Management's Discussion and Analysis of
Financial Condition and Results of Operations
Connecticut Energy Corporation ("Connecticut Energy" or "Company") and its
subsidiaries and their representatives may, from time to time, make written or
oral statements, including statements contained in the Company's filings with
the Securities and Exchange Commission and in its annual report to shareholders,
including its Form 10-K for the fiscal year ended September 30, 1999, which
constitute or contain "forward-looking" information as that term is defined in
the Private Securities Litigation Reform Act of 1995.
All statements other than the financial statements and other statements of
historical facts included in this annual report to shareholders regarding the
Company's financial position and strategic initiatives and addressing industry
developments are forward-looking statements. Where, in any forward-looking
statement, the Company, or its management, expresses an expectation or belief as
to future results, such expectation or belief is expressed in good faith and
believed to have a reasonable basis, but there can be no assurance that the
statement of expectation or belief will result or be achieved or accomplished.
Factors which could cause actual results to differ materially from those stated
in the forward-looking statements may include, but are not limited to, general
and specific economic, financial and business conditions; federal and state
regulatory, legislative and judicial developments which affect the Company or
significant groups of its customers; the impact of competition on the Company's
revenues; fluctuations in weather from normal levels; changes in development and
operating costs; the availability and cost of natural gas; the availability and
terms of capital; exposure to environmental liabilities; the costs and effects
of unanticipated legal proceedings; the successful implementation and
achievement of internal performance goals; the impact of unusual items resulting
from ongoing evaluations of business strategies and asset valuations; changes in
business strategy; and estimates of future costs or the effect on future
operations as a result of events that could result from the Year 2000 issue
described further herein.
RESULTS OF OPERATIONS
NET INCOME
The Company's consolidated net income is detailed below:
(in thousands, except per share)
Years ended September 30, 1999 1998 1997
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Net income $16,688 $19,011 $16,441
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Net income, excluding merger-related expenses $20,222 $19,011 $16,441
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Net income per share - diluted $ 1.61 $ 1.88 $ 1.81
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Net income per share, excluding merger-related expenses - diluted $ 1.95 $ 1.88 $ 1.81
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Weighted average common shares outstanding - diluted 10,361 10,104 9,096
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Net income for 1999 was approximately 12% lower compared to 1998 primarily
due to merger-related expenses. Excluding merger-related expenses, net income
would have been $20,222,000, an increase of approximately 6%; and earnings per
share would have been $1.95, or approximately 4% higher than in 1998. The
increase in net income, excluding merger-related expenses, for 1999 was
principally due to higher firm margins earned by the Company's principal
subsidiary, The Southern Connecticut Gas Company ("Southern"), and its
nonutility subsidiary, CNE Energy Services Group, Inc. ("CNE Energy"), as well
as earnings of the Company's other nonutility subsidiaries, CNE Development
Corporation ("CNE Development") from brokering fees and CNE Venture-Tech, Inc.
("CNE Venture-Tech") from service bureau fees. The Company's nonutility
subsidiaries contributed approximately $0.17 to earnings per share in 1999,
representing approximately 11% of consolidated earnings per share of $1.61. The
increase in the Company's net income, excluding merger-related expenses, for
1999 compared to last year was also due to lower operations expense and lower
provisions for gross earnings and state income taxes.
Partially offsetting the increase in net income, excluding merger-related
expenses, for 1999 were lower interruptible margins, higher depreciation and
amortization expense, higher provisions for property and federal income taxes
and higher other deductions compared to last year.
Net income for 1998 was a record for the Company. Net income increased
approximately 16% and earnings per share were approximately 4% higher compared
to 1997. Factors which contributed to increased net income for 1998 included
higher firm margins earned by Southern, lower taxes, higher other income and
lower total interest expense. Additionally, the Company's nonutility
subsidiaries contributed approximately $0.17 to earnings per
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Connecticut Energy Corporation
share in 1998, representing approximately 9% of consolidated earnings per share.
The contribution to 1998 earnings by the nonutility subsidiaries was principally
due to firm margins earned by CNE Energy and the gain recognized from its sale
of 50% of its joint venture interests in Total Peaking Services, LLC ("TPS") and
CNE Peaking, LLC ("CNEP") to Conectiv Energy Supply, Inc., a subsidiary of
Conectiv. Partially offsetting these positive impacts on net income for 1998
were lower interruptible margins and higher operating expenses in the areas of
operations, maintenance and depreciation.
TOTAL SALES AND TRANSPORTATION VOLUMES
The Company's total volumes of gas sold and transported in 1999 were
approximately 38,381 MMcf, or approximately 6% higher compared to 1998. The
increase was primarily due to higher firm contract and firm transportation
volumes and was partially offset by lower interruptible volumes.
The Company's total volumes of gas sold and transported in 1998 were
approximately 36,260 MMcf, representing a decrease of approximately 21% compared
to 1997. This decrease occurred in all sales categories and was primarily
attributable to warmer weather and the competitive price of certain alternate
fuels. Higher firm transportation and firm contract volumes in the 1998 period
partially offset the overall decrease in total sales and transportation volumes.
FIRM SALES, FIRM TRANSPORTATION AND FIRM CONTRACT VOLUMES
The Company's firm volumes for 1999 increased approximately 28% compared to
1998. This was primarily due to firm volumes generated by a contract to
transport natural gas to an electric generating plant in Bridgeport,
Connecticut, which began operations in July 1998. Also contributing to the
increase in firm volumes in 1999 was the continued growth in Southern's
residential customer base and conversions of nonheating customers to heating
customers. The increase in firm volumes for the 1999 period was also attributed
to an increase in firm transportation and firm contract sales volumes and was
partially offset by lower industrial firm sales primarily due to customers'
switching to firm transportation services. Weather in 1999 was relatively
unchanged compared to 1998.
The Company's firm volumes for 1998 increased approximately 3% compared to
1997. This was primarily due to an increase in firm transportation and firm
contract volumes, growth in Southern's customer base and conversions of
nonheating customers to heating customers. The overall increase in this category
was partially offset by lower firm sales due to weather that was approximately
7% warmer than in 1997.
INTERRUPTIBLE SALES AND TRANSPORTATION VOLUMES
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. Margins earned, net of gross earnings
tax, from on-system interruptible services in excess of an annual target were
allocated through a margin sharing mechanism between Southern and its firm
customers. Beginning June 1, 1996, excess on-system margins earned that would
have been returned to Southern's firm customers have been redirected, with
Connecticut Department of Public Utility Control ("DPUC") approval, to fund
certain economic development and hardship assistance programs (see section
entitled "Interruptible Margin Sharing" for further details). Off-system margins
earned, net of gross earnings tax, continue to be shared between Southern and
its firm customers. Gross margin retained represents the difference between
gross margin earned and margin to be allocated through the margin sharing
mechanism.
The chart below depicts Southern's volumes of gas sold to and transported for
on-system interruptible customers, off-system sales volumes and off-system
transportation volumes under a special contract with The Connecticut Light and
Power Company for its Devon electric generating station as well as gross margins
earned and retained due to the margin sharing mechanism on these services:
(dollars in thousands)
Years ended September 30, 1999 1998 1997
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Gross margin earned $6,330 $9,867 $12,872
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Gross margin retained $4,230 $5,981 $ 7,242
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Volumes sold and transported (MMcf) 9,563 13,690 23,794
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Interruptible gross margin earned and retained by Southern has decreased
since 1997 principally due to the competitive price of other energy sources
compared to natural gas.
Interruptible volumes sold and transported in 1999 were lower for all
interruptible categories, with the exception of on-system transportation, which
was slightly higher than in 1998. Lower off-system sales and
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Connecticut Energy Corporation
off-system transportation volumes were primarily responsible for the decrease in
interruptible volumes. The reduction in off-system sales volumes was primarily
due to the elimination of off-system sales activity by Southern as of April 1,
1999 (see section entitled "Gas Supply Management Agreement" for further
details).
GROSS MARGIN
The Company's gross margin in 1999 was approximately 6% higher than in 1998
principally due to higher firm margins, which were a record for the Company. The
increase in firm margins was attributed to the following factors: a full year of
margins earned by Southern and CNE Energy under a firm contract to transport
natural gas to an electric generating plant in Bridgeport, increased firm
transportation revenues, an increase in Southern's residential customer base and
conversions of nonheating customers to heating customers. Also contributing to
gross margin, to a lesser extent, were the Company's other nonutility
subsidiaries. Lower interruptible margins in 1999 partially offset the overall
increase in gross margin compared to 1998.
The Company's gross margin in 1998 was approximately 2% higher than in 1997.
The increase in gross margin was principally attributed to higher firm margins
and was partially offset by lower interruptible margins.
Southern's firm rates include a Weather Normalization Adjustment ("WNA"),
which allows Southern to charge or credit the non-gas portion of its firm rates
to reflect deviations from normal weather. The operation of the WNA collected
approximately $6,085,000, $6,093,000 and $2,252,000 from firm customers in 1999,
1998 and 1997, respectively, due to warmer than normal weather.
Southern's firm sales rates include a Purchased Gas Adjustment clause ("PGA")
which allows Southern to flow back to its customers, through periodic
adjustments to amounts billed, increased or decreased costs incurred for
purchased gas compared to base rate levels without affecting gross margin.
Adjustments related to Southern's PGA increased revenues and gas costs by
approximately $725,000, $11,050,000 and $6,206,000 for 1999, 1998 and 1997,
respectively.
OPERATIONS EXPENSE
Operations expense decreased approximately 5% in 1999 compared to 1998
primarily due to a lower provision for uncollectibles because of increased
collection efforts, lower lease payments related to the sublease of Southern's
liquefied natural gas ("LNG") plant to TPS, lower costs for certain outside
legal services and lower general liability insurance premiums. Higher costs for
collection agency fees partially offset the decrease in operations expense in
the 1999 period.
Operations expense increased approximately 10% in 1998 compared to 1997
primarily due to higher costs for labor, partly due to early retirement
incentives paid to union employees during the third quarter of 1998; outside
services; customer service; uncollectibles; conservation expense; regulatory
commission expense; and certain other general and administrative expenses. Also
contributing to the increase in operations expense compared to 1997 were higher
costs related to the Company's Restricted Stock Award Plan and higher operations
expense recorded by the Company's nonutility subsidiaries. Partially offsetting
the overall increase in operations expense for 1998 were lower expenses in the
areas of pensions and postretirement health care as well as lower amortizations
related to Southern's certified hardship forgiveness program due to the
conclusion of the amortization period as of December 31, 1996.
Beginning in 1994, the DPUC has allowed Southern to recover certain deferred
shortfalls in energy assistance funding from various state and federal agencies
related to the 1991/92 and 1992/93 heating seasons as well as deferred costs
associated with Southern's certified hardship forgiveness program. Accordingly,
included in operations expense for 1999, 1998 and 1997 was approximately
$262,000, $620,000 and $1,619,000, respectively, related to these amortizations,
which concluded as of December 31, 1998.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization expense for the Company has increased in each
of the last three years due to additions to plant in service by Southern and
increased amortizations by the Company's nonutility subsidiaries.
FEDERAL AND STATE INCOME TAXES
The provision for federal and state income taxes for 1999 was higher compared
to 1998 primarily due to the non-deductibility of certain merger-related
expenses and the tax treatment of conservation program expenses. These increases
were partially offset by the reduction of the Company's accrual for prior years'
taxes that was recorded during fiscal 1999.
The total provision for federal and state income taxes decreased
approximately 28% in 1998 compared to 1997 primarily due to a lower effective
tax rate. The lower effective tax rate was principally due to the tax treatment
of premiums paid for the refinancing of long-term debt in 1998 as well as the
tax treatment of uncollectibles and property taxes.
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Connecticut Energy Corporation
MUNICIPAL, GROSS EARNINGS AND OTHER TAXES
Municipal, gross earnings and other taxes for 1999 were approximately 11%
higher compared to 1998 primarily due to the absence of a reduction to property
tax expense which occurred in 1998 as a result of a DPUC Decision which required
Southern to change its accounting treatment for accruing property taxes (see
section entitled "Change in Accounting Treatment for Property Taxes" for further
details). A lower provision for gross earnings tax in 1999 partially offset the
overall increase in municipal, gross earnings and other taxes.
Municipal, gross earnings and other taxes decreased approximately 12% in 1998
compared to 1997. The decrease was primarily due to Southern's change in its
accounting treatment for accruing property taxes and, to a lesser extent, lower
gross earnings tax due to lower revenues.
OTHER DEDUCTIONS (INCOME), NET
The increase in other deductions for 1999 was primarily due to a reduction in
equity earnings from CNE Energy's joint venture, Conectiv/CNE Energy Services,
LLC, and, to a lesser extent, higher promotional expenses recorded by Southern.
Partially offsetting the increase in other deductions was an increase in rental
income recorded by Southern for the sublease of its LNG plant to TPS.
Other income for 1998 was higher compared to 1997 primarily due to the
recognition of a gain in connection with the sale of a 50% interest in TPS by
CNE Energy, the favorable operating results of the Company's nonutility
subsidiaries and an increase in investment income related to investments in a
nonqualified employee benefit plan trust.
MERGER-RELATED EXPENSES
In the quarter ended June 30, 1999, the Company began recording
merger-related expenses, which as of September 30, 1999, totaled approximately
$3,534,000, net of income taxes. These expenses are primarily comprised of
investment banking and legal fees and compensation expense related to the
accelerated vesting of certain shares issued under the Company's Restricted
Stock Award Plan (see section entitled "Connecticut Energy Corporation/Energy
East Corporation Merger" for additional information).
INTEREST EXPENSE
Total interest expense increased approximately 2% for 1999 compared to 1998
primarily due to an increase in long-term debt expense related to CNE Energy's
1998 financing of the construction of distribution facilities to transport
natural gas to an electric generating plant in Bridgeport. The increase in total
interest expense was partially offset by lower interest expense on short-term
borrowings due to lower average short-term borrowings and a lower weighted
average interest rate, lower interest expense on deferred purchased gas cost
balances and lower interest expense related to pipeline refunds not yet returned
to firm customers.
Total interest expense decreased approximately 4% in 1998 compared to 1997
primarily due to lower short-term interest expense related to lower average
short-term borrowings, lower long-term debt expense due to debt repayments and
lower interest expense on pipeline refunds not yet returned to firm customers.
Partially offsetting the decrease in total interest expense was an increase in
interest expense on deferred purchased gas costs and an increase in long-term
debt expense due to borrowings by CNE Energy.
The Company obtains short-term funds at the most competitive rates by
utilizing bank borrowings at money market rates. Short-term interest rates
averaged 5.48% in 1999, 6.02% in 1998 and 5.71% in 1997.
INFLATION
Inflation as measured by the Consumer Price Index for all urban consumers was
approximately 1.9%, 1.6% and 2.7% for 1999, 1998 and 1997, respectively.
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 are generally 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.
REGULATORY MATTERS
Rate Review Docket/Rate Case Application
In accordance with Connecticut statutes, Southern has undergone a periodic
review of its rates and services by the DPUC that commenced in January 1998. A
periodic review entails a complete review by the DPUC of Southern's financial
and operating records; and public hearings are held to determine whether
Southern's current rates are unreasonably discriminatory or more or less than
just, reasonable and adequate.
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Connecticut Energy Corporation
In July 1998, the DPUC issued a Decision in Docket No. 97-12-21, DPUC
Financial and Operational Review of The Southern Connecticut Gas Company - Phase
I, regarding the "overearnings" portion of the rate review docket. According to
Connecticut statutes, the DPUC may review a utility which earns 100 basis points
or more over its allowed rate of return for six consecutive months. In its
Decision, the DPUC ordered a rate reduction of $528,000 on an annual basis.
On February 10, 1999, the DPUC issued a Decision in Docket No. 97-12-21 on
the periodic review. In this Decision, the DPUC found Southern's present rate
structure to be more than just and adequate for both the current and projected
operating and financial needs of the company; and the DPUC proposed that
Southern's allowed rate of return on common equity be adjusted from 11.45% to
10.61%, which would produce an overall allowed return on rate base of 9.65%. It
also stated that Southern was overearning by approximately $9,400,000. Part of
the overearning resulted from an exclusion from rate base of 50% of the costs
incurred to construct a twenty-inch gas trunkline to assist Southern in
transporting gas throughout its system. This exclusion was based upon the DPUC's
belief that these costs should be divided between regulated and nonregulated
operations. This exclusion from rate base totaled approximately $5,422,000. The
DPUC has stated that this allocation will be reviewed in future proceedings and
could be revised based upon the relative benefits that this trunkline project
brings to regulated and nonregulated operations. The DPUC further ordered
Southern to submit a proposal for allocating the overearnings by March 25, 1999
or file an application for a rate case no later than July 15, 1999.
In response to the DPUC's Decision on the periodic review, Southern filed an
Appeal in Connecticut Superior Court regarding the claimed disallowance of the
twenty-inch gas trunkline from rate base and related depreciation from operating
expenses (see section entitled "Trunkline Appeal" for further details) and opted
to file a comprehensive rate case, which includes proposals for incentive-based
rates. Southern's rate case application with the DPUC, Docket No. 99-04-18, DPUC
Review of The Southern Connecticut Gas Company's Rates and Charges, also
requests an increase in rates designed to produce additional annual revenues of
approximately $24,195,000. This would increase Southern's projected annual
revenues by approximately 10.56%. Southern has not had an increase in its base
rates since December 1993. There are no assurances that the requested rates will
be approved, in whole or in part.
The DPUC has separated Docket No. 99-04-18 into two phases. Phase I addresses
Southern's overearnings and Phase II addresses Southern's request for a rate
increase.
On July 1, 1999, in Phase I of Docket No. 99-04-18, Southern and The Office
of Consumer Counsel ("OCC") reached a Settlement Agreement which resulted in an
immediate rate reduction for firm sales customers. In accordance with the
Settlement Agreement, which was approved by the DPUC, Southern was required to
reduce its rates by $1,300,000 on an annual basis. Both the $1,300,000 rate
reduction and the $528,000 rate reduction ordered by the DPUC in Docket No.
97-12-21 will remain in effect until the date new rates are effective pursuant
to a DPUC Order in Phase II of Docket No. 99-04-18.
The hearing phase of Docket No. 99-04-18 has concluded and Southern
anticipates a Decision in Phase II by mid-January 2000. Southern's new base
rates, if approved, would become effective at that time.
On August 24, 1999, in a separate proceeding, the OCC filed a petition with
the DPUC seeking a review of Southern's earnings for the period ended June 30,
1999. The OCC alleged that Southern earned in excess of its authorized return
and that there should be a rate reduction or other relief afforded to
ratepayers.
The DPUC agreed to review the OCC's claims and scheduled a hearing for
October 14, 1999. On October 7, 1999, the OCC and Southern filed with the DPUC a
proposed settlement of the OCC's claims. The DPUC cancelled the October 14, 1999
hearing. If the settlement is accepted by the DPUC, Southern will reduce rates
for its firm sales customers by an additional $1,000,000. The rate reduction
will take the form of a credit to customers' bills for the months of November
1999 through February 2000.
Action by the DPUC on the proposed settlement is anticipated in November
1999.
Trunkline Appeal
Subsequent to the filing of the Appeal by Southern in the Connecticut
Superior Court in March 1999 regarding the treatment of its trunkline
investment, the DPUC answered the Appeal by denying Southern's claims. Southern
filed its Brief in support of its Appeal in June 1999.
In July 1999, the DPUC moved to dismiss the Appeal. The DPUC based its Motion
to Dismiss on the grounds of mootness and lack of aggrievement.
In September 1999, the Connecticut Superior Court held a hearing on the
DPUC's claims. The Court denied the DPUC's Motion to Dismiss and ordered the
DPUC to file its Brief on the merits of the Appeal by October 20, 1999. The
DPUC's Brief was filed with the Court.
A Superior Court hearing on the Appeal is likely to occur prior to December
31, 1999, with a Decision by the Court thereafter.
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Connecticut Energy Corporation
Change in Accounting Treatment for Property Taxes
In October 1997, Southern requested that the DPUC consider a proposed change
in Southern's accounting treatment for property taxes which would allow Southern
to account for such taxes as a prepaid expense. This method is consistent with
the practice of other major public service companies in Connecticut. Southern
had been accruing for property taxes in the year prior to the payment date. In
November 1997, under the reopened Docket No. 93-03-09, Application of The
Southern Connecticut Gas Company to Increase Its Rates and Charges, the DPUC
approved Southern's proposal. The stipulations in the Decision ordered Southern
to reduce its reserve for property taxes by approximately $3,722,000, with 50%,
or approximately $1,861,000, flowing through as a one-time reduction to property
tax expense in the first quarter of fiscal 1998 and the remaining 50% refunded
to firm customers through the operation of the PGA in three equal amounts during
the following quarter.
Unbundling of Natural Gas Services Docket
In March 1999, the DPUC issued a Decision in the second phase of Docket No.
97-07-11, DPUC Generic Investigation into Issues Associated with the Unbundling
of Natural Gas Services by Connecticut Local Distribution Companies. In the
Decision, the DPUC approved the implementation of daily demand meter charges for
firm sales and transportation customers and established balancing service
charges and conditions. The DPUC also authorized a newly created FTS-3
transportation service that uses algorithms instead of daily demand meters to
measure daily demand. This rate is available only to commercial and industrial
customers that use less than 500 Mcf per year.
With respect to Southern's billable service work, the DPUC concluded that
other ratepayers do not subsidize the cost of service work. The DPUC stated that
the resources necessary to provide this form of service work also provide the
Company with the resource flexibility essential to satisfy basic safety and
emergency work. The DPUC also stated that the natural gas public utility
industry has historically promoted and developed this service to promote the use
of natural gas as a fuel. Consequently, billable service work, according to the
DPUC, has become an expected part of a public service company's responsibility
to serve. Therefore, the DPUC denied Southern's request to discontinue billable
service work at this time. The next phase of this proceeding will investigate
cost of service issues associated with providing unbundled service.
Gas Supply Management Agreement
On February 26, 1999, Southern received a Decision from the DPUC regarding a
gas supply management agreement entered into with an outside vendor. In its
Decision, the DPUC approved Southern's agreement with Sempra Energy Trading
Corp. ("Sempra"), titled Natural Gas Annual Supply and Delivery Service and
Asset Optimization Agreement ("Sempra Agreement"), in its entirety, including
85%/15% margin sharing with firm customers and shareholders, respectively. Under
the Sempra Agreement, Sempra manages certain of Southern's gas assets and
Southern transfers the ability to make off-system sales and receive capacity
release funds. In return, Sempra pays a management fee to Southern, which is
included as part of the calculation to determine the margin to be shared with
firm customers through the operation of the PGA. The term of the Sempra
Agreement is one year, beginning April 1, 1999 and ending March 31, 2000. The
margin sharing arrangement approved in the Decision replaced the margin sharing
mechanism that had been in place for off-system sales and capacity releases as
approved by the DPUC in January 1996 in Docket No. 93-03-09, Application of The
Southern Connecticut Gas Company to Increase Its Rates and Charges - Reopening
I; however, it did not affect Southern's on-system interruptible margin sharing
mechanism.
In addition to the contract executed with Southern, Sempra also executed a
separate agreement with CNE Development. This agreement requires CNE Development
to perform consulting services on structured energy transactions.
Interruptible Margin Sharing
Pursuant to Southern's 1993 rate order, which incorporated the provisions of
the previously approved Partial Settlement of Certain Issues ("Partial
Settlement"), a target margin, net of gross earnings tax, was established for
on-system sales and transportation to Southern's interruptible customers.
Margins collected in excess of this target were shared between firm customers
and Southern on an 80%/20% split.
In January 1996, Southern requested a reopening of the 1993 rate proceeding
to propose a plan to redirect excess on-system margins to be returned to
ratepayers for calendar years 1996, 1997 and 1998 to fund certain economic
development initiatives in Bridgeport and to provide grants to customers to
reduce Southern's hardship assistance balances.
In April 1996, the DPUC issued a final Decision regarding Southern's
proposal. The DPUC effectively approved Southern's proposal with certain
modifications in the direction of funding of economic development initiatives,
the imposition of a cap of $6,000,000 per year of ratepayer margins to be split
equally between the programs, and certain implementation and status reporting
requirements.
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Connecticut Energy Corporation
YEAR 2000 READINESS DISCLOSURE
General
The Company believes it is ready for the Year 2000. All of the critical
systems are ready and contingency plans are in place. Management believes that
it has taken the reasonably prudent steps necessary to prepare for the Year
2000.
Since 1996, the Company has been working on various aspects of the Year 2000
issue. It has been implementing individual strategies targeted at the specific
nature of the Year 2000 issue in each of the following areas: (1)
business-application systems, (2) embedded systems, (3) vendor and supplier
relationships, (4) customers and (5) contingency planning. The Company has
completed its Year 2000 project. To coordinate its comprehensive Year 2000
program, the Company established a Year 2000 Task Force, chaired by the Vice
President, General Counsel and Secretary who reports directly to the Chairman
and Chief Executive Officer. The Year 2000 Task Force includes executive
management and employees with expertise from various disciplines including, but
not limited to, information technology, operations, customer service, marketing,
engineering, finance, facilities and communications, internal audit, purchasing
and law. In addition, the Company has utilized the expertise of outside
consultants to assist in the implementation of the Year 2000 program in such
areas as project initiation and planning, business-application systems inventory
and analysis, business-application systems remediation, business-application
systems replacement, and embedded systems inventory and analysis.
Southern is subject to regulation from the DPUC, among other governmental
agencies. Since January 1999, the DPUC, through an independent auditing firm,
has been auditing Southern and the other major investor-owned utilities in
Connecticut. As a result of this audit, the DPUC issued a Draft Decision on
September 30, 1999 finding that Southern "has completed all of its major
preparations for the Year 2000, including the development of contingency plans
and the testing of several pieces of the plans." Southern separately continues
to respond to the DPUC's auditors as they continue periodic Year 2000-related
monitoring of Southern and the other investor-owned utilities throughout the
remainder of 1999 to coordinate contingency plans and customer communications
strategies.
Vendors and Suppliers
The Company has contacted, in writing, vendors and suppliers of products and
services that it considers important to its operations. These contacts have
included, among others, suppliers of interstate transportation capacity, natural
gas producers, financial institutions and electric, telephone and water
companies. Most vendors have responded, but the quality of the responses
received from vendors and suppliers is not uniform. As a result, the Company
will continue to work with these vendors and suppliers to determine their level
of Year 2000 compliance. The Company has evaluated the degree of its vendors'
and suppliers' readiness and has developed appropriate contingency plans that,
among other things, establish various vendor and supplier redundancies. In
addition, the Company's contingency plan calls for increasing certain inventory
levels during the last calendar quarter of 1999 to provide ample supplies in the
event certain vendors fail to deliver goods due to the Year 2000. With respect
to those vendors and suppliers identified by the Company as critical to the
Company's operations, the Company has conducted in-depth interviews with all
vendors, including suppliers of interstate transportation capacity, natural gas
producers, and all vendors supplying electric, telephone and water services to
the Company's operations. The Company believes its critical vendors will be
fully prepared for the Year 2000.
Customers
The Company has no single customer, residential, commercial or industrial,
which generates a material portion of the Company's annual revenues. The Company
identified its major firm, interruptible and transportation customers and
communicated with these major customers to attempt to identify their level of
Year 2000 compliance. Many of these customers have their own Year 2000 projects
in progress, and the Company has not been informed that these customers
anticipate any Year 2000 related failures that would affect their consumption of
natural gas. The Company contacted each of its major customers to exchange Year
2000 readiness information during the spring of 1999.
Contingency Planning
The Company's Year 2000 strategies include contingency planning, encompassing
business continuity both within the Company and in the external business
environment. The planning effort includes critical Company areas such as
computing, networks, vendors and suppliers, operations, personnel and business
systems as well as systems and infrastructure external to the Company. All of
the members of the Company's senior management team have participated in various
aspects of the Company's contingency planning efforts. Separately, as part of
its normal business practice, the Company maintains plans to follow during
emergency circumstances, some of which
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Connecticut Energy Corporation
could arise from Year 2000-related problems. The Company has completed its
contingency plan for the Year 2000 and is continuing efforts to coordinate the
plan with various parties, including critical vendors and municipalities in
Southern's service area. The Company will revise the plan as needed during the
remainder of 1999.
Potential Risks
The Company believes the most significant potential risks to its internal
operations are as follows: (1) the ability to use electronic devices to control
and operate its distribution system, (2) the ability to render timely bills to
its customers and (3) the ability to maintain continuous operation of its
computer systems. The Company's Year 2000 program addresses each of these risks
and the remediation or replacement of these systems is completed. Furthermore,
the contingency plan outlines alternatives in the event that any Year
2000-related situations may occur.
The Company relies on the producers of natural gas and suppliers of
interstate transportation capacity to deliver natural gas to the Company's
distribution system. External infrastructure, such as electric, telephone and
water service, is necessary for the Company's basic operations as well as the
operations of many of its customers. Should any of these critical vendors fail,
the impact of any such failure could become a significant challenge to the
Company's ability to meet the demands of its customers, to operate its
distribution system and to communicate with its customers. It could also have a
material adverse financial impact including, but not limited to, lost sales
revenues, increased operating costs and claims from customers related to
business interruptions. The Company's program to address Year 2000 issues
emphasizes continued monitoring and/or testing of the progress of these critical
vendors and suppliers toward meeting the projected completion of their Year 2000
programs.
Financial Implications
The Company has generated nonrecurring expenses of approximately $342,000
over the three-year period ended September 30, 1999 for business-application
systems remediation, embedded systems replacement and certain existing
business-application systems replacement. Over the same time period, the Company
has capitalized costs of approximately $11,441,000 incurred to replace certain
existing business-application software systems with new systems that will be
Year 2000 operational and provide additional business management information.
Each of the components of the Company's Year 2000 program is completed and
the Company believes it is taking all reasonable steps necessary to be able to
operate successfully through and beyond the turn of the century.
Year 2000 Readiness Disclosure
The discussion contained herein is a "Year 2000 Readiness Disclosure" as
defined in the federal Year 2000 Readiness Disclosure Act.
The estimates and conclusions herein contain forward-looking statements and
are based on management's best estimates of future events. Risks to completing
the Year 2000 program include the availability of resources, the Company's
ability to discover and correct the potential Year 2000 sensitive problems which
could have a serious impact on specific facilities, and the ability of suppliers
to bring their systems into Year 2000 compliance.
RECENT ACCOUNTING DEVELOPMENTS
Effective October 1, 1999, the Company will adopt Statement of Position 98-5,
"Reporting on the Costs of Start-Up Activities" ("SOP 98-5"). SOP 98-5 requires
costs associated with start-up activities and costs classified as organizational
costs to be expensed as incurred. Adoption of this SOP, which relates
exclusively to the Company's nonutility operations, is not expected to have a
significant impact on the Company's financial condition or results of
operations.
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"), has been amended by
Statement of Financial Accounting Standards No. 137, which defers the effective
date of SFAS 133. SFAS 133 will become effective for all fiscal quarters of all
fiscal years beginning after June 15, 2000; therefore, it will become effective
for the Company on October 1, 2000. Adoption of this Statement is not expected
to have a significant impact 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 capital
expenditure programs and other corporate purposes, Connecticut Energy and
Southern have credit lines with a number of banks as detailed on page 17:
16
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
Shared
Connecticut
As of September 30, 1999 Southern Energy/Southern Total
- -----------------------------------------------------------------------------------------------
Committed lines $50,000,000 $20,000,000 $70,000,000
Uncommitted lines -- 5,000,000 5,000,000
As of September 30, 1999, unused lines of credit totaled $53,200,000.
Operating cash flows were higher for 1999 compared to 1998 primarily due to a
decrease in prepaid expenses, lower tax payments, a higher comparative increase
in other current liabilities related to the Sempra Agreement, higher accounts
payable balances, a higher comparative increase in other deferred credits, lower
gas inventories and lower refunds paid to customers. Partially offsetting the
increase in operating cash flows for 1999 were lower collections from customers
through the operation of the PGA.
Operating cash flows for 1998 were slightly lower compared to 1997 primarily
due to lower accrued taxes, pipeline refunds returned to firm customers and
lower liabilities related to margins earned, which were used to fund certain
economic development initiatives in Bridgeport. The decrease in operating cash
flows in 1998 was partially offset by collections from customers through the
operation of the PGA.
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.
INVESTING ACTIVITIES
Capital Expenditures
Capital expenditures, net of contributions in aid of construction,
approximated $29,508,000 in 1999, of which approximately 19% represents
expenditures by CNE Venture-Tech primarily related to its service bureau.
Capital expenditures, net of contributions in aid of construction, approximated
$24,614,000 in 1998 and $28,443,000 in 1997. Southern relies upon cash flows
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.
Capital expenditures in 2000 will approximate $29,900,000. Approximately
$26,200,000 of budgeted capital expenditures has been allocated to Southern, of
which approximately 26% is earmarked for new business. The majority of
Southern's remaining planned capital expenditures are to improve, protect and
maintain its existing gas distribution system. Over the 2000-2004 period, it is
estimated that total expenditures for new plant and equipment will range between
$140,000,000 and $160,000,000.
Nonutility Ventures
In September 1997, CNE Energy formed a joint venture with Conectiv, a holding
company formed by the merger of Delmarva Power & Light Company and Atlantic
Energy, Inc. The venture operates under the name Conectiv/CNE Energy Services,
LLC ("Conectiv/CNE Energy") and sells natural gas, electricity, fuel oil and
other services and markets a full range of energy-related planning, financial,
operational and maintenance services to commercial, industrial and municipal
customers in New England. Conectiv/CNE Energy has formed various alliances with
energy-related entities to market energy commodities and services to commercial
and industrial customers in New England.
As a result of the impending merger between Energy East Corporation ("Energy
East") and Connecticut Energy, Conectiv sold its 50% interest in Conectiv/CNE
Energy to CNE Energy. Energy East Solutions, Inc., an indirect subsidiary of
Energy East, subsequently acquired Conectiv's former interest in the joint
venture from CNE Energy.
In September 1998, CNE Energy and Conectiv Energy Supply, Inc., a subsidiary
of Conectiv, formed two joint ventures, TPS and CNEP. TPS, headquartered in
Bridgeport, operates a 1.2 billion cubic foot LNG open access storage facility
in Milford, Connecticut. The facility has access to three major natural gas
pipelines in New England: Algonquin Gas Transmission Company, Iroquois Gas
Transmission System, L.P. and Tennessee Gas Pipeline Company. TPS has received
FERC approval of its market-based tariffs and began storing and redelivering
customer-owned LNG at the Milford facility in fiscal 1999. CNEP provides a firm
in-market supply source to assist energy marketers and LDCs in meeting the
maximum demands of their customers by offering firm supplies for peak-shaving
and emergency deliveries. CNEP operates out of Newark, Delaware.
In 1999, CIS Service Bureau, LLC ("CIS"), a wholly-owned affiliate of CNE
Venture-Tech, began operations. CIS is a service bureau providing access to
customer billing software and other related services for utilities and energy
services providers, including Southern and CNE Energy.
17
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Connecticut Energy Corporation
Bridgeport Harbor Station Plant
In July 1998, Southern completed construction of the distribution facilities
needed to transport natural gas from a gate station in Stratford, Connecticut,
to a new 520 megawatt electric generating plant in Bridgeport. The gas turbine
plant is the largest non-nuclear generating plant in Connecticut and has the
capacity to provide enough electricity to service up to 260,000 homes.
FINANCING ACTIVITIES
Common Stock Dividends
In June 1998, the quarterly dividend paid per share on the Company's common
stock was increased to $0.335 per share, or an annual indicated dividend rate of
$1.34 per share.
Public Offering
In November 1997, the Company completed a public sale of 1,035,000 shares of
its common stock at a price of $24.25 per share and received net proceeds of
approximately $24,224,000. The proceeds of this sale were used for the repayment
of Southern's short-term debt.
MTN Program
In 1996, Southern initiated a Medium-Term Notes ("MTN") program, which was
approved by the DPUC. The program permits the issuance, from time to time, of up
to $75,000,000 of secured MTNs over a four-year period in varying amounts and
with varying terms.
In August 1996, Southern made its first issuance and sale under the program
of $20,000,000 in secured MTNs ("Series 1"). Series 1 MTNs have a weighted
average rate of 7.84% and will be redeemed through payments of $5,000,000 and
$15,000,000 in the years 2006 and 2026, respectively. Proceeds from the sale
were principally used to reduce short-term borrowings incurred primarily in
connection with Southern's construction program.
Southern's second issuance and sale of $17,000,000 in secured MTNs ("Series
2") occurred in September 1998. Series 2 MTNs have a weighted average rate of
6.71% and will be redeemed through payments of $3,000,000 and $14,000,000 in the
years 2003 and 2028, respectively. Proceeds from the sale were used to
repurchase $12,073,000 of Series T and Series U First Mortgage Bonds. The DPUC
has allowed the deferral of the unamortized issuance costs of Series 2 MTNs as
well as the premiums related to the repurchase of these notes. The total of
these unamortized issuance costs and repurchase premiums was approximately
$4,857,000 and is being amortized over the average life of this series.
Term Loan Agreement
In May 1998, CNE Energy entered into a term loan agreement with a bank to be
utilized to reimburse Southern for costs incurred to construct distribution
facilities to transport natural gas to an electric generating plant in
Bridgeport. Borrowings were completed in August 1998.
The method, timing and amounts of any future financings by the Company or its
subsidiaries will depend on a variety of factors, including capitalization
ratios, coverage ratios, interest costs, the state of the capital markets and
general economic conditions.
CONNECTICUT ENERGY CORPORATION/ENERGY EAST CORPORATION MERGER
On April 23, 1999, the Boards of Directors of Energy East and Connecticut
Energy announced that the companies have signed a definitive merger agreement
under which Connecticut Energy will become a wholly-owned subsidiary of Energy
East in a transaction which is valued at $617,000,000 including the assumption
of debt.
Shareholders of Connecticut Energy will receive $42.00 per share, 50% payable
in stock and 50% in cash. Shareholders will be able to specify the percentage of
the consideration they wish to receive in stock and in cash, subject to
proration. Shareholders who elect to receive stock will receive between 1.43 and
1.82 shares of Energy East stock for each share of Connecticut Energy stock,
depending on the average price of Energy East's stock during a twenty-day period
prior to closing. This equates to a collar of between $23.10 and $29.40 for
Energy East shares. Based upon Energy East's closing price of $26.25 on April
22, 1999, the Connecticut Energy shareholder would receive 1.60 Energy East
shares for each Connecticut Energy share. The transaction is expected to be
tax-free to Connecticut Energy's shareholders to the extent they receive common
stock of Energy East. The combination will be accounted for using the purchase
method of accounting.
18
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
A special meeting of Connecticut Energy's shareholders was held on September
14, 1999 to vote on the merger, and in excess of 80% of shareholders approved
the Plan of Merger. The merger remains conditioned on, among other things, the
approval of various regulatory agencies, including the DPUC and the Securities
and Exchange Commission. The companies anticipate that these approvals can be
obtained by January 2000 and that the merger will be completed shortly
thereafter.
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." On September 8, 1997, Southern received a letter from the DEP informing
it that the three sites had been entered on the Connecticut inventory of
hazardous waste sites. The letter states that the site located on Pine Street in
Bridgeport may be of particular interest to the state of Connecticut because of
its proximity to the Department of Transportation Expansion Project of the U.S.
Highway Route No. 95 Corridor. Placement of the sites on the inventory of
hazardous waste sites means that the DEP may pursue remedial action pursuant to
the Connecticut General Statutes.
Each site is located in an area that permits Southern to voluntarily perform
any remedial action. Connecticut law also allows Southern to retain a licensed
environmental professional to conduct further environmental assessments and, if
necessary, to develop remedial action plans in accordance with Connecticut
remediation standard regulations.
Southern has conferred with officials of the DEP, including the DEP liaison
for the Department of Transportation's U.S. Highway Route No. 95 Corridor
expansion project, to establish priorities in connection with the environmental
assessments. As a result of those conferences, Southern and the DEP have
negotiated and executed a Consent Order with respect to the Pine Street site.
Pursuant to the Consent Order, Southern has agreed to undertake an investigation
of the Pine Street site and its immediate surrounding area to determine
potential sources of contamination and remediate contamination which may be
found to have emanated or be emanating from the Pine Street site as a result of
Southern's activities on the site. The schedule and scope of the investigation
have been agreed to by Southern and the DEP. As a result of this Consent Order,
Southern has recorded and deferred $150,000 for costs related to the site
investigation. When the investigation is complete, Southern should be able to
propose to the DEP what, if any, plan for remediation is appropriate for the
site. Until such site investigation is complete, management cannot predict the
cost, if any, of any appropriate remediation for the Pine Street site.
Southern is to deliver a revised site investigation report to the DEP during
the first quarter of fiscal 2000. This report will describe conditions existing
at the Pine Street site and provide the basis for evaluating and selecting
remedial action alternatives. An additional report concerning possible remedial
action alternatives will be prepared and submitted to the DEP following approval
of the revised site investigation report. Southern anticipates that a range of
possible remediation costs for the Pine Street site will be reasonably estimable
at the time Southern submits its remedial alternatives report to the DEP.
Southern has elected to proceed with the rehabilitation of a bulkhead located
where the Pine Street site abuts Cedar Creek, a tidal water body connected to
Long Island Sound. The estimated cost of the rehabilitation of $2,065,000 has
been recorded and deferred as part of Southern's environmental remediation plan.
Due to the status of the investigative and remedial design process at the Pine
Street site, Southern has recorded and deferred only its currently budgeted
investigative and legal costs associated with that process. Additional costs are
anticipated, but cannot be reasonably estimated at this time.
Other than as described above, management cannot at this time predict the
cost for any future site analysis and remediation for the remaining two sites,
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 most recent rate order and regulatory precedent with other local
distribution companies in Connecticut, 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, results of operations or cash flows.
19
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Statements of Income
(dollars in thousands, except per share)
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
Operating Revenues $228,296 $242,431 $252,008
Purchased gas 99,617 120,572 132,672
- -------------------------------------------------------------------------------------------------------------------------
Gross margin 128,679 121,859 119,336
- -------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operations 48,733 51,471 46,773
Maintenance 3,591 3,701 3,579
Depreciation and amortization 17,944 16,904 15,774
Federal and state income taxes 7,931 6,438 8,935
Municipal, gross earnings and other taxes 15,030 13,525 15,386
- -------------------------------------------------------------------------------------------------------------------------
Total operating expenses 93,229 92,039 90,447
- -------------------------------------------------------------------------------------------------------------------------
Operating income 35,450 29,820 28,889
- -------------------------------------------------------------------------------------------------------------------------
Other deductions (income), net 1,843 (2,331) (1,229)
Merger-related expenses, net of income taxes 3,534 -- --
- -------------------------------------------------------------------------------------------------------------------------
Income before interest expense 30,073 32,151 30,118
- -------------------------------------------------------------------------------------------------------------------------
Interest Expense:
Interest on long-term debt and
amortization of debt issue costs 12,804 12,086 12,321
Other interest, net 581 1,054 1,356
- -------------------------------------------------------------------------------------------------------------------------
Total interest expense 13,385 13,140 13,677
- -------------------------------------------------------------------------------------------------------------------------
Net Income $ 16,688 $ 19,011 $ 16,441
- -------------------------------------------------------------------------------------------------------------------------
Net income per share - basic $ 1.62 $ 1.89 $ 1.81
- -------------------------------------------------------------------------------------------------------------------------
Net income per share - diluted $ 1.61 $ 1.88 $ 1.81
- -------------------------------------------------------------------------------------------------------------------------
Dividends paid per share $ 1.34 $ 1.33 $ 1.32
- -------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - basic 10,270,953 10,051,868 9,060,308
- -------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 10,360,950 10,104,115 9,095,521
- -------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
Consolidated Statements of Comprehensive Income
(dollars in thousands)
Years ended September 30, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
Net Income $16,688 $19,011 $16,441
- ----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of income taxes:
minimum pension liability adjustment 253 (46) (427)
- ----------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income 253 (46) (427)
- ----------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $16,941 $18,965 $16,014
- ----------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
20
- -------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Balance Sheets
(dollars in thousands, except per share)
As of September 30, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
Assets
Utility Plant:
Plant in service, at cost $423,808 $406,948
Construction work in progress 2,646 5,767
- --------------------------------------------------------------------------------------------------------------------------
Gross utility plant 426,454 412,715
Less: accumulated depreciation 148,573 137,493
- --------------------------------------------------------------------------------------------------------------------------
Net utility plant 277,881 275,222
Nonutility property, net 13,683 4,526
- --------------------------------------------------------------------------------------------------------------------------
Net utility plant and other property 291,564 279,748
- --------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 6,446 10,091
Accounts and notes receivable (less allowance for doubtful
accounts of $2,338 in 1999 and $2,065 in 1998) 27,952 26,921
Accrued utility revenues, net 2,198 2,511
Unrecovered purchased gas costs 6,109 2,529
Inventories 6,202 10,491
Prepaid expenses 1,780 5,863
- --------------------------------------------------------------------------------------------------------------------------
Total current assets 50,687 58,406
- --------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Unamortized debt expenses 10,496 10,841
Unrecovered deferred income taxes 50,653 49,800
Other 71,380 60,606
- --------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 132,529 121,247
- --------------------------------------------------------------------------------------------------------------------------
Total assets $474,780 $459,401
- --------------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
Common Shareholders' Equity:
Common stock - par value $1 per share: authorized -
30,000,000 shares; issued and outstanding - 10,362,127
in 1999 and 10,289,692 in 1998 $ 10,362 $ 10,290
Capital in excess of par value 122,685 119,961
Unearned compensation -- (310)
Retained earnings 50,474 47,685
Adjustment for minimum pension liability, net of income taxes (220) (473)
- --------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 183,301 177,153
- --------------------------------------------------------------------------------------------------------------------------
Redeemable Preferred Stock -- --
Long-Term Debt 148,062 150,007
- --------------------------------------------------------------------------------------------------------------------------
Total capitalization 331,363 327,160
- --------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 21,800 22,400
Current maturities of long-term debt 1,585 1,321
Accounts payable 11,779 10,499
Federal, state and deferred income taxes 236 1,537
Other accrued taxes 2,348 2,024
Interest payable 3,366 3,386
Customers' deposits 1,635 1,627
Refunds due customers 446 454
Other 10,712 4,886
- --------------------------------------------------------------------------------------------------------------------------
Total current liabilities 53,907 48,134
- --------------------------------------------------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes 75,220 72,884
Deferred investment tax credits 2,392 2,684
Other 9,775 8,389
- --------------------------------------------------------------------------------------------------------------------------
Total deferred credits 87,387 83,957
- --------------------------------------------------------------------------------------------------------------------------
Commitments and contingencies 2,123 150
- --------------------------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $474,780 $459,401
- --------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
21
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Statements of Changes
in Common Shareholders' Equity
(dollars in thousands, except per share)
Adjust- Total
Common Stock ment for Common
--------------------- Capital in Unearned Minimum Share-
Number Par Excess of Compen- Retained Pension holders'
of Shares Value Par Value sation Earnings Liability Equity
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1996 9,012,267 $ 9,012 $ 91,079 -- $ 37,870 -- $137,961
Issuance through Dividend
Reinvestment Plan 107,054 107 2,205 -- -- -- 2,312
Issuance through Restricted
Stock Award Plan and Non-
Employee Director Stock Plan 53,147 53 1,256 -- -- -- 1,309
Unearned compensation -- -- -- $(1,068) -- -- (1,068)
Net income -- -- -- -- 16,441 -- 16,441
Dividends paid on common stock
($1.32 per share) -- -- -- -- (12,014) -- (12,014)
Adjustment for minimum pension
liability, net of income taxes -- -- -- -- -- $(427) (427)
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1997 9,172,468 9,172 94,540 (1,068) 42,297 (427) 144,514
Public Offering 1,035,000 1,035 23,189 -- -- -- 24,224
Issuance through Dividend
Reinvestment Plan 81,324 82 2,208 -- -- -- 2,290
Issuance through Non-Employee
Director Stock Plan 900 1 24 -- -- -- 25
Unearned compensation -- -- -- 758 -- -- 758
Net income -- -- -- -- 19,011 -- 19,011
Dividends paid on common stock
($1.33 per share) -- -- -- -- (13,623) -- (13,623)
Adjustment for minimum pension
liability, net of income taxes -- -- -- -- -- (46) (46)
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998 10,289,692 10,290 119,961 (310) 47,685 (473) 177,153
Issuance through Dividend
Reinvestment Plan 70,868 71 2,135 -- -- -- 2,206
Issuance through Restricted
Stock Award Plan and Non-
Employee Director Stock Plan 40,467 40 2,002 -- -- -- 2,042
Shares retired under Restricted
Stock Award Plan (38,900) (39) (1,413) -- -- -- (1,452)
Unearned compensation -- -- -- 310 -- -- 310
Net income -- -- -- -- 16,688 -- 16,688
Dividends paid on common stock
($1.34 per share) -- -- -- -- (13,899) -- (13,899)
Adjustment for minimum pension
liability, net of income taxes -- -- -- -- -- 253 253
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999 10,362,127 $10,362 $122,685 $ -- $50,474 $(220) $183,301
- --------------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
22
- -------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Statements of Cash Flows
(dollars in thousands)
Years ended September 30, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities:
Net income $ 16,688 $ 19,011 $ 16,441
Adjustments to Reconcile Net Income to Net Cash:
Depreciation and amortization 19,062 18,065 16,704
Provision for losses on accounts receivable 6,020 7,735 7,297
(Increase) Decrease in Assets:
Accounts and notes receivable (7,051) (5,477) (5,603)
Accrued utility revenues, net 313 30 67
Unrecovered purchased gas costs (3,580) 2,994 (5,523)
Inventories 4,289 2,115 2,725
Prepaid expenses 3,846 (2,096) (2,607)
Unamortized debt expenses (75) (185) (42)
Deferred charges and other assets (6,317) (6,231) (5,593)
Increase (Decrease) in Liabilities:
Accounts payable 1,280 (2,110) (1,641)
Accrued taxes (977) (6,023) 1,605
Refundable purchased gas costs -- -- (520)
Other current liabilities 5,806 (1,383) 2,594
Deferred income taxes and investment tax credits 1,002 854 1,303
Deferred credits and other liabilities 3,653 482 1,611
- ----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 43,959 27,781 28,818
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities:
Capital expenditures (29,574) (24,681) (28,504)
Contributions in aid of construction 66 67 61
(Payments for) proceeds from retirement of utility plant (500) 33 462
Investment in special contract distribution main (1,211) (11,394) --
Energy ventures (3,311) (777) (1,458)
- ----------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (34,530) (36,752) (29,439)
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities:
Dividends paid on common stock (13,899) (13,623) (12,014)
Issuance of common stock 3,106 27,297 2,553
Issuance of long-term debt -- 29,328 --
Repayments of long-term debt (1,681) (4,654) (595)
Repurchase of long-term debt -- (12,073) --
Payment of premium on repurchase of long-term debt -- (4,857) --
(Decrease) increase in short-term borrowings (600) (9,000) 12,200
- ----------------------------------------------------------------------------------------------------------------------
Net cash (used) provided by financing activities (13,074) 12,418 2,144
- ----------------------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and cash equivalents (3,645) 3,447 1,523
Cash and cash equivalents at beginning of year 10,091 6,644 5,121
- ----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 6,446 $ 10,091 $ 6,644
- ----------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash Paid During the Year for:
Interest $ 13,520 $ 13,321 $ 14,200
Income taxes $ 7,250 $ 9,050 $ 5,041
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES:
In the year ended September 30, 1999, 39,767 shares of unregistered common
stock were issued pursuant to the Company's Restricted Stock Award Plan and 700
shares of unregistered common stock were issued pursuant to the Non-Employee
Director Stock Plan. In the year ended September 30, 1999, 92,014 shares that
had been issued pursuant to the Company's Restricted Stock Award Plan were
awarded to participants and 38,900 of such shares were retired to satisfy
certain tax obligations associated with these awards.
In the year ended September 30, 1998, 900 shares of unregistered common stock
were issued pursuant to the Company's Non-Employee Director Stock Plan.
In the year ended September 30, 1997, 52,247 shares of unregistered common
stock were issued pursuant to the Company's Restricted Stock Award Plan and 900
shares of unregistered common stock were issued pursuant to the Non-Employee
Director Stock Plan.
See notes to consolidated financial statements.
23
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Note 1 -- Summary of Significant Accounting Policies
GENERAL
Connecticut Energy Corporation's ("Connecticut Energy" or "Company")
consolidated financial statements include the accounts of all subsidiary
companies, and all significant intercompany transactions and accounts have been
eliminated.
The Company's principal subsidiary, The Southern Connecticut Gas Company
("Southern"), is subject to regulation 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 ("GAAP") as applied
to regulated public utilities and are in accordance with the accounting
requirements and ratemaking practices of the DPUC.
In preparing the financial statements in conformity with GAAP, the Company
uses estimates. Estimates are disclosed when there is a reasonable possibility
for change in the near term. For this purpose, near term is defined as a period
of time not to exceed one year from the date of the financial statements. The
Company's financial statements have been prepared based on management's
estimates of the impact of regulatory, legislative and judicial developments on
the Company or significant groups of its customers. The recorded amounts of
certain accruals, reserves, and deferred charges and other assets could be
materially impacted if circumstances change which affect these estimates.
LINE OF BUSINESS
Connecticut Energy is a public utility holding company primarily engaged in
the retail distribution of natural gas for residential, commercial and
industrial uses through its utility subsidiary, Southern. Through its nonutility
subsidiary, CNE Energy Services Group, Inc. ("CNE Energy"), the Company provides
energy products and services to commercial and industrial customers throughout
New England. The Company also participates in a natural gas purchasing
cooperative through another nonutility subsidiary, CNE Development Corporation
("CNE Development"). A third nonutility subsidiary, CNE Venture-Tech, Inc. ("CNE
Venture-Tech"), invests in ventures that offer technologically advanced
energy-related products and operates a service bureau.
In September 1997, CNE Energy formed a joint venture with Conectiv, a holding
company formed by the merger of Delmarva Power & Light Company and Atlantic
Energy, Inc. The venture operates under the name Conectiv/CNE Energy Services,
LLC ("Conectiv/CNE Energy") and sells natural gas, electricity, fuel oil and
other services and markets a full range of energy-related planning, financial,
operational and maintenance services to commercial, industrial and municipal
customers in New England. Conectiv/CNE Energy has formed various alliances with
energy-related entities to market energy commodities and services to commercial
and industrial customers in New England.
As a result of the impending merger between Energy East Corporation ("Energy
East") and Connecticut Energy, Conectiv sold its 50% interest in Conectiv/CNE
Energy to CNE Energy. Energy East Solutions, Inc., an indirect subsidiary of
Energy East, subsequently acquired Conectiv's former 50% interest in the joint
venture from CNE Energy.
In September 1998, CNE Energy and Conectiv Energy Supply, Inc., a subsidiary
of Conectiv, formed two joint ventures, Total Peaking Services, LLC ("TPS") and
CNE Peaking, LLC ("CNEP"). TPS, headquartered in Bridgeport, Connecticut,
operates a 1.2 billion cubic foot liquefied natural gas ("LNG") open access
storage facility in Milford, Connecticut. The facility has access to three major
natural gas pipelines in New England: Algonquin Gas Transmission Company,
Iroquois Gas Transmission System, L.P. and Tennessee Gas Pipeline Company. TPS
has received Federal Energy Regulatory Commission approval of its market-based
tariffs and began storing and redelivering customer-owned LNG at the Milford
facility in fiscal 1999. CNEP provides a firm in-market supply source to assist
energy marketers and local gas distribution companies ("LDCs") in meeting the
maximum demands of their customers by offering firm supplies for peak-shaving
and emergency deliveries. CNEP operates out of Newark, Delaware.
In 1999, CIS Service Bureau, LLC ("CIS"), a wholly-owned affiliate of CNE
Venture-Tech, began operations. CIS is a service bureau providing access to
customer billing software and other related services for utilities and energy
services providers, including Southern and CNE Energy.
See Note 11, "Segment Information," for further details regarding the
Company's utility and nonutility segments.
24
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
ACCOUNTING FOR THE EFFECTS OF REGULATION
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 were unregulated.
In the application of SFAS 71, Southern follows accounting policies that
reflect the impact of the rate treatment of certain events or transactions. The
most significant of these policies include the recording of deferred gas costs,
deferred conservation costs, deferred hardship heating customer accounts
receivable arrearages, deferred environmental evaluation and remediation costs
and an unfunded deferred income tax liability, with a corresponding unrecovered
asset, to account for temporary differences previously flowed through to
ratepayers.
Southern had net regulatory assets as of September 30, 1999 and 1998 of
$83,128 and $74,955, respectively. These amounts are included in deferred
charges and other assets and deferred credits in the consolidated balance sheets
and are solely due to the application of the provisions of SFAS 71.
Effective April 1, 1996, the DPUC unbundled the sale of natural gas to firm
commercial and industrial customers by giving these customers an option to
purchase natural gas from independent brokers or marketers. Commercial and
industrial customers electing to purchase natural gas in this manner pay a
DPUC-approved firm transportation rate to LDCs for the use of their distribution
systems.
Southern is one of three Connecticut LDCs whose firm transportation rates are
designed to provide the same margins earned from bundled sales services. Because
these rates are margin neutral, there has not been any impact upon Southern's
ability to recover deferred costs through cost-based rate regulation. Firm
transportation rates have eliminated only the gas cost component of the rates
previously charged to these customers. The Company has not experienced any
adverse impact on its earnings or results of operations from this change in rate
structure. Additionally, the DPUC's initiatives for competition have not been
directed toward services for certain groups of customers, including residential
classes, which represent the majority of Southern's total throughput and gross
margin.
Management believes that Southern continues to meet the requirements of SFAS
71 because Southern's rates for regulated services provided to its customers are
subject to DPUC approval, are designed to recover Southern's costs of providing
regulated services, and continue to be subject to cost-of-service based rate
regulation by the DPUC.
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 twenty-two
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
customers, 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 sales 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.
CONSERVATION ADJUSTMENT MECHANISM
In a Decision dated August 23, 1995, the DPUC provided the Connecticut LDCs
with guidelines by which conservation-related expenditures not included in
current rates charged would be evaluated by the DPUC for recovery through a
Conservation Adjustment Mechanism ("CAM"). Based upon an annual DPUC review of
Southern's filing, which was last approved in May 1999, Southern is allowed to
include as part of its monthly PGA a separate CAM factor to recover these
deferred charges. Firm transportation customers, who are not subject to the PGA,
are charged a specific CAM.
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 WNA was implemented in January
1994 and operates for ten months of the year (September through June).
25
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
FEDERAL INCOME TAXES
The Company and its eligible subsidiaries file a consolidated federal income
tax return. Federal income taxes are deferred under the liability method in
accordance with Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes." Under the liability method, deferred income taxes are
provided for all differences between financial statement and tax basis of assets
and liabilities. Additional deferred income taxes and offsetting regulatory
assets or liabilities are recorded to recognize that income taxes will be
recoverable or refundable through future revenues. 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.
NET INCOME PER SHARE
Net income per share is computed based upon the weighted average number of
common shares outstanding during each year.
UTILITY PLANT
Utility plant is stated at original cost. The costs of additions and major
replacements of retired units are capitalized. Costs include labor, direct
materials and certain indirect charges such as engineering and supervision.
Replacements of minor items of property and the costs of maintenance and repairs
are included in maintenance expense. For a normal retirement, the original cost
of the property, plus removal cost, less salvage value, is charged to
accumulated depreciation when the property is retired and removed from service.
DEPRECIATION
For financial accounting purposes, depreciation of utility plant is computed
using the composite straightline rates prescribed by the DPUC. The annual
composite rate allowed for book depreciation for Southern is 4.15% for all years
presented. 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.
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.
DEFERRED CHARGES AND OTHER ASSETS
Deferred charges and other assets include amounts related to the following:
As of September 30, 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
Conservation costs $ 3,972 $ 5,004
Energy assistance funding shortfall -- 262
Environmental evaluation costs 1,105 684
Environmental remediation costs 2,065 --
Hardship heating customer accounts receivable arrearages 19,461 16,399
Hardship heating customer assistance grant program 3,493 1,748
Investment in energy ventures 7,506 4,195
Investment in special contract distribution main 12,605 11,394
LNG facility 215 207
Nonqualified benefit plans 3,715 3,023
Prepaid pension and postretirement medical contributions 13,855 14,207
Other 3,388 3,483
- ----------------------------------------------------------------------------------------------------------------------
$71,380 $60,606
- ----------------------------------------------------------------------------------------------------------------------
Southern has been allowed to recover various deferred charges in rates over
periods ranging from three to five years in accordance with the DPUC's Decision
in Southern's latest rate case.
26
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
DEFERRED CREDITS
Deferred credits include amounts related to the following:
As of September 30, 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
Economic development initiatives $ 371 $ 397
Insurance reserves 1,646 1,153
Interruptible margin sharing 412 1,210
Nonqualified benefit plans 4,205 3,522
Other 3,141 2,107
- ----------------------------------------------------------------------------------------------------------------------
$9,775 $8,389
- ----------------------------------------------------------------------------------------------------------------------
STOCK-BASED COMPENSATION PLAN
The Company applies the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS 123"), to its
Restricted Stock Award Plan in accordance with Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," as permitted by SFAS
123 (see Note 6, "Common Shareholders' Equity," for further details).
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.
RECENT ACCOUNTING DEVELOPMENTS
Effective October 1, 1999, the Company will adopt Statement of Position 98-5,
"Reporting on the Costs of Start-Up Activities" ("SOP 98-5"). SOP 98-5 requires
costs associated with start-up activities and costs classified as organizational
costs to be expensed as incurred. Adoption of this SOP, which relates
exclusively to the Company's nonutility operations, is not expected to have a
significant impact on the Company's financial condition or results of
operations.
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"), has been amended by
Statement of Financial Accounting Standards No. 137, which defers the effective
date of SFAS 133. SFAS 133 will become effective for all fiscal quarters of all
fiscal years beginning after June 15, 2000; therefore, it will become effective
for the Company on October 1, 2000. Adoption of this Statement is not expected
to have a significant impact on the Company's financial condition or results of
operations.
NOTE 2 -- PROVISION FOR INCOME TAXES
The provision for income taxes includes the following:
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
Taxes currently payable - federal $5,855 $ 4,840 $4,220
Taxes currently payable - state (13) 1,793 1,232
- -------------------------------------------------------------------------------------------------------------------------
5,842 6,633 5,452
Deferred taxes - federal/state 2,089 (195) 3,483
- -------------------------------------------------------------------------------------------------------------------------
Total income tax provision 7,931 6,438 8,935
Tax benefit associated with merger-related expenses (601) -- --
- -------------------------------------------------------------------------------------------------------------------------
Total income tax provision, net of tax benefit associated
with merger-related expenses $7,330 $ 6,438 $8,935
- -------------------------------------------------------------------------------------------------------------------------
Sources and tax effects of items which gave rise to deferred tax expense are
as follows:
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
Amortization of deferred investment tax credits $ (292) $ (292) $ (292)
Depreciation 1,725 1,468 1,775
Unrecovered purchased gas costs 1,253 (1,048) 2,180
Other (597) (323) (180)
- -------------------------------------------------------------------------------------------------------------------------
$2,089 $ (195) $3,483
- -------------------------------------------------------------------------------------------------------------------------
27
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
The following table reconciles the income tax provision calculated using the
federal statutory tax rate to the actual income tax expense:
Years ended September 30, 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
Statutory federal tax rate 35% 35% 35%
Allowance for doubtful accounts,
including amounts forgiven and deferred (5) (5) (1)
Conservation costs 2 -- (1)
Cost to retire assets, net of salvage (1) (1) (1)
Depreciation differences 2 3 3
Investment tax credits (1) (1) (1)
Merger-related expenses 4 -- --
Pension contribution 1 2 (1)
Premium paid - cancellation of bonds -- (7) --
Property taxes - effect of accounting treatment change -- (3) --
Reduction of prior years' accruals (10) -- --
State taxes, net of federal tax benefit 3 5 3
Other, net 1 (3) (1)
- ------------------------------------------------------------------------------------------------------------------
Effective tax rate 31% 25% 35%
- ------------------------------------------------------------------------------------------------------------------
Deferred income tax liabilities (assets) are composed of the following:
As of September 30, 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Tax effect of temporary differences for:
Depreciation $27,248 $25,523
Regulatory assets - income taxes 50,653 49,800
- -------------------------------------------------------------------------------------------------------------------
Gross liabilities 77,901 75,323
- -------------------------------------------------------------------------------------------------------------------
Contributions in aid of construction (1,143) (758)
Nonqualified benefit plans (1,363) (1,124)
Other (175) (557)
- -------------------------------------------------------------------------------------------------------------------
Gross assets (2,681) (2,439)
- -------------------------------------------------------------------------------------------------------------------
Net deferred income tax liability - long-term $75,220 $72,884
- -------------------------------------------------------------------------------------------------------------------
As of September 30, 1999 and 1998, the balance sheet caption "Federal, state
and deferred income taxes" includes approximately $2,138 and $885, respectively,
of current deferred federal and state income taxes.
NOTE 3 -- LONG-TERM DEBT
Long-term debt outstanding consists of the following:
As of September 30, 1999 1998
- ------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS:
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
- ------------------------------------------------------------------------------------------------------------------
102,000 102,000
MEDIUM-TERM NOTES:
MTN1, Series 1, 7.50%-7.95%, due August 3, 2026 20,000 20,000
MTN1, Series 2, 5.95%-6.88%, due September 15, 2028 17,000 17,000
- ------------------------------------------------------------------------------------------------------------------
37,000 37,000
TERM LOAN:
Term loan, due August 1, 2005 10,647 12,328
Less: current maturities of long-term debt 1,585 1,321
- ------------------------------------------------------------------------------------------------------------------
$148,062 $150,007
- ------------------------------------------------------------------------------------------------------------------
28
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
Substantially all of the utility plant of Southern is subject to the lien of
its mortgage bond indenture dated March 1, 1948, as supplemented from time to
time. See Note 6, "Common Shareholders' Equity," for dividend restrictions.
Expenses incurred in connection with long-term borrowings are normally amortized
on a straightline basis over the respective lives of the issues giving rise
thereto.
Series W First Mortgage Bonds are due in bullet payments in the years 2021
and 2031, respectively. Series V, X and Y are due in single payments in the
years 2020, 2012 and 2013, respectively.
In August 1996, Southern issued and sold $20,000 in secured Medium-Term Notes
("MTN1, Series 1"). These notes have a weighted average rate of 7.84% and will
be redeemed through payments of $5,000 and $15,000 in the years 2006 and 2026,
respectively. Proceeds from the sale were principally used to reduce short-term
borrowings incurred primarily in connection with Southern's construction
program.
In September 1998, Southern issued and sold $17,000 in secured Medium-Term
Notes ("MTN1, Series 2"). These notes have a weighted average rate of 6.71% and
will be redeemed through payments of $3,000 and $14,000 in the years 2003 and
2028, respectively. Proceeds from the sale were used to repurchase $12,073 of
Series T and Series U First Mortgage Bonds. The DPUC has allowed the deferral of
the unamortized issuance costs of Series 2 MTNs as well as the premiums related
to the repurchase of these notes. The total of these unamortized issuance costs
and repurchase premiums was approximately $4,857 and is being amortized over the
average life of this series.
In May 1998, CNE Energy entered into a term loan agreement with a bank to be
utilized to reimburse Southern for costs incurred to construct distribution
facilities to transport natural gas to an electric generating plant in
Bridgeport. Borrowings were completed in August 1998. The interest rate on
outstanding borrowings will vary in accordance with prevailing interest rates.
In connection with the term loan, CNE Energy entered into an interest rate
swap arrangement with the financial institution that made the loan to provide
interest rate protection for the loan maturities, totaling $6,263, from May 2002
through the end of the loan term. The swap arrangement matures August 1, 2004.
The interest rate swap fixed the interest reference rate on $6,263 of loan
principal at 5.775%. CNE Energy will be reimbursed for incremental interest
expense incurred in excess of the 5.775% and incurs additional expense for
incremental interest expense below 5.775%. During 1999, CNE Energy incurred
minor additional interest expense in connection with the interest rate swap
arrangement. The fair value of the interest rate swap at September 30, 1999 is a
positive $133. However, CNE Energy would not receive a payment if the swap
arrangement were terminated with a positive fair value.
Principal maturities for the five fiscal years subsequent to September 30,
1999 are as follows: 2000 - $1,585; 2001 - $1,761; 2002 - $1,761; 2003 - $4,761;
2004 - $1,937; total - $11,805.
NOTE 4 -- SHORT-TERM BORROWINGS
The Company follows the practice of borrowing from banks on a short-term
basis. The following information relates to these borrowings:
As of September 30, 1999 1998
- ------------------------------------------------------------------------------------------------------------------
Outstanding $21,800 $22,400
Weighted average interest rate 5.84% 5.73%
- ------------------------------------------------------------------------------------------------------------------
As of September 30, 1999, Connecticut Energy and Southern have credit lines
with a number of banks as detailed below:
Shared
Connecticut
Energy/
Southern Southern Total
- -------------------------------------------------------------------------------------------------------------------
Committed lines $50,000 $20,000 $70,000
Uncommitted lines -- 5,000 5,000
- -------------------------------------------------------------------------------------------------------------------
In lieu of compensating balances, Southern pays fees for its committed lines
of credit, which are approximately 1/4 of 1% of the amount of the line of
credit. The aggregate annual commitment fees on these lines were $83, $88 and
$115 for the years ended September 30, 1999, 1998 and 1997, respectively. As of
September 30, 1999, unused lines of credit totaled $53,200.
29
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
NOTE 5 -- REDEEMABLE PREFERRED STOCK
The following table summarizes the shares of preferred stock authorized,
issued and outstanding:
As of September 30, 1999 1998
- ------------------------------------------------------------------------------
The Southern Connecticut Gas Company:
Cumulative preferred stock, $100 par value
Authorized 200,000 200,000
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
In 1997, the Company established a Restricted Stock Award Plan for certain
senior officers of the Company and its subsidiaries to motivate participants to
work toward achieving corporate objectives beneficial to the Company and its
shareholders by awarding them shares of common stock which become vested upon
achievement of certain objectives. Such shares are exempt from registration
pursuant to Section 4(2) of the Securities Act of 1933.
On September 13, 1999, 92,014 shares issued under the Restricted Stock Award
Plan became unrestricted actual awards. Of the 92,014 shares awarded, 38,900
shares were retired to satisfy certain tax obligations associated with these
awards.
In 1997, the Company also established a Non-Employee Director Stock Plan. The
purpose of the Non-Employee Director Stock Plan is to align the interests of
non-employee directors with the Company's shareholders by awarding them shares
of common stock. The total number of shares that may be issued under the plan
may not exceed 13,000. This number is subject to adjustment to prevent the
dilution or enlargement of any rights of any participant with respect to his or
her stock. Such shares are exempt from registration pursuant to Section 4(2) of
the Securities Act of 1933. As of September 30, 1999, 2,500 shares have been
issued under the Non-Employee Director Stock Plan.
The Company issues common stock through the Dividend Reinvestment and Stock
Purchase Plan ("DRP") and an employee savings plan ("Target Plan"). 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. During 1999, an additional 1,000,000
shares were reserved for issuance under the Target Plan. As of September 30,
1999, there were 1,253,887 shares reserved for issuance under the DRP and Target
Plan.
Southern's indentures relating to long-term debt 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,
$52,076 of Southern's retained earnings as of September 30, 1999 was available
for such purposes.
NOTE 7 -- EMPLOYEE BENEFITS
The Company adopted disclosure rules required by Statement of Financial
Accounting Standards No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits," during 1999.
PENSION PLANS
Southern maintains two noncontributory pension plans covering substantially
all of its employees and employees of certain affiliates. 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
30
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Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
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").
Southern maintains 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 of the Company and its
subsidiaries.
POSTRETIREMENT HEALTH CARE BENEFITS
Southern provides certain health care benefits for retired employees of
Southern and certain affiliates who were hired prior to November 1, 1995.
Benefits are provided to eligible employees who have reached age 55 and have
completed at least five years of service with the Company before retirement.
Health care benefits are also extended to qualifying dependents.
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.
In 1994, a Voluntary Employees' Beneficiary Association ("VEBA") trust was
established as permitted under Section 501(c)(9) of the IRC to fund
postretirement health care benefits for union employees and their qualifying
dependents; and in 1999, a VEBA trust was established to fund such benefits for
salaried employees and their qualifying dependents.
The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets for the years ended September 30,
1999 and 1998 and a statement of the funded status as of September 30, 1999 and
1998:
Pension Other Benefits
- ------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------
Change in Benefit Obligation:
Net benefit obligation at beginning of year $ 82,152 $ 72,670 $18,163 $16,627
Service cost 2,573 2,284 395 369
Interest cost 5,549 5,438 1,188 1,207
Plan amendments 171 -- -- --
Actuarial (gain) loss (5,428) 6,085 (455) 894
Other 1,237 -- -- --
Gross benefits paid (4,301) (4,325) (1,335) (934)
- ------------------------------------------------------------------------------------------------------------------
Net benefit obligation at end of year $ 81,953 $ 82,152 $17,956 $18,163
- ------------------------------------------------------------------------------------------------------------------
Change in Plan Assets:
Fair value of plan assets at beginning of year $ 97,560 $ 98,207 $ 9,771 $ 7,988
Actual return on plan assets 13,093 4,430 1,543 589
Employer contributions -- -- 800 2,170
Expenses (1,026) (752) (43) (42)
Gross benefits paid (4,301) (4,325) (1,335) (934)
- ------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $105,326 $ 97,560 $10,736 $ 9,771
- ------------------------------------------------------------------------------------------------------------------
Reconciliation of Funded Status:
Funded status at end of year $ 23,373 $ 15,408 $(7,220) $(8,392)
Unrecognized net transition obligation 153 321 10,749 11,518
Unrecognized prior service cost 3,078 3,342 -- --
Unrecognized net actuarial gain (19,357) (10,072) (4,179) (3,154)
- ------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ 7,247 $ 8,999 $ (650) $ (28)
- ------------------------------------------------------------------------------------------------------------------
Amounts Recognized in Statement
of Financial Position:
Prepaid benefits cost $ 10,135 $ 10,488 -- --
Accrued benefit liability (2,888) (1,489) $ (650) $ (28)
Additional minimum liability (742) (1,036) -- --
Intangible asset 376 228 -- --
Accumulated other comprehensive income 366 808 -- --
- ------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ 7,247 $ 8,999 $ (650) $ (28)
- ------------------------------------------------------------------------------------------------------------------
31
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Connecticut Energy Corporation
The following tables provide the components of net periodic cost for the
plans for the years ended September 30, 1999, 1998 and 1997 and the assumptions
used in the measurement of these costs and the Company's benefit obligations:
Pension Other Benefits
----------------------------------- ---------------------------------
1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
Net Periodic Cost:
Service cost $ 2,573 $ 2,284 $ 2,255 $ 395 $ 369 $ 354
Interest cost 5,549 5,438 5,370 1,188 1,207 1,223
Expected return on assets (7,978) (7,591) (6,830) (804) (791) (524)
Amortization:
Transition obligation 169 169 169 767 767 767
Prior service cost 435 516 516 -- -- --
(Gain) loss 98 34 (21) (69) (150) (168)
- -------------------------------------------------------------------------------------------------------------------------
Total amortization 702 719 664 698 617 599
- -------------------------------------------------------------------------------------------------------------------------
846 850 1,459 1,477 1,402 1,652
Regulatory adjustment -- -- 58 -- -- 31
- -------------------------------------------------------------------------------------------------------------------------
Total expense $ 846 $ 850 $ 1,517 $1,477 $1,402 $1,683
- -------------------------------------------------------------------------------------------------------------------------
Portion capitalized to utility plant $ 160 $ 179 $ 357 $ 280 $ 294 $ 396
- -------------------------------------------------------------------------------------------------------------------------
Key assumptions used in the determination of the projected benefit
obligations and the fair value of plan assets were:
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Discount rate 7 1/2% 6 3/4% 7 1/2%
Salary increase rate 4 3/4% 4 % 4 3/4%
Expected rate of return on assets 9 1/4% 9 1/4% 9 1/2%
- ---------------------------------------------------------------------------------------------------------------
In measuring the accumulated postretirement benefit obligation, the assumed
initial health care cost trend rates used to measure the expected cost of
benefits are 7% for pre-age 65 claims and 6% for post-age 65 claims.
The rates decline to 5% by the years 2003 and 2001, respectively.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% Increase 1% Decrease
- -------------------------------------------------------------------------------------------------------------
Effect on the total service and interest cost components
of net periodic postretirement health care benefit cost $ 71 $ (83)
Effect on the health care component of the accumulated
postretirement benefit obligation 899 (999)
- -------------------------------------------------------------------------------------------------------------
SAVINGS PLAN
Southern maintains a savings plan ("Target Plan") covering substantially all
of its employees and employees of certain affiliates who meet minimum service
and age requirements. Employees may elect to contribute to the plan through
payroll deductions on either a taxable or a tax-deferred basis as permitted by
Section 401(k) of the IRC. Participants receive a matching contribution of 50%
of the first 6% of annual compensation and become vested in the matching
contribution over a five year period. Benefits are payable upon retirement,
death, disability or termination of employment. Amounts expensed under the plan
were $798, $778 and $782 for years ended September 30, 1999, 1998 and 1997,
respectively.
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Connecticut Energy Corporation
NOTE 8 -- LEASES
Total rental expense was $2,664, $3,050 and $2,830 for the years ended
September 30, 1999, 1998 and 1997, respectively. The approximate aggregate
minimum rental commitments (exclusive of taxes, maintenance, etc.) under
noncancelable operating leases for each of the five years subsequent to
September 30, 1999 are as follows:
Years ending September 30, 2000 2001 2002 2003 2004 Thereafter
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Office space $2,143 $2,132 $2,132 $2,218 $2,262 $20,657
LNG plant 609 609 609 609 609 10,040
Other 70 76 66 -- -- --
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Total commitment $2,822 $2,817 $2,807 $2,827 $2,871 $30,697
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In 1995, the LNG plant lease agreement was renewed for two consecutive terms
of twelve years. The lease contains an option to purchase the plant at a price
based on the then fair market sales value of the unit as defined therein.
During 1998, Southern subleased the LNG facility to CNE Energy. CNE Energy,
in turn, subleased the LNG facility to TPS. Southern will continue to operate
the LNG facility under an agreement with TPS and will remain primarily
responsible for the lease payments in the event that the sublessees do not make
the required payments.
NOTE 9 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
Dec. 31, March 31, June 30, Sept. 30,
1999 Quarters ended 1998 1999 1999 1999
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $61,594 $106,164 $35,377 $25,161
Gross margin 33,810 56,995 22,916 14,958
Operating income (loss) 9,296 20,333 5,056 765
Net income (loss) 6,095 16,746 (766) (5,387)
Net income (loss) per share-diluted* 0.59 1.62 (0.07) (0.52)
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Dec. 31, March 31, June 30, Sept. 30,
1998 Quarters ended 1997 1998 1998 1998
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $76,507 $100,773 $38,002 $27,149
Gross margin 34,031 52,599 20,155 15,074
Operating income (loss) 9,366 18,376 2,222 (144)
Net income (loss) 6,166 15,250 (1,019) (1,386)
Net income (loss) per share-diluted 0.64 1.49 (0.10) (0.13)
- -----------------------------------------------------------------------------------------------------------------------------
*Calculated on the basis of diluted weighted average shares outstanding during
the applicable quarter.
NOTE 10 -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instrument for which it is practicable to estimate that
value:
CASH AND CASH EQUIVALENTS
The carrying amount approximates fair value because of the short-term
maturity of these instruments.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on quoted
market prices for the same or similar issues or on current rates offered to the
Company for debt of the same remaining maturities.
The estimated fair value of the Company's long-term debt is as follows:
As of September 30, 1999 1998
- -----------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------
Long-term debt
(including current maturities) $149,647 $176,179 $151,328 $181,854
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33
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Connecticut Energy Corporation
Note 11 -- Segment Information
On October 1, 1998, the Company adopted Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information." This Statement establishes standards for reporting financial
information about operating segments as well as related disclosures about
products and services, geographic areas and major customers.
The Company has two reportable operating segments: utility and nonutility.
The utility segment operates in a regulated environment under the authority of
the DPUC with respect to customer rates and the maintenance of accounting
records, in contrast to the nonutility segment which does not operate under
these constraints.
The utility segment consists of Southern and the nonutility segment consists
of CNE Development, CNE Energy and CNE Venture-Tech. The services provided,
geographic areas served and accounting policies of the segments are described in
Note 1, "Summary of Significant Accounting Policies." The performance of each
segment is evaluated based on its respective contribution to consolidated net
income.
The following is selected financial information for each of the Company's
business segments:
Reportable Segments Consolidated
Utility Nonutility Other* Total
- ---------------------------------------------------------------------------------------------------------------------
Year ended September 30, 1999
Operating revenues $223,526 $ 6,226 $(1,456) $228,296
Operations expense 48,016 1,041 (324) 48,733
Depreciation and amortization 16,997 947 -- 17,944
Operating income 32,918 3,409 (877) 35,450
Other deductions (income), net 946 848 49 1,843
Net income 19,139 1,740 (4,191) 16,688
- ---------------------------------------------------------------------------------------------------------------------
As of September 30, 1999
Equity investment -- 7,506 -- 7,506
Total assets 440,483 34,324 (27) 474,780
- ---------------------------------------------------------------------------------------------------------------------
Year ended September 30, 1998
Operating revenues 241,657 774 -- 242,431
Operations expense 49,269 320 1,882 51,471
Depreciation and amortization 16,719 185 -- 16,904
Operating income 32,352 (1,114) (1,418) 29,820
Other deductions (income), net 674 (2,970) (35) (2,331)
Net income 18,407 1,707 (1,103) 19,011
- ---------------------------------------------------------------------------------------------------------------------
As of September 30, 1998
Equity investment -- 4,195 -- 4,195
Total assets 430,927 25,558 2,916 459,401
- ---------------------------------------------------------------------------------------------------------------------
Year ended September 30, 1997
Operating revenues 252,008 -- -- 252,008
Operations expense 46,332 92 349 46,773
Depreciation and amortization 15,727 47 -- 15,774
Operating income 29,721 (398) (434) 28,889
Other deductions (income), net (410) (817) (2) (1,229)
Net income 16,185 418 (162) 16,441
- ---------------------------------------------------------------------------------------------------------------------
As of September 30, 1997
Equity investment -- 3,418 -- 3,418
Total assets 413,556 5,010 5,715 424,281
- ---------------------------------------------------------------------------------------------------------------------
*The Other category includes the assets and unallocated administrative expenses
of the Company and intersegment eliminations.
34
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Connecticut Energy Corporation
NOTE 12 -- CONNECTICUT ENERGY CORPORATION/ENERGY EAST CORPORATION MERGER
On April 23, 1999, the Boards of Directors of Energy East and Connecticut
Energy announced that the companies have signed a definitive merger agreement
under which Connecticut Energy will become a wholly-owned subsidiary of Energy
East in a transaction which is valued at $617,000 including the assumption of
debt.
Shareholders of Connecticut Energy will receive $42.00 per share, 50% payable
in stock and 50% in cash. Shareholders will be able to specify the percentage of
the consideration they wish to receive in stock and in cash, subject to
proration. Shareholders who elect to receive stock will receive between 1.43 and
1.82 shares of Energy East stock for each share of Connecticut Energy stock,
depending on the average price of Energy East's stock during a twenty-day period
prior to closing. This equates to a collar of between $23.10 and $29.40 for
Energy East shares. Based upon Energy East's closing price of $26.25 on April
22, 1999, the Connecticut Energy shareholder would receive 1.60 Energy East
shares for each Connecticut Energy share. The transaction is expected to be
tax-free to Connecticut Energy's shareholders to the extent they receive common
stock of Energy East. The combination will be accounted for using the purchase
method of accounting.
In the quarter ended June 30, 1999, the Company began recording
merger-related expenses, which as of September 30, 1999, totaled approximately
$3,534, net of income taxes. These expenses are primarily comprised of
investment banking and legal fees and compensation expense related to the
accelerated vesting of certain shares issued under the Company's Restricted
Stock Award Plan.
A special meeting of Connecticut Energy's shareholders was held on September
14, 1999 to vote on the merger, and in excess of 80% of shareholders approved
the Plan of Merger. The merger remains conditioned on, among other things, the
approval of various regulatory agencies, including the DPUC and the Securities
and Exchange Commission. The companies anticipate that these approvals can be
obtained by January 2000 and that the merger will be completed shortly
thereafter.
NOTE 13 -- 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." On September 8, 1997, Southern received a letter from the DEP informing
it that the three sites had been entered on the Connecticut inventory of
hazardous waste sites. The letter states that the site located on Pine Street in
Bridgeport may be of particular interest to the state of Connecticut because of
its proximity to the Department of Transportation Expansion Project of the U.S.
Highway Route No. 95 Corridor. Placement of the sites on the inventory of
hazardous waste sites means that the DEP may pursue remedial action pursuant to
the Connecticut General Statutes.
Each site is located in an area that permits Southern to voluntarily perform
any remedial action. Connecticut law also allows Southern to retain a licensed
environmental professional to conduct further environmental assessments and, if
necessary, to develop remedial action plans in accordance with Connecticut
remediation standard regulations.
Southern has conferred with officials of the DEP, including the DEP liaison
for the Department of Transportation's U.S. Highway Route No. 95 Corridor
expansion project, to establish priorities in connection with the environmental
assessments. As a result of those conferences, Southern and the DEP have
negotiated and executed a Consent Order with respect to the Pine Street site.
Pursuant to the Consent Order, Southern has agreed to undertake an investigation
of the Pine Street site and its immediate surrounding area to determine
potential sources of contamination and remediate contamination which may be
found to have emanated or be emanating from the Pine Street site as a result of
Southern's activities on the site. The schedule and scope of the investigation
have been agreed to by Southern and the DEP. As a result of this Consent Order,
Southern has recorded and deferred $150 for costs related to the site
investigation. When the investigation is complete, Southern should be able to
propose to the DEP what, if any, plan for remediation is appropriate for the
site. Until such site investigation is complete, management cannot predict the
cost, if any, of any appropriate remediation for the Pine Street site.
35
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Connecticut Energy Corporation
Southern is to deliver a revised site investigation report to the DEP during
the first quarter of fiscal 2000. This report will describe conditions existing
at the Pine Street site and provide the basis for evaluating and selecting
remedial action alternatives. An additional report concerning possible remedial
action alternatives will be prepared and submitted to the DEP following approval
of the revised site investigation report. Southern anticipates that a range of
possible remediation costs for the Pine Street site will be reasonably estimable
at the time Southern submits its remedial alternatives report to the DEP.
Southern has elected to proceed with the rehabilitation of a bulkhead located
where the Pine Street site abuts Cedar Creek, a tidal water body connected to
Long Island Sound. The estimated cost of the rehabilitation of $2,065 has been
recorded and deferred as part of Southern's environmental remediation plan. Due
to the status of the investigative and remedial design process at the Pine
Street site, Southern has recorded and deferred only its currently budgeted
investigative and legal costs associated with that process. Additional costs are
anticipated, but cannot be reasonably estimated at this time.
Other than as described above, management cannot at this time predict the
cost for any future site analysis and remediation for the remaining two sites,
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 most recent rate order and regulatory precedent with other local
distribution companies in Connecticut, 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, results of operations or cash flows.
36
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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 PricewaterhouseCoopers LLP to review audit plans and results and
the Company's accounting, financial reporting and internal control practices,
procedures and results. Both PricewaterhouseCoopers LLP 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, Treasurer Chief Accounting Officer
and Assistant Secretary
Report of Independent Accountants
To the Board of Directors and
Shareholders of Connecticut Energy Corporation
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income and comprehensive income, changes in common
shareholders' equity and of cash flows present fairly, in all material respects,
the financial position of Connecticut Energy Corporation and its subsidiaries at
September 30, 1999 and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended September 30, 1999, in
conformity with generally accepted accounting principles. 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 of these statements in accordance with
generally accepted auditing standards which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/ PricewaterhouseCoopers LLP
Hartford, CT
October 29, 1999
37
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Connecticut Energy Corporation