margins shared between firm customers and shareholders on
an 80%/20% split. As part of this Partial Settlement, Southern agreed that,
except for certain adverse events, it would not file a general application to
increase rates which would become effective on or before November 30, 1995.
Federal Regulation. Southern is affected by various federal regulations,
including regulations which (1) provide for emergency authority and curtailment
allocations under the Natural Gas Policy Act of 1978 when pipeline supplies are
limited and (2) establish certain retail policies for natural gas utilities
<PAGE> 9
under the Public Utility Regulatory Policies Act of 1978. Southern is also
subject to the Natural Gas Pipeline Safety Act of 1968 with respect to the
construction, operation and maintenance of its mains, services and LNG
facilities as well as other federal regulations pertaining to safety standards
concerning such facilities. Currently, these federal regulations have a
minimal direct effect on Southern's day-to-day operations. Southern is also
subject to various federal, state and local regulation with respect to
environmental matters (including hazardous waste regulation) and local zoning
and other regulations. To date, such regulations have not materially
impacted Southern's capital expenditures, earnings or operations.
Regulations promulgated under the Clean Air Act Amendments of 1990 and the
Energy Policy Act of 1992, which require reduced pollution levels and certain
energy efficiency standards, have begun to affect Southern. Among other things,
the Clean Air Act Amendments (1) impose stringent emissions standards for all
vehicles beginning in 1994; (2) mandate the gradual phase-in of alternative fuel
vehicles for fleets of more than 10 vehicles beginning in 1998; and (3) require
power plants to phase in significant emission reductions of sulfur dioxide and
nitrogen oxide by the year 2000. Similarly, the Energy Policy Act of 1992 (1)
requires that federal vehicles begin phasing-in the use of alternative fuels as
early as 1993; (2) offers tax incentives to private parties who use or
facilitate the use of alternative fuel vehicles and (3) requires a lessening
reliance on foreign fuels. Over time, it is expected that these regulations
will lead to an increasing demand for natural gas. Southern already has begun
to participate in the expanded markets for natural gas that are emerging due to
these regulatory mandates.
Since 1986, FERC has effected major changes in the regulations governing the
natural gas industry, especially FERC Order No. 636. Although the Company is
not subject to FERC jurisdiction, FERC's actions increase competition in the
natural gas industry by requiring interstate pipeline companies to provide gas
transportation to others on a non-discriminatory basis. This increased
competition may assist Southern, at least in the short-term, by replacing some
higher cost gas supplies with less costly supplies. For a discussion of the
impact of FERC Order No. 636, see page 7.
Environmental Matters. Southern has identified coal tar residue at three
sites in Connecticut. This residue results from historic coal gasification
operations conducted at those sites by Southern's predecessors from the late
1800s through the first part of this century. Many gas distribution companies
throughout the country carried on such gas manufacturing operations during the
same period. The coal tar discovered at Southern's three sites is not
designated a hazardous material by any federal or Connecticut agency, but some
of its constituents are classified as hazardous.
On April 27, 1992, Southern notified the Connecticut Department of
Environmental Protection ("DEP") and the United States Environmental Protection
Agency of the presence of coal tar residue on the three sites. On November 9,
1994, the DEP informed Southern that it had performed a preliminary review of
the information provided to it by Southern and had determined that, based on
current priorities and limited staff resources, a comprehensive review of site
conditions and subsequent participation by the DEP "are not possible at this
time". Until the DEP conducts a comprehensive review, no discussions with it
addressing the extent and type of remedial action, if any, as well as the time
period over which such action would take place, can occur.
Given the DEP's response, management cannot at this time predict the costs
of any future site analysis and remediation, if any, nor can it estimate when
any such costs, if any, would be incurred. Such future analytical and cleanup
costs could possibly be significant.
Based upon the provisions of the Partial Settlement, management believes
that Southern will properly be able to recover the costs of investigation and
remediation, if any, through its customer rates. The method, timing and extent
of any recovery remain uncertain, but management currently does not expect that
the incurrence of such costs will have a material adverse effect on the
Company's financial condition or results of operations.
<PAGE> 10
Item 2. Properties
- - -------------------
The Company's materially important physical plant and properties consist
primarily of Southern's gas distribution facilities. Southern had 2,057 miles
of main and 118,814 service units as of September 30, 1994. It leases office
space in Bridgeport, New Haven and Madison, owns properties in Bridgeport and
New Haven that were formerly service centers and owns propane air facilities in
New Haven and Trumbull.
In 1972, Southern entered into a long-term lease of the LNG plant in
Milford, Connecticut. The initial lease period is for 25 years.
In 1992, Southern entered into an operating lease which consolidated
administrative functions at one location in Bridgeport, Connecticut. The lease
term is for 20 years.
In March 1993, Southern entered into an operating lease for the purpose of
consolidating its operating centers at one location in Orange, Connecticut. The
consolidation occurred during the second quarter of fiscal 1994, and the lease
term is for 20 years.
Substantially all of Southern's utility properties and plant are subject to
the lien of the indenture and supplemental indentures securing its first
mortgage bonds. It is management's opinion that the materially important
physical plant and properties as described herein is suitable and adequate for
the purpose of delivering gas for customer use.
Item 3. Legal Proceedings
- - --------------------------
In September 1993, Southern received notification of the results of audits
by the City of New Haven pursuant to Connecticut's omitted property statute.
The City of New Haven claimed that Southern owed approximately $2,600,000 in
additional personal property taxes related to years 1990 through 1992; however,
Southern was not aware of any audit finding of significant omitted personal
property. Instead, the City of New Haven's claim was based on the assessor's
retroactive reassessment of Southern's personal property. Southern initiated
legal actions against the City of New Haven which alleged that, among other
things, the City of New Haven had no statutory authority to issue tax bills
based upon retroactive reassessments of previously declared property on which
taxes were paid and that the City of New Haven's contingent fee agreement with
the firm which audited Southern's records was illegal. Southern also
instituted legal actions challenging the City of New Haven's assessment of
Southern's personal property for the 1993 Grand List.
On June 29, 1994, Southern and the City of New Haven entered into a
Stipulation and Agreement ("Agreement") in settlement of these court actions.
The Agreement provided for a $200,000 payment related to the tax years 1990
through 1992 without conceding liability on any of the issues involved; and a
resolution of the disputed 1993 personal property assessment, which resulted in
a reduction of the original 1993 assessment of approximately $1,500,000 to a new
assessment of approximately $800,000.
Item 4. Submission of Matters to a Vote of Security Holders
- - ------------------------------------------------------------
None
<PAGE> 11
PART II
-------
Item 5. Market for Common Stock and Related Stockholder Matters
- - ----------------------------------------------------------------
Common Stock Data
- - -----------------
The Company's common stock is listed for trading on the New York Stock
Exchange. The Company's common stock symbol is CNE.
The following table shows the high and low price range of the Company's
common stock and quarterly dividends paid.
Market Price and Dividend Data
- - ------------------------------
1994
- - ----
(Quarter Ended) High Low Dividend
- - --------------- ---- --- --------
December 31, 1993 $26 $23 $.32
March 31, 1994 25 20 .32
June 30, 1994 22 1/2 20 1/4 .325
September 30, 1994 22 1/4 20 1/4 .325
1993
- - ----
(Quarter Ended) High Low Dividend
- - --------------- ---- --- --------
December 31, 1992 $23 1/2 $20 $.32
March 31, 1993 25 22 1/2 .32
June 30, 1993 26 1/2 24 .32
September 30, 1993 26 24 .32
As of September 1994, the Company and its predecessors have paid 339
consecutive quarterly cash dividends. Cash dividends have been paid since 1850,
and the Company currently expects that dividends will continue to be paid in the
future.
The major source of funds for payment of the Company's dividends is the
dividends received on the shares of Southern's common stock owned by the
Company. Southern's indenture relating to long-term debt, and its Amended and
Restated Certificate of Incorporation contain restrictions as to the
declaration or payment of cash dividends on, or the reacquisition of, capital
stock. Under the most restrictive of such provisions, $19,209,000 of retained
earnings at September 30, 1994 were available for such purposes.
The approximate number of shareholders of record of the Company's common
stock as of November 25, 1994 was 12,074.
Item 6. Selected Financial Data
- - --------------------------------
The presentation under "Eleven Year Financial Summary" for the five years
in the period ended September 30, 1994 on pages 40 and 41 of Connecticut Energy
Corporation's 1994 Annual Report to Shareholders is incorporated herein by
reference.
Item 7. Management's Discussion and Analysis of Financial Condition
- - --------------------------------------------------------------------
and Results of Operations
- - -------------------------
The "Management's Discussion and Analysis" on pages 17 to 23 of Connecticut
Energy Corporation's 1994 Annual Report to Shareholders is incorporated herein
by reference.
<PAGE> 12
Item 8. Financial Statements and Supplementary Data
- - ----------------------------------------------------
The Consolidated Statements of Income, Consolidated Balance Sheets,
Consolidated Statements of Cash Flows, Consolidated Statements of Changes in
Common Shareholders' Equity, Notes to Consolidated Financial Statements on pages
24 to 38 and the Report of Independent Accountants as set forth on page 39 of
Connecticut Energy Corporation's 1994 Annual Report to Shareholders are
incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
- - ------------------------------------------------------------------------
Financial Disclosure
- - --------------------
None
<PAGE> 13
PART III
--------
Item 10. Directors and Executive Officers of the Registrant
- - ------------------------------------------------------------
Information required in this item regarding directors is contained in the
Company's definitive Proxy Statement at pages 2 to 4 which will be mailed to
shareholders on or about December 14, 1994, which is incorporated by reference
herein. A list of executive officers of the registrant and Southern follows:
Executive Officers of Connecticut Energy Corporation
----------------------------------------------------
and
---
The Southern Connecticut Gas Company
------------------------------------
Position and
Business Experience for the
Name and Age Past 5 Years
- - ------------ ----------------------------------------
J. R. Crespo, 52 Chairman of the Board, President and
Chief Executive Officer of the Company
and Southern (1990), President and Chief
Executive Officer of the Company and
Southern (1989). Prior to joining the
Company in 1989, he was Managing Partner
of the Utility Regulatory and Advisory
Services practice of Coopers & Lybrand,
New York.
Vincent L. Ammann, Jr., 35 Vice President and Chief Accounting
Officer of the Company and Group Vice
President, Corporate Planning and
Administration of Southern (1994), Vice
President and Chief Accounting Officer of
the Company and Southern (1991),
Controller of Southern (1990). Prior to
joining Southern in 1990, he was Senior
Manager, National Public Utility Services
Group of Deloitte and Touche (1988) and
Audit Manager, Deloitte, Haskins and
Sells (1986).
Carol A. Forest, 46 Vice President, Finance, Chief Financial
Officer and Treasurer of the Company and
Southern (1991), Vice President, Finance
and Chief Financial Officer of the
Company (1985) and Southern (1984).
Michael H. Pinto, 67 Vice President, Government Affairs of the
Company (1991), Director, Governmental
Relations of Southern (1990), Director,
Economic Development of Southern (1985).
J. Richard Tiano, 50 Vice President, General Counsel and
Secretary of the Company and Southern
(1988). Prior to joining the Company and
Southern in 1988, he was a partner in the
law firm of Wickwire, Gavin, P.C.,
Washington, D.C.
<PAGE> 14
Thomas A. Trotta, 57 Senior Vice President and Chief Operating
Officer of Southern (1992), Senior Vice
President, Operations of Southern (1991),
Vice President, Sales and Customer
Services of Southern, (1989), Assistant
Vice President, Operations of Southern
(1989).
Samuel R. Clammer, 57* Vice President, Engineering and Gas
Supply of Southern (1992), Senior Vice
President, Engineering, Planning and Gas
Control of Southern (1989), Vice
President, Planning of Southern (1989).
Prior to joining Southern, he was a
consultant with Brown, Williams, Quinn
and Chinn (1988).
Frank L. Esposito, 62 Vice President, Human Resources and
Corporate Services of Southern (1992),
Vice President Human Resources of
Southern (1991), Director, Human
Resources of Southern (1982).
James P. Healy, 52 Vice President, Information Technology of
Southern (1992), Senior Vice President,
Corporate Development of Southern (1986).
Ernest W. Karkut, 52 Vice President, Purchasing and Plant
Services of Southern (1994), Vice
President, Customer Support Services of
Southern (1992), Assistant Vice
President, Customer Support Services of
Southern (1991), Assistant Vice
President, Financial Planning and
Treasurer of Southern (1991), Assistant
Vice President, Financial Planning of
Southern (1989), Director, Financial
Planning of Southern (1989).
Peter D. Loomis, 46 Vice President, Distribution and
Customer Service of Southern (1992),
Group Director, Customer Services (1991),
Director, Consumer Service (1989).
Larry S. McGaughy, 47 Vice President, Marketing and Corporate
Engineering of Southern (1994), Vice
President, Marketing and Gas Control of
Southern (1991), Vice President,
Corporate Planning and Marketing of
Southern (1990). Group Director, Sales
and Marketing of Southern (1990). Prior
to joining Southern in 1990, he was the
Director, Marketing and Energy Services
at Tampa Electric (1986).
<PAGE> 15
Phyllis A. O'Brien, 49 Vice President, Accounting and Regulatory
Services of Southern (1994), Vice
President, Corporate and Regulatory
Planning of Southern (1993), Group
Director, Corporate Regulatory and Supply
Planning of Southern (1991), Group
Director, Planning, Rates and Regulatory
Affairs of Southern (1991), Director,
Planning, Rates and Regulatory Affairs of
Southern (1990), Director, Rate Planning
and Regulatory Affairs of Southern
(1989).
*Retired effective June 1, 1994.
Item 11. Executive Compensation
- - --------------------------------
Information required in this Item is contained in the Company's definitive
Proxy Statement on pages 6 to 11 which will be mailed to shareholders on or
about December 14, 1994, which is incorporated by reference herein.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- - ------------------------------------------------------------------------
Information required in this Item is contained in the Company's definitive
Proxy Statement on page 4 which will be mailed to shareholders on or about
December 14, 1994, which is incorporated by reference herein.
Item 13. Certain Relationships and Related Transactions
- - --------------------------------------------------------
Information required in this Item is contained in the Company's definitive
Proxy Statement on pages 5 and 10 which will be mailed to shareholders on or
about December 14, 1994, which is incorporated by reference herein.
<PAGE> 16
PART IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- - -------------------------------------------------------------------------
(a) List of documents filed as part of this Report:
1. Financial Statements
--------------------
Among the responses to this Item 14 (a) are the following financial
statements which are incorporated herein by reference in Item 8 above:
(i) Consolidated Balance Sheets for the years ended September 30, 1994
and 1993.
(ii) Consolidated Statements of Income for the years ended September 30,
1994, 1993 and 1992.
(iii) Consolidated Statements of Changes in Common Shareholders' Equity
for the years ended September 30, 1994, 1993 and 1992.
(iv) Consolidated Statements of Cash Flows for the years ended September
30, 1994, 1993, and 1992.
(v) Notes to Consolidated Financial Statements
(vi) Report of Independent Accountants
2. Financial Statements and Supplementary Data required by Item 8
--------------------------------------------------------------
(A) Schedule Description Page
-------- ----------- ----
Report of Independent Accountants on
Financial Statement Schedules 21
V. Property, Plant and Equipment 22
VI. Accumulated Depreciation and Depletion
of Property, Plant and Equipment 23
VIII. Valuation and Qualifying Accounts 24
All other schedules are omitted because they are not required, are
inapplicable, or the information is otherwise shown in the financial statements
or notes thereto.
3. Exhibits Required by Item 601 of Securities and Exchange Commission
-------------------------------------------------------------------
Regulation S-K
--------------
(A) The following such exhibits are filed as a separate section of this
report.
<PAGE> 17
Exhibits
--------
(3) Certificate of Incorporation and By-Laws
----------------------------------------
The Amended and Restated Certificate of Incorporation of Connecticut Energy
Corporation is incorporated herein by reference to Item 6 of the Company's Form
10-Q filed for the quarter ended March 31, 1991 at pages 14 through 22. The
Amended and Restated By-Laws of Connecticut Energy Corporation are incorporated
herein by reference to Item 6 of the Company's Form 10-Q filed for the quarter
ended June 30, 1993 at pages 21 through 32.
The Amended and Restated Certificate of Incorporation of The Southern
Connecticut Gas Company is incorporated herein by reference to Item 6 of Form
10-Q filed for the quarter ended June 30, 1990 at pages 40 through 51. The
Amended and Restated By-Laws of The Southern Connecticut Gas Company are
incorporated herein by reference to Item 6 of the Company's Form 10-Q filed for
the quarter ended December 31, 1990 at pages 82 through 90.
(4) Instruments Defining Rights of Security Holders, Including Indentures
---------------------------------------------------------------------
(i) Indenture between The Bridgeport Gas Light Company and The
Bridgeport City Trust Company, as Trustee, dated as of March 1, 1948.
Incorporated herein by reference in Exhibit 4(b) (1) to Registration Statement
2-10566.
(ii) In addition to the Indenture referred to in 4 (i) hereof,
there have been twenty-six indentures supplemental thereto and a Financing
Agreement among The Southern Connecticut Gas Company, Industrial Leasing Trust
No. 3, Industrial Leasing Corporation, The Travelers Insurance Company and The
Connecticut Bank and Trust Company, Trustee dated as of April 1, 1972, copies of
all of which the Company agrees to furnish to the Commission upon request.
(10) Material Contracts
------------------
(i) Gas Purchase and Sales Agreement between The Southern
Connecticut Gas Company and Tenngasco Corporation, Tenngasco Exchange
Corporation, Tenngasco Marketing Corporation, Tenneco Oil Company, Houston Oil
and Minerals Corporation, Tinco, Ltd., Tenneco Exploration, Ltd. and Tenneco
Exploration II, Ltd., dated as of April 11, 1985, incorporated by reference to
Form 10-K for the fiscal year ended December 31, 1986 at pages 42 to 72.
(ii) Storage Service Agreement between Penn-York Energy Corporation
and The Southern Connecticut Gas Company, dated as of January 1, 1988,
incorporated by reference to Form 10-K for the fiscal year ended December 31,
1987 at pages 166 to 171.
(iii) Interruptible Gas Transportation Contract and Amendment No.
1, thereto, among Tenngasco Corporation, The Southern Connecticut Gas Company
and The United Illuminating Co., dated as of May 14, 1987 and August 1, 1989,
respectively, incorporated by reference to Form 10-K for the fiscal year ended
December 31, 1989 at pages 238 to 258.
(iv) Amendment No. 2 to Interruptible Gas Transportation Contract
among Tenngasco Corporation, The Southern Connecticut Gas Company and The United
Illuminating Company dated as of November 1, 1990, incorporated by reference to
Form 10-K for the transition period from January 1, 1990, to September 30, 1990,
at pages 90 to 91.
<PAGE> 18
(v) Gas Transportation Contract between Iroquois Gas Transmission
System, L.P. and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.32 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(vi) Gas Sales Agreement No. 1 by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.33 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(vii) Gas Sales Agreement No. 2 by and between Alberta Northeast Gas
Unlimited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.34 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(viii) Gas Sales Agreement by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.35 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(ix) Gas Sales Agreement by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.36 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(x) Gas Sales Agreement by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference in Exhibit 10.37 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(xi) Storage Service Transportation Contract between Tennessee Gas
Pipeline Company and The Southern Connecticut Gas Company, dated November 1,
1990, incorporated by reference to Form 10-K for the fiscal year ended September
30, 1992 at pages 182 to 190.
(xii) Storage Service Agreement between CNG Transmission Corporation
and The Southern Connecticut Gas Company, dated October 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 130
to 137.
(xiii) Gas Storage Contract between Tennessee Gas Pipeline Company
and The Southern Connecticut Gas Company, dated September 1, 1993, incorporated
by reference to Form 10-K for the fiscal year ended September 30, 1993 at pages
138 to 142.
(xiv) Gas Transportation Agreement between Tennessee Gas Pipeline
Company and The Southern Connecticut Gas Company, dated August 19, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 143 to 151.
(xv) Gas Transportation Agreement between Tennessee Gas Pipeline
Company and The Southern Connecticut Gas Company, dated August 19, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 152 to 159.
(xvi) Service Agreement between Texas Eastern Transmission
Corporation and The Southern Connecticut Gas Company, dated June 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 160 to 170.
<PAGE> 19
(xvii) Service Agreement between Texas Eastern Transmission
Corporation and The Southern Connecticut Gas Company, dated June 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 171 to 180.
(xviii) Service Agreement between Texas Eastern Transmission
Corporation and The Southern Connecticut Gas Company, dated June 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 181 to 192.
(xix) Service Agreement between Texas Eastern Transmission
Corporation and The Southern Connecticut Gas Company, dated June 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 193 to 204.
(xx) Service Agreement between Texas Eastern Transmission
Corporation and The Southern Connecticut Gas Company, dated June 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1993 at pages 214 to 220.
(xxi) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 221
to 227.
(xxii) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 228
to 235.
(xxiii) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 236
to 243.
(xxiv) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 244
to 251.
(xxv) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 252
to 257.
(xxvi) Service Agreement between Algonquin Gas Transmission Company
and The Southern Connecticut Gas Company, dated October 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 258
to 277.
<PAGE> 20
Executive Compensation Plans and Arrangements
---------------------------------------------
(xxvii) Employment Agreement between The Southern Connecticut Gas
Company and J. R. Crespo, dated as of March 24, 1992, incorporated by reference
to Form 10-K for the fiscal year ended September 30, 1992 at pages 213 to 229.
(xxviii) Amended and Restated Deferred Compensation Agreement between
The Southern Connecticut Gas Company and J. R. Crespo, dated as of October 21,
1993, incorporated by reference to Form 10-K for the fiscal year ended September
30, 1993 at pages 278 to 288.
(xxix) The Southern Connecticut Gas Company, Board of Directors
Retirement Plan, effective October 1, 1992, is filed herewith at pages 27 to 30.
(xxx) The Southern Connecticut Gas Company, Management Compensation
Plan, effective October 1, 1992, incorporated by reference to Form 10-K for the
fiscal year ended September 30, 1992 at pages 251 to 253.
(xxxi) Agreements between The Southern Connecticut Gas Company and
Philip R. Marsilius and Henry Chauncey, Jr. relating to deferred compensation as
directors, dated as of December 27, 1988 and December 31, 1988, incorporated by
reference to Form 10-K for the fiscal year ended December 31, 1988 at pages 58
to 62 and pages 63 to 67.
(xxxii) Supplemental Retirement Benefits Plan effective October 1,
1993, incorporated by reference to Form 10-Q for the quarter ended December 31,
1993 at pages 25 to 28.
(13) Annual Report to Security Holders
---------------------------------
Connecticut Energy Corporation's 1994 Annual Report to Shareholders is
filed herewith at pages 31 to 82.
(21) Subsidiaries of the Registrant
------------------------------
A list of Connecticut Energy Corporation's subsidiaries is incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at page 335.
(27) Financial Data Schedule
-----------------------
Financial Data Schedule UT is filed herewith at page 83.
(b) No reports on Form 8-K were filed during the last quarter of 1994.
<PAGE> 21
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
------------------------------------------------------------------
To the Board of Directors and Shareholders
of Connecticut Energy Corporation:
Our report on the consolidated financial statements of Connecticut Energy
Corporation has been incorporated by reference in this Form 10-K from page 39 of
the 1994 Annual Report to Shareholders of Connecticut Energy Corporation. In
connection with our audits of such financial statements, we have also audited
the related financial statement schedules listed in Item 14(a)2 of this Form
10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to be
included therein.
S/ Coopers & Lybrand, L.L.P.
New Haven, Connecticut
November 1, 1994
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We consent to the incorporation by reference in the Prospectus constituting part
of the Registration Statements on Form S-3 (No. 33-47684-3) and Form S-8
(No. 33-39245 and 33-51763) of Connecticut Energy Corporation of our report
dated November 1, 1994, on our audits of the consolidated financial
statements of Connecticut Energy Corporation as of September 30, 1994 and 1993,
and for the years ended September 30, 1994, 1993 and 1992, appearing on page 39
of the 1994 Annual Report to Shareholders of Connecticut Energy Corporation
which is incorporated in this Annual Report on Form 10-K. We also consent to
the incorporation by reference of our report on the financial statement
schedules, which appears above.
S/ Coopers & Lybrand, L.L.P.
New Haven, Connecticut
December 6, 1994
<PAGE> 22
<TABLE>
SCHEDULE V
PROPERTY PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 and 1992
(000's)
<CAPTION>
Balance Additions Sales and Balance
September 30, 1993 at Cost Retirements Other September 30, 1994
------------------ --------- ----------- ----- ------------------
<S> <C> <C> <C> <C> <C>
GAS PLANT:
Intangibles 141 --- --- --- 141
Production 3,314 36 100 (389) 2,861
Storage 6,086 224 --- --- 6,310
Distribution 278,847 23,763 1,718 (2,166) 298,726
General 22,703 4,450 3,017 (2,257) 21,879
Construction Work in Progress 2,860 (824) --- --- 2,036
------- ------ ----- ----- -------
Gross Utility Plant 313,951 27,649 4,835 (4,812) 331,953
Other Non-utility Property 97 --- --- 3,319(B) 3,416
Leasehold Costs --- --- --- --- ---
Intangible Drilling Costs --- --- --- --- ---
Lease and Well Equipment --- --- --- --- ---
------- ------ ----- ----- -------
Total Property, Plant and Equipment 314,048 27,649 4,835 (1,493) 335,369
======= ====== ===== ===== =======
(B) Transfer of gross book value of former operating centers from utility
property to non-utility property.
</TABLE>
<TABLE>
<CAPTION>
Balance Additions Sales and Balance
September 30, 1992 at Cost Retirements Other September 30, 1993
------------------ --------- ----------- ----- ------------------
<S> <C> <C> <C> <C> <C>
GAS PLANT:
Intangibles 141 --- --- --- 141
Production 3,241 21 --- 52 3,314
Storage 6,128 10 --- (52) 6,086
Distribution 259,464 20,833 1,941 491 278,847
General 22,530 3,668 1,588 (1,907)(A) 22,703
Construction Work in Progress 2,183 677 --- --- 2,860
------- ------ ----- ----- -------
Gross Utility Plant 293,687 25,209 3,529 (1,416) 313,951
Other Non-utility Property 163 --- --- (66) 97
Leasehold Costs 1,104 --- 1,104 --- ---
Intangible Drilling Costs 4,090 --- 4,090 --- ---
Lease and Well Equipment 3,896 --- 3,896 --- ---
------- ------ ------ ----- -------
Total Property, Plant and Equipment 302,940 25,209 12,619 (1,482) 314,048
======= ====== ====== ===== =======
(A) Includes the removal of original cost related to the transfer of title to
the headquarters property.
</TABLE>
<TABLE>
<CAPTION>
Balance Additions Sales and Balance
September 30, 1991 at Cost Retirements Other September 30, 1992
------------------ --------- ----------- ----- ------------------
<S> <C> <C> <C> <C> <C>
GAS PLANT:
Intangibles 141 --- --- --- 141
Production 3,240 --- --- 1 3,241
Storage 6,012 166 --- (50) 6,128
Distribution 242,660 18,734 1,896 (34) 259,464
General 21,579 1,769 793 (25) 22,530
Construction Work in Progress 230 1,953 --- --- 2,183
------- ------ ----- --- -------
Gross Utility Plant 273,862 22,622 2,689 (108) 293,687
Other Non-utility Property 163 --- --- --- 163
Leasehold Costs 1,104 --- --- --- 1,104
Intangible Drilling Costs 4,090 --- --- --- 4,090
Lease and Well Equipment 3,896 --- --- --- 3,896
------- ------ ----- --- -------
Total Property, Plant and Equipment 283,115 22,622 2,689 (108) 302,940
======= ====== ===== === =======
</TABLE>
<PAGE> 23
<TABLE>
SCHEDULE VI
<CAPTION>
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 and 1992
(000's)
Balance Charged to Cost of Removal Balance
September 30, 1993 Operations Other Retirements Less Salvage September 30, 1994
------------------ ---------- ----- ----------- --------------- ------------------
<S> <C> <C> <C> <C> <C> <C>
GAS PLANT:
Production 2,069 82 (403) 100 --- 1,648
Storage 915 249 --- --- --- 1,164
Distribution 79,033 11,373 (965) 1,710 1,228 86,503
General 10,134 1,831 (908) 3,026 (112) 8,143
------ ------ ----- ----- ----- ------
Total Gas Plant 92,151 13,535 (2,276) 4,836 1,116 97,458
Other Non-Utility
Property 88 --- 836 --- --- 924
Leasehold Costs --- --- --- --- --- ---
Intangible Drilling
Costs --- --- --- --- --- ---
Lease and Well
Equipment --- --- --- --- --- ---
------ ------ ----- ----- ----- ------
Total 92,239 13,535 (1,440) 4,836 1,116 98,382
====== ====== ===== ===== ===== ======
</TABLE>
<TABLE>
<CAPTION>
Balance Charged to Cost of Removal Balance
September 30, 1992 Operations Other Retirements Less Salvage September 30, 1993
------------------ ---------- ----- ----------- --------------- ------------------
<S> <C> <C> <C> <C> <C> <C>
GAS PLANT:
Production 1,974 95 --- --- --- 2,069
Storage 673 242 --- --- --- 915
Distribution 71,040 10,589 9 1,928 677 79,033
General 9,946 1,091 601 1,601 (97) 10,134
------ ------ --- ----- --- ------
Total Gas Plant 83,633 12,017 610 3,529 580 92,151
Other Non-Utility
Property 235 --- (147) --- --- 88
Leasehold Costs 1,011 --- (1,011) --- --- ---
Intangible Drilling
Costs 3,781 --- (3,781) --- --- ---
Lease and Well
Equipment 3,802 8 (3,810) --- --- ---
------ ------ ----- ----- --- ------
Total 92,462 12,025 (8,139) 3,529 580 92,239
====== ====== ===== ===== === ======
</TABLE>
<TABLE>
<CAPTION>
Balance Charged to Cost of Removal Balance
September 30, 1991 Operations Other Retirements Less Salvage September 30, 1992
------------------ ---------- ----- ----------- --------------- ------------------
<S> <C> <C> <C> <C> <C> <C>
GAS PLANT:
Production 1,881 93 --- --- --- 1,974
Storage 429 244 --- --- --- 673
Distribution 63,829 9,957 (169) 1,864 713 71,040
General 9,028 944 612 825 (187) 9,946
------ ------ --- ----- --- ------
Total Gas Plant 75,167 11,238 443 2,689 526 83,633
Other Non-Utility
Property --- --- 235 --- --- 235
Leasehold Costs 1,005 6 --- --- --- 1,011
Intangible Drilling
Costs 3,761 20 --- --- --- 3,781
Lease and Well
Equipment 3,782 20 --- --- --- 3,802
------ ------ --- ----- --- ------
Total 83,715 11,284 678 2,689 526 92,462
====== ====== === ===== === ======
</TABLE>
<PAGE> 24
<TABLE>
<CAPTION>
CONNECTICUT ENERGY CORPORATION
------------------------------
SCHEDULE VIII - VALUATION AND QUALIFYING
----------------------------------------
ACCOUNTS
--------
YEARS ENDED SEPTEMBER 30, 1994, 1993 and 1992
---------------------------------------------
(000's)
Col. A Col. B Col. C Col. D Col. E
- - ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Additions
---------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End of
Description of Period Expenses Accounts Deductions Period
- - ----------- ---------- ---------- ---------- ---------- ---------
Allowance for
Doubtful
Accounts
1994 (1) $ 4,251 $ 6,962 $ 1,482 (2) $ 8,948 (3) $ 3,747
1993 (1) $ 4,074 $ 4,324 $ 4,627 (4) $ 8,774 (3) $ 4,251
1992 (1) $ 3,170 $ 7,043 $ 1,120 (2) $ 7,259 (3) $ 4,074
</TABLE>
Notes:
- - ------
(1) Reserve deducted in the Balance Sheet from the asset to which it applies
(2) Recoveries on accounts previously charged off
(3) Accounts charged off as uncollectible
(4) Recoveries on accounts previously charged off and deferral of energy
assistance shortfalls
<PAGE> 25
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
(Registrant) CONNECTICUT ENERGY CORPORATION
S/ J. R. Crespo
- - --------------------------------------------------
J. R. Crespo, Director, Chairman of the Board,
President and Chief Executive Officer
Dated: November 29, 1994
<PAGE> 26
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
S/ Henry Chauncey, Jr. S/ Samuel M. Sugden
- - ----------------------------------- ---------------------------------
Henry Chauncey, Jr., Director Samuel M. Sugden, Director
Dated: November 29, 1994 Dated: November 29, 1994
S/ James P. Comer S/ Christopher D. Turner
- - ---------------------------------- ---------------------------------
James P. Comer, M.D., Director Christopher D. Turner, Director
Dated: November 22, 1994 Dated: November 29, 1994
S/ J. R. Crespo S/ Helen B. Wasserman
- - ---------------------------------- ---------------------------------
J. R. Crespo, Director, Chairman Helen B. Wasserman, Director
of the Board, President and Dated: November 29, 1994
Chief Executive Officer
Dated: November 29, 1994
S/ Richard F. Freeman S/ Vincent L. Ammann, Jr.
- - ---------------------------------- ---------------------------------
Richard F. Freeman, Director Vincent L. Ammann, Jr.
Dated: November 29, 1994 Vice President and Chief
Accounting Officer,
(Principal Accounting Officer)
Dated: November 29, 1994
S/ Richard M. Hoyt S/ Carol A. Forest
- - ---------------------------------- ---------------------------------
Richard M. Hoyt, Director Carol A. Forest, Vice President,
Dated: November 29, 1994 Finance, and Treasurer,
(Principal Financial Officer)
Dated: November 29, 1994
S/ Paul H. Johnson S/ J. Richard Tiano
- - ---------------------------------- ---------------------------------
Paul H. Johnson, Director J. Richard Tiano, Vice President,
Dated: November 29, 1994 General Counsel and Secretary
Dated: November 29, 1994
S/ Newman M. Marsilius, III
- - ----------------------------------
Newman M. Marsilius, III, Director
Dated: November 29, 1994
<PAGE> 27
THE SOUTHERN CONNECTICUT GAS COMPANY
BOARD OF DIRECTORS RETIREMENT PLAN
The retirement plan set forth herein is known as The Southern
Connecticut Gas Company Board of Directors Retirement Plan (the
"Plan"). The Plan shall be effective October 1, 1992 and shall
continue in effect until amended, superseded or terminated by a
resolution of the Board of Directors of The Southern Connecticut
Gas Company.
1. Definitions: The following terms when used in this Plan with
initial capital letters shall have the meanings assigned to
them below:
(a) "Annual Retainer" means the annual retainer payable to
members of the Board of Directors during the fiscal year
in which the Eligible Director attains the age of sixty-
five (65).
(b) "Change in Control" of the Company shall be deemed to
have occurred if:
(i) Any Person is or becomes an Acquiring Person;
(ii) Less than 2/3 of the total membership of the Board
of Directors of the Company shall be Continuing
Directors; or
(iii) The shareholders of the Company shall approve a
merger or consolidation of the Company or a plan
of complete liquidation of the Company or an
agreement for the sale or disposition by the
Company of all or substantially all of the
Corporation's assets.
In connection with this definition of "Change in
Control", the capitalized terms in the definition are
defined as follows: (a) "Acquiring Person" means any
Person who is or becomes a "beneficial owner" as defined
in Rule 13d-3 of the Securities Exchange Act of 1934, as
amended (the "Exchange Act") of securities of the
Company; (b) "Affiliate" and "Associate" shall have the
meanings ascribed to such terms in Rule 12b-2 of the
General Rules and Regulations under the Exchange Act; (c)
"Continuing Director" means any member of the Board of
Directors of the Company who was a member of the Board on
October 1, 1992 and any successor of that Continuing
Director while such successor is a member of the Board of
Directors of the Company and who is not an Acquiring
Person or an Affiliate or Associate of any Acquiring
<PAGE> 28
Person and who is elected to succeed the Continuing
Director by a majority of the Continuing Directors; and
(d) "Person" shall have the meaning assigned to it in
Section 13(d) and 14(d) of the Exchange Act.
(c) "Code" means the Internal Revenue Code of 1954, as
amended. All references to any section of the Code shall
be deemed to refer not only to such section but also to
any amendment thereof and any successor statutory
provision.
(d) "Company" means The Southern Connecticut Gas Company and
any person, firm or corporation which may succeed to the
business of the Company by merger, consolidation or
otherwise and which, by appropriate action, shall adopt
the Plan.
(e) "Effective Date" means October 1, 1992.
(f) "Eligible Director" means a member of the Board of
Directors of the Company eligible to receive payments in
accordance with the terms of the Plan.
(g) "Plan" means The Southern Connecticut Gas Company Board
of Directors Retirement Plan and as it may hereafter be
amended.
(h) "Plan Year" means the Fiscal Year October 1 - September
30.
(i) "Retirement Date" means the date on which the Eligible
Director retires from the Board of Directors of the
Company but shall not be earlier than the date on which
the Eligible Director attains the age of sixty-five (65).
2. Eligibility: If an individual, duly elected to the Board of
Directors of the Company, receives a retainer as a Director
for five (5) years and is sitting as a Director at Retirement
Date, such individual shall be an Eligible Director entitled
to receive payments in accordance with the terms of this Plan.
3. Payments: An Eligible Director shall receive an annual
payment, payable in monthly installments commencing on the
first day of the month following the Retirement Date, of an
amount equal to the Annual Retainer payable to Directors
during the Fiscal Year in which the Eligible Director attains
the age sixty-five (65) and is sitting as a Director of the
Company at Retirement Date. Such payments shall continue for
a period of ten (10) years or the life of the Eligible
Director, whichever is shorter. If a Director dies before
payments under this Plan are to be made, the Director's estate
shall have no claim on any amounts accrued for such Director.
<PAGE> 29
4. Accrual of Payments, Funding and Trust Accounts: Commencing
October 1, 1992 the Company shall accrue on a monthly basis
the total amount of the monthly payments to be paid to
Eligible Directors calculated on the net present value due and
owing to each Eligible Director after the Director reaches the
Retirement Date. Such amounts shall be a credit to a
special account on the Company's books designated "Directors'
Retirement Account".
The Company shall not be required to fund or otherwise
segregate assets for the payments to Eligible Directors.
Notwithstanding the foregoing, the Company shall establish a
trust fund (or amend an existing trust fund) (the "Trust").
The Company shall contribute an amount that it determines to
be sufficient to actuarially fund the Eligible Directors'
monthly payments under this Plan. The Company shall review
such funding levels once a year as of January 1 and, if needed
to maintain the funding on a sound actuarial basis, increase
or decrease the level of funding. The Trust shall be a "rabbi
trust" and shall be embodied in a trust agreement with an
institutional trustee (the "Trustee"). Payments to Eligible
Directors shall be paid from the funds in the "rabbi trust" by
the Trustee to the extent not paid by the Company. The
Trustee shall establish an account (an "Account") for this
Plan to which shall be credited annually the Company's total
contribution to be made pursuant to this Section 4. The
account shall be credited with interest as earned, including
realized an unrealized investment gains and losses. The
establishment of the Account is solely for accounting and
funding purposes and shall not otherwise restrict the use of
the funds in the Trust.
5. Directors' Contributions: This Plan is a non-contribution
retirement plan.
6. Qualification of Plan: This Plan is a non-qualified plan as
defined in Sections 401(a) and 501(a) of the Code.
7. Restrictions on Transfers: No Eligible Director shall assign,
transfer or pledge any right or claim which such Eligible
Director may have under this Plan.
8. Successors to Company: No merger or acquisition of the
Company or any Change in Control of the Company shall cause
this Plan to be amended, superseded or terminated. Such
amendment, supersedure or termination shall occur only with
the approval of the Board of Directors at a meeting of the
Board of Directors held in accordance with the By-Laws of the
Company.
<PAGE> 30
9. Accounting: The Company, at no cost to Eligible Directors,
shall annually, or at other times deemed appropriate by the
Company's management, retain the services of counsel,
independent accountants and actuaries to assure that the
accounting accruals are consistent with the terms of this Plan
and applicable laws. To the extent permitted by law, the
Company shall be entitled to rely upon all tables, valuations,
certificates, opinions and reports furnished by any actuary,
accountant, counsel or other person(s) employed or engaged for
such purposes.
10. Expenses of Administration. All expenses that shall arise in
connection with the administration of the Plan including, but
not limited to, the compensation of any actuary, accountant,
counsel, other experts or other person who shall be appointed
by the Company in connection with the administration thereof,
shall be paid by the Company.
11. Amendment: The Company reserves the right to amend, modify,
suspend or terminate the Plan by action of its Board of
Directors, provided, however, no such action shall operate to
recapture for the Company any payments previously made to an
Eligible Director under the Plan, nor except to the extent
necessary to meet the requirements of the Code or any other
governmental authority, to deprive an Eligible Director of any
benefit due such Eligible Director under the Plan.
12. Notices: Any notices required or permitted to be given under
this Plan shall be in writing and shall be deemed to have been
given when delivered, or when mailed, if mailed by registered
or certified mail, return receipt requested to the respective
addresses of the Company and Eligible Director or to such
other address as any party hereto shall designate to the other
party in writing.
13. Severability: The provisions of the Plan are severable. The
invalidity or unenforceability of any provision of the Plan
shall not affect the validity or enforceability of any other
provision.
14. Governing Law: This Plan shall be governed by and interpreted
in accordance with the substantive of laws of the State of
Connecticut, except as any such laws may be preempted by
federal law.
<PAGE>
[LOGO] Connecticut Energy Corporation
1994 Annual Report
Business is both an
Art and a Discipline...
<PAGE>
Providing security in
a constantly changing
environment involves
planning and profound
commitment. To craft
the optimum business
structure requires mastery
in knowledge and a focused
strategy. These qualities
form the foundation of
Connecticut Energy
Corporation.
<PAGE>
Service Area
Franchise Area
Connecticut
Rhode Island
New York
Long Island
IN TOWNS CURRENTLY SERVED
Square miles 488
Population 775,547*
Number of households 318,533+
Miles of gas main in service 2,057
IN CONNECTICUT
Square miles 4,872
Population 3,287,116*
Number of households 1,343,524+
+Connecticut Dept. of Housing
*Based on 1990 U.S. Census Figures.
<PAGE>
BUSINESS PROFILE
Connecticut Energy Corporation is a holding company primarily
engaged in the retail distribution of natural gas for residential, commercial
and industrial uses through its wholly owned subsidiary, The Southern
Connecticut Gas Company (Southern). Southern delivers natural gas to
approximately 153,000 customers in 22 Connecticut communities.
DIVIDENDS
Connecticut Energy Corporation through its predecessor companies has paid cash
dividends on its common stock since 1850, the longest consecutive dividend
payment record of any utility or nonfinancial company listed on the New York
Stock Exchange. In September 1994, the Company paid its 339th consecutive
quarterly dividend. The dividend has increased in 14 of the last 15 years.
STOCK LISTING INFORMATION
Connecticut Energy's common stock is listed on the New York Stock Exchange
under the ticker symbol "CNE". Quotes may be obtained in daily newspapers where
it is listed under "ConnEn" in the New York Stock Exchange composite table. In
October 1994, Connecticut Energy was selected for inclusion in the newly formed
Standard & Poor's SmallCap 600 index. Investment and Shareholder information is
on pages 45 and 46.
HIGHLIGHTS
<TABLE>
<CAPTION>
Years ended September 30, 1994 1993 % Change
- - -----------------------------------------------------------------------------
Financial (dollars in thousands)
- - -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $240,873 $212,762 13.2
Gross margin 114,003 99,717 14.3
Net income 12,843 11,053 16.2
Total assets 352,920 299,795 17.7
Common shareholders' equity 125,719 99,853 25.9
Long-term debt 119,917 120,511 (0.5)
Total capitalization 245,636 221,002 11.1
Return on average common equity (%) 10.84 10.87 (0.3)
- - -----------------------------------------------------------------------------
Per Share
- - -----------------------------------------------------------------------------
Net income $ 1.58 $ 1.50 5.3
Dividends paid 1.29 1.28 0.8
Market value at year end 21.63 24.88 (13.1)
Book value at year end 14.45 13.33 8.4
- - -----------------------------------------------------------------------------
Other
- - -----------------------------------------------------------------------------
Weighted average common shares outstanding 8,134,021 7,377,419 10.3
Shares outstanding at year end 8,700,266 7,488,467 16.2
Shareholders of record 12,094 11,094 9.0
Shareholders in dividend reinvestment plan 6,621 6,049 9.5
Institutional ownership (shares) 1,842,000 1,375,000 34.0
Number of employees at year end 572 599 (4.5)
- - -----------------------------------------------------------------------------
</TABLE>
STOCK PRICE
CHART
High Low Close
'89 18 7/8 14 18
'90 18 14 1/2 16 5/8
'91 19 3/8 14 1/4 19
'92 24 3/4 18 5/8 22 1/4
'93 26 1/2 20 1/8 24 7/8
'94 26 20 21 5/8
TOTAL RETURN
Ten Year Compound
Return on $1,000
There is no assurance that similar
rates of return will be experienced
by the Company's shareholders in
the future.
CHART
9/84 1,000.000
9/85 1,262.280
9/86 1,718.575
9/87 1,754.109
9/88 1,835.401
9/89 2,489.751
9/90 2,475.384
9/91 3,042.622
9/92 3,777.323
9/93 4,447.971
9/94 4,100.064
THREE
<PAGE>
TO OUR SHAREHOLDERS
PHOTO
Fiscal 1994 was a landmark year for the natural gas industry, marking the
culmination of a prolonged journey through the regulatory restructuring
process. It was also a landmark year for our Company. Five years ago we made a
commitment to maintain steady and consistent growth in earnings in spite of
external variables. It gives me great pleasure to report that Connecticut
Energy Corporation achieved record earnings this year, which marks the fifth
consecutive year in which we have achieved our objective.
Net income was a record $12,843,000, or $1.58 per share of common stock, an
increase of 5.3 percent over 1993. We have achieved our goal of continued
improvement in earnings and financial stability by transforming the knowledge
we have acquired from seasons past into measurable actions which are clearly
focused upon today and tomorrow.
Rate Settlement Approved
As a result of our timely and constructive regulatory initiatives, our
subsidiary, The Southern Connecticut Gas Company, negotiated a rate case
settlement that was approved and implemented in December 1993. The settlement
increased base rates by 6.6 percent, contributing significantly to the growth
in revenues and earnings in fiscal 1994. An important component of the rate
settlement was the implementation of a Weather Normalization Adjustment (WNA)
- - -- which will enhance earnings stability over the long term. As a result of
the WNA, we can be more aggressive in pursuing future growth opportunities in
nonfirm markets.
Consolidation Complete
During February we completed the consolidation and relocation of our
operating departments into one central facility. Upon consolidation, our two
autonomous union locals merged to form one new local. We continue to look at
every aspect of our business for ways in which to further improve productivity
and enhance our level of customer service. It is these efforts, rather than
frequent rate relief, that will keep our services and rates competitive and
enable us to grow.
Record Throughput
The Federal Energy Regulatory Commission's (FERC) restructuring rule,
Order No. 636, became fully effective in November 1993. The first winter's
operation under Order No. 636 presented unique challenges for gas supply
planning and tested the reliability of delivery during sustained
record-breaking cold weather. The portfolio of supply, transportation and
storage contracts which we had negotiated was more than adequate to serve our
customers.
Firm sales reached an all time high of 22.7 billion cubic feet (Bcf), and
sales and transportation service to interruptible customers also broke previous
records at 10.5 Bcf. For the first time, we were able to capitalize on new
market opportunities by selling and transporting our gas to customers outside
of our distribution system. Off-system throughput totalled 3.3 Bcf, or
approximately 10 percent of total throughput. Clearly, the ability to provide
gas service outside of our distribution system presents tremendous future
growth potential in a restructured operating environment.
Expansion in Traditional Markets
Our residential heating market is the cornerstone of our profitability today
and will be a significant source of growth for many years in the future. During
fiscal 1994 we added over 2,500 new heating customers to our residential
market. We also realized significant growth in new commercial and industrial
load additions. Another traditional market opportunity is currently unfolding
in the electric to gas conversion area, which is a market where gas now has an
overwhelming competitive price advantage. We have set a target to increase our
heating saturation along main from approximately 40 percent to 60 percent by
the year 2000, and we intend to accomplish this objective by increasing the
utilization of our existing distribution system.
Emerging Markets
A number of long-term growth opportunities have begun to emerge
in nontraditional areas such as the natural gas vehicle (NGV) market and
the electric generation market. We have installed natural gas filling stations
at the corporate headquarters of a local telephone company and have contracted
to install a station at one of the
FOUR
<PAGE>
post office branches in our service territory. As we see Clean Air Act
compliance regulations begin to take effect, the combination of state and
federal tax credits will provide an added incentive for the conversion of
vehicles to use natural gas.
After extensive negotiations, we signed a contract with a major electric
utility to convert two of its oil fired electric generating units to also burn
gas. In July, the generating plant began using gas, contributing 3.2 Bcf to
1994 throughput in less than three months.
Increasing Competition
Implementation of FERC Order No. 636 marked the culmination of a move towards
open market competition for the natural gas industry. At the state level, the
Connecticut Department of Public Utility Control (DPUC) also evaluated the
impact of restructuring on local gas distribution companies, and it found that
"unbundling" the services of local distribution companies is the next logical
step towards a truly competitive natural gas industry. The DPUC also addressed
the importance of evaluating government imposed costs, such as the gross
receipts tax and hardship uncollectible expense, which are currently being
borne disproportionately by Connecticut's utilities.
Our Company has realized significant margins from nonfirm business this
year, and we expect to pursue these markets with even greater intensity in the
future. Our direct access to all three pipelines serving our region, combined
with our LNG liquefaction and storage facility, provides another means of
managing gas supply as well as generating additional profits.
Our restructured operating environment brings with it a level of competition
which in the past had been unprecedented for gas utilities. We see a more
competitive marketplace as a positive development, and we have eagerly
positioned ourselves to capitalize on its inherent opportunities.
Adapting to Change
We have been diligent in our commitment to control operations and capital
costs as we position the Company to operate in a more competitive business
environment. Our employees have been quick to adapt to numerous changes in the
industry and within the Company. We are working smarter, more efficiently and
with more focus on customer service than we were five years ago, and I
compliment all of our employees for their high level of cooperation and
commitment. I would also like to take the opportunity to thank Samuel R.
Clammer, Vice President, Engineering and Gas Supply, for sharing his expertise
in supply management before retiring this year.
Performance for Our Shareholders
Providing an attractive total return to our shareholders over the long term
continues to be our primary corporate objective. This year we again increased
your dividend, as we have in 14 of the last 15 years. We have also been
successful in gradually reducing our dividend payout ratio, which further adds
to Connecticut Energy's financial stability.
Over the past year we have seen the price of gas distribution stocks decline
primarily as a result of rising interest rates. However, we have continued to
produce consistent attractive total returns for our shareholders over the long
term. Our five year average annualized total return was 9.4 percent, which
exceeded the 8.7 percent return for the S&P 500 index. The 10 year total return
was 14.2 percent compared to 13.7 percent for the S&P 500 index.
Setting the Agenda for the Future
From the 1990 Amendments to the Clean Air Act and the passage of the
National Energy Policy Act in 1992 ... to the 1993 FERC restructuring rule that
revolutionized the way gas distribution companies purchase and transport gas
... to state and federal tax incentives for natural gas vehicle conversions ...
the natural gas industry today bears as much resemblance to our industry of
five years ago as a finely tuned Stradivarius does to the block of wood from
which it was so skillfully crafted.
A master craftsman constructing an instrument draws upon the skill and the
mastery gained over years of experience. Creating the instrument with precision
and exacting standards, but using new and untested materials, can create
challenges not previously encountered.
Connecticut Energy is facing similar challenges in new markets it has never
before entered. Our industry has changed dramatically, but our blueprint -- for
providing the highest level of customer service, keeping rates competitive and
increasing our earnings -- has remained the same.
Through our work with customers and contractors, legislators and regulators,
we are pleased to see an expanded awareness for the benefits natural gas can
provide as both an efficient and environmentally friendly energy source. Now is
the time for us to seize this awareness and capitalize on the expanded markets
before us. By using a disciplined approach in all that we undertake, we are
mastering the art of competition -- crafting the optimum business structure to
succeed in the marketplace of the future.
S/ J.R. Crespo
J.R. Crespo
Chairman, President and Chief Executive Officer
Glossary located on page 44.
FIVE
<PAGE>
Dramatic Changes in Recent History
Looking back over the regulatory and legislative changes affecting the
natural gas industry in the last decade provides a brief sketch of how
dramatically our Company's operating environment has changed. Just last winter,
the 1993 Federal Energy Regulatory Commission's (FERC) restructuring rule,
Order No. 636, became fully effective. This order revolutionized the way gas
utilities purchase and transport gas. Distribution companies such as ours took
full responsibility for the direct purchase of natural gas and for its storage
and transportation to their gate stations. This restructuring rule was the
culmination of over a decade of federal deregulation of our industry.
Our careful planning for the restructured operating environment showed
positive results last year. In one of the coldest winters ever experienced in
the northeast, we broke our previous peak-day sendout record eight times during
January and February 1994, set a new peak-day record which was 12 percent
higher than the previous peak-day sendout, and set a new monthly record sendout
as well. In spite of the extreme cold, we were able to assure reliable delivery
to meet firm customer requirements, and we had a portfolio of supplies that was
more than adequate. Clearly our foresight and planning were visible.
Locally, Connecticut regulators also adopted some bold changes this year.
For example, the Department of Public Utility Control (DPUC) recognized the
emergence of strong competition
Insightful planning is essential for preparing the proper strategy.
Our broad based experience in the gas industry allows
us to be proactive in the marketplace -- setting the agenda for change
rather than responding to circumstance. This emphasis on long-term
planning continues to be a primary focus of management.
TOTAL THROUGHPUT
Billion Cubic Feet (Bcf)
CHART
1989 1990 1991 1992 1993 1994
Firm Sales 21.183 20.704 19.012 21.292 22.094 22.727
Interpt. Sales 2.364 1.98 2.785 3.133 4.643 6.968
Transportation 3.946 4.688 5.999 4.859 1.653 0.219
Off System 3.322
SIX
<PAGE>
PHOTO
in the energy markets, and it intends to have "unbundled" services in place for
distribution companies in Connecticut no later than November 1, 1995. This
change will eliminate some of the constraints in our large customer market and
allow us to compete with other energy suppliers on a more level playing field.
The DPUC also supported our request for a Weather Normalization Adjustment --
the first for a New England gas distribution company -- in our rates. This
adjustment mitigates the effects on firm revenue of extreme weather
(temperatures varying from a 30 year average). It also provides the Company
and its customers a more stable budget within which to operate.
Federal legislation in the form of the Clean Air Act Amendments of 1990 and
the Energy Policy Act of 1992 cleared a path of opportunities through both
their regulations and incentives. The Clean Air Act Amendments impose stringent
emissions standards on vehicles and power plants, mandate the use of
alternative fuels for fleet vehicles and eliminate the production by 1995 of
chlorofluorocarbons (CFCs) used heavily as a refrigerant for electric air
conditioning. The Energy Policy Act also promotes energy efficiency, reduces
dependence on foreign fuels -- which significantly affects the energy mix of
Connecticut -- and mandates a more rapid implementation of fleet vehicle
conversions to alternative fuels. The incentives provided by these Acts in the
form of tax credits help customers overcome some of the economic hurdles of
compliance, making natural gas an attractive alternative indeed.
Our Company encouraged the Connecticut legislature to pass two key bills in
1994 to improve the competitiveness of natural gas as a vehicular fuel for
fleets. The first bill eliminates the 31 cents per gallon road use tax on
natural gas until 1999. It also distinguishes Connecticut
SEVEN
<PAGE>
as only the second state in the nation to provide a 50 percent tax credit for
investment in alternative fuel stations and conversion equipment. The second
bill, which our Company introduced, eliminates the five percent gross receipts
tax on natural gas as a vehicular fuel.
These groundbreaking legislative and regulatory changes would have had a
diminished effect on our markets, however, without the ample supplies we
enjoyed this past winter and the capacity of three pipelines to which we are
directly connected.
In the past five years we have worked with legislators and regulators,
directly and in cooperative efforts with such groups as the American Gas
Association and the New England Gas Association. We have been at the forefront
in setting the agenda for change, rather than just responding to circumstances,
and the results have been positive. What follows is a review of our current
market opportunities and our strategies for operating successfully in the
increasingly competitive environment of the future.
Achieving excellence in all areas of business is the result of
profound commitment. This commitment is manifested through
knowledgeable personnel, attentive customer service, state of
the art technology and well managed supply. We believe our
responsibility is a public trust and remain committed to
honoring that trust.
Markets: Current and Emerging
The foundation of our Company's profitability today is our firm customer
market, which contributes over 90 percent of our gross margins. We continue to
offer incentives to potential customers along our existing distribution system
to switch to natural gas heating. We were successful in adding over 2,500 new
residential heating customers in 1994, and we will persist in developing this
attractive source of profitable growth.
Although we are beginning to see signs of improvement in the economic
climate in our service territory, the competitive forces we had anticipated
affecting our business are strong and real. We realize customer growth is a
cultivation
EIGHT
<PAGE>
PHOTO
process, and we continue to lay a foundation for that process so
our customer base will grow as the economy does. We have paid particular
attention to maintaining our high level of customer satisfaction, and we know
that word of mouth advertising from satisfied customers is a very important
tool for our future growth. We have also developed a network of 130 contractors
who, in addition to being updated by us on the latest technology and equipment
available, can also receive incentives for identifying new potential customers.
Certainly, our role in educating consumers about changes in regulations and
technology cannot be overlooked. We recently co-sponsored a full-day seminar on
compliance with the Clean Air Act, which attracted 150 industrial customers and
industry marketing representatives. In addition to positioning natural gas as
the solution to environmental regulations, the program also provided our
customers with assistance in completing Department of Environmental Protection
filing requirements. Feedback on the seminar from our existing and potential
industrial customers was excellent.
Updating consumers as well as engineers and contractors on significant
technological changes is also important. For example, at a local business expo
we introduced to our service area
MARGIN SOURCE BY
CUSTOMER GROUP
(dollars in millions)
CHART
'89 '90 '91 '92 '93 '94
Residential 58.31 57.913 57.153 62.449 63.391 71.643
Comm./Indust. Firm 20.13 20.481 20.937 22.740 23.376 26.003
Nonfirm 3.121 3.383 5.302 3.666 2.427 4.258
NINE
<PAGE>
PHOTO
the Triathlon gas combination heating and cooling system, with a programmable
electronic thermostat. This breakthrough technology, which has been tested for
the last few years and has just come to market, has commanded attention because
it has the potential to considerably reduce the operating expenses of large
homes or businesses.
In our firm commercial and industrial markets we have added both heating and
cooling load this year. We know customers must have a compelling reason to
commit capital dollars in a tight economy. For the New Haven school system, it
was operationally cost effective to switch 28 schools to heat with natural gas
this year. In addition, they were relieved of the potential liability of
leakage from the oil tanks at one or more of those schools.
More large customers are looking at the economics of installing one of
several engine-driven, absorption or desiccant dehumidification cooling
applications now available. The increased production of natural gas cooling
equipment is bringing initial costs down, and the longer service life of the
equipment, as well as lower operating costs, have made natural gas cooling very
economical for many of our hospital, office, supermarket and manufacturing
customers.
We have added interruptible business this year from larger customers who may
have used only one fuel previously, and from new businesses which are
replacing oil with natural gas as their alternative. For the first time this
year, we also had a few of our larger firm customers, which already had
dual-fuel capacity, switch to interruptible service. Although we do not have
many customers with that capability, our ability to unbundle services in the
future will allow us to offer more new services to meet specific customer needs
and stay competitive.
TEN
<PAGE>
TODAY'S PLAN FOR TOMORROW'S MARKETS
Natural Gas Vehicles (NGVs)
We have been very pleased with the success achieved in the natural gas
vehicle market this year, and we see this market gradually gaining momentum
through the turn of the century. Fleet cars typically use the same volume of
natural gas as a home heating customer, and NGV vans and trucks average up to
ten times that volume.
The federal regulations and incentives already mentioned provide a catalyst
for fleet-owning companies to consider the natural gas alternative. The two
pieces of Connecticut legislation which were passed this spring provide an
additional economic stimulus. With the U. S. Postal Service converting 62 mail
trucks in East Haven this year, our customers can see a local example of a
practical application.
Connecticut, along with the other New England states, has been designated as
a serious non-attainment area for specified air pollutants. Because of this, we
face more stringent standards for vehicle emissions. The New England Gas
Association, of which we are a member and which is headed by our Chairman,
co-sponsored an NGV Expo with the Department of Energy in September. Two
hundred people attended, and for most, this was their first exposure to NGVs.
Many were surprised to learn that Chrysler Corporation has been selling natural
gas powered minivans and that Ford, General Motors and American Honda are now
entering this market.
True mastery is the process of evolution in knowledge. Understanding
gained from seasons past becomes the action of today. It is only through
intense, mature effort over time that mastery is attained. For almost a
century and a half, we have cultivated this awareness.
ELEVEN
Electric Generation
The completion of the lateral connection and regulator station for
Connecticut Light and Power Company's (CL&P) Devon electric generating station
this summer gave our Company the ability to transport natural gas to a second
of three electric generating plants in our service area. For the first three
months after the July completion, CL&P estimated that the burning of natural
gas had reduced its sulfur dioxide emissions by 1,500 tons and had saved its
customers about $1.5 million in fuel costs. Providing service to electric
generators resulted in a significant increase in throughput this year,
contributing 10 percent of total volumes.
Offering Flexible Services
The strong firm customer market we have built provides us with the foundation
of our revenue stream. As we have foreseen changes in the industry, the market
and the economy, we have continued to pursue additional markets which demand
flexibility in the services customers need. In coming years, we envision that
an increasing proportion of our gross margin will come from nonfirm customers,
and we are planning for that eventuality now.
Our Company is the only New England distribution company with direct access
to three pipelines, and we can store gas supplies for later use. Our ability in
the near future to offer a "balancing" service -- balancing the difference
between volumes contracted for and volumes actually used on a daily basis --
will give us a further competitive advantage.
PHOTO
TWELVE
<PAGE>
The addition of both firm and nonfirm customers in 1994 contributed to our
breaking all prior volumetric records. Firm sales were 22.7 billion cubic feet
(Bcf); interruptible sales and transportation service reached 10.5 Bcf.
Through-put totaled 33.2 Bcf, which was 13 percent higher than our previous
record of 29.3 Bcf in 1992.
Financial Discipline:
A Company Prepared for the Future
One of our most satisfying achievements in 1994 was our ability to, once
again, show growth in earnings per share. In spite of the slowly recovering
economy and low oil prices, Connecticut Energy's net income reached a record
level of $12,843,000, or $1.58 per share, an increase of five percent over last
year's earnings per share.
Although the weather was 5 percent colder than normal since January, our
firm customers benefitted by having their bills lowered with credits totalling
$2,766,000 through the operation of the Weather Normalization Adjustment. Even
with this reduction to gross margin, we were still able to produce record
earnings.
The growth in 1994 earnings per share enabled us to meet another important
objective: to continue to reduce our dividend payout ratio. We succeeded in
dropping our payout ratio to 82 percent and we did so while showing modest
growth in dividends per share paid to our shareholders.
True knowledge is skill in action. By applying focused attention in all
that we undertake, success is achieved. We respect the understanding
that hard work and discipline are at the root of that success. Attention
to detail is the means as well as the goal.
DIVIDEND PAYOUT
(dollars per share)
CHART
'89 '90 '91 '92 '93 '94
Earnings $1.28 $1.33 $1.38 $1.43 $1.50 $1.58
Dividends $1.20 $1.23 $1.24 $1.265 $1.28 $1.29
THIRTEEN
<PAGE>
PHOTO
We have made a commitment to achieve steady and consistent growth in earnings
each year in spite of external variables, and we are pleased that 1994 marks
the fifth consecutive year in which we accomplished that goal. Without the
solid financial foundation we have built through adhering to long-term
objectives, however, we would not have the footing nor the flexibility to
pursue the new markets ahead of us. Our strategic process has included
affecting internal changes when needed and modifying external variables when
possible.
Making Internal Changes
After considerable and precise planning, our Company completed the
consolidation of our two operating centers and meter shop this year into one
centrally located facility. This followed the consolidation last year of three
administrative office locations into one headquarters building. These moves
achieved efficiencies not previously possible, most notably in staffing
flexibility, dispatching crews, maintaining service vehicles, and managing
materials and supplies. The consolidation has also allowed us to reorganize
some operating departments, which has increased employee efficiency and
customer service capabilities. Concurrently, we have been able to reduce the
number of employees, mostly through attrition, from 599 a year ago to 572 at
the end of fiscal 1994.
The decision to go forward with these consolidations was thoroughly reviewed
for cost effectiveness. We have been diligent in holding down our operations
and maintenance costs when possible. We are very pleased that our operations
and maintenance expenses as a percentage of gross margin have stayed below 48
percent, and we anticipate maintaining that level in the coming year.
FOURTEEN
<PAGE>
Affecting External Change
There are many variables which directly affect us and over which we have
little control. Working creatively to modify external circumstances, however,
has brought positive results.
We have no control over the weather. Yet by requesting and receiving a
Weather Normalization Adjustment in our rates, we have added a significant
level of stability to our revenues to counter the dramatic impact which
unusually warm temperatures had on our revenues and earnings in previous
years.
Our landmark rate settlement last year marked the first time we were able
to negotiate a stipulated agreement, thus avoiding the time and cost of a full
rate case. We have made concerted efforts on many fronts to work with our
regulators and legislators, and we have cooperatively affected change.
Achieving Financial Flexibility and Stability
We continued to take steps in 1994 to enhance our financial flexibility and
strengthen our capital structure. In March, we successfully completed the sale
of one million new shares of Connecticut Energy common stock. The issue
realized net proceeds of $19.4 million and reflects the lowest cost of common
equity capital we have ever issued in a public offering. It was an
accomplishment for our Company to have been able to complete this transaction
during a period of significant market volatility.
Our capital structure was also strengthened by continued response to the
Customer Stock Purchase Plan (CSPP) component of our Dividend Reinvestment and
Stock Purchase Plan. This plan provides us with the ability to raise common
equity in the least costly manner and to continue adding common equity
gradually over time. Response from our customers continues to be excellent.
Since the inception of the CSPP, over 2,000 customers have become shareholders,
investing approximately $4 million in our Company.
As a result of our common equity infusions, we reached another long-awaited
target in April when we were able to pay off all short-term debt for a period
of time. The last time our short-term debt balance was reduced to zero had been
in September 1988.
Success can be measured by the recognition that our efforts met our
goals. The value we provide to our shareholders and customers
each year sets incremental benchmarks upon which to judge our
long-term vision.
OPERATIONS AND MAINTENANCE
EXPENSES AS A PERCENT OF MARGIN
(dollars in millions)
CHART
'89 '90 '91 '92 '93 '94
O & M Expenses $89 $90 $92 $99 $100 $114
FIFTEEN
<PAGE>
PHOTO
We also redeemed Southern's last outstanding publicly issued preferred stock.
Given the low face value of the amount outstanding, the relatively high rate
of the nontax deductible dividends, additional debt issuance restrictions, and
the administrative burden of maintaining these outstanding voting shares, we
redeemed all 6,500 outstanding shares in December 1993.
The changes in our industry and our Company have converged to provide a
stable foundation from which the pursuit of new markets is possible. The high
percentage of margin derived from our firm customer base reflects a more stable
business position than some other distribution companies, and the added Weather
Normalization Adjustment can contribute to greater revenue stability. According
to Standard & Poor's, our distribution business has once again had its A-
long-term debt rating and "stable" outlook affirmed. Our track record of cost
containment, our lowered payout ratio, and our improved equity ratio as a
result of the stock offering this year, were also cited as positive features
in our stable financial outlook.
Long-Term Total Return
The market in 1994 was a difficult one for income stocks in general and gas
distribution stocks in particular. The impact of rapidly rising interest rates,
coupled with the heightened competitive risks perceived by investors, caused
downward pressure which impacted 1994 total returns. However, over the past
five and ten years we provided our shareholders with average annual total
returns of 9.4 percent and 14.2 percent, respectively. For those same periods,
the S&P 500 index returns were 8.7 percent and 13.7 percent, respectively.
Once again, we have clearly achieved our primary corporate objective: to
provide our shareholders with above average long-term total returns on their
investment in Connecticut Energy.
A Whole New Industry
The primary focus of our actions over the past year has been the strategic
preparation of every aspect of our Company to capitalize on the opportunities
which the rapidly changing business, regulatory, legislative and technological
environments have placed before us. Our goal is to offer the most competitive
and broadest array of energy services to our customers. We expect this focus,
combined with our resolve to hold down costs and enhance customer satisfaction,
will continue to increase shareholder value.
Providing financial security, stability and growth in a constantly changing
environment involves insight and commitment -- qualities that set apart
successful organizations. Our broad based experience in the natural gas
industry has allowed us to be proactive in the marketplace, setting the agenda
for change rather than responding to circumstances. The skills we have mastered
are not unlike the creativity required of the person who envisions and crafts a
violin ... or the proficiency of the virtuoso who makes the instrument come to
life in a performance. By applying focused attention in all that we undertake,
we are creating the optimum business structure to perform in the more
competitive marketplace of the future.
Kyung Yu, Concertmaster, New Haven Symphony
Orchestra and Assistant Professor, Yale School
of Music. The Company is a proud sponsor of
the Orchestra.
SIXTEEN
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Net Income
Connecticut Energy Corporation's ("Company") consolidated net income for the
fiscal years ended September 30 is detailed below:
<TABLE>
<CAPTION>
(in thousands, except per share) 1994 1993 1992
- - ------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income $12,843 $11,053 $10,227
==============================================================================
Net income per share $1.58 $1.50 $1.43
==============================================================================
Weighted average shares outstanding 8,134 7,377 7,136
- - ------------------------------------------------------------------------------
</TABLE>
Net income for 1994 was a record for the Company and increased approximately
16% when compared with 1993. Factors affecting the improved results for 1994
were the implementation of a 6.6% rate increase on December 9, 1993 by the
Company's wholly owned subsidiary, The Southern Connecticut Gas Company
("Southern"), the ability to retain additional interruptible margins earned due
to the changes in the annual margin sharing period and target made by the
Connecticut Department of Public Utility Control ("DPUC") in the recent rate
decision for Southern and the continued conversion of existing nonheating
customers to heating customers. Partially offsetting these increases were
higher operations expenses in the areas of uncollectibles, wages (including
some overtime costs due to the colder winter weather), employee benefits,
depreciation, rent and increased taxes due to higher pre-tax income and higher
revenues.
Results for 1994 were also affected by higher interest costs due to Southern's
issuance of $15,000,000 and $12,000,000 in additional long-term debt in
December 1992 and September 1993, respectively. The increases in interest
costs on long-term debt for 1994 were offset by lower other interest costs.
Net income in 1993 increased approximately 8% when compared with 1992. Gross
margin, a key statistic in the gas distribution business, increased by
approximately $869,000 in 1993 when compared with 1992, primarily due to
increased sales to firm customers because of colder weather and the conversion
of nonheating customers to heating customers.
Net income in 1993 was positively impacted by a lower provision for
uncollectible accounts due to a favorable DPUC Decision regarding the deferral
of certain shortfalls in energy assistance funding from state and federal
agencies relating to the 1991/92 and 1992/93 heating seasons, as well as a low
effective tax rate relating to certain flow-through tax benefits for deferred
uncollectible expenses and deferred gas costs.
Operating Revenues
Operating revenues are derived principally from the distribution of natural gas
to firm and interruptible customers by Southern. Southern's firm class of
customers have priority of service with no interruptions. Interruptible
customers are generally large industrial or commercial customers which have the
capability of utilizing an alternate fuel; their service can be interrupted by
Southern (if necessary) to service firm customers.
Operating revenues were approximately 13% higher in 1994 when compared with
1993. This increase can be attributed to the impact of a 6.6% increase in
Southern's rates implemented on December 9, 1993, higher collections through
the operation of Southern's Purchased Gas Adjustment Clause ("PGA") and the
addition of more heating customers through conversion of existing nonheating
customers. In Southern's most recent rate proceeding, the DPUC approved the
implementation of a Weather Normalization Adjustment ("WNA") under which the
non-gas portion of Southern's firm rates is charged or credited monthly to
reflect deviations from normal weather. The implementation of the WNA occurred
in January of 1994. Since the weather during the period in which the WNA
operated was approximately 5% colder than normal, Southern returned
approximately $2,766,000 to firm customers.
Operating revenues were approximately 5% higher in 1993 when compared with
1992. This increase in operating revenues was attributed to slightly colder
weather than in 1992, which resulted in the increased use of gas by Southern's
firm customers, higher collections from customers through the operation of the
PGA and continued conversions of nonheating customers to heating customers.
Connecticut Energy Corporation
SEVENTEEN
<PAGE>
Total Sales and Transportation Volumes
Southern's total volume of gas sold and transported reached a record level of
33,236 MMcf in 1994, which was a 17% increase over 1993, and was 13% higher
than the record set in 1992. The 1994 level was higher principally due to
increased firm and interruptible sales, as well as transportation volumes in
accordance with a special contract for Connecticut Light and Power Company's
Devon generating station which began in July 1994. Throughput in 1993 was
approximately 3% lower than the previous record level set in 1992, principally
due to lower volumes of third party gas transported to end users.
Firm Sales Volumes
Firm sales volumes were approximately 3% higher in 1994 when compared with
1993. This increase was primarily attributable to weather being approximately
5% colder than 1993 and the continued conversion of nonheating customers to
heating customers.
Firm sales volumes were approximately 4% higher in 1993 when compared with 1992
principally due to weather that was approximately 2% colder than 1992 and the
continued conversion of nonheating customers to heating customers.
Interruptible Sales and Transportation Volumes
The chart below depicts volumes of gas both sold to and transported for
interruptible customers, off-system sales and transportation volumes under
special contract by Southern, as well as gross margins earned and retained due
to the margin sharing mechanisms on these sales:
<TABLE>
<CAPTION>
(in thousands) 1994 1993 1992
- - ----------------------------------------------------------------------------
<S> <C> <C> <C>
Gross margin earned $7,421 $5,560 $4,853
============================================================================
Gross margin retained $5,346 $3,272 $4,311
============================================================================
Volumes sold and transported (MMcf) 10,509 6,296 7,992
- - ----------------------------------------------------------------------------
</TABLE>
Margins earned on volumes delivered to interruptible customers vary depending
upon the relationship of the market price for alternate fuels to the cost of
natural gas and related transportation. Additionally, margins earned, net of
gross earnings tax, from interruptible service in excess of an annual target
are allocated through a margin sharing mechanism between firm customers and
Southern. Margins earned and retained by Southern were higher for 1994 as
compared with 1993. The increase in margins retained for 1994 is principally
attributable to the change in the margin sharing year and an increase in the
target margin level from $2,000,000 to $4,000,000 in accordance with the DPUC's
decision in Southern's latest rate case.
Although volumes delivered in 1993 were lower than in 1992, total margins
earned in 1993 were greater than 1992. Margins retained by Southern in 1993,
however, were lower than 1992 because the DPUC allowed Southern to suspend the
margin sharing mechanism during 1992.
Purchased Gas Expense
Purchased gas expense increased during 1994 when compared to 1993 primarily due
to increased gas costs through operation of the PGA, a higher base cost of gas
and higher firm sales volumes. In addition, gas costs were higher in 1994 due
to the suspension of the flow-through of approximately $2,468,000 in gas cost
credits and $4,048,000 in interstate pipeline refunds to Southern's customers
relating to the recovery of previously deferred transition costs. In accordance
with the Federal Energy Regulatory Commission's ("FERC") Order No. 636,
Southern's cost of gas is expected to increase as a result of the pass-through
of transition costs arising from its interstate pipelines. (See section
entitled "FERC Order No. 636 Transition Costs" for further detail.)
Purchased gas expense increased during 1993 as compared with 1992 primarily due
to higher sales volumes and increased gas costs collected through the PGA.
Purchased gas expense increased during 1992 due primarily to higher firm sales
volumes during 1992 and higher incremental costs associated with the
procurement of additional long-term gas supplies. Additionally, Southern
recorded an increase in its purchased gas expense in 1992 to recover
approximately $6,834,000 of previously deferred take-or-pay, contract buy-out
and contract buy-down costs in accordance with a DPUC decision.
Connecticut Energy Corporation
EIGHTEEN
<PAGE>
Operations Expense
Operations expense was approximately 21% higher in 1994 as compared with 1993.
Approximately 49% of this increase is a result of a higher expense for
uncollectible accounts. In December 1992, the DPUC allowed Southern to defer
certain shortfalls in energy assistance funding from various state and federal
agencies related to the 1991/92 and 1992/93 heating seasons. The DPUC decision
positively impacted Southern's provision for uncollectible accounts for 1993.
Southern has been allowed to recover these deferred costs as well as deferred
costs associated with Southern's certified hardship forgiveness program
beginning January 1, 1994 in accordance with the DPUC's latest rate decision.
Accordingly, included in operations expense for 1994 is approximately
$1,726,000 relating to these amortizations. The remainder of this increase is
due to higher employee benefit costs relating to the adoption and the current
recovery of postretirement health care expenses accrued under Statement of
Financial Accounting Standards No. 106 ("SFAS 106"), as well as increases in
other operations expenses such as wages, rent, insurance and other general and
administrative expenses.
Operations expense was approximately 4% lower in 1993 when compared with 1992.
This decrease was principally attributable to the positive impact on Southern's
provision for uncollectible accounts due to a December 1992 Decision by the
DPUC to allow Southern to defer, for future recovery, certain shortfalls in
energy assistance funding related to the 1991/92 and 1992/93 heating seasons.
The total shortfall in energy assistance subject to this treatment that was
deferred during 1993 was $3,100,000. This decrease more than offset increases
in other operations expenses such as wages, rent, conservation and general and
administrative expenses.
Maintenance Expense
Maintenance expense for 1994 increased approximately 9% when compared to 1993.
This increase is primarily attributable to a higher level of maintenance
activity due to the colder winter weather.
Depreciation and Depletion Expense
Depreciation expense for Southern has increased in each of the last three years
because of additions to plant in service.
Federal and State Income Taxes
The total provision for federal and state income taxes increased in 1994 by
approximately 41% when compared with 1993. This increase was primarily due to
higher pre-tax income in 1994, coupled with higher effective tax rates due to
the flow-through tax effect of the amortization of previously deferred costs.
The total provision for federal and state income taxes increased in 1993 by
approximately 18% when compared with 1992. This increase was primarily due to
higher pre-tax income. The Company's effective tax rate for 1993 was similar to
1992 due to certain flow-through tax benefits.
Municipal, Gross Earnings and Other Taxes
Municipal, gross earnings and other taxes increased over the last three years
principally due to higher provisions for gross earnings taxes because of higher
revenues.
Interest Expense and Preferred Stock Dividends
Total interest expense and preferred stock dividends remained relatively
unchanged for 1994 when compared with 1993. Higher long-term interest costs
associated with higher average borrowings from the issuance of $15,000,000 of
Series X First Mortgage Bonds in December 1992 and $12,000,000 of Series Y
First Mortgage Bonds in September 1993 were offset by the recovery of higher
interest income primarily related to deferred transition costs arising from
implementation of FERC Order No. 636 by interstate pipelines and lower interest
costs related to interstate pipeline refunds. Additionally, short-term interest
costs were lower in 1994 due to lower average short-term borrowings.
Total interest expense and preferred stock dividends remained relatively
unchanged for 1993 when compared with 1992 levels. Offsetting the increase in
long-term interest costs during 1993, which was primarily due to higher average
long-term debt balances, were higher interest costs during 1992 because of the
reversal of previously deferred interest costs relating to take-or-pay,
contract buy-out and contract buy-down costs. Although Southern experienced an
increase in average short-term borrowings in 1993 when compared with 1992,
short-term interest costs decreased primarily due to significantly lower
applicable short-term interest rates in 1993.
Connecticut Energy Corporation
NINETEEN
<PAGE>
Southern strives to borrow short-term funds at the most competitive rates by
utilizing commercial paper and bank borrowings at money market rates.
Short-term interest rates averaged 3.74% in 1994 compared with 3.47% in 1993
and 4.48% in 1992.
Inflation
Inflation as measured by the Consumer Price Index for all urban consumers was
approximately 3.0% in 1994, 1993 and 1992. Operations and maintenance expenses
increase as a result of inflation, as does depreciation expense due to higher
replacement costs of plant and equipment. As a regulated utility, Southern's
increases in expenses generally are recoverable from customers through rates
approved by the DPUC. In management's opinion, inflation has not had a material
impact on net income and the results of operations over the last three years.
Rate Matters
On December 1, 1993, the DPUC issued a final Decision on Southern's latest rate
request. This Decision incorporated the Partial Settlement of Certain Issues
("Partial Settlement") which was previously approved by the DPUC and resolved
most of the significant financial aspects of Southern's original rate request,
including an increase in base rates of $13,400,000 based upon Southern's sales
forecast as originally filed, an allowed return on equity of 11.45% and the
implementation of the WNA. In addition, Southern was permitted to recover
previously deferred costs over amortization periods from three to five years
associated with shortfalls in energy assistance, the certified hardship
arrearage forgiveness program, environmental remediation expenditures, economic
development programs and undepreciated gas holder costs.
The Partial Settlement also provides for current recovery of postretirement
health care expenses accrued under SFAS 106 and the establishment of a target
margin, net of gross earnings tax, of $4,000,000 for on-system sales and
transportation to Southern's interruptible customers with excess margins shared
between firm customers and shareholders on an 80%/20% split. (See section
entitled "FERC Order No. 636 Transition Costs" for further detail.)
As part of this Partial Settlement, Southern agreed that, except for certain
adverse events, it would not file a general application to increase rates which
would become effective on or before November 30, 1995.
Recent Accounting Developments
In November 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits" ("SFAS 112"), which will be effective for the
Company's fiscal year ending September 30, 1995. This statement establishes
accrual accounting for benefits such as unemployment compensation, severance
benefits and disability benefits to former or inactive employees after
employment terminates but before retirement. The adoption of SFAS 112 is
required by the first quarter of fiscal 1995, and the Company intends to adopt
this statement prospectively. The impact of this new standard is not expected
to have a material effect on the Company's financial condition or results of
operations.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
The seasonal nature of Southern's business creates large short-term cash
demands primarily to finance gas purchases, customer accounts receivable and
certain tax payments. To provide these funds, as well as funds for its capital
expenditure program and other corporate purposes, Southern has committed lines
of credit with a number of banks totalling $30,000,000 and uncommitted lines of
credit with two of its banks totalling $14,000,000, in addition to a revolving
credit line agreement for up to $20,000,000 with one of its banks. This latter
agreement has a revolving credit feature through December 21, 1996, followed by
a term loan period through December 21, 2000. At September 30, 1994, Southern
had unused lines of credit of $45,200,000. Because of the availability of
short-term credit and the ability to issue long-term debt and additional
equity, management believes it has adequate financial flexibility to meet its
anticipated cash needs.
Operating cash flows in 1994 were positively affected by higher net income,
lower gas inventories and lower deferred gas cost balances as well as the
recovery of the majority of the transition cost balances paid to date.
Partially offsetting these increases were higher accounts receivable balances.
Connecticut Energy Corporation
TWENTY
<PAGE>
Investing Activities
Capital expenditures approximated $26,600,000 in 1994, $26,100,000 in 1993 and
$22,600,000 in 1992. Southern relies upon cash flow provided by operating
activities to fund a portion of these expenditures, with the remainder funded
by short-term borrowings and, at some later date, long-term debt and capital
stock financings. Southern's capital expenditures in 1995 will approximate
$25,550,000 of which 37% is budgeted for new business. The majority of the
remaining planned capital expenditures are to improve, protect and maintain its
existing gas distribution system. Over the 1995-99 period, Southern estimates
that total expenditures for new plant and equipment will range between
$110,000,000 and $130,000,000.
Financing Activities
As of June 1994, the quarterly dividend paid per share on the Company's common
stock was increased to $0.325 per share or an annual indicated dividend rate of
$1.30 per share.
In March 1994, the Company completed a public sale of 1,000,000 shares of
common stock at a price of $20 1/8 per share and received net proceeds of
$19,375,000. The proceeds were used for the repayment of short-term debt and
for other general corporate purposes.
In December 1993, Southern redeemed all outstanding shares of its 4 3/4% $100
par value cumulative preferred stock. The redemption price was 100% of par
value plus accrued dividends through December 30, 1993.
Southern issued and sold $12,000,000 in Series Y First Mortgage Bonds at a rate
of 7.08% and $15,000,000 in Series X First Mortgage Bonds at a rate of 7.67% in
September 1993 and in December 1992, respectively. Each issuance was privately
placed with single, separate lenders. The Series Y and Series X Bonds each have
a life of 20 years and are required to be redeemed through payments of
$12,000,000 and $15,000,000 on October 1, 2013 and December 15, 2012,
respectively. Proceeds from the sales of Series Y and Series X Bonds were used
principally to reduce short-term borrowings incurred primarily in connection
with Southern's capital expenditure program.
Cash flows from the Company's Dividend Reinvestment and Stock Purchase Plan
("DRP") increased in 1993 when compared to 1992. This increase was primarily
due to the issuance of additional shares resulting from the initiation of a
customer stock purchase plan as part of the DRP.
As of June 1992, the quarterly dividend paid per share on the Company's
outstanding common stock was increased to $0.32 per share or an annual
indicated dividend rate of $1.28 per share.
In November 1991, Southern issued and sold $60,000,000 in Series W First
Mortgage Bonds at a composite interest rate of 9.05% to three lenders in a
private placement. These bonds have a weighted average life of 32.5 years and
are required to be redeemed through payments of $45,000,000 and $15,000,000 in
the years 2021 and 2031, respectively.
Proceeds from the sale of Series W Bonds were used to reduce short-term
borrowings incurred to repurchase $47,750,000 of Series P, Q, R, S and a
portion of Series T First Mortgage Bonds, as well as $5,000,000 in 11%
Subordinated Notes. These long-term debt securities had sinking fund
requirements and principal payments of $41,568,000 over the 1992-96 time frame,
with total sinking fund requirements and principal payments for all of
Southern's outstanding long-term debt issues for the same time frame totalling
$48,086,000. In addition, the DPUC allowed the deferral of the unamortized
issuance costs of the repurchased debt issues as well as the premiums relating
to the repurchase of these issues. The total of these unamortized issuance
costs and repurchase premiums was $5,636,000 and will be amortized over the
average life of the Series W First Mortgage Bonds.
Financing plans for 1995 include a proposed private placement of approximately
$10,000,000 of long-term debt tentatively scheduled for the latter part of
fiscal 1995 with the proceeds being used for the repayment of short-term debt
and for other general corporate purposes. The method, timing and amounts of any
future financings by the Company or Southern will depend on a variety of
factors, including capitalization ratios, coverage ratios, interest costs, the
state of the capital markets and general economic conditions.
Connecticut Energy Corporation
TWENTY ONE
<PAGE>
In response to the competitive forces and regulatory changes being faced by the
Company, the Company has from time to time considered, and expects to continue
to consider, various strategies designed to enhance its competitive position
and to increase its ability to adapt to and anticipate changes in its utility
business. These strategies may include business combinations with other
companies as well as acquisitions of related or unrelated businesses. The
Company may from time to time be engaged in preliminary discussions regarding
one or more of these potential strategies. No assurances can be given as to
whether any potential transaction of the type described above may actually
occur, or as to the ultimate effect thereof on the financial condition or
competitive position of the Company.
Take-or-Pay, Contract Buy-Out and Contract Buy-Down Costs
Prior to 1992, Southern deferred amounts paid to its interstate pipeline
suppliers related to take-or-pay, contract buy-out and contract buy-down costs
and accrued and deferred interest on its unrecovered payments, pending the
DPUC's decision on this matter. In the first quarter of 1992, the DPUC issued a
Decision regarding the method of recovery of these deferred amounts, but did
not provide recovery of incurred and deferred interest.
As of September 30, 1994, Southern has recovered approximately $5,374,000 from
its firm customers through the suspension of the flow-through of purchased gas
credits, $1,343,000 from the suspension of the flow-through of pipeline refunds
to its customers and $602,000 from interruptible customers through the
application of the uniform volumetric surcharge. Approximately $726,000 will
continue to be recovered from interruptible customers through the uniform
volumetric surcharge.
FERC Order No. 636 Transition Costs
As a result of Order No. 636 issued by the FERC, costs are being incurred by
Southern's interstate pipeline suppliers to convert existing "bundled" sales
services to "unbundled" transportation and storage services. These transition
costs include: (1) unrecovered gas costs, (2) gas supply realignment costs, (3)
stranded investment costs and (4) new facilities costs.
Southern has incurred approximately $8,815,000 in transition costs as of
September 30, 1994. Of this total, $4,468,000 represent unrecovered gas costs
and $4,347,000 represent gas supply realignment costs and stranded investment
costs. On July 8, 1994, the DPUC issued a Decision regarding implementation of
FERC Order No. 636 by the Connecticut local gas distribution companies. The
DPUC addressed, among other things, the mechanism for the recovery of deferred
transition costs. Under this mechanism, the DPUC has allowed the recovery of
the unrecovered gas cost balances from the suspension of flow-through of
purchased gas cost credits attributable to the twelve month period ended August
31, 1993 and all future years ending August 31 as well as refunds received
after October 1, 1993 from interstate pipelines. Additionally, any subsequent
refunds from interstate pipelines as well as any credits received by Southern
for release of its capacity on interstate pipelines shall be used to offset
Southern's payments of unrecovered gas costs until fully recovered. As of
September 30, 1994, Southern has recovered approximately $4,468,000 in
unrecovered gas costs through a combination of these recovery mechanisms.
Gas supply realignment costs as well as stranded investment costs are to be
recovered by Southern as follows: (1) retention of 50% of margins derived
through off-system sales; (2) retention of 50% of all interruptible margins
earned above Southern's target level; (3) retention of pipeline refunds or
deferred gas cost credits for the 1992/93 period and all subsequent annual
deferred gas cost periods that are in excess of the estimated unrecovered gas
cost portion of transition costs; (4) retention of any capacity release credits
received from pipelines in excess of those needed for unrecovered purchased gas
costs and (5) if needed, a per unit surcharge applied to firm customers' bills,
which will be evaluated in subsequent annual deferred gas cost proceedings.
There is no hierarchy in the use of the first four recovery measures, and any
and all could be utilized as available. All subsequent annual deferred gas cost
credits will be applied on an annual basis. All other transition cost credits
will be immediately applied on a monthly basis to offset transition costs which
have been or will be subsequently billed. As of September 30, 1994, Southern
has recovered approximately $3,020,000 in gas supply realignment costs as well
as stranded investment costs through a combination of these recovery
mechanisms.
Connecticut Energy Corporation
TWENTY TWO
<PAGE>
Environmental Matters
Southern has identified coal tar residue at three sites in Connecticut. This
residue results from historic coal gasification operations conducted at those
sites by Southern's predecessors from the late 1800s through the first part of
this century. Many gas distribution companies throughout the country carried on
such gas manufacturing operations during the same period. The coal tar
discovered at Southern's three sites is not designated a hazardous material by
any federal or Connecticut agency, but some of its constituents are classified
as hazardous.
On April 27, 1992, Southern notified the Connecticut Department of
Environmental Protection and the United States Environmental Protection Agency
of the presence of coal tar residue on the three sites. As a result of this
notification, further discussions would address the extent and type of remedial
action, if any, as well as the time period over which such action would occur.
Because this process is at an early stage, management cannot at this time
predict the costs of any future site analysis and remediation, if any, nor can
it estimate when any such costs, if any, would be incurred. Such future
analytical and cleanup costs could possibly be significant.
Based upon the provisions of the Partial Settlement, management believes that
Southern will properly be able to recover the costs of investigation and
remediation, if any, through its customer rates. The method, timing and extent
of any recovery remain uncertain, but management currently does not expect that
the incurrence of such costs will have a material adverse effect on the
Company's financial condition or results of operations.
Personal Property Tax Audits
In September 1993, Southern received notification of the results of audits by
the City of New Haven pursuant to Connecticut's omitted property statute. The
City of New Haven claimed that Southern owed approximately $2,600,000 in
additional personal property taxes related to years 1990 through 1992; however,
Southern was not aware of any audit finding of significant omitted personal
property. Instead, the City of New Haven's claim was based on the assessor's
retroactive reassessment of Southern's personal property. Southern initiated
legal actions against the City of New Haven which alleged that, among other
things, the City of New Haven had no statutory authority to issue tax bills
based upon retroactive reassessments of previously declared property on which
taxes were paid and that the City of New Haven's contingent fee agreement with
the firm which audited Southern's records was illegal. Southern also instituted
legal actions challenging the City of New Haven's assessment of Southern's
personal property for the 1993 Grand List.
On June 29, 1994, Southern and the City of New Haven entered into a Stipulation
and Agreement ("Agreement") in settlement of these court actions. The
Agreement provided for a $200,000 payment related to the tax years 1990 through
1992 without conceding liability on any of the issues involved; and a
resolution of the disputed 1993 personal property assessment, which resulted
in a reduction of the original 1993 assessment of approximately $1,500,000 to a
new assessment of approximately $800,000.
Consolidation of Operating Facilities
On March 30, 1993, Southern entered into an operating lease to consolidate its
three operating centers located at three cities within Southern's service
territory at one central geographic location in Orange, Connecticut. The DPUC
approved certain accounting treatment relative to the consolidation of the
operating centers which included the transfer of the net book value of
Southern's former operating centers from utility property to nonutility
property after the completion of the relocation. The consolidation of
Southern's operating facilities was completed in the second quarter of
fiscal 1994.
Connecticut Energy Corporation
TWENTY THREE
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
Years ended September 30, 1994 1993 1992
- - -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $240,873 $212,762 $203,011
Purchased gas 126,870 113,045 104,163
- - -----------------------------------------------------------------------------------------------------------------
Gross margin 114,003 99,717 98,848
- - -----------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operations 50,209 41,331 43,230
Maintenance 4,035 3,692 3,651
Depreciation and depletion 13,031 12,051 11,327
Federal and state income taxes 5,402 3,821 3,232
Municipal, gross earnings and other taxes 16,314 15,697 15,080
- - -----------------------------------------------------------------------------------------------------------------
Total operating expenses 88,991 76,592 76,520
- - -----------------------------------------------------------------------------------------------------------------
Operating income 25,012 23,125 22,328
- - -----------------------------------------------------------------------------------------------------------------
Other deductions, net 586 510 531
- - -----------------------------------------------------------------------------------------------------------------
Interest Expense and Preferred Stock Dividends:
Interest on long-term debt and amortization of debt issue costs 10,920 9,945 9,064
Other interest, net and preferred stock dividends 663 1,617 2,506
- - -----------------------------------------------------------------------------------------------------------------
Total interest expense and preferred stock dividends 11,583 11,562 11,570
- - -----------------------------------------------------------------------------------------------------------------
Net Income $ 12,843 $ 11,053 $ 10,227
=================================================================================================================
Net income per share $ 1.58 $ 1.50 $ 1.43
=================================================================================================================
Dividends paid per share $ 1.29 $ 1.28 $ 1.265
=================================================================================================================
Weighted average common shares outstanding 8,134,021 7,377,419 7,135,779
- - -----------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
Connecticut Energy Corporation
TWENTY FOUR
<PAGE>
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
As of September 30, 1994 1993
- - ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility Plant:
Plant in service, at cost $329,917 $311,091
Construction work in progress 2,036 2,860
- - ------------------------------------------------------------------------------------------------------------------
Gross utility plant 331,953 313,951
Less: accumulated depreciation 97,458 92,151
- - ------------------------------------------------------------------------------------------------------------------
Net utility plant 234,495 221,800
Nonutility property, net 2,492 9
- - ------------------------------------------------------------------------------------------------------------------
Net utility plant and other property 236,987 221,809
- - ------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,637 2,214
Accounts and notes receivable (less allowance for doubtful
accounts of $3,747 in 1994 and $4,251 in 1993) 23,698 18,403
Accrued utility revenue, net 2,630 2,307
Unrecovered purchased gas costs 4,523 5,975
Inventories 14,678 16,312
Prepaid expenses 1,847 1,565
- - ------------------------------------------------------------------------------------------------------------------
Total current assets 49,013 46,776
- - ------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Unamortized debt expenses 6,317 6,466
Unrecovered deferred taxes 35,398 --
Other 25,205 24,744
- - ------------------------------------------------------------------------------------------------------------------
Total deferred charges 66,920 31,210
- - ------------------------------------------------------------------------------------------------------------------
Total assets $352,920 $299,795
==================================================================================================================
Capitalization and Liabilities
Common Shareholders' Equity:
Common stock -- par value $1 per share:
authorized -- 20,000,000 shares;
issued and outstanding -- 8,700,266 in 1994; 7,488,467 in 1993 $ 8,700 $ 7,488
Capital in excess of par value 85,265 62,808
Retained earnings 31,754 29,665
Adjustment for minimum pension liability (net of income taxes) -- (108)
- - ------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 125,719 99,853
- - ------------------------------------------------------------------------------------------------------------------
Redeemable preferred stock -- 638
Long-term debt 119,917 120,511
- - ------------------------------------------------------------------------------------------------------------------
Total capitalization 245,636 221,002
- - ------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 18,800 23,500
Current maturities of long-term debt 594 595
Accounts payable 10,886 11,960
Refunds due customers -- 1,964
Federal, state and deferred income taxes 3,565 3,634
Property and other accrued taxes 5,289 5,173
Interest payable 3,315 2,916
Customers' deposits 1,901 2,058
Other accrued liabilities 4,137 1,818
- - ------------------------------------------------------------------------------------------------------------------
Total current liabilities 48,487 53,618
- - ------------------------------------------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes 51,121 13,668
Deferred investment tax cred 3,853 4,146
Other 3,823 7,361
- - ------------------------------------------------------------------------------------------------------------------
Total deferred credits 58,797 25,175
- - ------------------------------------------------------------------------------------------------------------------
Commitments and contingencies -- --
- - ------------------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $352,920 $299,795
==================================================================================================================
</TABLE>
See notes to consolidated financial statements.
Connecticut Energy Corporation
TWENTY FIVE
<PAGE>
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' EQUITY
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
Adjustment
Common Stock Capital for Total
---------------------- in Minimum Common
Number Par Excess of Retained Pension Shareholders'
of Shares Value Par Value Earnings Liability Equity
- - ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance at September 30, 1991 7,096,634 $7,097 $54,647 $ 26,878 -- $ 88,622
Issuance through dividend
reinvestment plan 138,287 138 2,648 -- -- 2,786
Net income -- -- -- 10,227 -- 10,227
Dividends paid on common stock
($1.265 per share) -- -- -- (9,030) -- (9,030)
- - ------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1992 7,234,921 $7,235 $57,295 $ 28,075 -- $ 92,605
Issuance through dividend
reinvestment plan 253,546 253 5,513 -- -- 5,766
Net income -- -- -- 11,053 -- 11,053
Dividends paid on common stock
($1.28 per share) -- -- -- (9,463) -- (9,463)
Adjustment for minimum pension
liability (net of income taxes) -- -- -- -- $(108) (108)
- - ------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1993 7,488,467 $7,488 $62,808 $ 29,665 $(108) $ 99,853
Public offering 1,000,000 1,000 18,375 -- -- 19,375
Issuance through dividend
reinvestment plan 211,799 212 4,082 -- -- 4,294
Net income -- -- -- 12,843 -- 12,843
Dividends paid on common stock
($1.29 per share) -- -- -- (10,754) -- (10,754)
Adjustment for minimum pension
liability (net of income taxes) -- -- -- -- 108 108
- - ------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1994 8,700,266 $8,700 $85,265 $ 31,754 -- $125,719
==============================================================================================================================
</TABLE>
See notes to consolidated financial statements.
Connecticut Energy Corporation
TWENTY SIX
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
<TABLE>
<CAPTION>
Years ended September 30, 1994 1993 1992
- - --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income $ 12,843 $ 11,053 $ 10,227
Adjustments to Reconcile Net Income to Net Cash:
Gain on sale of headquarters property -- (66) --
Loss on sale of subsidiaries -- 68 --
Depreciation, depletion and amortization 13,844 12,825 11,930
Provision for losses on accounts receivable 6,962 4,350 7,000
(Increase) Decrease in Assets:
Accounts and notes receivable (12,248) (3,923) (14,269)
Accrued utility revenue, net (323) (274) (72)
Unrecovered purchased gas costs 1,452 (5,975) --
Inventories 1,634 (3,720) (3,158)
Prepaid expenses (282) (495) 141
Unamortized debt expense (87) (244) (693)
Deferred charges and other assets (4,852) (8,072) 6,662
Increase (Decrease) in Liabilities:
Accounts payable (1,661) 3,636 1,745
Refunds due customers (1,964) 1,432 (767)
Accrued taxes 47 1,656 (1,060)
Other current liabilities 2,561 (921) (1,679)
Deferred income taxes and investment tax credits 1,706 129 790
Deferred credits and other liabilities 177 1,794 (1,739)
- - --------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 19,809 13,253 15,058
- - --------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities:
Capital expenditures (26,669) (26,136) (22,782)
Proceeds from sale of headquarters property -- 2,005 --
Proceeds from sale of subsidiaries 28 180 --
Contributions in aid of construction 51 66 148
Payments for retirement of utility plant (779) (276) (163)
- - --------------------------------------------------------------------------------------------------------
Net cash used in investing activities (27,369) (24,161) (22,797)
- - --------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities:
Dividends paid on common stock (10,754) (9,463) (9,030)
Issuance of common stock 23,669 5,766 2,786
Issuance of long-term debt -- 27,000 60,000
Repayments of long-term debt (594) (594) (4,140)
Repurchase of long-term debt -- -- (52,678)
Redemption of preferred stock (638) (50) (50)
Payment of premium on repurchase of long-term debt -- -- (5,056)
(Decrease) increase in short-term borrowings (4,700) (14,800) 18,400
- - --------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 6,983 7,859 10,232
- - --------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and cash equivalents (577) (3,049) 2,493
Cash and cash equivalents at beginning of year 2,214 5,263 2,770
- - --------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 1,637 $ 2,214 $ 5,263
========================================================================================================
Supplemental Disclosures of Cash Flow Information
Cash Paid During the Year for:
Interest $ 11,332 $ 11,101 $ 9,692
Income taxes $ 4,252 $ 2,747 $ 4,842
</TABLE>
See notes to consolidated financial statements.
Connecticut Energy Corporation
TWENTY SEVEN
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of all subsidiary
companies. Connecticut Energy Corporation's ("Company") wholly owned
subsidiary, The Southern Connecticut Gas Company ("Southern"), is subject to
regulations by the Connecticut Department of Public Utility Control ("DPUC")
with respect to rates charged for service and the maintenance of accounting
records, among other things. Southern's accounting policies conform to
generally accepted accounting principles as applied to regulated public
utilities and are in accordance with the accounting requirements and ratemaking
practices of the DPUC. All significant intercompany transactions and accounts
have been eliminated.
Line of Business
Operating revenues of the Company are derived primarily from Southern's
operations as a retail natural gas distributor. Through nonregulated
subsidiaries, the Company was engaged in a limited amount of gas production and
transportation activities. In February 1993, the assets and liabilities of its
nonregulated subsidiaries were sold.
Accounting Changes
The Company adopted Statement of Financial Accounting Standards No. 106
"Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS
106") and Statement of Financial Accounting Standards No. 109 "Accounting for
Income Taxes" ("SFAS 109") effective October 1, 1993. See Note 2, "Provision
for Income Taxes", and Note 7, "Employee Benefits", for further detail.
Utility Plant
Utility plant is stated at original cost. The costs of additions and of major
replacements of retired units are capitalized. Costs include labor, direct
material and certain indirect charges such as engineering and supervision.
Replacement of minor items of property and the cost of maintenance and repairs
are included in maintenance expense. For normal retirements, the original cost
of property, together with removal cost, less salvage value, is charged to
accumulated depreciation when the property is retired and removed from service.
Depreciation
For financial accounting purposes, depreciation of utility plant is computed on
the composite straightline rates prescribed by the DPUC. The annual composite
rate allowed for book depreciation for Southern is 4.15%. Depreciation of
transportation and power-operated equipment is computed separately and based on
their estimated useful lives. For federal income tax purposes, the Company
computes depreciation using accelerated methods.
Federal Income Taxes
In accordance with the requirements of the DPUC and the Economic Recovery Tax
Act of 1981 ("ERTA"), income tax reductions to Southern resulting from such
items as liberalized depreciation on 1981 to 1994 plant additions and
investment tax credits on 1981 to 1986 plant additions are deferred and
amortized to income over the useful lives of the remaining assets. Prior to
1981, Southern had treated the differences between tax and book depreciation on
plant and equipment as adjustments to tax provisions ("flow-through method")
and continues to utilize the flow-through method on pre-1981 depreciation. With
specific permission from the DPUC, Southern also provides deferred federal
income taxes for certain items, such as unrecovered purchased gas costs, that
are reported in different time periods for tax purposes and financial reporting
purposes. In addition, the oil and gas subsidiaries had provided deferred or
prepaid taxes on all items directly related to exploration, drilling and
transportation.
In February 1992, the Financial Accounting Standards Board ("FASB") issued SFAS
109. SFAS 109 establishes financial accounting and reporting standards for
deferred income taxes using an asset and liability approach. SFAS 109 requires,
among other things, the recognition of the effect on deferred taxes of enacted
tax rate and law changes in the year in which they occur.
The Company has adopted SFAS 109, effective October 1, 1993, and has adjusted
deferred tax balances to reflect the differences between the tax and financial
statement basis of all assets and liabilities, regardless of whether deferred
taxes had been previously provided. Deferred tax liabilities have been reduced
to the extent they had been previously provided at federal statutory rates in
excess of the rates in effect on the effective date of adoption. In accordance
with
Connecticut Energy Corporation
TWENTY EIGHT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" ("SFAS 71"), the Company recorded an
additional deferred tax liability and a corresponding regulatory asset of
approximately $35,398 due to the adoption of SFAS 109. The effect of the
adoption of SFAS 109 on net income is not material since this adjustment will
be recognized in income in future periods as the temporary differences reverse.
Utility Revenues
The primary source of the Company's revenue is derived from Southern's retail
distribution of natural gas. Southern's service area spans 22 Connecticut towns
from Westport to Old Saybrook including the urban communities of Bridgeport and
New Haven. Southern bills its customers on a cycle basis throughout each month
and accrues revenues related to volumes of gas consumed by the customer but not
billed at month end. The accrual of unbilled revenues is recorded net of
related gas costs and accrued expenses.
Purchased Gas Costs
Southern's firm rates include a Purchased Gas Adjustment clause ("PGA"), under
which purchased gas costs above or below base rate levels are charged or
credited to customers. As prescribed by the DPUC, most differences between
Southern's actual purchased gas costs and the current cost recovery are
deferred for future recovery or refund through the PGA.
Weather Normalization Adjustment
Southern's firm rates include a Weather Normalization Adjustment ("WNA") under
which the non-gas portion of these rates is charged or credited monthly to
reflect deviations from normal temperatures. The implementation of the WNA
occurred in January 1994 and operates for ten months of the year (September
through June).
Deferred Charges
Included in other deferred charges are amounts related to the deferral of
certain hardship heating customer accounts receivable arrearages totalling
$10,211 and $6,894 in 1994 and 1993, respectively; the deferral of certain
shortfalls in energy assistance funding related to the 1991/92 and 1992/93
heating seasons amounting to $2,742 and $3,100 in 1994 and 1993, respectively;
prepaid pension contributions of $6,355 and $5,532 in 1994 and 1993,
respectively, and an intangible pension asset of $101 and $3,652 in 1994 and
1993, respectively.
Deferred Credits
Included in other deferred credits are amounts related to a minimum pension
liability totaling $101 and $3,816 for 1994 and 1993, respectively, as more
fully described in Note 7, "Employee Benefits."
Statement of Cash Flows
For purposes of reporting cash flows, short-term investments having maturities
of three months or less are considered to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market, cost generally being
determined on the basis of the average cost method. Inventories consist
primarily of fuel stock and smaller amounts of materials, supplies and
appliances.
Net Income Per Share
Net income per share is computed based upon the weighted average number of
common shares outstanding during each year.
NOTE 2 -- PROVISION FOR INCOME TAXES
Effective October 1, 1993, the Company adopted SFAS 109. In accordance with
SFAS 71, the Company has a regulatory asset of $35,398 related to the
cumulative amount of income taxes on temporary differences previously flowed
through to ratepayers due to the adoption of SFAS 109. In addition, the Company
has a deferred tax liability of $35,398 related to future tax benefits to be
flowed back to ratepayers associated with unamortized investment tax credits
and decreases in both federal and state statutory tax rates. Both the
regulatory asset and liability are recognized over the regulatory lives of the
related taxable bases concurrent with the realization in rates.
Connecticut Energy Corporation
TWENTY NINE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
The provision for income taxes includes:
<TABLE>
<CAPTION>
Years ended September 30, 1994 1993 1992
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Taxes currently payable -- federal $2,958 $ 968 $3,034
Taxes currently payable -- state 1,464 347 945
- - ----------------------------------------------------------------------------------------------
$4,422 $1,315 $3,979
- - ----------------------------------------------------------------------------------------------
Deferred (prepaid) taxes -- federal $ 980 $2,506 $ (747)
Deferred (prepaid) taxes -- state -- -- --
- - ----------------------------------------------------------------------------------------------
$ 980 $2,506 $ (747)
- - ----------------------------------------------------------------------------------------------
Total income tax provision $5,402 $3,821 $3,232
==============================================================================================
</TABLE>
Sources and tax effects of items which gave rise to deferred taxes are:
<TABLE>
<CAPTION>
1994 1993 1992
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amortization of deferred investment tax credits $ (292) $ (292) $ (292)
Unrecovered purchased gas costs (508) 2,378 (1,322)
Depreciation and depletion 1,779 1,664 1,654
Minimum tax credits 452 (1,111) (740)
Other (451) (133) (47)
- - ----------------------------------------------------------------------------------------------
$ 980 $2,506 $ (747)
==============================================================================================
</TABLE>
The following table reconciles the income tax provision calculated using
the federal statutory tax rate to the book provision for federal and state
income taxes.
<TABLE>
<CAPTION>
1994 1993 1992
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
U. S. statutory federal tax rate 35% 34.75% 34%
Depreciation differences 4% 5% 7%
Allowance for doubtful accounts,
including amounts forgiven and deferred (7%) (16%) (5%)
Investment tax credits (2%) (2%) (2%)
Cost to retire assets, net of salvage (2%) (1%) (2%)
State taxes, net of federal tax benefit 5% 2% 6%
Pension contribution (2%) -- (3%)
Premium on bond retirement -- -- (15%)
Reduction due to graduated tax rates (.6%) (.75%) --
Other, net (.4%) 4% 4%
- - ----------------------------------------------------------------------------------------------
Effective tax rate 30% 26% 24%
==============================================================================================
</TABLE>
Deferred income tax liabilities (assets) are composed of the following:
<TABLE>
<CAPTION>
At September 30, 1994
- - --------------------------------------------------------------
<S> <C>
Tax effect of temporary differences for:
Depreciation $18,508
Items previously flowed through 35,398
Alternative minimum tax (1,463)
Investment tax credits 3,853
Contribution in aid of construction (654)
Pension contribution (547)
Other (121)
- - --------------------------------------------------------------
Net deferred income tax liability -- long-term $54,974
==============================================================
</TABLE>
At September 30, 1994 and 1993, the balance sheet caption, "Federal, state and
deferred income taxes" included approximately $1,566 and $2,292, respectively,
of current deferred federal and state income taxes.
Connecticut Energy Corporation
THIRTY
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
At September 30, 1994 and 1993, the balance sheet caption, "Federal, state and
deferred income taxes" included approximately $1,463 and $1,915, respectively,
of minimum tax credits available to reduce federal income taxes to be paid in
future periods.
NOTE 3 -- LONG-TERM DEBT
Long-term debt outstanding at September 30, 1994 and 1993 consisted of:
<TABLE>
<CAPTION>
1994 1993
- - ------------------------------------------------------------------------------
<S> <C> <C>
First Mortgage Bonds:
Series L, 8%, due March 1, 1998 $ 4,620 $ 4,760
Series T, 10.02%, due September 1, 2003 4,091 4,546
Series U, 9.70%, due July 31, 2019 9,800 9,800
Series V, 9.85%, due July 31, 2020 15,000 15,000
Series W, 8.93% - 9.13%, due November 17, 2031 60,000 60,000
Series X, 7.67%, due December 15, 2012 15,000 15,000
Series Y, 7.08%, due October 1, 2013 12,000 12,000
- - ------------------------------------------------------------------------------
120,511 121,106
Less -- amounts due within one year 594 595
- - ------------------------------------------------------------------------------
$119,917 $120,511
==============================================================================
</TABLE>
Under the provisions of Southern's mortgage bond indenture dated March 1, 1948,
as supplemented from time to time, sinking fund payments are required at
various dates for Series L and Series T First Mortgage Bonds. Series W First
Mortgage Bonds are due in bullet payments in the years 2021 and 2031,
respectively. Additionally, Series U, V, X and Y are due in single payments in
the years 2019, 2020, 2012 and 2013, respectively. Substantially all of the
utility plant of Southern is subject to the lien of its mortgage bond
indentures. See Note 6 for dividend restrictions.
The aggregate annual sinking fund contributions and principal maturities for
the five fiscal years subsequent to September 30, 1994 are as follows: 1995 --
$594; 1996 -- $595; 1997 -- $595; 1998 -- $4,654; 1999 -- $455; total --
$6,893.
Expenses incurred in connection with long-term borrowings are normally
amortized on a straightline method over the respective lives of the issues
giving rise thereto.
NOTE 4 -- SHORT-TERM BORROWINGS
The Company follows the practice of borrowing on a short-term basis from banks
and through the sale of commercial paper. The following information relates to
these borrowings for the years ended September 30, 1994, 1993 and 1992.
<TABLE>
<CAPTION>
1994 1993 1992
- - ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Bank Loans
Outstanding at the end of the year $12,800 $10,500 $22,300
Weighted average interest rate at year end 5.41% 3.36% 3.59%
Average amount outstanding during year $14,951 $15,879 $17,328
Weighted average interest rate during year* 3.74% 3.47% 4.37%
Maximum amount outstanding at any month end $37,400 $29,200 $26,600
Commercial Paper
Outstanding at the end of the year $ 6,000 $13,000 $16,000
Weighted average interest rate at year end 4.95% 3.29% 3.35%
Average amount outstanding during year $ 3,950 $11,517 $ 9,496
Weighted average interest rate during year* 3.74% 3.46% 4.67%
Maximum amount outstanding at any month end $13,000 $16,000 $16,000
- - ---------------------------------------------------------------------------------------
<FN>
*Determined by dividing annual interest expense by average amount outstanding
during the year.
</TABLE>
Connecticut Energy Corporation
THIRTY ONE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
The Company's committed short-term bank credit lines amounted to $30,000, a
portion of which supports the issuance of commercial paper. Southern has
uncommitted lines of credit with two of its banks totalling $14,000 in addition
to a revolving credit/term loan agreement with one of its banks. This latter
agreement provides an additional credit line of up to $20,000. The revolving
credit feature is in effect through December 21, 1996 and is followed by a term
loan period through December 21, 2000. At September 30, 1994, Southern had no
outstanding borrowings under this agreement. The fee for this facility is 1/8
of 1% per annum. At September 30, 1994, the Company had unused lines of credit
of $45,200. In lieu of compensating balances, Southern pays fees for its lines
of credit which are approximately 3/10 of 1% of the amount of the line of
credit. The aggregate annual commitment fees on these lines were approximately
$124 for the year ended September 30, 1994.
NOTE 5 -- REDEEMABLE PREFERRED STOCK
The following table summarizes the shares of preferred stock authorized, issued
and outstanding at September 30, 1994 and 1993:
<TABLE>
<CAPTION>
1994 1993
- - -------------------------------------------------------------------------
<S> <C> <C>
The Southern Connecticut Gas Company:
Cumulative preferred stock, $100 par value:
Authorized 200,000 200,000
4.75% issued and outstanding -- 6,500
- - -------------------------------------------------------------------------
Preferred stock, $1 par value:
Authorized 600,000 600,000
Issued and outstanding -- --
- - -------------------------------------------------------------------------
Preference stock, $1 par value:
Authorized 1,000,000 1,000,000
Issued and outstanding -- --
- - -------------------------------------------------------------------------
Connecticut Energy Corporation:
Preference stock, $1 par value:
Authorized 1,000,000 1,000,000
Issued and outstanding -- --
- - -------------------------------------------------------------------------
</TABLE>
The 4.75% preferred stock outstanding at December 30, 1993 was redeemed at par
value, plus accrued dividends.
Southern's $1 par value preferred stock ranks on a parity as to dividends and
payments in liquidation with Southern's $100 par value preferred stock, while
the preference stock is preferred as to dividends and payments in liquidation
over Southern's common stock but is subordinate to the other classes of
preferred stock.
NOTE 6 -- COMMON SHAREHOLDERS' EQUITY
The indentures relating to the long-term debt and the Amended and Restated
Certificate of Incorporation of Southern contain restrictions as to the
declaration or payment of cash dividends on capital stock and the reacquisition
of capital stock. Under the most restrictive of such provisions, $19,209 of
Southern's retained earnings at September 30, 1994 was available for such
purposes.
The Company currently has two plans under which it issues common stock: the
Employee Stock Ownership Plan ("ESOP") and the Dividend Reinvestment and Stock
Purchase Plan ("DRP"). Additionally, common stock can be issued through a
savings plan ("Target Plan"); however, through September 30, 1994, all shares
have been acquired by the trustee through open market purchases. At the
election of the Company, contributions for the ESOP are made to a trustee who
uses the funds to acquire Company stock to be distributed to non-bargaining
unit and certain bargaining unit employees who are at least 21 years of age
with one year of service. These distributions are made upon termination or
retirement. There were no contributions to the ESOP made during the years ended
September 30, 1994 and 1993. The DRP permits shareholders to automatically
reinvest their cash dividends or invest optional limited amounts of cash
payments in newly issued shares or open market purchases of the Company's
common stock. At September 30, 1994, there were 1,763,193 shares reserved for
issuance under the DRP, ESOP and Target Plans.
Connecticut Energy Corporation
THIRTY TWO
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
NOTE 7 -- EMPLOYEE BENEFITS
Retirement Plans
Southern maintains two noncontributory pension plans covering substantially all
of its employees. The plan covering salaried and certain clerical employees
provides pension benefits based on compensation during the five years before
retirement and on years of service. The union-negotiated plan provides benefits
of stated amounts for each year of service. It is the Company's policy to fund
annually the periodic pension cost of its retirement plans subject to the
minimum and maximum contribution limitations of the Internal Revenue Code.
A regulatory adjustment has been made to the net periodic pension cost to
reflect the amount of pension cost that is realized through the ratemaking
process.
The Company recorded an additional minimum liability of $101 and $3,816
representing the excess of the accumulated benefit obligation over the fair
value of plan assets and accrued pension costs at September 30, 1994 and 1993,
respectively. This liability is offset by an intangible asset of $101 and
$3,652 at September 30, 1994 and 1993, respectively, which represents
unrecognized prior service costs and, in 1993, the balance (net of income
taxes) was charged to a separate component of shareholders' equity.
Net periodic pension cost for the years ended September 30, 1994, 1993 and 1992
included the following components:
<TABLE>
<CAPTION>
1994 1993 1992
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost benefits earned during the period $ 2,117 $ 2,031 $ 1,611
Interest cost on projected benefit obligation 4,263 3,923 3,755
Actual return on plan assets (1,986) (6,817) (4,818)
Net amortization and deferral (1,829) 2,883 1,394
- - ----------------------------------------------------------------------------------------------
Net periodic pension cost $ 2,565 $ 2,020 $ 1,942
Regulatory adjustment 22 (177) (99)
- - ----------------------------------------------------------------------------------------------
Net pension cost $ 2,587 $ 1,843 $ 1,843
- - ----------------------------------------------------------------------------------------------
Portion capitalized to utility plant $ 439 $ 328 $ 332
==============================================================================================
</TABLE>
<TABLE>
<CAPTION>
September 30, 1994 September 30, 1993
Plans Where: Plans Where:
- - ----------------------------------------------------------------------------------------------------------------
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
Actuarial present value of benefit obligation: Benefits Assets Benefits Assets
- - ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Vested benefit obligation $(43,249) $ (3) $(31,174) $(16,752)
- - ----------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation $(46,808) $(326) $(32,917) $(18,758)
- - ----------------------------------------------------------------------------------------------------------------
Actuarial present value of
projected benefit obligation $(54,337) $(758) $(41,540) $(18,758)
Plan assets at fair value 58,217 -- 38,738 17,913
- - ----------------------------------------------------------------------------------------------------------------
Projected benefits obligation in excess of
plan assets 3,880 (758) (2,802) (845)
Transition obligation 996 -- 750 415
Prior service costs 3,582 317 579 3,406
Unrecognized (gain) loss (2,983) (18) 3,045 (5)
Adjustment required to recognize minimum liability -- (101) -- (3,816)
- - ----------------------------------------------------------------------------------------------------------------
Prepaid pension cost (liability), net $ 5,475 $(560) $ 1,572 $ (845)
================================================================================================================
</TABLE>
Connecticut Energy Corporation
THIRTY THREE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
Key assumptions used in the determination of the projected benefit obligations
and the fair value of plan assets were:
<TABLE>
<CAPTION>
1994 1993
- - -------------------------------------------------------------
<S> <C> <C>
Discount rates 8 1/2% 7%
Salary increase rates 5 1/2% 5%
Expected rate of return on assets 9% 9 1/4%
- - -------------------------------------------------------------
</TABLE>
The significant majority of the assets of the pension plans is invested in
common stock, fixed income securities and balanced mutual funds, with the
balance in cash and short-term investments.
Effective October 1, 1993, Southern established non-qualified pension programs
to provide benefits on compensation in excess of the limitations imposed by the
Internal Revenue Code and to provide additional retirement income to designated
officers.
Southern maintains a savings plan covering substantially all of its employees
who meet minimum service requirements pursuant to which the participants may
elect to contribute to the plan, through payroll deductions, 2% or more of
their annual compensation either on an after-tax or before-tax basis as
permitted by Section 401(k) of the Internal Revenue Code. Participants receive
a matching contribution of 50% of the first 6% of annual compensation.
Participants vest over a five year period and benefits are paid to employees
upon retirement, death, disability or termination. Amounts expensed under the
plan were $795, $772 and $670 for years ended September 30, 1994, 1993 and
1992, respectively.
Postretirement Health Care Benefits
In addition to providing pension benefits, Southern provides certain health
care benefits for retired employees. Substantially all of the Company's
employees may become eligible for those benefits if they reach age 55 while
working for the Company and have completed at least 10 years of service. Prior
to October 1, 1993, Southern recognized the cost of providing these benefits
by expensing $350 annually in excess of paid medical claims in accordance with
funding provided by a rate decision in 1990.
Effective October 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other than Pensions" ("SFAS 106"), which requires accrual accounting
for postretirement benefits during the employee's years of service with
Southern. Southern has elected to amortize the transition obligation over 20
years. In the DPUC's Decision on Southern's latest rate request, Southern was
allowed current recovery of SFAS 106 costs through customer base rates which
became effective December 9, 1993. The expense of implementing SFAS 106 prior
to full recovery in rates, which amounted to $367, was deferred and is being
recovered over a three year period.
The postretirement benefit costs for the fiscal year ended September 30, 1994
includes the following components:
<TABLE>
<S> <C>
- - ----------------------------------------------------------
Service cost $ 598
Interest cost 1,282
Actual return on plan assets (113)
Net amortization and deferral 880
- - ----------------------------------------------------------
Net periodic postretirement benefit cost $2,647
Regulatory adjustment (275)
- - ----------------------------------------------------------
Net postretirement benefit cost $2,372
==========================================================
</TABLE>
In 1990, Southern amended the Pension Plan for Salaried and Certain Other
Employees to establish an account within the Pension Plan trust as permitted
under Section 401(h) of the Internal Revenue Code to fund a portion of
Southern's anticipated future postretirement benefit liability with amounts
allowed through the ratemaking process. Through the use of the existing trust
and the establishment of a Voluntary Employees' Benefit Association Trust as
permitted under Section 501(c)(9) of the Internal Revenue Code, Southern plans
to fund its full postretirement benefit expense under SFAS 106.
Connecticut Energy Corporation
THIRTY FOUR
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
The following table reconciles the funded status of the plans with the amount
recognized in the consolidated balance sheet as of September 30, 1994:
<TABLE>
<S> <C>
- - -----------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ (8,712)
Fully eligible active plan participants (3,262)
Other active plan participants (6,176)
- - -----------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation $(18,150)
Plan assets at fair value 1,333
- - -----------------------------------------------------------------------------------
Accumulated postretirement benefit obligation in excess of plan assets (16,817)
Unamortized transition obligation 16,592
Prior service cost --
Unrecognized (gain) loss (2,336)
- - -----------------------------------------------------------------------------------
(Accrued) postretirement benefit obligation $ (2,561)
===================================================================================
</TABLE>
The expected long-term rate of return on plan assets is 9%. The assumed initial
health care cost trend rates used to measure the expected cost of benefits in
1994 were 14% for pre-age 65 claims and 10% for post-age 65 claims. The rates
decline to 6% by the year 2010. The weighted average discount rate used to
measure the accumulated postretirement benefit obligation was 8.5%. A one
percentage point increase in the assumed health care cost trend rate would
increase the service cost and interest cost components of the net periodic
postretirement benefit cost by approximately $157 and would increase the
accumulated postretirement benefit obligation for health care benefits by
approximately $1,239.
Postemployment Benefits
In November 1992, the FASB issued Statement of Financial Accounting Standards
No. 112, "Employers' Accounting for Postemployment Benefits" ("SFAS 112"),
which will be effective for the Company's fiscal year ending September 30,
1995. The adoption of SFAS 112 is required by the first quarter of fiscal 1995,
and the Company intends to adopt this statement prospectively. This statement
establishes accrual accounting for benefits such as unemployment compensation,
severance benefits and disability benefits to former or inactive employees
after employment terminates but before retirement. The impact of this new
standard is not expected to have a material effect on the Company's financial
condition or results of operations.
NOTE 8 -- LEASES
Total rental expense was $2,864, $2,405 and $2,133 for the years ended
September 30, 1994, 1993 and 1992 respectively. Southern's approximate
aggregate minimum rental commitments (exclusive of taxes, maintenance, etc.)
under noncancelable operating leases for each of the five fiscal years
subsequent to September 30, 1994 are in total:
<TABLE>
<CAPTION>
Commitment Office space LNG plant Other
- - ---------------------------------------------------------------------
<S> <C> <C> <C>
1995 $ 2,003 $ 609 $312
1996 2,003 609 190
1997 2,003 304 1
1998 2,111 -- --
1999 2,110 -- --
Thereafter 31,397 -- --
- - ---------------------------------------------------------------------
Total commitment $41,627 $1,522 $503
=====================================================================
</TABLE>
On March 30, 1993, Southern entered into an operating lease for the purpose of
consolidating its operating centers at one location in Orange, Connecticut. The
consolidation occurred during the second quarter of fiscal 1994 and the initial
period of the lease is for 20 years.
In 1992, Southern entered into an operating lease which consolidated
administrative functions at one location in Bridgeport, Connecticut. The lease
period commenced in October 1992 and is for an initial period of 20 years.
Connecticut Energy Corporation
THIRTY FIVE
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
The Liquified Natural Gas plant lease agreement provides, among other things,
for an initial term of 25 years, which expires in December 1996, with an option
to renew the lease for two terms of 12 years each at rental rates based
primarily on the then fair market value of the plant. There is also an option,
from time to time, to purchase the plant for a purchase price based on the then
fair market value of the plant.
NOTE 9 -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
Amounts charged to costs and expenses for the years ended September 30, 1994,
1993 and 1992 included:
<TABLE>
<CAPTION>
1994 1993 1992
- - -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Maintenance and repairs $ 4,035 $ 3,692 $ 3,651
Depreciation and depletion 13,031 12,051 11,327
Property taxes 3,821 4,450 4,528
Connecticut gross earnings tax 10,506 9,349 8,690
Connecticut corporation business tax 1,464 347 945
Other taxes 213 210 151
Federal Insurance Contribution Act 2,198 2,090 2,111
Taxes capitalized as part of utility plant (424) (402) (400)
- - -------------------------------------------------------------------------------------------
</TABLE>
NOTE 10 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
Dec. 31 March 31 June 30 Sept. 30
1994 Quarter ended 1993 1994 1994 1994
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $66,714 $111,838 $36,835 $25,486
Gross margin 30,107 50,490 20,131 13,275
Operating income (loss) 8,072 16,730 1,779 (1,569)
Net income (loss) 4,998 13,753 (1,338) (4,570)
Net income (loss) per share* $ 0.67 $ 1.77 $ (0.16) $ (0.53)
- - ----------------------------------------------------------------------------------------------
<CAPTION>
Dec. 31 March 31 June 30 Sept. 30
1993 Quarter ended 1992 1993 1993 1993
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $64,163 $ 91,613 $33,779 $23,207
Gross margin 29,360 42,024 16,523 11,810
Operating income (loss) 8,549 14,916 915 (1,255)
Net income (loss) 5,837 11,711 (2,267) (4,228)
Net income (loss) per share* $ 0.80 $ 1.59 $ (0.31) $ (0.57)
- - ----------------------------------------------------------------------------------------------
<FN>
*Calculated on the basis of weighted average shares outstanding during the
applicable quarter.
</TABLE>
NOTE 11 -- DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate
that value:
Cash and short-term investments
The carrying amount 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 or on the current rates offered to
the Company for debt of the same remaining maturities.
Connecticut Energy Corporation
THIRTY SIX
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
The estimated fair values of the Company's financial instruments are as
follows:
<TABLE>
<CAPTION>
1994
- - ---------------------------------------------------------------------------------
Carrying Fair
Amount Value
- - ---------------------------------------------------------------------------------
<S> <C> <C>
Cash and short-term investments $ 1,637 $ 1,637
Long-term debt (including current maturities) (120,511) (124,905)
- - ---------------------------------------------------------------------------------
</TABLE>
NOTE 12 -- COMMITMENTS AND CONTINGENCIES
Take-or-Pay, Contract Buy-out and Contract Buy-down Costs
Prior to 1992, Southern deferred amounts paid to its interstate pipeline
suppliers related to take-or-pay, contract buy-out and contract buy-down costs
and accrued and deferred interest on its unrecovered payments. On November 20,
1991, the DPUC issued a Decision regarding the method of recovery of these
deferred amounts. The Decision did not provide recovery of incurred and
deferred interest.
As of September 30, 1994, Southern has recovered approximately $5,374 from firm
customers through the suspension of the flow-through of purchased gas credits,
$1,343 from the suspension of the flow-through of pipeline refunds and $602
from interruptible customers through the application of the uniform volumetric
surcharge in accordance with the DPUC Decisions. Approximately $726 will
continue to be recovered from interruptible customers through the uniform
volumetric surcharge.
Environmental Matters
Southern has identified coal tar residue at three sites in Connecticut. This
residue results from historic coal gasification operations conducted at those
sites by Southern's predecessors from the late 1800s through the first part of
this century. Many gas distribution companies throughout the country carried on
such gas manufacturing operations during the same period. The coal tar
discovered at Southern's three sites is not designated a hazardous material by
any federal or Connecticut agency, but some of its constituents are classified
as hazardous.
On April 27, 1992, Southern notified the Connecticut Department of
Environmental Protection and the United States Environmental Protection Agency
of the presence of coal tar residue on the three sites. As a result of this
notification, further discussions would address the extent and type of remedial
action, if any, as well as the time period for such action. Because this
process is at an early stage, management cannot at this time predict the costs
of any future site analysis and remediation, if any, nor when such costs, if
any, may be incurred. Such future analytical and clean-up costs could possibly
be significant.
Based upon the provisions of the Partial Settlement, management believes that
Southern will properly be able to recover the costs of investigation and
remediation, if any, from its customers. The method, timing and extent of any
recovery remain uncertain, but management currently does not expect that the
incurrence of such costs will have a material adverse effect on the Company's
financial condition or results of operations.
FERC Order No. 636 Transition Costs
As a result of Order No. 636 issued by the Federal Energy Regulatory Commission
("FERC"), costs are being incurred by Southern's interstate pipeline suppliers
to convert existing "bundled" sales services to "unbundled" transportation and
storage services. These transition costs include: (1) unrecovered gas costs,
(2) gas supply realignment costs, (3) stranded investment costs and (4) new
facilities costs.
Connecticut Energy Corporation
THIRTY SEVEN
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share)
Southern has incurred approximately $8,815 in transition costs as of September
30, 1994. Of this total, $4,468 represent unrecovered gas costs and $4,347
represent gas supply realignment costs and stranded investment costs. On July
8, 1994, the DPUC issued a Decision regarding implementation of FERC Order No.
636 by the Connecticut local gas distribution companies. The DPUC addressed,
among other things, the mechanism for the recovery of deferred transition
costs. Under this mechanism, the DPUC has allowed the recovery of the
unrecovered gas cost balances from the suspension of flow-through of purchased
gas cost credits attributable to the twelve month period ended August 31, 1993
and all future years ending August 31 as well as refunds received after October
1, 1993 from interstate pipelines. Additionally, any subsequent refunds from
interstate pipelines as well as any credits received by Southern for release
of its capacity on interstate pipelines shall be used to offset Southern's
payments of unrecovered gas costs until fully recovered. As of September 30,
1994, Southern has recovered approximately $4,468 in unrecovered gas costs
through a combination of these recovery mechanisms.
Gas supply realignment costs as well as stranded investment costs are to be
recovered by Southern as follows: (1) retention of 50% of margins derived
through off-system sales; (2) retention of 50% of all interruptible margins
earned above Southern's target level; (3) retention of pipeline refunds or
deferred gas costs credits for the 1992/93 period and all subsequent annual
deferred gas cost periods that are in excess of the estimated unrecovered gas
cost portion of transition costs; (4) retention of any capacity release credits
received from pipelines in excess of those needed for unrecovered purchased gas
costs and (5) if needed, a per unit surcharge applied to firm customers' bills,
which will be evaluated in subsequent annual deferred gas cost proceedings.
There is no hierarchy in the use of the first four recovery measures, and any
and all could be utilized as available. All subsequent annual deferred gas cost
credits will be applied on an annual basis. All other transition cost credits
will be immediately applied on a monthly basis to offset transition costs which
have been or will be subsequently billed. As of September 30, 1994, Southern
has recovered approximately $3,020 in gas supply realignment costs as well as
stranded investment costs through a combination of these recovery mechanisms.
Personal Property Tax Audits
In September 1993, Southern received notification of the results of audits by
the City of New Haven pursuant to Connecticut's omitted property statute. The
City of New Haven claimed that Southern owed approximately $2,600 in additional
personal property taxes related to years 1990 through 1992; however, Southern
was not aware of any audit finding of significant omitted personal property.
Instead, the City of New Haven's claim was based on the assessor's retroactive
reassessment of Southern's personal property. Southern initiated legal actions
against the City of New Haven which alleged that, among other things, the City
of New Haven had no statutory authority to issue tax bills based upon
retroactive reassessments of previously declared property on which taxes were
paid and that the City of New Haven's contingent fee agreement with the firm
which audited Southern's records was illegal. Southern also instituted legal
actions challenging the City of New Haven's assessment of Southern's personal
property for the 1993 Grand List.
On June 29, 1994, Southern and the City of New Haven entered into a Stipulation
and Agreement ("Agreement") in settlement of these court actions. The Agreement
provided for a $200 payment related to the tax years 1990 through 1992 without
conceding liability on any of the issues involved; and a resolution of the
disputed 1993 personal property assessment, which resulted in a reduction of
the original 1993 assessment of approximately $1,500 to a new assessment of
approximately $800.
Connecticut Energy Corporation
THIRTY EIGHT
<PAGE>
MANAGEMENT RESPONSIBILITY FOR
FINANCIAL STATEMENTS
The management of Connecticut Energy Corporation is responsible for the
preparation and integrity of the consolidated financial statements and all
other financial information included in this annual report. The financial
statements were prepared in conformity with generally accepted accounting
principles consistently applied and they necessarily include amounts which are
based on estimates and judgments made with due consideration to materiality.
Management maintains a system of internal accounting controls which it believes
provides reasonable assurance that Company policies and procedures are complied
with, assets are safeguarded and transactions are executed in accordance with
appropriate corporate authorization and recorded in a manner which permits
management to meet its responsibility for the preparation of financial
statements. The Company's system of controls includes the communication and
enforcement of written policies and procedures.
The Audit Committee of the Board of Directors, comprised of non-employee
directors, meets periodically and as necessary with management, the internal
auditors and Coopers & Lybrand L.L.P. to review audit plans and results and the
Company's accounting, financial reporting and internal control practices,
procedures and results. Both Coopers & Lybrand L.L.P. and the Company's
internal audit department have full and free access to all levels of
management.
S/ Carol A. Forest S/ Vincent L. Ammann, Jr.
Carol A. Forest Vincent L. Ammann, Jr.
Vice President, Finance, Vice President and
Chief Financial Officer and Treasurer Chief Accounting Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
of Connecticut Energy Corporation
We have audited the accompanying consolidated balance sheets of Connecticut
Energy Corporation and its subsidiaries (the Company) as of September 30, 1994
and 1993 and the related consolidated statements of income, changes in common
shareholders' equity and cash flows for each of the three years in the period
ended September 30, 1994. 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 Connecticut
Energy Corporation and its subsidiaries as of September 30, 1994 and 1993, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended September 30, 1994 in conformity with
generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, in fiscal 1994
the Company changed its methods of accounting for income taxes and
postretirement benefits other than pensions.
S /Coopers & Lybrand, L.L.P.
New Haven, Connecticut
November 1, 1994
Connecticut Energy Corporation
THIRTY NINE
<PAGE>
ELEVEN YEAR FINANCIAL SUMMARY
(Financial information presented for 1994 through 1990 is for the twelve month
period ended September 30; all information for prior years is for the twelve
month period ended December 31.)
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
1994 1993 1992 1991
-----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operations
Operating revenues $240,873 $212,762 $203,011 $179,172
Purchased gas 126,870 113,045 104,163 86,778
Gross margin 114,003 99,717 98,848 92,394
Operations and maintenance expenses 54,244 45,023 46,881 42,475
Depreciation and depletion 13,031 12,051 11,327 10,540
Federal income taxes 3,938 3,474 2,287 4,324
Other taxes 17,778 16,044 16,025 15,238
Other deductions and (income), net 586 510 531 349
Interest expense 11,575 11,530 11,536 10,428
Subsidiary preferred stock dividends 8 32 34 36
Income before cumulative effect of accounting change $ 12,843 $ 11,053 $ 10,227 $ 9,004
Cumulative effect of accounting change -- -- -- --
Net income $ 12,843 $ 11,053 $ 10,227 $ 9,004
Net income per share before cumulative
effect of accounting change (f) $ 1.58 $ 1.50 $ 1.43 $ 1.38
Net income per share (f) $ 1.58 $ 1.50 $ 1.43 $ 1.38
Annual dividend paid per common share (f) $ 1.29 $ 1.28 $ 1.265 $ 1.24
-----------------------------------------------------------------------------------------------------------------
*Capitalization
Common shareholders' equity $125,719 $ 99,853 $ 92,605 $ 88,622
Redeemable preferred stock -- 638 687 736
Long-term debt 119,917 120,511 94,106 87,378
-----------------------------------------------------------------------------------------------------------------
Total capitalization $245,636 $221,002 $187,398 $176,736
-----------------------------------------------------------------------------------------------------------------
*Capitalization (% of total)
Common shareholders' equity 51.2 45.2 49.4 50.1
Redeemable preferred stock -- 0.3 0.4 0.4
Long-term debt 48.8 54.5 50.2 49.5
-----------------------------------------------------------------------------------------------------------------
Total capitalization 100.0% 100.0% 100.0% 100.0%
-----------------------------------------------------------------------------------------------------------------
*Common Stock (f)
Shares outstanding at end of period 8,700,266 7,488,467 7,234,921 7,096,634
Book value per share at end of period $ 14.45 $ 13.33 $ 12.80 $ 12.49
Market value per share at end of period $ 21.63 $ 24.88 $ 22.25 $ 19.00
Average daily trading volume 5,500 9,000 4,500 5,000
Shareholders of record at year end 12,094 11,094 9,153 9,163**
Percent of institutional ownership 21 18 18 14
-----------------------------------------------------------------------------------------------------------------
Assets
Gross utility plant $331,953 $313,951 $293,687 $273,862
Net utility plant $234,495 $221,800 $210,054 $198,695
*Additions to utility plant (capital expenditures) $ 26,618 $ 26,070 $ 22,634 $ 20,331
Oil and gas properties, net -- -- $ 496 $ 542
Total assets $352,920 $299,795 $269,504 $247,969
-----------------------------------------------------------------------------------------------------------------
Ratios (% of total)
Gross margin as a % of operating revenues 47.3 46.9 48.7 51.6
Dividend payout as a % of earnings 81.6 85.3 88.5 89.9
Effective federal tax rate 23.0 24.0 18.0 32.0
*Return on ending common equity 10.2 11.1 11.0 10.2
Price to earnings 13.7 16.6 15.6 13.8
Dividend yield 6.0 5.1 5.7 6.5
Market price as a % of book value 149.7 186.6 173.8 152.1
-----------------------------------------------------------------------------------------------------------------
<FN>
*Information used in the National Association of Investors Corporation (NAIC)
stock selection format.
**A number of duplicated accounts were consolidated when the Company changed
Transfer Agents in July 1992.
(a) The results for both the year ended September 30, 1990 and December 31,
1989 include the results for the three months ended December 31, 1989,
which included the effects of the unusually cold weather experienced in
the month of December and a writedown of the value of oil and gas
properties.
(b) Includes the cumulative effect of accounting change for municipal property
taxes which increased earnings by $.21 per share.
(c) The writedown of the value of oil and gas properties reduced earnings by
$.10 per share in 1990 and 1989; $.05 per share in 1987; $.16 per share in
1984.
</TABLE>
Connecticut Energy Corporation
FORTY
<PAGE>
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------
(a)(b)(c) (a)(c) (c) (d) (e) (c)
<S> <C> <C> <C> <C> <C> <C>
$174,059 $171,218 $156,978 $157,867 $156,028 $163,847 $163,925
84,154 81,794 71,787 75,337 79,333 88,517 89,115
89,905 89,424 85,191 82,530 76,695 75,330 74,810
44,085 42,636 38,869 38,218 36,011 34,965 33,453
10,664 10,297 8,533 8,427 7,487 7,632 7,817
3,819 4,740 5,839 6,325 5,270 5,416 5,595
14,431 14,560 14,146 13,617 13,487 13,452 14,375
(228) 356 713 276 261 (12) 75
10,156 8,598 7,653 7,484 6,848 6,898 6,065
39 403 751 849 1,244 1,403 1,419
$ 6,939 $ 7,834 $ 8,687 $ 7,334 $ 6,087 $ 5,576 $ 6,011
1,280 -- -- -- 1,911 -- --
$ 8,219 $ 7,834 $ 8,687 $ 7,334 $ 7,998 $ 5,576 $ 6,011
$ 1.12 $ 1.28 $ 1.49 $ 1.38 $ 1.16 $ 1.21 $ 1.35
$ 1.33 $ 1.28 $ 1.49 $ 1.38 $ 1.53 $ 1.21 $ 1.35
$ 1.23 $ 1.20 $ 1.17 $ 1.12 $ 1.12 $ 1.07 $ 1.01
----------------------------------------------------------------------------------------------------------
$ 74,413 $ 75,001 $ 73,311 $ 61,187 $ 58,731 $ 55,573 $ 46,901
786 835 6,429 7,270 8,112 12,487 12,659
91,506 79,686 69,137 64,461 58,714 53,666 48,104
----------------------------------------------------------------------------------------------------------
$166,705 $155,522 $148,877 $132,918 $125,557 $121,726 $107,664
----------------------------------------------------------------------------------------------------------
44.6 48.2 49.2 46.0 46.8 45.7 43.5
0.5 0.6 4.3 5.5 6.4 10.3 11.8
54.9 51.2 46.5 48.5 46.8 44.0 44.7
----------------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
----------------------------------------------------------------------------------------------------------
6,250,161 6,176,665 6,088,017 5,346,879 5,277,276 5,209,677 4,517,781
$ 11.91 $ 12.14 $ 12.04 $ 11.45 $ 11.13 $ 10.67 $ 10.38
$ 16.63 $ 17.63 $ 14.50 $ 13.67 $ 16.00 $ 12.25 $ 11.42
2,950 4,200 2,850 2,550 4,500 3,150 2,250
7,382 7,493 7,662 7,577 7,960 7,778 7,702
15 16 16 13 N/A N/A N/A
----------------------------------------------------------------------------------------------------------
$255,446 $241,624 $222,236 $204,947 $191,589 $172,396 $156,492
$189,108 $181,358 $166,970 $155,289 $144,509 $130,415 $119,012
$ 23,102 $ 23,184 $ 19,471 $ 17,790 $ 20,543 $ 17,344 $ 13,567
$ 605 $ 698 $ 1,760 $ 1,889 $ 2,564 $ 3,026 $ 4,099
$229,600 $239,327 $214,458 $193,842 $186,449 $173,211 $161,976
----------------------------------------------------------------------------------------------------------
51.6 52.2 54.3 52.3 49.2 46.0 45.6
92.5 93.8 78.5 81.2 73.2 88.4 74.8
35.0 37.0 38.0 44.0 42.0 44.0 43.0
11.0 10.4 11.8 12.0 13.6 10.0 12.8
12.5 13.8 9.7 9.9 10.5 10.1 8.5
7.4 6.8 8.1 8.2 7.0 8.7 8.8
139.6 145.2 120.4 119.4 143.8 114.8 110.0
----------------------------------------------------------------------------------------------------------
<FN>
(d) Includes cumulative effect of accounting change for unbilled revenues which
increased earnings by $.37 per share. The writedown of the value of oil
and gas properties in 1986 reduced earnings by $.03 per share.
(e) The adoption of the new pension accounting standard in 1985 reduced pension
costs and increased earnings by $.09 per share when compared to 1984. The
writedown of the value of oil and gas properties reduced earnings by $.12
per share.
(f) Adjusted to reflect the Company's 3-for-2 stock split in October 1989 and a
2-for-1 stock split in May 1984.
</TABLE>
Connecticut Energy Corporation
FORTY ONE
<PAGE>
OPERATING DATA
<TABLE>
<CAPTION>
Sept. 30 Sept. 30 Sept. 30 Sept. 30 Sept. 30 Dec. 31
Years ended 1994 1993 1992 1991 1990 1989
- - ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Table 1
Percentage of Operating Revenues
- - ------------------------------------------------------------------------------------------------------------------------------
Purchased gas costs 52.7 53.1 51.3 48.4 48.4 47.8
Operations 20.8 19.4 21.3 21.7 23.0 22.6
Maintenance 1.7 1.7 1.8 2.0 2.3 2.3
Depreciation and depletion 5.4 5.7 5.6 5.9 6.1 6.0
Taxes 9.0 9.2 9.0 10.9 10.5 11.3
- - ------------------------------------------------------------------------------------------------------------------------------
Purchased gas costs and
operating expenses 89.6 89.1 89.0 88.9 90.3 90.0
- - ------------------------------------------------------------------------------------------------------------------------------
Interest expense and other
deductions, net 5.1 5.7 6.0 6.1 5.7 5.5
Earnings applicable to common
stock (a) 5.3 5.2 5.0 5.0 4.0 4.5
- - ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
Table 2
Analysis by Customer Class Averaged Over 12 Months
- - ------------------------------------------------------------------------------------------------------------------------------
Residential nonheating
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf* consumption per customer 23 24 24 24 26 26
Annual revenue per customer $ 317 $ 299 $ 300 $ 289 $ 290 $ 279
Rate per Mcf $ 13.74 $ 12.62 $ 12.35 $ 12.04 $ 11.32 $ 10.89
Margin per Mcf $ 8.36 $ 7.63 $ 7.52 $ 7.61 $ 7.13 $ 6.97
Annual number of customers 35,170 36,184 37,444 39,186 40,997 42,001
- - ------------------------------------------------------------------------------------------------------------------------------
Residential heating
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 115 110 108 97 108 110
Annual revenue per customer $ 1,187 $ 1,074 $ 1,045 $ 904 $ 941 $ 919
Rate per Mcf $ 10.35 $ 9.73 $ 9.70 $ 9.36 $ 8.69 $ 8.33
Margin per Mcf $ 5.03 $ 4.81 $ 4.81 $ 4.95 $ 4.56 $ 4.49
Annual number of customers 102,043 100,872 99,706 97,406 95,240 93,447
- - ------------------------------------------------------------------------------------------------------------------------------
Residential apartments
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 2,132 2,132 2,149 2,006 2,152 2,217
Annual revenue per customer $ 16,611 $ 15,294 $15,217 $ 13,401 $13,141 $12,764
Rate per Mcf $ 7.79 $ 7.18 $ 7.08 $ 6.68 $ 6.11 $ 5.76
Margin per Mcf $ 2.59 $ 2.35 $ 2.33 $ 2.38 $ 2.08 $ 2.02
Annual number of customers 751 751 739 725 707 694
- - ------------------------------------------------------------------------------------------------------------------------------
Commercial
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 452 444 435 387 415 409
Annual revenue per customer $ 3,826 $ 3,527 $ 3,440 $ 2,917 $ 2,902 $ 2,714
Rate per Mcf $ 8.47 $ 7.95 $ 7.90 $ 7.53 $ 6.99 $ 6.64
Margin per Mcf $ 3.15 $ 3.03 $ 3.02 $ 3.13 $ 2.85 $ 2.80
Annual number of customers 13,142 12,965 12,831 12,758 12,717 12,459
Annual number of heating customers 7,813 7,630 7,541 7,498 7,479 7,297
- - ------------------------------------------------------------------------------------------------------------------------------
Industrial firm
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 2,199 2,085 1,925 1,754 1,856 1,900
Annual revenue per customer $ 16,568 $ 14,935 $13,691 $ 11,812 $11,584 $11,202
Rate per Mcf $ 7.53 $ 7.16 $ 7.11 $ 6.73 $ 6.24 $ 5.89
Margin per Mcf $ 2.30 $ 2.30 $ 2.32 $ 2.40 $ 2.16 $ 2.10
Annual number of customers 1,274 1,283 1,287 1,305 1,334 1,314
Annual number of heating customers 731 728 716 716 722 702
- - ------------------------------------------------------------------------------------------------------------------------------
Interruptible and off-peak
- - ------------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 37,870 30,545 23,035 21,933 14,558 16,303
Annual revenue per customer $121,940 $105,892 $86,215 $104,186 $56,657 $57,061
Rate per Mcf $ 3.22 $ 3.47 $ 3.74 $ 4.75 $ 3.89 $ 3.50
Margin per Mcf $ 0.87 $ 0.88 $ 0.99 $ 1.39 $ 1.06 $ 0.82
Annual number of customers 184 152 136 127 136 145
- - ------------------------------------------------------------------------------------------------------------------------------
Number of total customers 152,564 152,207 152,143 151,507 151,131 150,059
Cost per Mcf of gas $ 4.22 $ 4.30 $ 4.02 $ 4.04 $ 3.71 $ 3.46
==============================================================================================================================
<FN>
*Mcf -- one thousand cubic feet; MMcf -- one million cubic feet
</TABLE>
Connecticut Energy Corporation
FORTY TWO
<PAGE>
OPERATING DATA
<TABLE>
<CAPTION>
Sept. 30 Sept. 30 Sept. 30 Sept. 30 Sept. 30 Dec. 31
Years ended 1994 1993 1992 1991 1990 1989
- - ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Table 3
Revenue by Customer Class
(dollars in thousands)
- - ------------------------------------------------------------------------------------------------------------------------
Residential $145,975 $131,632 $127,224 $110,062 $111,321 $110,392
Commercial firm 50,838 46,022 44,316 37,538 37,080 35,003
Industrial firm 21,339 19,180 17,696 15,557 15,527 15,236
- - ------------------------------------------------------------------------------------------------------------------------
Total firm revenue $218,152 $196,834 $189,236 $163,157 $163,928 $160,631
- - ------------------------------------------------------------------------------------------------------------------------
Interruptible, transportation
and special contract $ 21,127 $ 14,697 $ 12,478 $ 14,814 $ 9,103 $ 9,695
Other 1,594 1,231 1,297 1,201 1,028 892
- - ------------------------------------------------------------------------------------------------------------------------
Total operating revenues $240,873 $212,762 $203,011 $179,172 $174,059 $171,218
========================================================================================================================
Margin by Customer Class (b)
- - ------------------------------------------------------------------------------------------------------------------------
Residential $ 71,643 $ 63,391 $ 62,449 $ 57,153 $ 57,913 $ 58,310
Commercial firm 19,315 17,265 16,946 15,446 15,102 14,699
Industrial firm 6,688 6,111 5,794 5,491 5,379 5,431
- - ------------------------------------------------------------------------------------------------------------------------
Total firm margin $ 97,646 $ 86,767 $ 85,189 $ 78,090 $ 78,394 $ 78,440
- - ------------------------------------------------------------------------------------------------------------------------
Interruptible, transportation
and special contract $ 4,258 $ 2,427 $ 3,666 $ 5,302 $ 3,383 $ 3,121
- - ------------------------------------------------------------------------------------------------------------------------
Total margins $101,904 $ 89,194 $ 88,855 $ 83,392 $ 81,777 $ 81,561
========================================================================================================================
Table 4
Sources of Gas Supply in MMcf*
- - ------------------------------------------------------------------------------------------------------------------------
Tennessee Gas Pipeline 24 -- 1,873 2,249 4,546 4,511
Algonquin Gas Transmission 53 229 2,521 5,476 7,518 7,662
Texas Eastern -- 372 1,539 1,649 -- --
SCG Gas Quest -- -- -- -- 111 97
Distrigas 1,287 761 1,472 1,435 2,602 2,735
Producers/Marketers 17,213 14,958 13,750 11,505 8,394 8,623
Alberta Northeast 12,631 12,446 4,863 -- -- --
- - ------------------------------------------------------------------------------------------------------------------------
Total 31,208 28,766 26,018 22,314 23,171 23,628
========================================================================================================================
Additional storage supply:
LNG 86 12 269 2 (22) 392
Pipeline (c) (388) (1,362) (1,345) -- (6) 99
Propane -- 33 -- 2 113 45
- - ------------------------------------------------------------------------------------------------------------------------
Total additional supply (302) (1,317) (1,076) 4 85 536
- - ------------------------------------------------------------------------------------------------------------------------
Total supply 30,906 27,449 24,942 22,318 23,256 24,164
========================================================================================================================
Table 5
Gas Throughput in MMcf* (d)
- - ------------------------------------------------------------------------------------------------------------------------
Sales:
Residential 14,038 13,635 13,233 11,790 12,957 13,391
Commercial firm 5,902 5,786 5,583 4,935 5,269 5,234
Industrial firm 2,787 2,673 2,476 2,287 2,478 2,558
Interruptible, transportation
and special contract (e)(f) 10,509 6,296 7,992 8,784 6,668 6,310
Other uses (g) 1,066 712 517 521 572 617
- - ------------------------------------------------------------------------------------------------------------------------
Total requirements 34,302 29,102 29,801 28,317 27,944 28,110
========================================================================================================================
Peak day delivery in Mcf 227,477 203,557 182,688 189,192 177,616 177,616
- - ------------------------------------------------------------------------------------------------------------------------
Degree days -- actual 5,750 5,467 5,354 4,654 5,523 5,744
Degree days as percentage
of 'normal' 104% 99% 97% 85% 100% 104%
========================================================================================================================
<FN>
(a) Before nonrecurring credit in 1990.
(b) Margin in this table is calculated as revenue minus purchased gas costs and
gross receipts tax.
(c) Includes new storages acquired during 1992 and 1993 due to the
restructuring of services under FERC Order No. 636.
(d) Sales volumes from the residential, commercial firm and industrial firm
classes of customers reflect volumes delivered but not yet billed at year
end.
(e) Interruptible service balances daily available supply and demand sales.
Southern or the customer can terminate interruptible service at any time.
(f) Transportation volumes represent customer-owned gas transported directly to
end users which includes volumes under a special contract for
transportation to Connecticut Light and Power Company's Devon generating
station.
(g) Includes gas used by Southern and unaccounted for gas.
</TABLE>
Connecticut Energy Corporation
FORTY THREE
<PAGE>
GLOSSARY
Balancing -- The process of reconciling the difference between gas deliveries
contracted for and gas actually used on a daily basis.
FERC Order No. 636 -- A mandate issued by the Federal Energy Regulatory
Commission, effective November 1, 1993, which required pipeline companies to
separate or "unbundle" the functions of selling and transporting natural gas.
Firm Customers -- Customers with priority of supply using natural gas under
contracts which anticipate no interruptions.
Gross Margin -- For gas distribution business, operating revenues minus the
cost of purchased gas equals the gross profit margin. The cost of gas is
passed directly on to customers.
Heating Degree Days -- The mean temperature for a single day subtracted from 65
degrees Fahrenheit, the temperature at which the average household begins
using heat.
Interruptible Customers -- Large industrial or commercial customers that have
dual fuel capabilities whose service can be interrupted if capacity is needed
to serve firm customers.
LNG -- Liquified Natural Gas: natural gas liquified by reducing its temperature
to minus 260 degrees Fahrenheit.
Mcf -- One thousand cubic feet: a standard measurement of natural gas. MMcf:
million cubic feet. Bcf: billion cubic feet.
NGV -- Natural gas-powered vehicle.
Off-System -- Providing gas service to parties outside of a company's own
distribution system.
Throughput -- The amount of gas carried on a distribution system, including gas
sold to and transported for end users.
Transportation Volumes -- Customer-owned gas purchased from a supply source and
conveyed through a pipeline or distribution system.
Weather Normalization Adjustment (WNA) -- Formula which adjusts customers'
monthly bills to reflect normal weather patterns (based on the 30-year average
temperature for each billing period), lowering bills during periods of colder
than normal weather and raising them during warmer than normal periods.
Connecticut Energy Corporation
FORTY FOUR
<PAGE>
INVESTMENT INFORMATION
To obtain a copy of Form 10-K filed with the Securities and Exchange Commission
or to request further financial information contact Judith Falango, Manager,
Investor and Shareholder Relations, Connecticut Energy Corporation, P.O. Box
1540, Bridgeport, CT 06601, or call (203) 579-1732.
NAIC Stock Selection Data
The National Association of Investors Corporation (NAIC) is an organization
with over 250,000 members which provides investment education for the long-term
value-oriented investor in common stock. As a corporate member of NAIC, the
following data is presented in NAIC's stock selection format. Historical
balance sheet data can be found on pages 40 and 41 in the Eleven Year Financial
Summary. Connecticut Energy Corporation was honored for two years in a row to
have its 1991 and 1992 annual report chosen by NAIC members as one of only five
"National Winners" for the Nicholson Awards.
Connecticut Energy is also a participant in NAIC's "Low Cost Investment Plan"
which encourages members to make regular contributions to dividend
reinvestment and stock purchase plans such as ours.
<TABLE>
<CAPTION>
Income-Revenue Data Common Share Data
====================================================================================================================
Gross margin Pretax (fed.) net Price range P-E ratio
------------ ----------------- ----------- ---------
Income Net Divi- % Yield
$ $ per $ % of tax income Earned dend Pay- on avg. $ $
Year mil. share(a) mil. g.m. $ mil. $ mil. $ $ out price high low high low
====================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1989 89.4 14.61 12.5 14.0 4.7 7.8 1.28 1.20 94 7.4 18 7/8 14 14.6 10.9
- - --------------------------------------------------------------------------------------------------------------------
1990 89.9 14.52 10.7 11.9 3.8 8.2(a) 1.33(a) 1.23 92 7.4 18 7/8 14 1/2 14.2 10.9
- - --------------------------------------------------------------------------------------------------------------------
1991 92.4 14.11 13.3 14.4 4.3 9.0 1.38 1.24 90 7.4 19 3/8 14 1/4 14.0 10.3
- - --------------------------------------------------------------------------------------------------------------------
1992 98.8 13.85 12.5 12.7 2.3 10.2 1.43 1.265 88 5.8 24 3/4 18 5/8 17.3 13.0
- - --------------------------------------------------------------------------------------------------------------------
1993 99.7 13.52 14.6 14.6 3.5 11.1 1.50 1.28 85 5.5 26 1/2 20 1/8 17.7 13.4
- - --------------------------------------------------------------------------------------------------------------------
1994 114.0 14.02 16.8 14.7 3.9 12.8 1.58 1.29 82 5.6 26 20 16.5 12.7
- - --------------------------------------------------------------------------------------------------------------------
5 Yr.
avg. 99.0 14.00 13.6 13.7 3.6 10.3 1.44 1.26 87 6.3 23 1/8 17 1/2 15.9 12.1
- - --------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Quarterly Financial Information
=================================================================================================================
Pretax (fed.)
Gross margin $ mil. net income $ mil. Earned per share $ Dividends paid per share $
Quarter -------------------- -------------------- -------------------- --------------------------
ended 1994 1993 1992 1994 1993 1992 1994 1993 1992 1994 1993 1992
=================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12/31 30.1 29.4 27.2 7.2 8.1 5.7 .67 .80 .57 .320 .320 .312
- - -----------------------------------------------------------------------------------------------------------------
3/31 50.5 42.0 41.2 20.0 16.3 14.8 1.77 1.59 1.50 .320 .320 .312
- - -----------------------------------------------------------------------------------------------------------------
6/30(b) 20.1 16.5 18.2 (2.7) (3.5) (1.7) (.16) (.31) (.14) .325 .320 .320
- - -----------------------------------------------------------------------------------------------------------------
9/30(b) 13.3 11.8 12.2 (7.7) (6.3) (6.3) (.53) (.57) (.49) .325 .320 .320
- - -----------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
================================================================================================================
Market price $
--------------------------------------------------------------------- Trading volume
Quarter 1994 1993 1992 in thousands
ended high low close high low close high low close 1994 1993 1992
================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
12/31 26 23 24 7/8 23 1/2 20 1/8 23 20 3/8 18 5/8 20 1/4 266.3 282.8 285.7
- - ----------------------------------------------------------------------------------------------------------------
3/31 25 20 21 1/4 25 3/8 22 1/2 25 1/8 21 7/8 18 7/8 21 1/4 508.7 892.5 317.2
- - ----------------------------------------------------------------------------------------------------------------
6/30 22 1/2 20 1/4 20 1/4 26 1/2 24 5/8 25 1/8 22 5/8 19 1/2 22 3/8 336.3 289.4 229.5
- - ----------------------------------------------------------------------------------------------------------------
9/30 22 1/4 20 1/4 21 5/8 26 24 3/8 24 7/8 24 3/4 21 5/8 22 1/4 262.2 543.0 275.5
- - ----------------------------------------------------------------------------------------------------------------
<FN>
(a) Includes the cumulative effect of accounting change in 1990.
(b) It is not unusual for a company primarily engaged in the distribution of
natural gas to incur a loss in quarters ending in June and September.
</TABLE>
Connecticut Energy Corporation
FORTY FIVE
<PAGE>
SHAREHOLDER INFORMATION
Annual Meeting
The Annual Meeting of Shareholders will take place Tuesday, January 31, 1995 at
10 a.m. in the Trumbull Marriott Hotel, 180 Hawley Lane, Trumbull, Connecticut.
Stock Listing Information
Connecticut Energy's common stock is listed on the New York Stock Exchange
under the ticker symbol "CNE". Quotes may be obtained in daily newspapers where
it is listed under "ConnEn" in the New York Stock Exchange composite table.
Shareholder Communications
In addition to the Connecticut Energy Corporation annual report, three
quarterly reports are published for shareholders. These reports are
automatically mailed to shareholders of record. If your shares are held in your
broker's name, you may receive quarterly reports by calling Connecticut Energy
collect (203) 579-1732 and requesting to be put on our mailing list for
quarterly reports.
Transfer Agent
The First National Bank of Boston (Bank of Boston) is the Transfer Agent and
Registrar for Connecticut Energy Corporation (CNE) common stock. No stock
transfer or shareholder account activity takes place at the Connecticut Energy
Corporation offices.
For the fastest response to any of the following needs:
Call Bank of Boston investor relations representatives toll free at:
(800) 736-3001 or
(800) 952-9245 TTY/TDD service for the hearing impaired
If you need
* to change your account mailing address
* to report a lost or stolen dividend check or stock certificate
* information about your shareholder account
* information about transferring shares
* an authorization form to join our Dividend Reinvestment and Stock
Purchase Plan
* a form to initiate the direct deposit of dividends
Or write Bank of Boston, Investor Relations, Mail Stop 45-02-09, P.O. Box 644,
Boston, MA 02102-0644
Dividends
Dividends on common stock are declared quarterly by the Board of Directors and
are usually paid on the last business day of each quarter. Shareholders of
record receive dividends directly from the Company's Transfer Agent, Bank of
Boston, unless they have elected to reinvest their dividends through the
Dividend Reinvestment and Stock Purchase Plan.
Direct Deposit
Your dividends can be directly deposited to your checking or savings account.
This not only gives you the availability of funds the same day they are paid,
it eliminates the worry of lost, stolen or mail delayed checks. Call Bank of
Boston at the toll free numbers above for an authorization form. Allow four to
six weeks for this to be in effect.
Connecticut Energy Corporation
FORTY SIX
<PAGE>
SHAREHOLDER INFORMATION (CONTINUED)
Dividend Reinvestment and Stock Purchase Plan
This Plan provides shareholders of the Company's common stock with a simple and
convenient method of investing dividends and/or voluntary cash contributions in
additional shares of the Company's stock without payment of any brokerage
commission or service charge.
Some important features of the Plan:
* Cash contributions are invested monthly.
* Voluntary cash contributions from $50 to $50,000 can be made.
* Bank draft authorization allows for automatic contributions to the Plan.
* A "safekeeping" feature allows shareholders to have Bank of Boston hold
their certificates.
* Shareholders can establish or roll over Individual Retirement Accounts (IRA)
through the Plan.
You must be a shareholder of record -- that is, the shares must be registered
in your name, not your broker's -- to participate. The total return graph
below shows the value of reinvesting dividends over time. $1,000 invested in
Connecticut Energy ten years ago (September 1984) would have grown to $2,027 at
the end of ten years. With dividends reinvested, the value of the same initial
investment would have grown to $4,100 in the same time period.
VALUE OF $1,000 INVESTED SEPT. 30, 1984
CHART
Initial Reinvested Stock
Investment Dividend Price
- - ----------------------------------------------
9/84 1000.000 0 1000.000
9/85 1156.254 106.0263 1262.280
9/86 1460.943 257.6324 1718.575
9/87 1390.630 363.4785 1754.109
9/88 1343.755 491.6461 1835.401
9/89 1687.510 802.2411 2489.751
9/90 1558.603 916.7809 2475.384
9/91 1781.261 1261.361 3042.622
9/92 2085.950 1691.373 3777.323
9/93 2332.045 2115.926 4447.971
9/94 2027.356 2072.708 4100.064
To receive additional information describing the Plan, including a prospectus
and enrollment information, call Bank of Boston toll free at (800) 736-3001 or
(800) 952-9245 TTY/TDD service for the hearing impaired.
Investment Dates
Cash contributions sent to purchase additional shares of stock through the
Dividend Reinvestment and Stock Purchase Plan are usually invested on the last
business day of the month. Checks for these purchases must be received by Bank
of Boston at least five business days before the investment date. Checks
received after the cut off date will be held until the next investment date.
Gift Certificates
If you are transferring shares of stock from your Dividend Reinvestment and
Stock Purchase Plan (Plan) account as a gift, we would be happy to supply you
with a gift certificate. This allows the actual shares to remain in safe-
keeping in a Plan account for the recipient. For further information call
Connecticut Energy Corporation collect at (203) 579-1732. Allow two weeks for
the transfer to occur.
Connecticut Energy Corporation
FORTY SEVEN
<PAGE>
CORPORATE DIRECTORY
Board of Directors
- - -----------------------------------
Connecticut Energy Corporation and
The Southern Connecticut Gas Company
J.R. Crespo
Chairman, President and Chief Executive
Officer, Connecticut Energy Corporation and
The Southern Connecticut Gas Company
Henry Chauncey, Jr.
Lecturer and Head of Management Program,
Department of Epidemiology and Public Health,
Yale School of Medicine
James P. Comer, M.D.
Maurice Falk Professor of Psychiatry, Yale
Child Study Center and Associate Dean,
Yale School of Medicine
Richard F. Freeman
President and Chief Executive Officer,
Bridgeport Area Foundation
Richard M. Hoyt
President and Chief Executive Officer,
Chapin & Bangs Company
Paul H. Johnson
President and Chief Executive Officer,
Gaylord Hospital
Newman M. Marsilius III
President and Chief Executive Officer,
The Producto Machine Company
Samuel M. Sugden
Chairman,
LeBoeuf, Lamb, Greene & MacRae L.L.P.
Christopher D. Turner
Regional Manager,
Resource Management International
Helen B. Wasserman
Member, Board of Governors for Higher
Education, State of Connecticut
Officers
- - ---------------------------------------------------------
Connecticut Energy Corporation
J.R. Crespo
Chairman, President and
Chief Executive Officer
Vincent L. Ammann, Jr.
Vice President and
Chief Accounting Officer
Carol A. Forest
Vice President, Finance,
Chief Financial Officer and Treasurer
Michael H. Pinto
Vice President, Government Affairs
J. Richard Tiano
Vice President, General Counsel and
Secretary
The Southern Connecticut
Gas Company
J.R. Crespo
Chairman, President and
Chief Executive Officer
Thomas A. Trotta
Senior Vice President and
Chief Operating Officer
Vincent L. Ammann, Jr.
Group Vice President, Corporate Planning
and Administration
Carol A. Forest
Vice President, Finance,
Chief Financial Officer and Treasurer
J. Richard Tiano
Vice President, General Counsel and
Secretary
Frank L. Esposito
Vice President, Human Resources and
Corporate Services
James P. Healy
Vice President, Information Technology
Ernest W. Karkut
Vice President, Purchasing and Plant Services
Peter D. Loomis
Vice President, Distribution and
Customer Service
Larry S. McGaughy
Vice President, Marketing and Corporate Engineering
Phyllis A. O'Brien
Vice President, Accounting and
Regulatory Services
Independent Accountants
- - -----------------------------------------
Coopers & Lybrand L.L.P.
2 Whitney Avenue
New Haven, CT 06510
Labor Union Leadership
- - -----------------------------------------
United Steel Workers of America
Local 12000
Gabriel Gambardella
President
Francis J. O'Connor
Vice President
[RECYCLE LOGO]
Continuing our commitment and concern for the environment as an integral part
of our business responsibility, this entire document was printed on recycled
paper containing 50% recovered fiber.
Connecticut Energy Corporation
FORTY EIGHT
<PAGE>
[LOGO] Connecticut Energy Corporation
855 Main Street
Bridgeport
Connecticut 06604
Special Olympics
World Games
Connecticut 1995
[LOGO]
TM
Official Provider
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