Connecticut Energy Corporation
Avenues of Opportunity
1995 Annual Report
Business Profile
Connecticut Energy Corporation (Connecticut Energy or Company)
is a holding company primarily engaged in the retail distribution of natural
gas for residential, commercial and industrial uses through its principal
subsidiary, The Southern Connecticut Gas Company (Southern). Southern
delivers natural gas in 22 Connecticut communities to approximately
154,000 customers which include approximately 175,000 firm residential
units. The Company also has two nonutility subsidiaries, Connecticut Energy
Development Corporation and Total Energy Services Group, Inc.
[MAP]
In towns currently served
Square miles 524
Population 770,870
Number of households 322,636
Miles of gas main in service 2,082
In Connecticut
Square miles 5,012
Population 3,275,276
Number of households 1,351,825
-- Algonquin Gas Transmission Co.
-- Iroquois Gas Transmission Co.
-- Tennessee Gas Pipeline Co.
Dividends
Connecticut Energy, 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 1995, the Company paid its 343rd 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 1994, Connecticut Energy was selected for inclusion in the newly
formed Standards & Poor's SmallCap 600 index. Investment and Shareholder
Information is on pages 41 and 42.
Highlights
Years ended September 30, 1995 1994 % Change
Financial (dollars in thousands, except per share)
Operating revenues $232,093 $240,873 (3.6)
Gross margin 116,510 114,003 2.2
Net income 14,060 12,843 9.5
Net income per share 1.60 1.58 1.3
Dividends paid per share 1.30 1.29 0.8
Total assets 370,088 352,920 4.9
Common shareholders' equity 131,561 125,719 4.6
Long-term debt 119,322 119,917 (0.5)
Total capitalization 250,883 245,636 2.1
Return on average common equity (%) 10.52 10.84 (3.0)
Other
Weighted average common shares outstanding 8,773,878 8,134,021 7.9
Shares outstanding at year end 8,865,210 8,700,266 1.9
Shareholders of record 11,688 12,094 (3.4)
Shareholders in dividend reinvestment plan 6,683 6,621 0.9
Institutional ownership (shares) 1,860,000 1,842,000 1.0
Average number of customers 154,216 152,564 1.1
Number of employees at year end 532 572 (7.0)
Earnings
Dollars Per Share
[CHART]
2.00
1.50 1.33 1.38 1.43 1.50 1.58 1.60
1.00
0.50
0.00
'90 '91 '92 '93 '94 '95
Net Income
Dollars In Thousands
[CHART]
15,000 14060
12,000 11053 12843
9,000 8219 9004 10227
6,000
3,000
0
'90 '91 '92 '93 '94 '95
To Our Shareholders
[PHOTO]
Fiscal 1995 marked the evolution of a new era in the natural gas industry and
the onset of a new direction for our Company. Our primary focus last year was
to position Connecticut Energy Corporation to compete successfully in the
market-driven business environment of the future. Throughout the year, we
achieved numerous accomplishments to strengthen our core foundation, while
creating the building blocks to capitalize on new growth opportunities and to
secure future energy markets.
Let me begin by highlighting our performance over the past year. It gives me
great pleasure to report that Connecticut Energy Corporation once again
achieved record earnings. Net income grew to a record level of $14,060,000,
which produced record earnings of $1.60 per share of common stock. Fiscal 1995
marks the sixth consecutive year in which we have achieved our goal to maintain
steady growth in earnings in spite of external variables. I know of no other
gas distribution company in the United States that will be able to make this
claim.
Unprecedented Growth
Changes in the marketplace and regulatory environment were clearly reflected
in the dramatic growth in our volumes. Our total throughput of approximately 50
billion cubic feet (Bcf) represented an increase of 50 percent over last year's
record level. Sales and transportation services to nonfirm customers -- both on
and off-system -- surpassed all previous records at 29.7 Bcf, representing 60
percent of total throughput.
Clearly, the source of future growth has changed significantly over the past
year. In order to remain competitive, we must be able to provide a broad array
of service options to customers in addition to traditional sales and
transportation services.
The New Energy Business
The energy business of the future will operate very differently than it has,
and the concept of the local utility as the only source of energy will
eventually disappear. Options will exist to meet heating, cooling and vehicular
energy demands. The level of sophistication of customers will increase as they
look for competitive pricing, outstanding service and a commitment from their
energy provider to meet their needs.
Our Company has positioned itself to respond to these needs -- in effect, to
provide a total energy service, far beyond what we can deliver now. Our level
of success will depend in large part upon our ability to recognize and make the
most of our business strengths. Accordingly, we will build on our outstanding
reputation and expertise in providing the services necessary to meet the needs
of existing and future customers.
The natural gas industry has already changed significantly. The unbundling of
supply and transportation on interstate pipelines has resulted in sales
off-system, capacity release arrangements and other innovative strategies that
have benefited our customers and the Company. In addition, many aspects of our
business have been simplified and made more efficient by improving technology.
These developments underscore that the traditional rules of "business as usual"
will not survive in the natural gas industry of tomorrow. Ongoing
organizational review and restructuring continue to prepare our Company for
this challenge.
The Approach
The three areas which our Company will focus its efforts to capitalize on
opportunities in the new energy business are: (1) coordination of natural gas
purchasing and sales efforts; (2) maximization of off-system sales through
effective use of our strategically located storage capacity; and (3) expansion
of our operations from a local natural gas distribution company to a regional
provider of total energy services.
This approach utilizes our existing facilities and business strengths,
specifically the expertise the Company and its predecessors have gained from
nearly one hundred fifty years in the energy business. At the same time, we
recognize the advantage of establishing strategic joint ventures that will
allow us to benefit from the skills and resources of other players in the
energy business. The key to growing our new business can be summed up in three
words: cooperate, optimize and diversify.
2
Cooperate: East Coast Natural
Gas Cooperative, L.L.C.
Early in fiscal 1995, we created a new subsidiary, Connecticut Energy
Development Corporation, to pursue investment opportunities related to the
purchase and sale of natural gas supplies both in and out of Connecticut. One
of the initial ventures of this subsidiary was to join with seven other East
Coast companies to form a cooperative to ensure reliability by sharing
resources and to purchase, sell and store gas supplies for the individual and
collective advantage of the members. This venture, the East Coast Natural Gas
Cooperative, L.L.C. (Coop), has enabled our Company to procure and negotiate
favorably priced, high volume gas supply purchases. We expect our participation
in the Coop will continue to reduce gas costs while ensuring supply during peak
times.
Optimize: LNG Facility Joint Venture
Storage capacity is perhaps the most valuable asset in the deregulated
natural gas industry. Effective use of our liquified natural gas (LNG) facility
will be critical to our future success. Accordingly, we have been assessing and
planning how best to maximize this facility, strategically located astride a
major interstate pipeline in the center of our service territory. The LNG
facility presents marketing opportunities beyond our distribution system and,
in fact, has the potential to become a "hub" for peaking services through the
use of the interconnections we have with three major interstate pipelines.
Until now, the LNG facility was considered for regulatory purposes to be part
of our distribution system and an intrastate facility; thus, its uses were
limited. We are presently engaged in the process of expanding the use of this
facility to include interstate transactions. Together with a joint venture
partner, we will seek the necessary state and federal approvals to expand the
use of the LNG facility outside of our service territory and beyond state
lines. With storage in the Northeast at a premium, we are confident that this
venture will serve us well with many customers in this region.
Diversify: Total Energy
Services Group, Inc.
In August 1995, Connecticut Energy Corporation created Total Energy Services
Group, Inc. In addition to participating in the LNG joint venture, this
subsidiary will enable us to offer complete energy services to commercial and
industrial customers throughout Connecticut and New England.
We have studied the market and concluded that customers are looking for a
"total energy" provider. As the gas industry "unbundles," we will be in an
excellent position to provide value to customers by managing their total energy
needs. We will evaluate a customer's particular requirements, recommend and
negotiate equipment acquisitions, service that equipment, and plan and manage
the optimal total energy package for that business including managing its air
emissions credits. This venture offers us the opportunity to capitalize on our
expertise and elevate our Company to a position of leadership, innovation and
excellence in the new energy marketplace.
Performance for Our Shareholders
Providing value to our shareholders over the long term continues to be our
primary corporate objective. For six years we have shown consecutive earnings
per share growth, and we have succeeded in dramatically reducing our dividend
payout ratio, while at the same time maintaining dividend growth at the
industry average. We have also been successful in strengthening our financial
profile and improving our fundamentals as a result of our consistent annual
growth in earnings.
Just as our marketplace has changed with the emergence of deregulation, so
too has the risk and return profile of utilities. Greater earnings volatility
can be expected as competition emerges and intensifies, and dividend payout
targets have been lowered to accommodate a potentially less predictable stream
of earnings. Investors will begin to expect a greater portion of their total
return to come from price appreciation in the future.
Drawing the Roadmap for Tomorrow
The demands of our industry's transformation require a company that is
willing to accept and embrace change. Today we are on the verge of initiating a
plan that aggressively and creatively responds to the industry challenges and
opportunities of tomorrow.
It is imperative that I take this opportunity to thank the members of our
Board of Directors for their strong support and contribution to our
performance during a particularly challenging and exciting year. Equally
important, I would like to thank our union employees, especially the union
leadership, for their strong commitment to the success of the Company.
Supported by all our dedicated employees and our strong resources, Connecticut
Energy Corporation is focused on the horizon. As we chart our course through
the landscape of change, we hold in our hands a clear roadmap to guide us in
securing future energy markets.
/s/ J. R. Crespo
J. R. Crespo
Chairman, President and
Chief Executive Officer
3
Capacity and Supply Management
Connecticut Energy Corporation and its principal subsidiary, The Southern
Connecticut Gas Company (Southern), are located at the gateway to New England.
Our location, combined with direct connections to the three interstate
pipelines which transport natural gas into our system and the rest of New
England, gives us a unique strategic advantage. In addition, we have a storage
facility in the center of our service area from which we can provide load
balancing and certain hub services. We have researched the most profitable
direction in which to use this specific combination of resources, and we have
developed an approach which effectively utilizes our existing facilities and
business strengths.
In the last few years we have seen our firm sales volumes remain between 20
and 23 billion cubic feet (Bcf). The growth in nonfirm sales, transportation
and off-system deliveries, however, has been dramatic. In fiscal 1993, the
first year in which our supply contracts were unbundled, our nonfirm
deliveries were approximately 6 Bcf. At the end of fiscal 1994, we began to
supply another electric generating station, and our nonfirm deliveries
increased to 10.5 Bcf. This year marked the first full year in which the
Connecticut Department of Public Utility Control (DPUC) allowed us to make
off-system sales, and nonfirm deliveries more than doubled to 29.7 Bcf.
Although the volumes are significant, per unit margins on nonfirm deliveries
are smaller than on firm sales. Therefore, we have taken steps to create new
business units to generate additional margins and profits. If we are to
continue our goal of year-over-year growth in earnings, we must be able to
augment our regulated earnings capacity with contributions to earnings from
new unregulated growth opportunities.
Total Throughput
Billion Cubic Feet (Bcf)
[CHART]
50 29.68
20.02
40
10.51
30 6.30 22.73
22.09
20
10
0
'93 '94 '95
// Firm
// Nonfirm
4
"We enjoy the unique strategic advantage of having
direct connections to New England's three interstate
pipelines and a storage facility, providing significant
opportunities for growth."
As part of our research, we have identified potential partners with whom
joint ventures can be formed to complement our resources. In the past year, we
created two new non-regulated subsidiaries, Connecticut Energy Development
Corporation (CEDC) and Total Energy Services Group, Inc. CEDC was formed
principally to obtain an equity interest in the East Coast Natural Gas
Cooperative, L.L.C., an alliance of eight local distribution companies (LDCs)
which will share resources, purchase gas collectively and take advantage of
marketing opportunities. As a result of this participation, we have realized
gas cost savings from discounts to indexed gas prices.
We spent a great deal of time in 1995 to create the preliminary building
blocks for the development of a total energy subsidiary. Market research has
indicated enormous potential within and outside of Southern's service territory
for providing energy commodities and services to large commercial and
industrial customers. We expect this subsidiary to be operational in early
fiscal 1996.
Another major undertaking throughout 1995 was our work to create a joint
venture opportunity utilizing our LNG facility. We are in the process of
preparing contracts and the necessary regulatory filings. An important
component of this project is the completion of a 20" main which will tie our
expansion alternatives to areas with the greatest growth potential and enable
us to move gas more readily throughout our system.
5
Deregulation and Emerging Markets
Deregulation
The Connecticut DPUC continues to be one of the more progressive utility
regulatory bodies in the United States. The natural gas distribution companies
in the state have worked with the DPUC over the last year to develop a
framework of unbundled rates that will be in place in fiscal 1996 for all
commercial and industrial customers.
In essence, unbundling will provide a new two-way avenue of opportunity. In
one direction, we are able to provide services and supplies for commercial and
industrial businesses outside of our franchise area as well as those we
currently serve. In the other direction, if the businesses Southern serves find
they can purchase supplies more economically from another entity, they will
have the ability to do so. Since our distribution system is needed to convey
the supplies, however, Southern will receive transportation margins. The rates
for our new firm transportation service have been designed to protect
Southern's margins. We will receive the same margin from firm transportation
service as we do from firm sales to commercial and industrial customers, which
significantly minimizes our risk.
As our Company and our industry move further into the competitive energy
market, there is an additional challenge to address: the issue of maintaining a
competitive edge while shouldering the government imposed business costs which
other energy suppliers do not bear. These societal costs come in a variety of
forms, the most burdensome of which are hardship customer costs and arrearage
forgiveness plans. Historically, these costs have been embedded in Southern's
rate structure during years when revenues and customers were virtually
assured. In this competitive environment, however, we need to peel away these
cost layers.
We have been working with our legislators and regulators to remove these
burdens which distort the price of our service. We succeeded in having
legislation passed which requires out-of-state marketers to pay gross earnings
tax, and we were responsible for a bill which lowers the tax on natural gas
sold as motor fuel. These are just two examples of our vigilance in leveling
this competitive playing field.
Emerging Markets
We have seen a marked increase in deliveries of natural gas to two of the
electric generating plants located in Southern's territory. In fiscal 1994,
6
"Deregulation and our unique combination of
resources are enabling us to pursue new avenues
of opportunity."
these deliveries were under 4 Bcf but rose to 19 Bcf in fiscal 1995. We have
also made progress in the cogeneration market. After lengthy negotiations with
Yale University to provide natural gas to their planned 13.5 megawatt
cogeneration facility, we have crossed the first hurdle in this process. This
spring, the DPUC approved our contract, allowing us to go forward with further
planning.
We are gradually expanding our cooling market with a number of new
applications installed this year. Quinnipiac College (pictured on page 9)
installed two-300 ton natural gas absorption chillers in its new School of Law
Center, after noting the energy cost savings from installing similar units in
its School of Business two years ago.
Desiccant dehumidification units, which are more efficient than conventional
cooling, have been installed in supermarkets, retail stores and a university
library. With this type of cooling, not only is the air cooled, but humidity is
extracted from the air allowing a more comfortable environment at a more
economical temperature setting. Hospitals, nursing homes and an ice skating
rink are other locations with which we have negotiated for cooling
installations this year. In total, we have added 927 tons of cooling in fiscal
1995.
The natural gas vehicle (NGV) market continues to expand as the foundation
infrastructure grows. In addition to previous contracts to provide fuel for
vehicles owned by a local telephone utility and for the 62 postal trucks in
East Haven, we signed a five year contract this year with the town of
Westport. Under that contract, we installed a fueling station, which will serve
the town's 10 new dual-fuel transit district buses, eight of the town's police
department vehicles and eventually other municipal vehicles. "Fuelmaker" units,
which are small on-site overnight fueling stations, have also been installed
for two local water company fleets, and we are continuing discussions with
several other fleet owners.
7
Traditional Markets
Our residential customer base continues to be the foundation of our revenues
and margins. Since the majority of these customers use natural gas for space
and water heating, they provide a steady and stable revenue stream. This allows
us a significant advantage over distribution companies with a larger commercial
and industrial base. Even with extreme variations in temperatures, our Weather
Normalization Adjustment (WNA) eliminates the risk of weather related margin
loss for the Company and the risk of excessive heating bills for the customer.
Thus, we have firm margins we can count on while we aggressively pursue
additional nonfirm business and new markets. In fiscal 1994, the WNA worked to
the benefit of our customers. In fiscal 1995, it benefitted the Company and
its shareholders. Southern is the only gas distribution company in New England
to have weather normalization.
Southern added nearly 2,400 new residential heating customers during fiscal
1995 by continuing promotions to noncustomers along mains, particularly
condominium owners who use electricity for heating. We expect to add about the
same number in the coming year, again mainly from existing homes along our
mains. We have recently seen increased conversion interest from homeowners who
are concerned about the liability associated with having an underground oil
tank.
Unless we can provide outstanding customer service, we will not be able to
maintain and grow our customer base. We continue to monitor criteria that we
have used as benchmarks of our service. The "utility scorecard," which the DPUC
instituted last year to rate customer service for all state utilities, rated
Southern as the best among Connecticut's gas
Customers Served
Per Employee
[CHART]
300 291
250 254 267
200
150
100
50
0
'93 '94 '95
8
"Our traditional customer base continues to be
the foundation of our revenues and margins."
distributors for both years. We have recently installed a state-of-the-art
telephone routing and monitoring service for customer calls, which has cut the
average call waiting time from more than a minute down to 31 seconds. We also
developed a pilot program to schedule times for service appointments on
customer premises and be there within two hours. Since March, 98 percent of
these appointments were kept within this time frame. All of these factors are
important to our customers, so we are continually challenged to meet and exceed
the standards we have set.
As an integral part of the community, nearly 50 percent of our workforce is
involved in volunteer activities. This year's highlight was our involvement
with the 1995 Special Olympics World Games held in New Haven. We engineered and
installed the cauldron burner of the huge Olympic Torch, which burned a natural
gas "flame of hope" continuously for nine days for the 7,000 athletes, their
coaches and their families. Our natural gas vehicles paced four torch runs and
the Special Olympics Marathon, and nearly 100 of our employees volunteered
their time to help make this major event for Connecticut a success.
9
The Changing Business Profile
We have demonstrated our ability to pursue the traditional and emerging
avenues of growth which are unfolding before us on the changing landscape.
Although our firm customers have traditionally provided the largest portion of
our revenues and margins, we are now exploring other new opportunities to
enable us to maintain our record of increased earnings each year.
With unbundled services at the federal and state levels and fewer regulatory
constraints, there are greater opportunities for growth but considerably more
competition. As our operating environment evolves from the regulated
distribution of natural gas to a more competitive and deregulated energy
business, there can be greater earnings volatility than previously expected
from utilities. To prepare for these changes, we have strengthened our
financial profile over the last few years. Our equity ratio is now over 52
percent. We have been deliberate in significantly reducing our dividend payout
ratio while maintaining dividend growth. Our steady and consistent growth in
earnings over the past six years has enabled us to improve our fundamentals
significantly.
We have also been successful in managing our costs. Operation and maintenance
expenses were nearly three percent below last year, and they were reduced to 45
percent of
Dividend Payout
Dollars Per Share
[CHART]
2.00
1.50 1.58 1.60
1.50 1.33 1.38 1.43 1.28 1.29 1.30
1.23 1.24 1.27
1.00
0.50
0.00
'90 '91 '92 '93 '94 '95
/ / Earnings / / Dividends
10
"Our earnings record demonstrates that we have
constructed firm footings on which to grow."
margins. We have continued stringent cost control measures by looking at every
aspect of operations, from restructuring departments where it makes sense, to
using the most cost effective technology.
Connecticut Energy's management made a commitment to shareholders six years
ago to achieve steady and consistent growth in earnings despite external
variables. In spite of a slow economy and low oil prices, we again achieved
growth in earnings per share. Although our business has changed, our commitment
to our shareholders has remained steadfast.
We are operating in a dynamic new marketplace with little room for error. Our
earnings record illustrates our commitment to our shareholders and demonstrates
that we have constructed firm footings from which to branch out to new markets.
Operations and
Maintenance Expenses
as a Percent of Margin
Dollars In Millions
[CHART]
120 64.00
59.80 53.00
100 55.00 54.20
45.00
80
60
40
20
0
'93 '94 '95
/ / O&M Expenses
/ / Margin
11
Financial Table of Contents
Management's Discussion and Analysis of
Financial Condition and Results of Operations ............... 13
Consolidated Statements of Income ............................. 20
Consolidated Balance Sheets ................................... 21
Consolidated Statements of Changes in
Common Shareholders' Equity ................................. 22
Consolidated Statements of Cash Flows ......................... 23
Notes to Consolidated Financial Statements .................... 24
Management Responsibility for Financial Statements ............ 35
Report of Independent Accountants ............................. 35
Eleven Year Financial Summary ................................. 36
Operating Data ................................................ 38
Glossary ...................................................... 40
Investment Information ........................................ 41
Shareholder Information ....................................... 42
Corporate Directory ........................................... 44
12 Connecticut Energy Corporation
Management's Discussion and
Analysis of Financial Condition
and Results of Operations
Results of Operations
Net Income
Connecticut Energy Corporation's ("Connecticut Energy" or "Company")
consolidated net income for the fiscal years ended September 30 is detailed
below:
(in thousands, except per share) 1995 1994 1993
- ------------------------------------------------------------------------------
Net Income $14,060 $12,843 $11,053
- ------------------------------------------------------------------------------
Net income per share $1.60 $1.58 $1.50
- ------------------------------------------------------------------------------
Weighted average shares outstanding 8,774 8,134 7,377
- ------------------------------------------------------------------------------
Net income for 1995 was a record for the Company and has increased
approximately 9% as compared to 1994. Factors affecting the improved results
for 1995 were as follows: additional interruptible and off-system margins
earned and retained by the Company's principal subsidiary, The Southern
Connecticut Gas Company ("Southern"), a 6.6% rate increase implemented by
Southern on December 9, 1993, the continued conversion of residential
nonheating customers to heating customers and lower operations and maintenance
expenses.
Net income in 1994 increased approximately 16% as compared to 1993. This
increase was primarily due to the implementation of a 6.6% rate increase in
December 1993 by 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")
and the conversion of residential nonheating customers to heating customers.
Total Sales and Transportation Volumes
Southern's total volumes of gas sold and transported reached a record level of
49,698 MMcf in 1995, which was a 50% increase over 1994. The 1995 level was
higher principally due to increases in interruptible sales, transportation
volumes in accordance with a special contract for The Connecticut Light and
Power Company's ("CL&P") Devon generating station which began in July 1994 and
off-system sales. Throughput in 1994 was approximately 17% higher than in 1993,
principally due to increased firm and interruptible sales, as well as
transportation volumes for CL&P's Devon station.
Firm Sales Volumes
Firm sales volumes were approximately 12% lower in 1995 as compared to 1994.
This decrease was primarily attributable to weather that was approximately 14%
warmer than 1994 and, to a lesser extent, customers switching between the firm
and interruptible rate classes and slightly lower usage per customer. This
decrease was partially offset by new customer additions and the continued
conversion of nonheating customers to heating customers.
Firm sales volumes were approximately 3% higher in 1994 as compared to 1993
principally due to weather that was approximately 5% colder than 1993 and the
continued conversion of nonheating customers to heating customers.
Connecticut Energy Corporation 13
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 with CL&P as well as gross margins earned and retained due to
the margin sharing mechanism on these services:
(in thousands) 1995 1994 1993
- --------------------------------------------------------------------------------
Gross margin earned $13,702 $ 7,421 $5,560
- --------------------------------------------------------------------------------
Gross margin retained $ 7,390 $ 5,346 $3,272
- --------------------------------------------------------------------------------
Volumes sold and transported (MMcf) 29,680 10,509 6,296
- --------------------------------------------------------------------------------
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 services 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 1995 as compared to
1994. The increase in margins retained for 1995 was principally attributable to
higher levels of interruptible sales due to warmer winter weather and
competitive gas prices as well as Southern's ability to share margins earned
from selling and transporting gas off-system pursuant to the DPUC's Decision
regarding the implementation of Federal Energy Regulatory Commission's ("FERC")
Order No. 636.
Margins earned and retained in 1994 were greater than 1993 principally due 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.
Gross Margin
The Company's gross margin increased by approximately 2% for 1995 as compared
to 1994. This increase can be principally attributed to higher margins earned
and retained from interruptible services.
Additionally, gross margin for 1995 was affected by the collection of
approximately $6,853,000 from firm customers through the operation of the
Weather Normalization Adjustment ("WNA") implemented in December of 1993. The
WNA collections helped offset the effects of lower firm sales volumes resulting
from weather that was approximately 10% warmer than normal during 1995.
Gross margin was approximately 14% higher in 1994 as compared to 1993. This
increase was primarily attributable to Southern's implementation of a 6.6% rate
increase in December 1993 and its ability to retain additional interruptible
margins earned due to the change in the annual margin sharing period and target
made by the DPUC in the 1993 rate Decision and the conversion of existing
residential nonheating customers to heating customers. Gross margin for 1994
was also impacted by the return to customers of approximately $2,900,000
through the operation of the WNA.
Southern's firm rates include a Purchased Gas Adjustment clause ("PGA") which
allows Southern to pass through to its customers, through periodic adjustments
to amounts billed, increased or decreased costs incurred for purchased gas as
compared to base rate levels without affecting gross margin. Adjustments
related to Southern's PGA decreased revenues and gas costs for 1995 by
approximately $3,756,000 and increased revenues and gas costs for 1994 and 1993
by $6,885,000 and $13,797,000, respectively.
14 Connecticut Energy Corporation
Operations Expense
Operations expense was approximately 2% lower in 1995 as compared to 1994. This
decrease was principally due to lower costs for labor, conservation programs,
pensions, employee health insurance and other general and administrative
expenses. This decrease was partially offset by a higher expense for
uncollectible accounts.
Operations expense was approximately 21% higher in 1994 as compared to 1993.
Approximately 49% of this increase was a result of a higher expense for
uncollectible accounts. The remainder of the increase was due to higher
employee benefit costs related to the adoption and 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.
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's action positively impacted
Southern's provision for uncollectible accounts for 1993. Southern has been
allowed to recover these 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 1995 and 1994 were approximately $2,987,000 and
$1,726,000 related to these amortizations.
Maintenance Expense
Maintenance expense for 1995 decreased approximately 7% as compared to 1994.
This decrease was primarily attributable to lower labor and material costs
associated with Southern's mains due to a lower level of maintenance activity
resulting from warmer than normal weather experienced during 1995.
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 1995 by
approximately 38% as compared to 1994. This increase was primarily due to
higher pre-tax income coupled with a higher effective tax rate for 1995.
Results for 1995 were also impacted by the flow-through tax effect of the
amortization of previously deferred costs. Partially offsetting these increases
in the tax provision for 1995 were benefits related to the current
deductibility of conservation program expenses and certain postretirement
health care and pension costs.
The total provision for federal and state income taxes increased in 1994 by
approximately 41% as compared to 1993. This increase was primarily due to
higher pre-tax income in 1994, coupled with a higher effective tax rate due to
the flow-through tax effect of the amortization of previously deferred costs.
Municipal, Gross Earnings and Other Taxes
Municipal, gross earnings and other taxes decreased approximately 6% in 1995 as
compared to 1994. This decrease was principally due to lower gross earnings
taxes due to lower revenues, lower sales and use taxes and lower property tax
expense primarily due to the successful litigation against the City of
Bridgeport concerning personal property tax audits.
Municipal, gross earnings and other taxes increased approximately 4% in 1994 as
compared to 1993 principally due to a higher provision for gross earnings taxes
because of higher revenues in 1994.
Connecticut Energy Corporation 15
Interest Expense and Preferred Stock Dividends
Total interest expense and preferred stock dividends increased approximately 6%
in 1995 as compared to 1994. The increase was primarily due to higher weighted
average short-term interest rates during 1995 and a higher interest expense
related to average deferred gas cost and margin sharing balances. Partially
offsetting the increased short-term debt costs was a lower expense related to
refunds owed to customers from interstate pipeline suppliers.
Total interest expense and preferred stock dividends remained relatively
unchanged for 1994 as compared to 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.
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 5.99% in 1995 as compared to 3.74% in 1994
and 3.47% in 1993.
Inflation
Inflation as measured by the Consumer Price Index for all urban consumers was
approximately 2.8% in 1995 and 3.0% in 1994 and 1993. 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 August 2, 1995, the DPUC issued a final Decision in Docket No. 94-11-12,
DPUC Review of Connecticut Local Distribution Companies' Cost of Service Study
Methodologies. In this docket, the DPUC investigated the issues surrounding the
development of firm transportation rates at the state level in response to FERC
Order No. 636. In its Decision, the DPUC provided guidelines for the
development of firm transportation rates to be offered by Connecticut's three
local distribution companies ("LDCs"). Each LDC is required to file specific
firm transportation rate proposals in separate company rate dockets. A firm
transportation rate option will be implemented for the largest commercial and
industrial customers upon the conclusion of each company's rate docket and will
be available to all commercial and industrial customers no later than April 1,
1996.
Southern filed its firm transportation rate proposal during the fourth quarter
of fiscal 1995 in order to comply with the DPUC's Decision. This filing did not
address Southern's revenue requirements and maintains the existing margin
recovery and rates of return established in the last rate case Decision issued
for Southern.
On December 1, 1993, the DPUC issued a final Decision regarding Southern's rate
request. The Decision incorporated the previously approved Partial Settlement
of Certain Issues ("Partial Settlement") 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. 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.
16 Connecticut Energy Corporation
The Partial Settlement also provided 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.
As part of the 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 March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"),
which will be effective for the Company's fiscal year ending September 30,
1997. This statement imposes stricter criteria for regulatory assets by
requiring that such assets be probable of future recovery at each balance sheet
date. The adoption of SFAS 121 is required by October 1, 1996, 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, Connecticut Energy has
committed lines of credit with a number of banks totalling $37,000,000. Of this
total, Southern has committed lines of credit of $32,000,000 in addition to
uncommitted lines of credit with two of its banks totalling $14,000,000 and 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,
1995, the Company had unused lines of credit of $46,800,000. 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 for 1995 were positively affected by higher net income,
the receipt of approximately $8,689,000 in interstate pipeline refunds used to
offset previously deferred transition costs, higher balances related to
Southern's interruptible margin sharing mechanism and lower accounts receivable
balances.
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.
Investing Activities
Capital expenditures approximated $27,600,000 in 1995, $26,600,000 in 1994 and
$26,100,000 in 1993. 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 1996 will approximate
$26,000,000 of which 25% is budgeted for new business. The majority
Connecticut Energy Corporation 17
of the remaining planned capital expenditures are to improve, protect and
maintain its existing gas distribution system. Over the 1996 - 2000 period,
Southern estimates that total expenditures for new plant and equipment will
range between $110,000,000 and $130,000,000.
In August 1995, the Company formed a new nonutility subsidiary, Total Energy
Services Group, Inc. ("TESG"). TESG is initially expected to engage in
activities relating to the selling, planning, purchasing and management of
various energy services to commercial and industrial end users.
In December 1994, the Company formed a new nonutility subsidiary, Connecticut
Energy Development Corporation ("CEDC"). CEDC is initially expected to
participate as an equity holder in an entity formed to purchase and market
natural gas and potentially participate in other nonregulated activities.
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 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.
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.
Financing plans for 1996 include the potential establishment of a Medium Term
Note ("MTN") program, subject to the approval of the DPUC. This program would
permit the issuance of up to $75,000,000 of secured MTN's over a four-year
period for varying amounts and terms. The current timetable would allow for the
commencement of this program sometime in the spring of 1996. 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.
18 Connecticut Energy Corporation
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.
FERC Order No. 636 Transition Costs
As a result of FERC Order No. 636, 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
unrecovered gas costs, gas supply realignment costs, stranded investment costs
and new facilities costs.
Southern has paid approximately $16,345,000 in transition costs as of September
30, 1995. Of this total, $4,461,000 represents unrecovered gas costs and
$11,884,000 represents 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 prescribed, among other things, the various mechanisms for the recovery of
deferred transition costs. As of September 30, 1995, Southern has recovered
substantially all of its deferred transition costs through the use of the
recovery mechanisms allowed by the DPUC.
Environmental Matters
Southern has identified coal tar residue at three sites in Connecticut
resulting from 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 residue 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 at the 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, timing and type of remedial action, if any, 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. While such future analytical and cleanup
costs could possibly be significant, management believes, based upon the
provisions of the Partial Settlement in Southern's last rate order, that
Southern will be able to recover these costs through its customer rates.
Although the method, timing and extent of any recovery remain uncertain,
management currently does not expect that the incurrence of such costs will
materially adversely impact the Company's financial condition or results of
operations.
Connecticut Energy Corporation 19
Consolidated Statements of Income
(dollars in thousands, except per share)
Years ended September 30, 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------
Operating Revenues $ 232,093 $ 240,873 $ 212,762
Purchased gas 115,583 126,870 113,045
- -----------------------------------------------------------------------------------------------------------------
Gross margin 116,510 114,003 99,717
- -----------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operations 49,113 50,209 41,331
Maintenance 3,743 4,035 3,692
Depreciation and depletion 14,050 13,031 12,051
Federal and state income taxes 7,436 5,402 3,821
Municipal, gross earnings and other taxes 15,282 16,314 15,697
- -----------------------------------------------------------------------------------------------------------------
Total operating expenses 89,624 88,991 76,592
- -----------------------------------------------------------------------------------------------------------------
Operating income 26,886 25,012 23,125
- -----------------------------------------------------------------------------------------------------------------
Other deductions, net 519 586 510
- -----------------------------------------------------------------------------------------------------------------
Interest Expense and Preferred Stock Dividends:
Interest on long-term debt and amortization of debt issue costs 10,859 10,920 9,945
Other interest, net and preferred stock dividends 1,448 663 1,617
- -----------------------------------------------------------------------------------------------------------------
Total interest expense and preferred stock dividends 12,307 11,583 11,562
- -----------------------------------------------------------------------------------------------------------------
Net Income $ 14,060 $ 12,843 $ 11,053
- -----------------------------------------------------------------------------------------------------------------
Net income per share $ 1.60 $ 1.58 $ 1.50
- -----------------------------------------------------------------------------------------------------------------
Dividends paid per share $ 1.30 $ 1.29 $ 1.28
- -----------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding 8,773,878 8,134,021 7,377,419
- -----------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
20 Connecticut Energy Corporation
Consolidated Balance Sheets
(dollars in thousands, except per share)
As of September 30, 1995 1994
- -------------------------------------------------------------------------------------------------------
Assets
Utility Plant:
Plant in service, at cost $350,715 $329,917
Construction work in progress 4,132 2,036
- -------------------------------------------------------------------------------------------------------
Gross utility plant 354,847 331,953
Less: accumulated depreciation 107,244 97,458
- -------------------------------------------------------------------------------------------------------
Net utility plant 247,603 234,495
Nonutility property, net 2,541 2,492
- -------------------------------------------------------------------------------------------------------
Net utility plant and other property 250,144 236,987
- -------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 4,635 1,637
Accounts and notes receivable (less allowance for doubtful
accounts of $3,553 in 1995 and $3,747 in 1994) 23,456 23,698
Accrued utility revenue, net 2,675 2,630
Unrecovered purchased gas costs 2,972 4,523
Inventories 13,115 14,678
Prepaid expenses 2,247 1,847
- -------------------------------------------------------------------------------------------------------
Total current assets 49,100 49,013
- -------------------------------------------------------------------------------------------------------
Deferred Charges:
Unamortized debt expenses 6,090 6,317
Unrecovered deferred taxes 37,717 35,398
Other 27,037 25,205
- -------------------------------------------------------------------------------------------------------
Total deferred charges 70,844 66,920
- -------------------------------------------------------------------------------------------------------
Total assets $370,088 $352,920
- -------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
Common Shareholders' Equity:
Common stock -- par value $1 per share:
authorized -- 20,000,000 shares;
issued and outstanding -- 8,865,210 in 1995; 8,700,266 in 1994 $ 8,865 $ 8,700
Capital in excess of par value 88,295 85,265
Retained earnings 34,401 31,754
- -------------------------------------------------------------------------------------------------------
Total common shareholders' equity 131,561 125,719
- -------------------------------------------------------------------------------------------------------
Redeemable preferred stock -- --
Long-term debt 119,322 119,917
- -------------------------------------------------------------------------------------------------------
Total capitalization 250,883 245,636
- -------------------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 24,200 18,800
Current maturities of long-term debt 594 594
Accounts payable 9,586 10,886
Refunds due customers 862 --
Federal, state and deferred income taxes 2,525 3,565
Property and other accrued taxes 4,877 5,289
Interest payable 3,311 3,315
Customers' deposits 1,843 1,901
Other accrued liabilities 3,419 4,137
- -------------------------------------------------------------------------------------------------------
Total current liabilities 51,217 48,487
- -------------------------------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes 56,359 51,121
Deferred investment tax credits 3,561 3,853
Other 8,068 3,823
- -------------------------------------------------------------------------------------------------------
Total deferred credits 67,988 58,797
- -------------------------------------------------------------------------------------------------------
Commitments and contingencies -- --
- -------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $370,088 $352,920
- -------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
Connecticut Energy Corporation 21
Consolidated Statements of Changes in Common Shareholders' Equity
(dollars in thousands, except per share)
Adjustment
Common Stock Capital for Total
----------------------- in Minimum Common
Number Par Excess of Retained Pension Shareholders'
of Shares Value Par Value Earnings Liability Equity
- -------------------------------------------------------------------------------------------------------------------------
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
Issuance through dividend
reinvestment plan 164,944 165 3,030 -- -- 3,195
Net income -- -- -- 14,060 -- 14,060
Dividends paid on common stock
($1.30 per share) -- -- -- (11,413) -- (11,413)
- -------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1995 8,865,210 $8,865 $88,295 $ 34,401 -- $131,561
- -------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
22 Connecticut Energy Corporation
Consolidated Statements of Cash Flows
(dollars in thousands)
Years ended September 30, 1995 1994 1993
- ---------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities:
Net income $ 14,060 $ 12,843 $ 11,053
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 14,985 13,844 12,825
Provision for losses on accounts receivable 6,548 6,962 4,350
(Increase) Decrease in Assets:
Accounts and notes receivable (6,306) (12,248) (3,923)
Accrued utility revenue, net (45) (323) (274)
Unrecovered purchased gas costs 1,551 1,452 (5,975)
Inventories 1,563 1,634 (3,720)
Prepaid expenses (400) (282) (495)
Unamortized debt expense (7) (87) (244)
Deferred charges and other assets (1,860) (4,852) (8,072)
Increase (Decrease) in Liabilities:
Accounts payable (1,300) (1,661) 3,636
Refunds due customers 862 (1,964) 1,432
Accrued taxes (1,452) 47 1,656
Other current liabilities (780) 2,561 (921)
Deferred income taxes and investment tax credits 2,627 1,706 129
Deferred credits and other liabilities 4,323 177 1,794
- ---------------------------------------------------------------------------------------------------
Net cash provided by operating activities 34,369 19,809 13,253
- ---------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities:
Capital expenditures (27,641) (26,669) (26,136)
Proceeds from sale of headquarters property -- -- 2,005
Proceeds from sale of subsidiaries 40 28 180
Contributions in aid of construction 32 51 66
Payments for retirement of utility plant (390) (779) (276)
- ---------------------------------------------------------------------------------------------------
Net cash used by investing activities (27,959) (27,369) (24,161)
- ---------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities:
Dividends paid on common stock (11,413) (10,754) (9,463)
Issuance of common stock 3,195 23,669 5,766
Issuance of long-term debt -- -- 27,000
Repayments of long-term debt (594) (594) (594)
Redemption of preferred stock -- (638) (50)
Increase (decrease) in short-term borrowings 5,400 (4,700) (14,800)
- ---------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities (3,412) 6,983 7,859
- ---------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents 2,998 (577) (3,049)
Cash and cash equivalents at beginning of year 1,637 2,214 5,263
- ---------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 4,635 $ 1,637 $ 2,214
- ---------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash Paid During the Year for:
Interest $ 11,701 $ 11,332 $ 11,101
Income taxes $ 6,636 $ 4,252 $ 2,747
See notes to consolidated financial statements.
Connecticut Energy Corporation 23
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 ("Connecticut Energy" or "Company")
principal 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.
Southern prepares its financial statements in accordance with the provisions of
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation" ("SFAS 71"), which requires a cost-based,
rate-regulated enterprise such as Southern to reflect the impact of regulatory
decisions in its financial statements. The DPUC's actions through the
ratemaking process can create regulatory assets in which costs are allowed for
ratemaking purposes in a period other than the period in which the costs would
be charged to expense if the reporting entity was unregulated.
In the application of SFAS 71, Southern follows accounting policies that
reflect the impact of the rate treatment of certain events or transactions that
are permitted to differ from generally accepted accounting principles. The most
significant of these policies include the recording of deferred gas costs,
pipeline transition costs, environmental evaluation costs, and an unfunded
deferred income tax liability, with a corresponding unrecovered asset, for
temporary differences previously flowed through to ratepayers.
Based on current regulation and recent DPUC decisions, the Company believes
that its use of regulatory accounting for Southern is appropriate and in
accordance with the provisions of SFAS 71.
Line of Business
Operating revenues of the Company are derived primarily from Southern's
operations as a retail natural gas distributor. Through former nonregulated
subsidiaries, the Company was engaged in a limited amount of gas production and
transportation activities. In February 1993, the assets and liabilities of
these nonregulated subsidiaries were sold. In December 1994, the Company formed
a new nonutility subsidiary, Connecticut Energy Development Corporation
("CEDC"). CEDC is initially expected to participate as an equity holder in an
entity formed to purchase and market natural gas and potentially participate in
other nonregulated activities. In August 1995, the Company formed a new
nonutility subsidiary, Total Energy Services Group, Inc. ("TESG"). TESG is
initially expected to engage in activities relating to the selling, planning,
purchasing and management of various energy services to commercial and
industrial end users.
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.
24 Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
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, the Economic Recovery Tax Act
of 1981 and subsequent amendments to the Internal Revenue Code, income tax
reductions to Southern resulting from such items as liberalized depreciation
on 1981 to 1995 plant additions and investment tax credits on 1981 to 1986
plant additions are deferred and amortized to income over the useful lives of
the related 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 utilized the flow-through method on
depreciation of pre-1981 assets. 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
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("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 SFAS 71, as of September 30, 1995, the Company has a deferred tax
liability and a corresponding regulatory asset of approximately $37,717 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.
Connecticut Energy Corporation 25
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
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
$10,223 and $10,211 in 1995 and 1994, respectively; the deferral of certain
shortfalls in energy assistance funding related to the 1991/92 and 1992/93
heating seasons amounting to $2,122 and $2,742 in 1995 and 1994, respectively;
prepaid pension and postretirement medical contributions of $7,969 and $6,355
in 1995 and 1994, respectively, and an intangible pension asset of $23 and $101
in 1995 and 1994, respectively. These deferred charges are among other
miscellaneous deferred charges which Southern has been allowed to recover in
rates over periods ranging from three to five years in accordance with the
DPUC's Decision in Southern's last rate case.
Deferred Credits
Included in other deferred credits are amounts related to a minimum pension
liability totalling $23 and $101 in 1995 and 1994, respectively, as more fully
described in Note 7, "Employee Benefits." Also included are amounts related to
Southern's interruptible margin sharing mechanisms totalling $4,851 and $604 in
1995 and 1994, respectively.
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 and recorded a
regulatory asset of $33,943 related to the cumulative amount of income taxes
on temporary differences previously flowed through to ratepayers. In addition,
the Company has a deferred tax liability of $3,561 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.
The provision for income taxes includes:
Years ended September 30, 1995 1994 1993
- --------------------------------------------------------------------------------------------
Taxes currently payable -- federal $3,817 $2,958 $ 968
Taxes currently payable -- state 1,535 1,464 347
- --------------------------------------------------------------------------------------------
$5,352 $4,422 $1,315
- --------------------------------------------------------------------------------------------
Deferred taxes -- federal $2,084 $ 980 $2,506
- --------------------------------------------------------------------------------------------
Total income tax provision $7,436 $5,402 $3,821
- --------------------------------------------------------------------------------------------
26 Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Sources and tax effects of items which gave rise to deferred taxes are:
Years ended September 30, 1995 1994 1993
- --------------------------------------------------------------------------------------------
Amortization of deferred investment tax credits $ (292) $ (292) $ (292)
Unrecovered purchased gas costs (542) (508) 2,378
Depreciation and depletion 1,956 1,779 1,664
Minimum tax credits 1,024 452 (1,111)
Other (62) (451) (133)
- --------------------------------------------------------------------------------------------
$2,084 $ 980 $2,506
- --------------------------------------------------------------------------------------------
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.
Years ended September 30, 1995 1994 1993
- --------------------------------------------------------------------------------------------
U. S. statutory federal tax rate 35% 35% 34.75%
Depreciation differences 3% 4% 5%
Allowance for doubtful accounts,
including amounts forgiven and deferred 1% (7%) (16%)
Investment tax credits (1%) (2%) (2%)
Cost to retire assets, net of salvage (1%) (2%) (1%)
State taxes, net of federal tax benefit 5% 5% 2%
Pension contribution (2%) (2%) --
Conservation expenses (3%) -- --
Reduction due to graduated tax rates -- (.6%) (.75%)
Other, net (2%) (.4%) 4%
- --------------------------------------------------------------------------------------------
Effective tax rate 35% 30% 26%
- --------------------------------------------------------------------------------------------
Deferred income tax liabilities (assets) are composed of the following:
As of September 30, 1995 1994
- -------------------------------------------------------------------------------
Tax effect of temporary differences for:
Depreciation $20,464 $18,508
Items previously flowed through 37,717 35,398
Alternative minimum tax (440) (1,463)
Investment tax credits 3,561 3,853
Contribution in aid of construction (689) (654)
Pension contribution (658) (547)
Other (35) (121)
- -------------------------------------------------------------------------------
Net deferred income tax liability -- long-term $59,920 $54,974
- -------------------------------------------------------------------------------
At September 30, 1995 and 1994, the balance sheet caption, "Federal, state and
deferred income taxes" included approximately $1,023 and $1,566, respectively,
of current deferred federal and state income taxes; and approximately $440 and
$1,463, respectively, of minimum tax credits available to reduce federal income
taxes to be paid in future periods.
Connecticut Energy Corporation 27
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Note 3 -- Long-Term Debt
Long-term debt outstanding at September 30, 1995 and 1994 consisted of:
1995 1994
- --------------------------------------------------------------------------------
First Mortgage Bonds:
Series L, 8%, due March 1, 1998 $ 4,480 $ 4,620
Series T, 10.02%, due September 1, 2003 3,636 4,091
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
- --------------------------------------------------------------------------------
119,916 120,511
Less -- amounts due within one year 594 594
- --------------------------------------------------------------------------------
$119,322 $119,917
- --------------------------------------------------------------------------------
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, "Common Shareholders' Equity," for dividend
restrictions.
The aggregate annual sinking fund contributions and principal maturities for
the five fiscal years subsequent to September 30, 1995 are as follows: 1996 --
$594; 1997 -- $595; 1998 -- $4,654; 1999 -- $455; 2000 -- $454; total --
$6,752.
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, 1995, 1994 and 1993.
1995 1994 1993
- -----------------------------------------------------------------------------------------------
Bank Loans:
Outstanding at the end of the year $19,200 $12,800 $10,500
Weighted average interest rate at year end 6.79% 5.41% 3.36%
Average amount outstanding during year $13,318 $14,951 $15,879
Weighted average interest rate during year* 5.96% 3.74% 3.47%
Maximum amount outstanding at any month end $29,000 $37,400 $29,200
Commercial Paper:
Outstanding at the end of the year $ 5,000 $ 6,000 $13,000
Weighted average interest rate at year end 5.97% 4.95% 3.29%
Average amount outstanding during year $ 2,595 $ 3,950 $11,517
Weighted average interest rate during year* 6.11% 3.74% 3.46%
Maximum amount outstanding at any month end $ 6,000 $13,000 $16,000
- -----------------------------------------------------------------------------------------------
<FN>
*Determined by dividing annual interest expense by average amount outstanding
during the year.
28 Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Connecticut Energy's committed short-term bank credit lines amounted to
$37,000, a portion of which supports the issuance of commercial paper.
Southern's share of the total committed credit lines amounted to $32,000.
Southern also 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, 1995, Southern had no outstanding borrowings under this agreement. The fee
for this facility is 1/8 of 1% per annum. At September 30, 1995, the Company
had unused lines of credit of $46,800. 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 $96, $124 and $102 for the years ended September 30, 1995,
1994 and 1993, respectively.
Note 5 -- Redeemable Preferred Stock
The following table summarizes the shares of preferred stock authorized, issued
and outstanding at September 30, 1995 and 1994:
1995 1994
- ------------------------------------------------------------------------------
The Southern Connecticut Gas Company:
Cumulative preferred stock, $100 par value:
Authorized 200,000 200,000
4.75% issued and outstanding -- --
- ------------------------------------------------------------------------------
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 -- --
- ------------------------------------------------------------------------------
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, it 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, $21,886 of
Southern's retained earnings at September 30, 1995 was available for such
purposes.
The Company currently issues common stock through the Dividend Reinvestment and
Stock Purchase Plan ("DRP") and an employee savings plan ("Target Plan").
The Company formerly issued common stock through the Employee Stock Ownership
Plan ("ESOP"); however, at the end of calendar year 1994, the assets of the
ESOP were merged with the Target Plan. There were no contributions to the ESOP
made during the years ended September 30, 1995 and 1994.
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, 1995, there
were 1,477,929 shares reserved for issuance under the DRP and Target Plan.
Connecticut Energy Corporation 29
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 employees provides pension
benefits based on compensation during the five years before retirement and on
years of service. The union plan provides negotiated 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 ("IRC").
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 $23 and $101
representing the excess of the accumulated benefit obligation over the fair
value of plan assets and accrued pension costs at September 30, 1995 and 1994,
respectively. This liability is offset by an intangible asset of $23 and $101
at September 30, 1995 and 1994, 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, 1995, 1994 and 1993
included the following components:
1995 1994 1993
- -----------------------------------------------------------------------------------------------
Service cost benefits earned during the period $ 1,868 $ 2,117 $ 2,031
Interest cost on projected benefit obligation 4,686 4,263 3,923
Actual return on plan assets (12,603) (1,986) (6,817)
Net amortization and deferral 8,135 (1,829) 2,883
- -----------------------------------------------------------------------------------------------
Net periodic pension cost $ 2,086 $ 2,565 $ 2,020
Regulatory adjustment 233 22 (177)
- -----------------------------------------------------------------------------------------------
Net pension cost $ 2,319 $ 2,587 $ 1,843
- -----------------------------------------------------------------------------------------------
Portion capitalized to utility plant $ 441 $ 439 $ 328
- -----------------------------------------------------------------------------------------------
The following table sets forth the funded status of Southern's pension plans at
September 30, 1995 and 1994:
September 30, 1995 September 30, 1994
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
- -------------------------------------------------------------------------------------------------------------------
Vested benefit obligation $(50,481) $ (457) $(43,249) $ (3)
- -------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation $(54,827) $ (637) $(46,808) $(326)
- -------------------------------------------------------------------------------------------------------------------
Actuarial present value of
projected benefit obligation $(64,718) $(1,591) $(54,337) $(758)
Plan assets at fair value 70,177 -- 58,217 --
- -------------------------------------------------------------------------------------------------------------------
Projected benefits obligation in excess of
plan assets 5,459 (1,591) 3,880 (758)
Transition obligation 827 -- 996 --
Prior service cost 3,178 295 3,582 317
Unrecognized (gain) loss (2,601) 635 (2,983) (18)
Adjustment required to
recognize minimum liability -- (23) -- (101)
- -------------------------------------------------------------------------------------------------------------------
Prepaid pension cost (liability), net $ 6,863 $ (684) $ 5,475 $(560)
- -------------------------------------------------------------------------------------------------------------------
30 Connecticut Energy Corporation
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:
1995 1994 1993
- -------------------------------------------------------------------------
Discount rate 7 1/4% 8 1/2% 7%
Salary increase rate 5 1/4% 5 1/2% 5%
Expected rate of return on assets 9 1/2% 9% 9 1/4%
- -------------------------------------------------------------------------
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 nonqualified pension programs
to provide benefits on compensation in excess of the limitations imposed by the
IRC and to provide additional retirement income to designated officers.
Southern maintains a savings plan covering substantially all of its employees
who meet minimum service and age 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 a before-tax
basis as permitted by Section 401(k) of the IRC. 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 or
their beneficiaries upon retirement, death, disability or termination. Amounts
expensed under the plan were $816, $795 and $772 for years ended September 30,
1995, 1994 and 1993, 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 five 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 years ended September 30, 1995 and
1994 include the following components:
1995 1994
- --------------------------------------------------------------------
Service cost $ 340 $ 598
Interest cost 1,401 1,282
Actual return on plan assets (594) (113)
Net amortization and deferral 1,071 880
- --------------------------------------------------------------------
Net periodic postretirement benefit cost $2,218 $2,647
Regulatory adjustment 122 (275)
- --------------------------------------------------------------------
Net postretirement benefit cost $2,340 $2,372
- --------------------------------------------------------------------
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 IRC to fund a portion of Southern's anticipated
future postretirement health care benefits liability with amounts allowed
through the ratemaking process. Through the use of the existing trust and the
establishment in 1994 of a Voluntary Employees' Beneficiary Association
("VEBA") trust as permitted under Section 501(c)(9) of the IRC, Southern plans
to fund its full postretirement benefit expense under SFAS 106.
Connecticut Energy Corporation 31
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
The significant majority of the assets of the VEBA trust is invested in a
diversified fund consisting of common stock and fixed income securities, with
the balance in cash and short-term investments.
The following table reconciles the funded status of the plan with the amounts
recognized in the consolidated balance sheets as of September 30, 1995 and
1994:
1995 1994
- ------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ (8,866) $ (8,712)
Fully eligible active plan participants (2,692) (3,262)
Other active plan participants (5,493) (6,176)
- ------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation $(17,051) $(18,150)
Plan assets at fair value 3,757 1,333
- ------------------------------------------------------------------------------
Accumulated postretirement benefit obligation in
excess of plan assets $(13,294) $(16,817)
Unamortized transition obligation 13,820 16,592
Unrecognized (gain) loss (2,131) (2,336)
- ------------------------------------------------------------------------------
(Accrued) postretirement benefit obligation $ (1,605) $ (2,561)
- ------------------------------------------------------------------------------
The expected long-term rate of return on plan assets is 9 1/2%. The assumed
initial health care cost trend rates used to measure the expected cost of
benefits were 10% for pre-age 65 claims and 8 1/2% for post-age 65 claims. The
rates decline to 5% by the year 2004 and 2002, respectively. The weighted
average discount rate used to measure the accumulated postretirement benefit
obligation was 7 1/4%. A one percentage point change in the assumed health care
cost trend rate would change the service cost and interest cost components of
the net periodic postretirement benefit cost by approximately $14 and $50,
respectively, and would change the accumulated postretirement benefit
obligation for health care benefits by approximately $691.
Note 8 -- Leases
Total rental expense was $3,074, $2,864 and $2,405 for the years ended
September 30, 1995, 1994 and 1993, 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, 1995 are in total:
Commitment Office space LNG plant Other
- ------------------------------------------------------------------------------
1996 $ 2,050 $ 609 $252
1997 2,037 608 75
1998 2,111 609 72
1999 2,111 608 54
2000 2,087 609 --
Thereafter 29,309 12,476 --
- ------------------------------------------------------------------------------
Total commitment $39,705 $15,519 $453
- ------------------------------------------------------------------------------
In 1995, the liquified natural gas ("LNG") plant lease agreement was renewed
for two consecutive terms of 12 years. The lease contains an option to
purchase the plant for a purchase price based on the then fair market sales
value of the unit as defined therein.
In March 1993, Southern entered into an operating lease for the purpose of
consolidating its operating centers at one location in Orange, Connecticut. The
lease is for a period of 20 years.
In October 1992, Southern entered into an operating lease which consolidated
administrative functions at one location in Bridgeport, Connecticut. The lease
is for a period of 20 years.
32 Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Note 9 -- Supplementary Income Statement Information
Amounts charged to costs and expenses for the years ended September 30, 1995,
1994 and 1993 included:
1995 1994 1993
- ------------------------------------------------------------------------------
Maintenance and repairs $ 3,743 $ 4,035 $ 3,692
Depreciation and depletion 14,050 13,031 12,051
Property taxes 3,557 3,821 4,450
Connecticut gross earnings tax 10,055 10,506 9,349
Connecticut corporation business tax 1,535 1,464 347
Other taxes 9 213 210
Federal Insurance Contribution Act 2,102 2,198 2,090
Taxes capitalized as part of utility plant (441) (424) (402)
- ------------------------------------------------------------------------------
Note 10 -- Quarterly Financial Data (Unaudited)
Dec. 31 March 31 June 30 Sept. 30
1995 Quarter ended 1994 1995 1995 1995
- ------------------------------------------------------------------------------
Operating revenues $65,523 $103,284 $39,755 $23,531
Gross margin 32,246 53,286 19,063 11,915
Operating income (loss) 8,072 18,988 1,203 (1,377)
Net income (loss) 4,941 15,715 (1,985) (4,611)
Net income (loss) per share* $ 0.57 $ 1.79 $ (0.23) $ (0.52)
- ------------------------------------------------------------------------------
Dec. 31 March 31 June 30 Sept. 30
1994 Quarter ended 1993 1994 1994 1994
- ------------------------------------------------------------------------------
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)
- ------------------------------------------------------------------------------
* Calculated on the basis of weighted average shares outstanding during the
applicable quarter.
Note 11 -- Disclosures About the 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 cash equivalents
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.
The estimated fair values of the Company's financial instruments are as
follows:
As of September 30, 1995 1994
- ------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------------------------------------------------
Long-term debt (including
current maturities) $(119,916) $(138,171) $(120,511) $(124,905)
- ------------------------------------------------------------------------------
Connecticut Energy Corporation 33
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Note 12 -- Commitments and Contingencies
Environmental Matters
Southern has identified coal tar residue at three sites in Connecticut
resulting from 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 residue 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 at the 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, timing and type of remedial action, if any, 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. While such future analytical and cleanup
costs could possibly be significant, management believes, based upon the
provisions of the Partial Settlement in Southern's last rate order, that
Southern will be able to recover these costs through its customer rates.
Although the method, timing and extent of any recovery remain uncertain,
management currently does not expect that the incurrence of such costs will
materially adversely impact 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 unrecovered gas costs, gas
supply realignment costs, stranded investment costs and new facilities costs.
Southern has paid approximately $16,345 in transition costs as of September 30,
1995. Of this total, $4,461 represents unrecovered gas costs and $11,884
represents 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 prescribed,
among other things, the various mechanisms for the recovery of deferred
transition costs. As of September 30, 1995, Southern has recovered
substantially all of its deferred transition costs through the use of the
recovery mechanisms allowed by the DPUC.
34 Connecticut Energy Corporation
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, 1995
and 1994 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, 1995. 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, 1995 and 1994, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended September 30, 1995 in conformity with
generally accepted accounting principles.
As discussed in Notes 2 and 7 to the consolidated financial statements, in
fiscal 1994 the Company changed its methods of accounting for income taxes and
postretirement benefits other than pensions.
/c/ Coopers & Lybrand L.L.P.
Coopers & Lybrand L.L.P.
New York, New York
November 1, 1995
Connecticut Energy Corporation 35
Eleven Year Financial Summary
Financial information presented for 1995 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)
1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------
Operations
Operating revenues $232,093 $240,873 $212,762 $203,011
Purchased gas 115,583 126,870 113,045 104,163
Gross margin 116,510 114,003 99,717 98,848
Operations and maintenance expenses 52,856 54,244 45,023 46,881
Depreciation and depletion 14,050 13,031 12,051 11,327
Federal income taxes 5,901 3,938 3,474 2,287
Other taxes 16,817 17,778 16,044 16,025
Other deductions and (income), net 519 586 510 531
Interest expense 12,307 11,575 11,530 11,536
Subsidiary preferred stock dividends -- 8 32 34
Income before cumulative effect of accounting change $ 14,060 $ 12,843 $ 11,053 $ 10,227
Cumulative effect of accounting change -- -- -- --
Net income $ 14,060 $ 12,843 $ 11,053 $ 10,227
Net income per share before cumulative
effect of accounting change (f) $ 1.60 $ 1.58 $ 1.50 $ 1.43
Net income per share (f) $ 1.60 $ 1.58 $ 1.50 $ 1.43
Annual dividend paid per common share (f) $ 1.30 $ 1.29 $ 1.28 $ 1.265
- --------------------------------------------------------------------------------------------------------------------
*Capitalization
Common shareholders' equity $131,561 $125,719 $ 99,853 $ 92,605
Redeemable preferred stock -- -- 638 687
Long-term debt 119,322 119,917 120,511 94,106
- --------------------------------------------------------------------------------------------------------------------
Total capitalization $250,883 $245,636 $221,002 $187,398
- --------------------------------------------------------------------------------------------------------------------
*Capitalization (% of total)
Common shareholders' equity 52.4 51.2 45.2 49.4
Redeemable preferred stock -- -- 0.3 0.4
Long-term debt 47.6 48.8 54.5 50.2
- --------------------------------------------------------------------------------------------------------------------
Total capitalization 100.0% 100.0% 100.0% 100.0%
- --------------------------------------------------------------------------------------------------------------------
*Common Stock (f)
Shares outstanding at end of period 8,865,210 8,700,266 7,488,467 7,234,921
Book value per share at end of period $ 14.84 $ 14.45 $ 13.33 $ 12.80
Market value per share at end of period $ 19.38 $ 21.63 $ 24.88 $ 22.25
Average daily trading volume 5,000 5,500 9,000 4,500
Shareholders of record at year end 11,688 12,094 11,094 9,153
Percent of institutional ownership 21 21 18 18
- --------------------------------------------------------------------------------------------------------------------
Assets
Gross utility plant $354,847 $331,953 $313,951 $293,687
Net utility plant $247,603 $234,495 $221,800 $210,054
*Additions to utility plant (capital expenditures) $ 27,609 $ 26,618 $ 26,070 $ 22,634
Oil and gas properties, net -- -- -- $ 496
Total assets $370,088 $352,920 $299,795 $269,504
- --------------------------------------------------------------------------------------------------------------------
Ratios (% of total)
Gross margin as a % of operating revenues 50.2 47.3 46.9 48.7
Dividend payout as a % of earnings 81.3 81.6 85.3 88.5
Effective federal tax rate 30.0 23.0 24.0 18.0
*Return on ending common equity 10.7 10.2 11.1 11.0
Price to earnings 12.1 13.7 16.6 15.6
Dividend yield 6.7 6.0 5.1 5.7
Market price as a % of book value 130.6 149.7 186.6 173.8
- --------------------------------------------------------------------------------------------------------------------
<FN>
*Information used in the National Association of Investors Corporation (NAIC)
stock selection format.
(a) The results for the years 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 and $.05 per share in 1987.
36 Connecticut Energy Corporation
1991 1990 1989 1988 1987 1986 1985
- --------------------------------------------------------------------------------------------------
(a)(b)(c) (a)(c) (c) (d) (e)
$179,172 $174,059 $171,218 $156,978 $157,867 $156,028 $163,847
86,778 84,154 81,794 71,787 75,337 79,333 88,517
92,394 89,905 89,424 85,191 82,530 76,695 75,330
42,475 44,085 42,636 38,869 38,218 36,011 34,965
10,540 10,664 10,297 8,533 8,427 7,487 7,632
4,324 3,819 4,740 5,839 6,325 5,270 5,416
15,238 14,431 14,560 14,146 13,617 13,487 13,452
349 (228) 356 713 276 261 (12)
10,428 10,156 8,598 7,653 7,484 6,848 6,898
36 39 403 751 849 1,244 1,403
$ 9,004 $ 6,939 $ 7,834 $ 8,687 $ 7,334 $ 6,087 $ 5,576
-- 1,280 -- -- -- 1,911 --
$ 9,004 $ 8,219 $ 7,834 $ 8,687 $ 7,334 $ 7,998 $ 5,576
$ 1.38 $ 1.12 $ 1.28 $ 1.49 $ 1.38 $ 1.16 1.21
$ 1.38 $ 1.33 $ 1.28 $ 1.49 $ 1.38 $ 1.53 $ 1.21
$ 1.24 $ 1.23 $ 1.20 $ 1.17 $ 1.12 $ 1.12 $ 1.07
- --------------------------------------------------------------------------------------------------
$ 88,622 $ 74,413 $ 75,001 $ 73,311 $ 61,187 $ 58,731 $ 55,573
736 786 835 6,429 7,270 8,112 12,487
87,378 91,506 79,686 69,137 64,461 58,714 53,666
- --------------------------------------------------------------------------------------------------
$176,736 $166,705 $155,522 $148,877 $132,918 $125,557 $121,726
- --------------------------------------------------------------------------------------------------
50.1 44.6 48.2 49.2 46.0 46.8 45.7
0.4 0.5 0.6 4.3 5.5 6.4 10.3
49.5 54.9 51.2 46.5 48.5 46.8 44.0
- --------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
- --------------------------------------------------------------------------------------------------
7,096,634 6,250,161 6,176,665 6,088,017 5,346,879 5,277,276 5,209,677
$ 12.49 $ 11.91 $ 12.14 $ 12.04 $ 11.45 $ 11.13 $ 10.67
$ 19.00 $ 16.63 $ 17.63 $ 14.50 $ 13.67 $ 16.00 $ 12.25
5,000 2,950 4,200 2,850 2,550 4,500 3,150
9,163 7,382 7,493 7,662 7,577 7,960 7,778
14 15 16 16 13 N/A N/A
- --------------------------------------------------------------------------------------------------
$273,862 $255,446 $241,624 $222,236 $204,947 $191,589 $172,396
$198,695 $189,108 $181,358 $166,970 $155,289 $144,509 $130,415
$ 20,331 $ 23,102 $ 23,184 $ 19,471 $ 17,790 $ 20,543 $ 17,344
$ 542 $ 605 $ 698 $ 1,760 $ 1,889 $ 2,564 $ 3,026
$247,969 $229,600 $239,327 $214,458 $193,842 $186,449 $173,211
- --------------------------------------------------------------------------------------------------
51.6 51.6 52.2 54.3 52.3 49.2 46.0
89.9 92.5 93.8 78.5 81.2 73.2 88.4
32.0 35.0 37.0 38.0 44.0 42.0 44.0
10.2 11.0 10.4 11.8 12.0 13.6 10.0
13.8 12.5 13.8 9.7 9.9 10.5 10.1
6.5 7.4 6.8 8.1 8.2 7.0 8.7
152.1 139.6 145.2 120.4 119.4 143.8 114.8
- --------------------------------------------------------------------------------------------------
<FN>
(d) Includes the 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. 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.
Connecticut Energy Corporation 37
Operating Data
Years ended September 30, 1995 1994 1993 1992 1991 1990
- ----------------------------------------------------------------------------------------------------------------------------
Table 1
Percentage of Operating Revenues
Purchased gas 49.8 52.7 53.1 51.3 48.4 48.4
Operations 21.2 20.8 19.4 21.3 21.7 23.0
Maintenance 1.6 1.7 1.7 1.8 2.0 2.3
Depreciation and depletion 6.0 5.4 5.7 5.6 5.9 6.1
Taxes 9.8 9.0 9.2 9.0 10.9 10.5
- ----------------------------------------------------------------------------------------------------------------------------
Purchased gas and operating expenses 88.4 89.6 89.1 89.0 88.9 90.3
- ----------------------------------------------------------------------------------------------------------------------------
Interest expense and other deductions, net 5.5 5.1 5.7 6.0 6.1 5.7
Earnings applicable to common stock (a) 6.1 5.3 5.2 5.0 5.0 4.0
- ----------------------------------------------------------------------------------------------------------------------------
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 22 23 24 24 24 26
Annual revenue per customer $ 317 $ 317 $ 299 $ 300 $ 289 $ 290
Rate per Mcf $ 14.11 $ 13.74 $ 12.62 $ 12.35 $ 12.04 $ 11.32
Margin per Mcf $ 8.96 $ 8.36 $ 7.63 $ 7.52 $ 7.61 $ 7.13
Annual number of customers 34,419 35,170 36,184 37,444 39,186 40,997
- ----------------------------------------------------------------------------------------------------------------------------
Residential heating
- ----------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 98 115 110 108 97 108
Annual revenue per customer $ 1,078 $ 1,187 $ 1,074 $ 1,045 $ 904 $ 941
Rate per Mcf $ 11.03 $ 10.35 $ 9.73 $ 9.70 $ 9.36 $ 8.69
Margin per Mcf $ 6.01 $ 5.03 $ 4.81 $ 4.81 $ 4.95 $ 4.56
Annual number of customers 104,067 102,043 100,872 99,706 97,406 95,240
- ----------------------------------------------------------------------------------------------------------------------------
Residential apartments
- ----------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 1,585 2,132 2,132 2,149 2,006 2,152
Annual revenue per customer $ 12,919 $ 16,611 $ 15,294 $ 15,217 $ 13,401 $ 13,141
Rate per Mcf $ 8.15 $ 7.79 $ 7.18 $ 7.08 $ 6.68 $ 6.11
Margin per Mcf $ 3.23 $ 2.59 $ 2.35 $ 2.33 $ 2.38 $ 2.08
Annual number of customers 843 751 751 739 725 707
- ----------------------------------------------------------------------------------------------------------------------------
Commercial
- ----------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 403 452 444 435 387 415
Annual revenue per customer $ 3,522 $ 3,826 $ 3,527 $ 3,440 $ 2,917 $ 2,902
Rate per Mcf $ 8.75 $ 8.47 $ 7.95 $ 7.90 $ 7.53 $ 6.99
Margin per Mcf $ 3.73 $ 3.15 $ 3.03 $ 3.02 $ 3.13 $ 2.85
Annual number of customers 13,412 13,142 12,965 12,831 12,758 12,717
Annual number of heating customers 8,005 7,813 7,630 7,541 7,498 7,479
- ----------------------------------------------------------------------------------------------------------------------------
Industrial firm
- ----------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 1,856 2,199 2,085 1,925 1,754 1,856
Annual revenue per customer $ 14,362 $ 16,568 $ 14,935 $ 13,691 $ 11,812 $ 11,584
Rate per Mcf $ 7.74 $ 7.53 $ 7.16 $ 7.11 $ 6.73 $ 6.24
Margin per Mcf $ 2.82 $ 2.30 $ 2.30 $ 2.32 $ 2.40 $ 2.16
Annual number of customers 1,258 1,274 1,283 1,287 1,305 1,334
Annual number of heating customers 722 731 728 716 716 722
- ----------------------------------------------------------------------------------------------------------------------------
Interruptible
- ----------------------------------------------------------------------------------------------------------------------------
Mcf consumption per customer 42,212 37,870 30,545 23,035 21,933 14,558
Annual revenue per customer $128,705 $121,940 $105,892 $ 86,215 $104,186 $ 56,657
Rate per Mcf $ 3.05 $ 3.22 $ 3.47 $ 3.74 $ 4.75 $ 3.89
Margin per Mcf $ 1.14 $ 0.87 $ 0.88 $ 0.99 $ 1.39 $ 1.06
Annual number of customers 217 184 152 136 127 136
- ----------------------------------------------------------------------------------------------------------------------------
Number of total customers 154,216 152,564 152,207 152,143 151,507 151,131
Cost per Mcf of gas $ 3.70 $ 4.22 $ 4.30 $ 4.02 $ 4.04 $ 3.71
- ----------------------------------------------------------------------------------------------------------------------------
<FN>
*Mcf -- one thousand cubic feet; MMcf -- one million cubic feet
38 Connecticut Energy Corporation
Operating Data
Years ended September 30, 1995 1994 1993 1992 1991 1990
- ----------------------------------------------------------------------------------------------------------------------------
Table 3
Revenue by Customer Class
(dollars in thousands)
- ----------------------------------------------------------------------------------------------------------------------------
Residential $135,061 $145,975 $131,632 $127,224 $110,062 $111,321
Commercial firm 47,558 50,838 46,022 44,316 37,538 37,080
Industrial firm 18,190 21,339 19,180 17,696 15,557 15,527
- ----------------------------------------------------------------------------------------------------------------------------
Total firm revenue $200,809 $218,152 $196,834 $189,236 $163,157 $163,928
- ----------------------------------------------------------------------------------------------------------------------------
Interruptible, transportation and
special contract $ 29,576 $ 21,127 $ 14,697 $ 12,478 $ 14,814 $ 9,103
Other 1,708 1,594 1,231 1,297 1,201 1,028
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues $232,093 $240,873 $212,762 $203,011 $179,172 $174,059
- ----------------------------------------------------------------------------------------------------------------------------
Margin by Customer Class (b)
- ----------------------------------------------------------------------------------------------------------------------------
Residential $ 72,480 $ 71,643 $ 63,391 $ 62,449 $ 57,153 $ 57,913
Commercial firm 20,005 19,315 17,265 16,946 15,446 15,102
Industrial firm 6,507 6,688 6,111 5,794 5,491 5,379
- ----------------------------------------------------------------------------------------------------------------------------
Total firm margin $ 98,992 $ 97,646 $ 86,767 $ 85,189 $ 78,090 $ 78,394
- ----------------------------------------------------------------------------------------------------------------------------
Interruptible, transportation and
special contract $ 5,755 $ 4,258 $ 2,427 $ 3,666 $ 5,302 $ 3,383
- ----------------------------------------------------------------------------------------------------------------------------
Total margins $104,747 $101,904 $ 89,194 $ 88,855 $ 83,392 $ 81,777
- ----------------------------------------------------------------------------------------------------------------------------
Table 4
Sources of Gas Supply in MMcf*
- ----------------------------------------------------------------------------------------------------------------------------
Tennessee Gas Pipeline (2) 24 -- 1,873 2,249 4,546
Algonquin Gas Transmission (7) 53 229 2,521 5,476 7,518
Texas Eastern -- -- 372 1,539 1,649 --
SCG Gas Quest -- -- -- -- -- 111
Distrigas 433 1,287 761 1,472 1,435 2,602
Producers/Marketers 20,155 17,213 14,958 13,750 11,505 8,394
Alberta Northeast 12,573 12,631 12,446 4,863 -- --
- ----------------------------------------------------------------------------------------------------------------------------
Total 33,152 31,208 28,766 26,018 22,314 23,171
- ----------------------------------------------------------------------------------------------------------------------------
Additional storage supply:
LNG 58 86 12 269 2 (22)
Pipeline (c) 172 (388) (1,362) (1,345) -- (6)
Propane -- -- 33 -- 2 113
- ----------------------------------------------------------------------------------------------------------------------------
Total additional supply 230 (302) (1,317) (1,076) 4 85
- ----------------------------------------------------------------------------------------------------------------------------
Total supply 33,382 30,906 27,449 24,942 22,318 23,256
- ----------------------------------------------------------------------------------------------------------------------------
Table 5
Gas Throughput in MMcf (d)
- ----------------------------------------------------------------------------------------------------------------------------
Sales:
Residential 12,280 14,038 13,635 13,233 11,790 12,957
Commercial firm 5,402 5,902 5,786 5,583 4,935 5,269
Industrial firm 2,336 2,787 2,673 2,476 2,287 2,478
Interruptible, transportation and
special contract (e)(f) 29,680 10,509 6,296 7,992 8,784 6,668
Other uses (g) 1,030 1,066 712 517 521 572
- ----------------------------------------------------------------------------------------------------------------------------
Total requirements 50,728 34,302 29,102 29,801 28,317 27,944
- ----------------------------------------------------------------------------------------------------------------------------
Peak day delivery in Mcf 253,999 227,477 203,557 182,688 189,192 177,616
- ----------------------------------------------------------------------------------------------------------------------------
Degree days -- actual 4,970 5,750 5,467 5,354 4,654 5,523
Degree days as percentage of 'normal' 90% 104% 99% 97% 85% 100%
- ----------------------------------------------------------------------------------------------------------------------------
<FN>
(a) Before nonrecurring credit in 1990.
(b) Margin in this table is calculated as revenue minus purchased gas costs and
gross earnings 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 The Connecticut Light and Power Company's Devon generating station.
(g) Includes gas used by Southern and unaccounted for gas.
Connecticut Energy Corporation 39
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.
40 Connecticut Energy Corporation
Investment Information
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 36 and 37 in the Eleven
Year Financial Summary.
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.
Income-Revenue Data Common Share Data
- ----------------------------------------------------------------------------------------------------------------------------------
Pretax Federal
Gross margin (fed.) net income Net Divi- % Yield Price range P-E ratio
$ $ per $ % of tax income Earned dend Pay- on avg. $ $
Year mil. share(a) mil. g.m. $ mil. $ mil. $ $ out price high low high low
- ----------------------------------------------------------------------------------------------------------------------------------
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 4.0 12.8 1.58 1.29 82 5.6 26 20 16.5 12.7
1995 116.5 13.28 20.0 17.1 5.9 14.1 1.60 1.30 81 6.4 22 18 1/2 13.8 11.6
5 Yr.
avg. 104.3 13.76 15.4 14.7 4.0 11.4 1.50 1.28 85 6.1 23 3/4 18 3/8 15.9 12.2
- ----------------------------------------------------------------------------------------------------------------------------------
Quarterly Financial Information
- ----------------------------------------------------------------------------------------------------------------------------------
Quarter Gross margin $ mil. Pretax (fed.) net income $ mil. Earned per share $ Dividends paid per share $
ended 1995 1994 1993 1995 1994 1993 1995 1994 1993 1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
12/31 32.2 30.1 29.4 7.2 7.2 8.1 .57 .67 .80 .325 .320 .320
3/31 53.3 50.5 42.0 22.7 20.0 16.3 1.79 1.77 1.59 .325 .320 .320
6/30(b) 19.1 20.1 16.5 (2.7) (2.7) (3.5) (.23) (.16) (.31) .325 .325 .320
9/30(b) 11.9 13.3 11.8 (7.2) (7.7) (6.3) (.52) (.53) (.57) .325 .325 .320
- ----------------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------------
Market price $ Trading volume
Quarter 1995 1994 1993 in thousands
ended high low close high low close high low close 1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
12/31 22 18 5/8 19 1/2 26 23 24 7/8 23 1/2 20 1/8 23 330.0 266.3 282.8
3/31 20 1/4 18 1/2 19 1/8 25 20 21 1/4 25 3/8 22 1/2 25 1/8 264.3 508.7 892.5
6/30 20 5/8 18 5/8 19 5/8 22 1/2 20 1/4 20 1/4 26 1/2 24 5/8 25 1/8 336.2 336.3 289.4
9/30 20 1/2 18 7/8 19 3/8 22 1/4 20 1/4 21 5/8 26 24 3/8 24 7/8 229.5 262.2 543.0
- ----------------------------------------------------------------------------------------------------------------------------------
<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.
Connecticut Energy Corporation 41
Shareholder Information
Annual Meeting
The Annual Meeting of Shareholders will take place Tuesday, January 30, 1996 at
10 a.m. in the Trumbull Marriott Hotel, 180 Hawley Lane, Trumbull, Connecticut.
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.
Dividends -- Direct Deposit -- Reinvestment
Dividends on common stock are declared quarterly by the Board of Directors and
are usually paid on the last business day of each quarter.
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.
The Dividend Reinvestment and Stock Purchase Plan provides shareholders with a
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 on purchases. Plan features include:
- -- Cash contributions from $50 to $50,000 can be made and are invested monthly.
- -- 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.
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
Call Bank of Boston investor relations representatives toll free at:
(800) 736-3001 or
(800) 952-9245 TTY/TDD service for the hearing impaired
Or write Bank of Boston, Investor Relations, Mail Stop 45-02-09, P.O. Box 644,
Boston, MA 02102-0644
42 Connecticut Energy Corporation
Shareholder Information (continued)
Quarterly Earnings Releases
Press releases are issued when the Company announces quarterly financial
results. For the 1996 quarters, results should appear in the Wall Street
Journal Digest of Earnings on or about January 31, April 24, July 24 and
November 2.
Chairman's Update Letters
If your Connecticut Energy account is held in a brokerage account instead of
your own name, we would like to send you a copy of the Chairman's Update which
is enclosed with the dividend checks or dividend reinvestment statements of
registered shareholders. Please call us at (800) 760-7776 and ask to be put on
our mailing list for the Chairman's quarterly updates.
Form 10-K
To obtain a copy of Form 10-K or to request further financial information
contact Judith Falango, Manager Investor and Shareholder Relations, at (800)
760-7776.
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 at (800) 760-7776. Allow two weeks for the
transfer to occur.
Internet Home Page
Connecticut Energy Corporation has established a home page on the World Wide
Web of the Internet. The following information, in addition to this annual
report, is available through our home page:
Forms 10-K and 10-Q
Earnings news releases
Chairman's update letters
Dividend Reinvestment and Stock Purchase Plan Prospectus
List of investment firms that follow Connecticut Energy
You may access our home page on InvestorsEdge at the address
(http://www.IRnet.com) by selecting "Corporate Profiles."
Connecticut Energy Corporation 43
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 Child Psychiatry, Yale
Child Study Center and Associate Dean,
Yale School of Medicine
Richard F. Freeman
President and Chief Executive Officer,
Greater 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,
Producto-Moore Companies
Samuel M. Sugden
Chairman,
LeBoeuf, Lamb, Greene & MacRae L.L.P.
Christopher D. Turner
Project Manager, Energy Sector
Bechtel International Consulting Group
Helen B. Wasserman
Member, Board of Governors for Higher
Education, State of Connecticut
Independent Accountants
Coopers & Lybrand L.L.P.
1301 Avenue of the Americas
New York, NY 10019-6013
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
Executive Vice President and
Chief Operating Officer
Carol A. Forest
Vice President, Finance,
Chief Financial Officer and Treasurer
J. Richard Tiano
Vice President, General Counsel and
Secretary
Labor Union Leadership
United Steel Workers of America
Local 12000
Gabriel Gambardella
President
Francis J. O'Connor
Vice President
Vincent L. Ammann, Jr.
Group Vice President
Peter D. Loomis
Group Vice President,
Customer and Operating Services
Salvatore A. Ardigliano
Vice President, Marketing
and Gas Supply Services
Frank L. Esposito
Vice President, Human Resources
James P. Healy
Vice President, Energy Services Planning
Ernest W. Karkut
Vice President, Purchasing and Plant Services
Larry S. McGaughy
Vice President, Corporate Engineering and
Special Projects
Phyllis A. O'Brien
Vice President, Accounting and
Regulatory Services
Patricia A. Younger
Vice President, Customer Relations
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44 Connecticut Energy Corporation
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855 Main Street
Bridgeport
Connecticut 06604