SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number 1-8369
CONNECTICUT ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Connecticut 06-0869582
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
855 Main Street
Bridgeport, Connecticut 06604
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code
(800) 760-7776
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
- --------------------------- ---------------------
Common Stock ($1 par value) New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Aggregate market value of the voting stock held by non-affiliates of the
registrant based on the closing price of such stock as of November 19, 1999:
$406,100,219
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes [ ] No [ ]
APPLICABLE ONLY TO CORPORATE REGISTRANTS:
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date:
Class Outstanding at November 19, 1999
- -------------------------- --------------------------------
Common Stock, $1 par value 10,363,004
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Connecticut Energy Corporation's 1999 Annual Report to Shareholders
are incorporated into Parts II and IV.
An index of exhibits to this Annual Report on Form 10-K may be found on page
28 hereof.
PART I
CONNECTICUT ENERGY CORPORATION
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, 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 Form 10-K 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.
Item 1. Business
General
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 principal subsidiary, The Southern Connecticut Gas Company
("Southern"), a Connecticut public service company. Southern's predecessor
companies, New Haven Gas Company and The Bridgeport Gas Company, were originally
incorporated in Connecticut in 1847 and 1849, respectively. The Company is
exempt from registration under the Public Utility Holding Company Act of 1935.
Southern serves approximately 160,000 customers in Connecticut, primarily in
twenty-two towns along the southern Connecticut coast from Westport to Old
Saybrook, which include the urban communities of Bridgeport and New Haven.
Southern is also authorized to lay mains and sell gas in an additional ten towns
in its service area, but does not currently provide any service to these towns.
The percentage of the Company's revenues contributed by each class of customers
for the last three years was as follows:
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------
Residential ................................ 59.5% 58.9% 57.9%
Commercial firm ............................ 14.6 17.7 19.5
Industrial firm ............................ 2.9 3.9 4.3
Firm transportation and firm contract ...... 11.5 5.5 2.4
Interruptible and other .................... 11.5 14.0 15.9
----- ----- -----
100.0% 100.0% 100.0%
===== ===== =====
Southern is the sole distributor of natural gas, other than bottled gas, in its
service area. Oil and electricity compete with gas in most industrial and
commercial markets and for residential space and water heating. In general,
Southern's firm rates are currently lower than electric rates for heating and,
on average, are generally competitive with fuel oil. Southern's gas sales are
affected by seasonal factors, and it experiences higher revenues during the
winter months.
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, 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 ("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 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," in the Company's 1999 Annual Report to
Shareholders for further details regarding the Company's utility and nonutility
segments.
As of September 30, 1999, the Company, through its subsidiaries, had 481
full-time employees, the majority of whom were employees of Southern.
Customers
General
From 1994 through 1999, the average number of on-system customers served by
Southern grew from approximately 152,600 to 160,200. Southern provides three
types of gas service to its on-system customers: firm sales, firm transportation
and interruptible. Firm service is provided to residential, commercial and
industrial customers who require a continuous gas supply throughout the year.
Southern serves approximately 181,000 firm residential units. Interruptible
service is available to those customers that have dual fuel capabilities which
allow them to alternate between natural gas and another fuel source. Firm
service for residential use includes service to multi-family units. Firm
transportation is available to commercial, industrial and multi-family customers
who have secured their own gas supply and require that Southern transport this
supply on its distribution system. Southern also provides transportation service
to certain commercial and industrial customers on an interruptible basis, where
the gas transported is owned by those customers.
Additionally, Southern has the approval of the Connecticut Department of Public
Utility Control ("DPUC") to participate in the off-system sales market. If gas
supplies are available after meeting on-system loads, Southern can sell to
customers within Connecticut or in out-of-state markets. The customers to whom
these sales are made are not permanent customers of Southern (see section
entitled "Gas Supply Management Agreement" for information regarding a change in
the management of Southern's off-system sales).
Firm Sales, Firm Transportation and Firm Contract
In 1999, firm services represented approximately 89% of operating revenues and
approximately 75% of the Company's total gas throughput. Firm sales to
industrial customers are likely to constitute a smaller percentage of Southern's
future total sales due to the changing character of the local economy and
continuing regulatory developments affecting the natural gas industry (see
section entitled "Unbundling of Natural Gas Services" for further details).
Southern provides firm contract sales service to Yale University in accordance
with rates specified in a DPUC-approved special contract for the sale of gas to
this facility. Southern provides firm contract transportation service to a 520
megawatt electric generating plant in Bridgeport in accordance with a
DPUC-approved contract.
Southern concentrates on customer additions that are the most cost-effective to
achieve. Over the past several years, Southern has focused on adding load along
its existing mains, which generally requires a lower capital outlay than adding
load requiring new main. Approximately 59% of the residences along Southern's
mains heat with natural gas. The conversion of these homes from an alternate
fuel to natural gas heat has been a major factor in increased load growth.
Interruptible Sales, Transportation and Special Contract Services
Interruptible sales, which include off-system sales, are priced flexibly and
competitively compared to the price paid for alternate fuels by larger
commercial and industrial customers. Southern's interruptible sales
fluctuate primarily due to the relative price differentials between
alternate fuels and natural gas as well as the availability of gas
not needed to serve firm customers.
In addition to interruptible sales, Southern transports gas, on an
interruptible basis, for delivery to certain large commercial and industrial
consumers. Because of recent regulatory developments, end users can contract
more easily than in the past for transportation service on interstate pipelines
to transport natural gas supplies purchased from producers/suppliers, rather
than purchase gas solely from LDCs. In Southern's service area, gas is
transported to customers using interstate pipeline transportation and
Southern's distribution system.
Southern provides transportation service to The Connecticut Light and Power
Company's Devon electric generating station in accordance with rates specified
in a special contract for the transportation of gas.
In 1999, interruptible sales, transportation and special contract services
represented approximately 10% of operating revenues and approximately 25% of
total gas throughput.
Transportation revenues are considerably less than revenues from gas sales
because customers pay only a fee for the transportation service. Gas sales
revenues include the cost of gas sold. Southern's average margins on
interruptible transportation service are less than its average margins on firm
sales and are usually less than its average margins on interruptible sales. To
the extent Southern negotiates its monthly prices for interruptible services
below its monthly standard offering price, lower margins may result.
The Company does not believe that the loss of any single customer or a few
customers would have a long-term material, adverse effect upon Southern's
business.
Marketing
General
Southern's marketing focus is to achieve significant growth in its customer base
while strengthening its position as a leading provider of natural gas energy and
high quality service. In addition to pursuing new residential and commercial
heating customers, Southern also pursues opportunities related to energy
market deregulation such as the development of merchant power plants and
the growing reliance by commercial and industrial customers on marketers for
natural gas supplies. By recognizing marketers as customers, Southern expects to
build relationships with them that will result in increased natural gas
load. Southern is using advanced technology to improve its sales efficiency. The
Company's sales force relies on an automated database to track consumer trends
and on specialized software to reduce the time required to enter new business
authorizations into its costing network.
Residential Market
In the residential heating market, despite record low oil prices, 2,654
customers were added in 1999 compared to 1,943 customers in 1998 and 2,641
customers in 1997. Residential conversions accounted for 62% of additions in
1999, 63% in 1998 and 60% in 1997. Southern's residential marketing programs
include a conversion burner program and an employee-generated leads program for
heating conversions. Southern continues to strengthen established relationships
with manufacturers and distributors to leverage their resources for adding
new business.
In addition, the Company recognizes that main extensions are an important source
of current and future growth. As a result, Southern may extend main from time to
time, whenever practicable, to portions of its franchise with limited or no gas
service. These main extension decisions are based on several factors, including
consumer interest in natural gas, density, size and age of homes, proximity to
existing main and capital investment requirements.
Commercial and Industrial Markets
In the commercial and industrial markets, emphasis is placed on adding new firm
and interruptible sales. Marketing programs for commercial and industrial
customers include a program offering customers the option of financing new
equipment through Southern and a conversion burner leasing program which
provides customers with a low cost opportunity to switch to natural gas. Through
these programs and effective advertising, 189 new customers were added during
1999 whose connected load exceeds 1,000 cubic feet per hour.
Effective April 1, 1996, firm transportation service became available to
commercial and industrial customers. As of September 30, 1999, there were 2,321
firm transportation customers purchasing natural gas directly from marketers,
which is an increase of approximately 30% from the 1,789 customers using firm
transportation as of September 30, 1998. The trend is for more of Southern's
commercial and industrial customers to become firm transportation customers once
they become aware of the associated benefits. Southern continues to encourage
commercial and industrial customers to proactively learn more about their
customer choice options.
The commercial marketing programs are targeted toward increasing natural gas
consumption in the industrial sector by promoting the productivity, product
quality, efficiency and environmental benefits of modern natural gas
technologies to industrial plant managers and specifiers. For example, natural
gas fired desiccant dehumidification equipment is beginning to be specified more
often in supermarket and ice-rink applications.
With the continuing deregulation of energy markets and advancements in natural
gas turbine technologies, cogeneration is a viable economic solution for many
industrial customers. Yale University, for example, is utilizing a 13.5-megawatt
cogeneration system that is providing both electricity and steam for many of its
facilities. The new state-of-the-art cogeneration facility uses three gas
turbines and other modern equipment to generate electricity and steam from
natural gas to provide heating and cooling to the central campus.
The Bridgeport Energy combined cycle electric generating plant is representative
of new energy marketplace dynamics created by deregulation. The facility
purchases its gas supplies through third party marketers. Southern then
transports the supplies to the plant via its eleven-mile natural gas
distribution facility that links the plant with the Iroquois Gas Transmission
System. This plant has the capability of consuming up to 30,000,000 Mcf of
volume annually.
Natural Gas Vehicles
Natural gas vehicles ("NGVs") represent another opportunity to increase the base
load usage of natural gas. Southern has been active in this market and continues
to annually increase the number of natural gas vehicles operating in its service
area. Existing customers include the U.S. Postal Service, R.R. Donnelley and
Sons Company, South Central Regional Water Authority, BHC Company and the towns
of Westport and Fairfield.
More fleets expect to add natural gas vehicles as federal legislation requires
fleets to "phase-in" the use of cleaner alternate fuel vehicles. Natural gas is
the leading alternate fuel for vehicle use.
The strategic location of Southern's franchise area, which lies along the
Interstate No. 95 and No. 91 Corridor, is key to maximizing the profitability
of the existing distribution system, specifically for natural gas vehicular
fueling use.
Gas Supply
General
Southern's long-term supply sources include (1) Canadian supplies purchased
from Alberta Northeast Gas Limited ("Alberta Northeast") with
transportation on Iroquois Gas Transmission System, L.P. ("Iroquois"), (2)
transportation and storage services from Tennessee Gas Pipeline Company
("Tennessee") with direct purchase of supply from producers and marketers, (3)
transportation and storage services from Texas Eastern Transmission Corporation
("Texas Eastern") with direct purchase of supply from producers and marketers,
(4) transportation services from Algonquin Gas Transmission Company
("Algonquin"), (5) transportation and storage services from CNG Transmission
Corporation ("CNG Transmission"), (6) transportation service from
Transcontinental Gas Pipeline Corporation ("Transco"), (7) transportation
service from National Fuel Gas Supply Corporation ("National Fuel") and (8)
liquid and vapor supplies from Distrigas of Massachusetts Corporation
("Distrigas"). These arrangements result in gas deliveries into Southern's
service territory through interconnections with three interstate pipelines:
Algonquin, Iroquois and Tennessee.
In addition to Southern's long-term firm supply arrangements, Southern purchases
spot supplies and utilizes interruptible transportation services from interstate
pipeline companies.
Southern's supply, transportation and storage agreements require Southern to pay
a fixed demand charge regardless of the amount of gas transported or stored. The
FERC regulates interstate pipeline companies in connection with the rates
charged to Southern for transportation and storage of natural gas.
Domestic Supply
Southern's domestic supply arrangements consist mainly of purchasing storage and
transportation services from interstate pipelines. Producers and marketers
provide the gas supply to support these services.
Southern has firm transportation and firm storage contracts with Tennessee.
Under one transportation contract, Southern has 13,336,000 Mcf of pipeline
capacity available on an annual basis. Southern's storage contract with
Tennessee provides 1,195,000 Mcf of storage capacity and two other
transportation contracts provide 3,700,000 Mcf of pipeline capacity in the
market area on an annual basis. Other transportation contracts with Tennessee
provide 516,000 Mcf of firm transportation service annually. One transportation
contract with Tennessee was due to expire on June 1, 2000 and was renewed
earlier in the year for four years. All other storage and transportation
contracts were due to expire on November 1, 2000 and Southern elected to renew
these contracts for one year. Southern has two further options to renew or turn
back all its Tennessee contracts.
A transportation contract with Texas Eastern provides 5,972,000 Mcf of capacity
on an annual basis. Additional contracts with Texas Eastern provide 1,383,000
Mcf of storage service and 12,108,000 Mcf of transportation service on an annual
basis. Contracts with Texas Eastern expire in the year 2012.
Southern has storage service contracts with CNG Transmission. One contract
provides 100 days of storage service with 648,000 Mcf of annual delivery. The
remaining term of this contract is thirteen years. Under other contracts,
which have remaining terms of four to eight years, CNG Transmission provides
773,000 Mcf of annual firm storage service and 1,028,000 Mcf of annual
transportation service. The gas is stored by CNG Transmission and
delivered to Southern under transportation contracts with Texas Eastern and
Algonquin.
Algonquin furnishes only transportation services to Southern. The deliveries
that Algonquin makes to Southern are gas supplies transported by other
interstate pipelines interconnected to Algonquin.
Southern has multiple, diverse purchase agreements with producers and marketers
for firm supply, which is delivered to customers under its transportation
agreements or stored under its storage agreements for later delivery during peak
periods. These agreements vary in terms of delivery obligations and the contract
terms range from one month to five years. Southern pays a monthly reservation
charge, but has no monthly purchase obligation under these agreements. Commodity
prices are based on price indexes by supply area or are negotiated.
Canadian Supply
Southern receives Canadian supply under its long-term contracts with Alberta
Northeast with firm transportation provided by Iroquois. These supply contracts
with Alberta Northeast provide Southern with 12,775,000 Mcf of firm Canadian
supply annually. Supply agreements with Alberta Northeast have remaining terms
of three to seven years, and the transportation agreement with Iroquois has a
remaining term of twelve years.
Supplemental Supply
Southern has an agreement with Distrigas to purchase 328,000 Mcf annually on a
firm basis. This contract continues for three years and includes a provision for
either vapor or liquid delivery, with an option to increase maximum daily
delivery over the term of the contract. Additionally, Southern has interruptible
purchase contracts with Distrigas.
Supplemental gas supplies from on-site LNG and liquefied propane air storage
facilities are available to meet peak and winter demand requirements (see
section entitled "Sublease of LNG Plant" for the Decision in Docket No.
96-04-30).
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 Southern's Purchased Gas Adjustment
clause. 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.
Capacity release programs are available on all interstate pipelines serving
Southern. Demand charges recovered from a replacement shipper flow back as a
reduction on the pipeline's monthly invoice. These demand reductions are used to
lower gas costs to firm customers through established margin sharing mechanisms
approved by the DPUC. As discussed above, Southern's capacity is currently
released to Sempra for optimization.
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.
Natural Gas Cooperative
CNE Development and five other major eastern U.S. natural gas distribution
companies or their affiliates form the East Coast Natural Gas Cooperative, LLC,
which accesses competitively priced gas supplies. Southern has experienced
reduced gas costs and increased operational flexibility as a result of the
activities of the cooperative.
FERC Initiatives
The FERC has several initiatives that will affect regulation of the natural gas
industry. On July 29, 1998, the FERC issued a Notice of Inquiry ("NOI") in
Docket No. RM98-12. In this proceeding, the FERC is seeking comments about the
need to change its current regulatory policies relating to (1) the pricing of
existing capacity, (2) the pricing of new capacity, (3) the use of index rates
and benchmark adjustments to streamline rate filings, (4) the means of employing
performance-based incentive regulation, (5) the use of market-based rates for
turnback capacity, (6) the use of market-based rates for unsubscribed capacity
and (7) the methods of negotiating pre-construction risk among parties to an
expansion of pipeline capacity.
On the same date that it issued its NOI, the FERC also issued a Notice of
Proposed Rulemaking ("NOPR") in Docket No. RM98-10. In this proceeding, the FERC
proposed the removal of price caps in the short-term market and proposed revised
regulations that would subject all released capacity to an auction process. The
FERC also proposed to permit pipelines to negotiate the terms and conditions of
transportation service under limited conditions.
On September 30, 1998, the FERC initiated two additional proceedings. In Docket
No. RM98-9, the FERC proposed to modify its regulations governing applications
to construct new pipeline capacity. Among other things, the FERC proposed to
expand the scope of pipeline certificate authorizations to allow pipelines to
replace and abandon more facilities than were covered by the existing blanket
certificate, including replacements involving incrementally larger replacement
pipe. In addition, the FERC proposed to establish an environmental checklist
intended to add certainty to the environmental review aspect of certificate
applications. In addition, the FERC proposed to establish an environmental
checklist intended to add certainty to the environmental review aspect of
certificate applications. On April 29, 1999, the FERC issued a Final Rule in
Order No. 603 largely adopting its earlier proposal. On September 29, 1999, the
FERC issued Order No. 603-A on rehearing, reaffirming its final rule,
subject to several minor changes. This rule should improve the filing process
for pipeline applicants and should not have an adverse impact on LDCs like
Southern.
Also on September 30, 1998, the FERC announced a NOPR in Docket No. RM98-16 to
expand the voluntary use of collaborative procedures for applicants proposing to
build new pipeline facilities as well as hydroelectric projects. With some minor
changes, the FERC adopted its proposal as a final rule in Order No. 608, issued
on September 15, 1999. The newly-adopted regulations are intended to bring
applicants and potentially affected parties together in a pre-filing
collaborative process to resolve significant issues, including issues likely
to be raised in the environmental review process.
With the exception of Docket Nos. RM98-9 and RM98-16, the above-mentioned
initiatives are still subject to the outcome of notice and comment procedures.
Therefore, it is difficult to ascertain the precise impact they will have on the
business interests of LDCs like Southern. Since the issuance of its NOPRs in
RM98-10 and RM98-12, however, the FERC held a June 7, 1999 public conference in
Docket No. PL99-2-000 on the issue of anticipated natural gas demand in the
northeastern United States over the next two decades, the timing and type of
growth, and the effect projected growth will have on existing pipeline capacity.
The FERC concluded that information received in these proceedings as well as its
recent experience evaluating proposals for new pipeline construction warranted a
reversal of its policy favoring rolled-in rate treatment for certificates
covering new construction not covered by the optional or blanket certificate
authorizations and on September 15, 1999 issued a Statement of Policy in Docket
No. PL99-3. Under the new "no subsidy" approach, the FERC will no longer lean
toward rolled-in rate treatment of costs for new projects and instead
will favor market-driven, incremental rate schemes. Southern believes that
it will benefit from application of the new policy, but notes that requests
for rehearing of the policy statement are currently pending and that the
possibility always exists that this policy could be revised on rehearing.
Pipeline Rate Case Decisions
On March 4, 1999, Algonquin submitted a joint settlement offer to the FERC in
Docket No. RP99-262. Under the unopposed settlement offer, which was approved by
the FERC on April 1, 1999 and went into effect on May 1, 1999, Southern will
experience approximately an 8% reduction in its rates. Algonquin has agreed
under the terms of the settlement to accept all of the risks associated with
turnback of capacity until May 1, 2003 and has also agreed to a rate moratorium
through that date.
On May 21, 1999, in Process Gas Consumers Group et al. v. FERC, 177 F.3d 995
(D.C. Cir. 1999), the U.S. Court of Appeals for the District of Columbia Circuit
granted Southern's petition for review and remanded to the FERC its Decision
authorizing Tennessee Gas Pipeline Company to use its Net Present Value method
to award meter capacity when existing customers seek to change receipt or
delivery points and authorizing Tennessee to employ a twenty-year cap on length
of a bid in evaluating competing bids for new capacity. Southern had argued that
these tariff provisions were unreasonable and placed existing customers at an
unfair disadvantage. The FERC has not yet taken action in response to the remand
order.
Southern is currently active in the Iroquois remand proceedings at RP94-72,
FA92-59 and RP97-126 regarding the recovery of legal fees associated with
construction and certification of the pipeline. The parties have reached an
agreement in principle that resolves not only the legal fees remand matter, but
also the issues from Docket No. RP97-126-000 that are pending court review at
the U.S. Court of Appeals for the District of Columbia Circuit (Nos. 99-1175 and
99-1177), as well as issues concerning Iroquois' future rate levels and a
related moratoria on rate filings. It is anticipated that a settlement document
will be filed with the FERC within forty-five days.
Rates and Regulation
Connecticut Regulation
General
Southern is subject to the jurisdiction of the DPUC as to accounting, rates,
charges, operating matters and the issuance of securities, both equity and debt,
other than borrowings maturing in twelve months or less. Southern's firm sales
rates change monthly pursuant to a DPUC-approved Purchased Gas Adjustment
clause, under which purchased gas costs above or below a specified base cost are
charged or credited to customers.
In setting authorized rates for Southern, the DPUC allows prospective
adjustments to a historical test year. Forward-looking adjustments to the
mid-point of the rate year (the first year that rates will be in effect) for
rate base, revenues, expenses and capital structure are allowed. The DPUC has
found that these refinements provide for better synchronization of the
ratemaking components. Costs used by the DPUC in determining Southern's rates
may not be the same as actual costs incurred by Southern during the period rates
are in effect. The sales used in establishing rates are based on "normal"
weather patterns. Actual rates of return realized may not necessarily equal the
authorized rates of return.
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.
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 and subsequently issued a Decision on the proposed settlement on
November 17, 1999 which requires Southern to 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 in the months of November 1999 through
February 2000.
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.
Unbundling of Natural Gas Services
In August 1995, the DPUC issued a final Decision in Docket No. 94-11-12, DPUC
Review of Connecticut Local Distribution Companies' Cost of Service Study
Methodologies. In this docket, the DPUC investigated the issues surrounding the
development of firm transportation rates at the state level in response to FERC
Order No. 636, which mandated the unbundling of interstate pipeline services.
Effective April 1, 1996, commercial and industrial gas customers in Connecticut
were given the ability to contract for their gas supplies from sources other
than the LDCs and pay the LDCs only for the transportation of that gas through
their distribution systems at DPUC-approved rates. The firm transportation
rates are designed to provide Southern with the same margins provided by
bundled services.
In August 1997, the DPUC initiated a generic docket, Docket No. 97-07-11, DPUC
Generic Investigation into Issues Associated with the Unbundling of Natural Gas
Services by Connecticut Local Distribution Companies, to investigate issues
associated with the unbundling of natural gas firm sales and transportation
services by LDCs in Connecticut, including Southern. The DPUC has conducted this
proceeding in two phases. The first phase addressed issues relating to firm
transportation service in its present form with respect to the delivery of sales
and transportation service by LDCs and marketers. The DPUC reopened each LDC's
latest rate case to consider proposed changes to its respective tariffs and
rates. An Interim Decision was approved on October 28, 1998 which affected the
way LDCs administer firm transportation services by providing for changes in the
load balancing provisions in the LDCs' tariffs as well as for enhanced billing
options for customers.
The second Interim Decision was received on March 17, 1999 in which 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. This rate is available only to commercial and
industrial customers that use less that 500 Mcf annually.
Regarding 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.
Sublease of LNG Plant
In August 1996, the DPUC issued a final Decision in Docket No. 96-04-30,
Application of The Southern Connecticut Gas Company to Dispose of a Portion of
Its Plant and Equipment. The DPUC approved certain proposals made by Southern
regarding the operation of its LNG tank and related facilities, which included
the sublease of the LNG tank and related facilities from Southern to CNE Energy,
which would, in turn, sublease the LNG facility to TPS. TPS has received FERC
approval of its market-based tariffs and began storing and redelivering customer
owned LNG beginning in fiscal 1999.
Interruptible Margin Sharing
In January 1996, Southern requested a reopening of its 1993 rate proceeding to
propose a plan to redirect excess on-system interruptible margins, which would
otherwise 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 the Bridgeport 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.
Federal Regulation
Southern is affected by various federal regulations, including regulations
which (1) provide for emergency authority and curtailment allocations under
the Natural Gas Policy Act of 1978 when pipeline supplies are limited and
(2) establish certain retail policies for natural gas utilities under the
Public Utility Regulatory Policies Act of 1978. Southern is also subject to
the Natural Gas Pipeline Safety Act of 1968 with respect to the construction,
operation and maintenance of its mains, services and LNG facilities as
well as other federal regulations pertaining to safety standards concerning
such facilities. Currently, these federal regulations have a minimal impact
on Southern's day-to-day operations. Southern must comply with various
federal, state and local regulations with respect to environmental matters
(including hazardous waste regulation), local zoning and other regulations. To
date, such regulations have not materially impacted Southern's capital
expenditures, earnings or operations.
Regulations promulgated under the Clean Air Act Amendments of 1990 and the
Energy Policy Act of 1992, which require reduced pollution levels and certain
energy efficiency standards, have begun to affect Southern. Among other things,
the Clean Air Act Amendments (1) impose stringent vehicle emissions standards
beginning in 1994, (2) mandate the gradual phase-in of alternate fuel vehicles
for fleets of more than ten vehicles beginning in 1998 and (3) require power
plants to phase-in significant emission reductions of sulfur dioxide and
nitrogen oxide by the year 2000. Similarly, the Energy Policy Act of 1992 (1)
requires that federal agencies begin phasing-in the use of alternate fuels in
vehicles in 1993, (2) offers tax incentives to private parties who use or
facilitate the use of alternate fuel vehicles and (3) requires a lessening
reliance on foreign fuels. In 1996, the FERC also issued Order No. 888,
mandating that electric utilities provide open access transmission at wholesale.
This Order has expanded opportunities for the sale of power from gas fired
generating units. Over time, these regulations will likely lead to an increasing
demand for natural gas. Southern has already begun to participate in the
expanded markets for natural gas emerging due to these regulatory mandates.
Since 1986, the FERC has effected major changes in the regulations governing the
natural gas industry, including FERC Order No. 636. The actions by the
FERC have increased competition in the natural gas industry by requiring
interstate pipeline companies to provide gas transportation to others on
a nondiscriminatory basis.
The FERC has also been involved in the oversight of the Gas Industry Standards
Board, a group comprised of interstate pipelines and shippers. The Board's
actions to standardize essential terms of interstate pipeline transportation
have an effect on the manner in which Southern interacts with suppliers and
pipeline companies. The FERC has also announced recent rulemaking initiatives
governing the prices and terms under which pipeline customers, including
Southern, can purchase capacity or resell the capacity they currently hold, a
point discussed in the section entitled "Recent FERC Initiatives." These
initiatives, if adopted, will also affect Southern's decisions regarding
the acquisition and retention of interstate pipeline capacity; however, the
nature of such impacts cannot now be predicted.
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.
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.
Year 2000 Readiness Disclosure
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.
See Management's Discussion and Analysis in the Company's 1999 Annual Report to
Shareholders for further details regarding the Year 2000 issue as it relates to
the Company's operations.
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.
Item 2. Properties
The Company's physical plant and properties primarily consist of Southern's gas
distribution facilities. Southern had 2,184 miles of main and 124,525 service
units as of September 30, 1999. It leases office space in Bridgeport, New Haven,
Orange and Madison; owns properties in Bridgeport and New Haven that were
formerly manufacturing sites; and owns a propane air facility in Trumbull.
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 for a purchase
price based on the then fair market sales value of the unit as defined therein.
During 1998, Southern began subleasing 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.
Substantially all of Southern's utility properties and plant are subject to the
lien of the indenture and supplemental indentures securing its first mortgage
bonds. It is management's opinion that the physical plant and properties as
described herein are suitable and adequate for the purpose of delivering gas for
customer use.
Item 3. Legal Proceedings
There are three lawsuits pending against The Southern Connecticut Gas Company in
the Complex Litigation Docket, Connecticut Heating and Cooling Contractors
Association, Inc., et al. v. Connecticut Natural Gas Corporation, et al.,
alleging conspiracy to violate antitrust laws against the three Connecticut
LDCs; Connecticut Cooling Total Air, Inc. v. Connecticut Natural Gas
Corporation, et al., alleging conspiracy to violate the Connecticut Unfair Trade
Practices Act against the three LDCs; and Connecticut Cooling Total Air, Inc. v.
Southern Connecticut Gas Company, alleging violation of the Connecticut Unfair
Trade Practices Act. All of the suits relate to the LDCs' provision of service
and maintenance to heating, cooling and ventilating systems and appliances. The
plaintiffs are two trade associations and one plumbing and heating contractor,
purporting to sue on behalf of a class of other such contractors. The cases have
been brought as class actions, but class certification has not been granted. One
of the cases against Connecticut Natural Gas alone was ordered to proceed to
trial in August 1999 and settled just prior to trial. While that case was
moving toward trial, discovery was stayed on the remaining cases. Yankee Gas has
been selected as the next case to proceed to trial, which has been scheduled to
commence on March 20, 2000. One of the cases against Southern is scheduled for
trial on December 4, 2000. The plaintiffs seek treble damages in excess of
$15,000, punitive damages, attorneys' fees and equitable relief. Southern is
defending itself vigorously in these lawsuits, which management believes are
without merit. In the opinion of management, resolution of these lawsuits is not
expected to have a material adverse impact on the Company's financial condition
or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
(a) A special meeting of shareholders of the registrant was held on September
14, 1999.
(b) Approval of the plan of merger among Connecticut Energy, Energy East and
Merger Company:
For Against Abstain
--- ------- -------
8,384,758 221,155 89,557
In excess of 80% of shareholders approved the Plan of Merger.
PART II
Item 5. Market for Common Stock Equity and Related Stockholder Matters
Common Stock Data
The Company's common stock is listed for trading on the New York Stock Exchange.
The Company's common stock ticker symbol is CNE.
The following table shows the quarterly high and low price ranges of the
Company's common stock and quarterly dividends paid during the years ended
September 30, 1999 and 1998:
Market Price and Dividend Data
1999 Quarters ended High Low Dividend
- ------------------- ---- --- --------
December 31, 1998 $32 $26 7/16 $0.335
March 31, 1999 31 24 1/4 0.335
June 30, 1999 39 3/16 24 5/16 0.335
September 30, 1999 38 14/16 36 11/16 0.335
1998 Quarters ended High Low Dividend
- ------------------- ---- --- --------
December 31, 1997 $30 7/16 $22 3/4 $0.33
March 31, 1998 30 3/4 25 11/16 0.33
June 30, 1998 32 1/4 25 5/8 0.335
September 30, 1998 29 11/16 25 1/16 0.335
As of September 1999, the Company and its predecessors have paid 359 consecutive
quarterly cash dividends. Cash dividends have been paid since 1850, and the
Company currently expects that dividends will continue to be paid in the future.
The major source of funds for payment of the Company's dividends are the
dividends received on the shares of Southern's common stock owned by the
Company. Southern's indentures relating to long-term debt contain restrictions
as to the declaration or payment of cash dividends on, or the reacquisition of,
capital stock. Under the most restrictive of such provisions, $52,076,000 of
retained earnings at September 30, 1999 was available for such purposes.
The approximate number of shareholders of record of the Company's common stock
as of November 19, 1999 was 9,116.
Item 6. Selected Financial Data
Financial information presented in this table is as of or for the twelve months
ended September 30:
<TABLE>
<CAPTION>
(dollars in thousands, except per share) 1999 1998 1997 1996 1995
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $228,296 $242,431 $252,008 $261,093 $232,093
Net income 16,688 19,011 16,441 15,165 14,060
Net income per share - diluted 1.61 1.88 1.81 1.70 1.60
Dividends paid per share 1.34 1.33 1.32 1.31 1.30
Total assets 474,780 459,401 424,281 399,228 370,088
Long-term debt 148,062 150,007 134,073 138,727 119,322
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" on pages 9 to 19 of the Company's 1999 Annual Report to Shareholders
is incorporated by reference herein.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
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. 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 $6,263,000
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
$6,263,000 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 was a positive $133,000. However, CNE Energy would not
receive a payment if the swap arrangement were terminated with a positive fair
value.
Item 8. Financial Statements and Supplementary Data
The Consolidated Statements of Income and Comprehensive Income, Consolidated
Balance Sheets, Consolidated Statements of Changes in Common Shareholders'
Equity, Consolidated Statements of Cash Flows and Notes to Consolidated
Financial Statements on pages 20 to 36 and the Report of Independent Accountants
on page 37 of the Company's 1999 Annual Report to Shareholders are incorporated
by reference herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Directors
The Board of Directors of the Company is compromised of eight members. The
Company's Certificate of Incorporation and By-Laws further provide that the
Board of Directors shall be divided into three classes as nearly equal in number
as possible. Each class will serve for three years, with one class being elected
each year.
Certain information concerning the Directors continuing in office, including the
business experience of each during the past five years, is set forth below.
Information Concerning Directors
Terms Expiring in 2000
J. R. Crespo is the Chairman of the Boards of Directors and Chief Executive
Officer of the Company and each of its subsidiaries. He is the President of the
Company and Southern. He is Chairman of the Executive Committees of the Boards
of Directors of the Company and Southern. Mr. Crespo has been a Director of
Southern since January 1989 and a Director of the Company since April 1989. From
1982 through 1988, he was Managing Partner - Utility Regulatory and Advisory
Services, Coopers & Lybrand. He is 57 years old.
Richard F. Freeman is the President and Chief Executive Officer, Greater
Bridgeport Area Foundation. He is a principal in the consulting firm of Freeman
& Associates and the former President and Chief Executive Officer and Trustee of
The Bank Mart. Mr. Freeman has been a Director of the Company and Southern since
1979 and is a member of the Executive, Nominating and Salary and Pension
Committees and Chairman of the Audit Committees of the Boards of Directors of
the Company and Southern. He is 65 years old.
Newman M. Marsilius III is the President and Chief Executive Officer,
Producto-Moore Companies, a specialty tool and machine manufacturer. He is a
member of the Board of Directors of the American Society of Precision Engineers.
He has been a Director of the Company and Southern since September 1992. He is
a member of the Company's and Southern's Audit Committees. He is 53 years old.
Terms Expiring in 2001
Henry Chauncey, Jr. is Lecturer and former Head of the Management Program,
Department of Epidemiology and Public Health, Yale School of Medicine, New
Haven, Connecticut. He was the President and Chief Executive Officer of Gaylord
Hospital from 1988 to 1994. Previously, from 1982 to 1988, he served as
President of Science Park Development Corporation, a Connecticut non-profit
corporation formed for the purpose of establishing a high technology business
development area in New Haven. Mr. Chauncey has been a Director of the
Company and Southern since 1986. He is a member of the Company's and Southern's
Nominating and Salary Committees and Executive Committees. He is 64 years old.
Richard M. Hoyt is the President and Chief Executive Officer of Chapin & Bangs,
a steel service center. He is also the Chairman and Chief Executive Officer of
Lindquist Steels, Inc., a distributor of tool steel; Chairman of the Board of
Directors of Bridgeport Hospital; a Trustee of the Bridgeport YMCA; and
a Director of Yale New Haven Health System and the Greater Bridgeport
Area Foundation. Mr. Hoyt has been a Director of the Company and Southern
since January 1992. He is a member of the Company's and Southern's Pension
Committees. He is 57 years old.
Christopher D. Turner is Project Manager, Energy Sector, Bechtel Technology
and Consulting Group, Bechtel Corporation. Previously, he was Principal
Executive Consultant for Resource Management International; Manager, Strategic
Business Operation, Power Technologies, Inc.; and President of C.D. Turner
Associates. From 1963 through January 1988, Mr. Turner was employed by Niagara
Mohawk Power Corporation and was Vice President of Corporate Development.
Mr. Turner has been a Director of the Company and Southern since 1989. He is
a member of the Executive, Nominating and Salary and Pension Committees of
the Boards of Directors of the Company and Southern. He is 56 years old.
Terms Expiring in 2002
James P. Comer, M.D. is the Maurice Falk Professor of Child Psychiatry, Yale
Child Study Center and Associate Dean, Yale School of Medicine, New Haven,
Connecticut. Dr. Comer has been a Director of the Company since 1979 and
a Director of Southern since 1976. He is a member of the Nominating and
Salary and Audit Committees of the Boards of Directors of the Company and
Southern. He is 65 years old.
Samuel M. Sugden is Of Counsel with the international law firm of LeBoeuf, Lamb,
Greene & MacRae L.L.P. Mr. Sugden has been a member of the Boards of Directors
of the Company and Southern since July 1993. He is Chairman of the Company's
and Southern's Nominating and Salary Committees. He is 56 years old.
Executives
A list of executive officers of the Company and Southern follows:
Executive Officers of Connecticut Energy Corporation
and
The Southern Connecticut Gas Company
Position and Business Experience for the Past
Name and Age Five Years
- ------------ ---------------------------------------------
J. R. Crespo, 57 Chairman, President and Chief Executive
Officer of the Company and Southern (1990).
Thomas A. Trotta, 62 Senior Vice President of the Company and
Executive Vice President and Chief Operating
Officer of Southern (1996); Executive Vice
President and Chief Operating Officer of
Southern (1995).
Vincent L. Ammann, Jr., 40 Vice President and Chief Accounting Officer
of the Company and President of CNE
Venture-Tech (1999); Vice President and Chief
Accounting Officer of the Company; Vice
President, Technology Applications of
Southern and President of CNE Venture-Tech
(1997); Vice President and Chief Accounting
Officer of the Company; Vice President,
Information Technology of Southern and Senior
Vice President of CNE Venture-Tech (1996);
Vice President and Chief Accounting Officer
of the Company and Group Vice President of
Southern (1994).
Samuel W. Bowlby, 61 Vice President, General Counsel and Secretary
of the Company and Southern (1997); Partner,
Tyler, Cooper & Alcorn, New Haven,
Connecticut (1970-1997).
Carol A. Forest, 51 Vice President, Finance, Chief Financial
Officer, Treasurer and Assistant Secretary of
the Company and Southern (1996); Vice
President, Finance, Chief Financial Officer
and Treasurer of the Company and Southern
(1991).
Janet L. Janczewski, 55 Senior Corporate Counsel and Assistant
Secretary of the Company and Southern (1997);
Corporate Counsel of Southern (1989).
Larry S. McGaughy, 52 Vice President of the Company and President
of CNE Development and CNE Energy (1998);
President of CNE Energy (1996); Vice
President, Corporate Engineering and Special
Projects of Southern (1995).
Michael H. Pinto, 72* Vice President, Government Affairs of the
Company (1991).
Salvatore A. Ardigliano, 50 Senior Vice President of Southern (1999);
Group Vice President and Chief Information
Officer of Southern (1998); Group Vice
President of Southern (1998); Vice President,
Marketing and Gas Supply Services of Southern
(1995); Vice President, Gas Supply Services
of Southern (1995).
Peter D. Loomis, 51 Group Vice President, Distribution Services
of Southern (1999); Group Vice President,
Operations of Southern (1998); Group Vice
President, Customer and Operating Services of
Southern (1995).
Phyllis A. O'Brien, 54 Group Vice President of Southern (1996); Vice
President, Accounting and Regulatory Services
of Southern (1994).
David Silverstone, 53 Group Vice President and Chief Administrative
Officer of Southern (1998); Group Vice
President of Southern (1998); Partner,
Silverstone and Koontz (1983-1998).
Ernest W. Karkut, 57 Vice President, Purchasing and Plant Services
of Southern (1994).
Diane L. Nunn, 51 Vice President, Information Services of
Southern (1999); Vice President, Distribution
and Gas Control Services of Southern (1998);
Vice President, Customer and Distribution
Services of Southern (1998); Group Director,
Customer and Distribution Services of
Southern (1996); Director, Human Resources of
of Southern (1990).
*retired effective January 1, 1999.
Item 11. Executive Compensation
Compensation of Directors of Connecticut Energy Corporation
The Directors do not receive any cash compensation for service on the Board of
Directors of Connecticut Energy, nor do they receive any compensation for
attendance at meetings of Connecticut Energy's Board of Directors and meetings
of its Committees.
Each Director of Connecticut Energy is also a Director of Southern. For the year
ending September 30, 1999, Southern's standard arrangement with its Directors,
other than Directors who are officers of Southern, for their services was to pay
them $600 each for each meeting of the Board of Directors attended. Southern
compensated each Committee Chairman an additional $600 for each Committee
meeting attended, and Committee members received $500 for each Committee meeting
attended. Except for the Chairman of the Board, each Director of Southern who
was not an officer of Southern was paid an annual retainer of $13,000.
Effective October 1, 1992, Southern has an unfunded retirement plan for its
non-employee Directors. If a Director attains 60 years of age and has received a
retainer for ten years, then the Director is eligible to retire and receive an
annual payment, payable in monthly installments commencing on the first day of
the month following such retirement, of an amount equal to the annual retainer
in effect during the year in which the Director retires, provided however, that
such amount will not exceed the amount paid to such Director during the year the
Director turned 65. Such payments shall continue for a period of ten years or
the life of the eligible Director, whichever is shorter, and no monthly payment
shall be made after the month in which an eligible Director dies. If a Director
dies before or after payments under the plan are made, no further amounts are
payable to the Director's surviving spouse, descendants or estate. A Director of
Southern who becomes a member of the Advisory Board of Directors after the
Merger contemplated by the Agreement and Plan of Merger dated April 23, 1999 by
and among Connecticut Energy, Energy East and Merger Co. shall continue as a
Director under the Plan. If a Director is determined to be eligible under the
Plan, years of service as a Director of Southern shall be added to years of
service on the Advisory Board of Directors. The plan is a non-contributory plan
and is not intended to qualify under Sections 401(a) and 501(a) of the Internal
Revenue Code of 1986, as amended.
Effective November 26, 1996, the Company has a Non-Employee Director Stock Plan.
The Plan provides that each Non-Employee Director will receive annually, for his
or her service as a Director, 100 shares of Common Stock on the day of the
Company's Annual Meeting of Shareholders. An aggregate of 13,000 shares of
Common Stock will be available for issuance under the Plan throughout its
ten-year projected life. The Common Stock to be issued under the Plan will be
made available from treasury or authorized and unissued shares of the Common
Stock of the Company.
The Company retained the law firm of LeBeouf, Lamb, Greene and MacRae, L.L.P.,
in which Mr. Sugden is Of counsel, for services rendered in fiscal year 1999.
Report of the Nominating and Salary Committee on Executive Compensation
The Nominating and Salary Committee (the "Committee") is a standing committee
composed entirely of outside Directors who are not employees of the Company or
any of its affiliates. Mr. Sugden is the Chairman. Messrs. Comer, Freeman,
Chauncey and Turner are the other members.
None of the members participate in any of the executive compensation plans
overseen and administered by the Committee with Board of Directors' approval,
and none participates in any compensation plan administered by the executives of
the Company.
Committee Functions
The Committee is responsible for assuring that compensation programs are
developed, implemented and administered to support the Company's fundamental
philosophy that compensation should be effectively linked to corporate and
individual performance. The Committee meets on a regularly scheduled basis. The
Committee reviews salary and incentive compensation programs as well as the
compensation of the President and Chief Executive Officer, Mr. Crespo, and other
senior executives. Reviews of executive performance and compensation occur
outside the presence of the executives who are being discussed. The Committee
has access to outside professional compensation consultants and meets with these
consultants, with and without executives present. The Committee also reviews
corporate organization, management development plans and benefits programs. It
makes reports and recommendations to the Company's Board of Directors on all of
these matters of organization and compensation. It has authority to grant awards
under both the Non-Employee Director Stock Plan and the Restricted Stock Award
Plan.
Corporate Compensation Philosophy
The Company's executive compensation program is designed to motivate, reward,
and retain the management talent needed to achieve the Company's business
objectives and to maintain the Company's position of leadership in the natural
gas distribution industry. Retention of executives who have developed the skills
and expertise required to lead a capital intensive organization is vital to the
Company's competitive strength. Motivation of these individuals is, and will
continue to be, key to the Company's success.
The philosophical basis of the compensation program is to pay for performance
and the level of responsibility of an individual's position. Assessments of both
individual and corporate performance influence executive compensation levels.
The Committee, with Board of Directors' approval, seeks to encourage a
performance-based environment that motivates individual performance by
recognizing the past year's results and by providing incentives for further
improvement in the future. This includes the ability to implement the Company's
business plans as well as to react to unanticipated external factors having a
significant impact on corporate performance. Compensation decisions for all
executives, including the named executive officers and Chief Executive Officer,
are based on the same criteria.
Compensation opportunities are linked to financial and operating performance.
For each executive, a significant percentage of compensation each year is at
risk; that is, it depends on the accomplishment of challenging performance goals
approved and reviewed by the Committee and the Board of Directors. The
percentage of compensation at risk for an executive increases with more
responsibilities and as opportunities to contribute directly to the success of
the organization increase. The performance upon which the incentive compensation
program is based is assessed annually to ensure that executives work to support
both the current as well as the strategic objectives of the Company and its
subsidiaries.
Components of Compensation
There are two major components to the Company's compensation program: Base
Salary and Management Incentive Compensation Awards.
Base Salary - A competitive base salary supports the philosophy of management
development and career orientation of executives and is consistent with the
long-term nature of the Company's business. The Company's compensation
philosophy is to pay base salaries to its executive officers that do not exceed
the median for comparable positions at other, comparable companies. Base
salaries for some executives will be set at a higher level if the Committee
concludes (and the Board of Directors agrees) that it is appropriate in light of
a particular individual's responsibilities, experience and personal performance.
Compensation opportunities must be sufficient to attract and retain the highly
qualified individuals the Company needs to succeed.
Salary budget expenditures and adjustments to the salary structure are a result
of annual reviews of competitive positioning (how the Company's salary structure
for comparable positions compares with that of other companies), business
performance and general economic factors. While there is no specific weighting
of these factors, competitive positioning is the primary consideration in
setting base salary. Business and other economic factors such as net income and
estimates of inflation are secondary considerations in establishing base salary.
The Committee recommends and the Board of Directors approves the salaries of the
President and Chief Executive Officer and the salaries of other elected
officers. The Committee met in November 1998 to recommend the 1999 salaries for
the President and Chief Executive Officer and to set the 1999 salaries for the
other elected officers. The Board of Directors approved the Committee's
recommendations. Any changes to these approved salaries must be reviewed by the
Committee and approved by the Board of Directors before implementation. Mr.
Crespo became President and Chief Executive Officer in 1989. His 1999 salary
reflects the size and complexity of the Company, as well as his experience and
personal contributions to corporate performance.
Management Incentive Awards - Corporate and individual performance goals are set
by the Committee and approved by the Board of Directors. The goals set each year
are ones which the Committee believes are challenging in light of all current
circumstances. If the financial performance of the Company does not meet a
certain threshold level specified by the Board of Directors for that year, then
no annual incentive awards would be paid for corporate performance.
Annual incentive opportunities are designed to provide a strong incentive for
executives to increase corporate earnings each year. The program places a
significant portion of the executive's annual compensation at risk. As a result
of the Company's overall compensation philosophy, approximately one quarter of
an executive's total annual cash compensation depends on the achievement of
annual performance goals. The amount of compensation at risk increases with the
executive's responsibilities. With limited exceptions, base salaries do not
exceed the median for comparable positions at comparable companies. If
performance goals are met, then an executive's annual cash compensation will
total more than the median total annual cash compensation for comparable
positions at comparable companies.
In evaluating the performance of Mr. Crespo, President and Chief Executive
Officer, the Committee, in addition to financial performance, considers such
factors as ethical business conduct, progress towards strategic plan objectives
and the general perception of Connecticut Energy and its subsidiaries by the
financial community and customers. Narrow quantitative measures or formulas are
not viewed as sufficiently comprehensive for this purpose. Mr. Crespo's 1999
award reflects his significant personal contributions to the business and his
leadership which resulted in 1999 performance that was strong relative to the
industry. This determination was based on the judgment of the Committee with
Board of Directors' approval. The combination of Mr. Crespo's base salary and
the management incentive award was comparable to other Chief Executive Officers
of competitive companies of similar size and with similar business results as
those of the Company.
Summary
The Committee has the responsibility to ensure that the Company's compensation
program satisfies the best interests of the shareholders. The Committee believes
that the existing compensation program is competitive and appropriate. Balancing
base salaries with management incentive awards is the foundation upon which the
Company's stability and business success should be built.
Samuel M. Sugden, Chairman
James P. Comer
Richard F. Freeman
Henry Chauncey, Jr.
Christopher D. Turner
Executive Compensation
All of the executive officers of the Company except two are currently officers
of Southern. The Company has no existing plan or arrangement to pay any
remuneration to such officers in addition to the compensation that they will
receive in their respective capacities as employees of Southern or another
Company subsidiary. The salaries paid by Southern or another Company subsidiary
during the last three years ended September 30, 1999 to each of the five
most highly compensated executive officers (or executive officers of the
Company's subsidiaries) were as follows:
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION(1)
- ------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long-Term Compensation
--------------------- ------------------------
Payouts
------------------------
LTIP
Payouts
($)
Name and Principal All Other
Position Year Salary Bonus Stock(3) Cash(4) Compensation
($) ($)(2) ($)(5)
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
J. R. Crespo 1999 468,750 194,198 2,107,074 142,655 12,334
Chairman, President and CEO 1998 441,250 249,000 -- -- 12,461
1997 411,250 207,244 -- -- 9,963
- ---------------------------------------------------------------------------------------------------------------------
Thomas A. Trotta 1999 256,000 63,276 4,800
Executive Vice President and COO 1998 246,000 82,600 4,800
1997 236,000 80,455 4,725
- ---------------------------------------------------------------------------------------------------------------------
Larry S. McGaughy 1999 170,667 45,852 403,050 27,256 9,300
President, CNE Energy Services 1998 159,300 55,976 -- -- 9,238
Group, Inc.; Vice President 1997 142,950 37,291 -- -- 4,288
Connecticut Energy
- ---------------------------------------------------------------------------------------------------------------------
Samuel W. Bowlby 1999 180,725 43,516 9,075
Vice President, General Counsel 1998 172,128 -- 5,425
and Secretary 1997 42,501 12,000 1,050
- ---------------------------------------------------------------------------------------------------------------------
Carol A. Forest 1999 148,900 46,205 8,967
Vice President, Treasurer and 1998 142,250 51,938 8,767
Assistant Secretary 1997 135,975 37,760 4,079
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) None of the perquisites and other personal benefits received by such named
persons exceed $50,000 or 10% of the total salary and bonus received by
such person for each year shown.
(2) With one exception, the amounts listed represent awards for the fiscal year
ended September 30, 1998 under the Company's management incentive program,
which awards are based on corporate and individual achievements and thus
are not awarded according to a preset payment schedule. Amounts for fiscal
1999 performance of the executive officers of the Company will be paid
in the first quarter of 2000. Amounts listed for Mr. Bowlby in this
column for fiscal year 1997 represent an initial signing bonus.
(3) The amounts shown represent the value of shares which became actual awards
and vested on September 13, 1999 pursuant to the Company's Restricted Stock
Award Plan. See footnotes (2) and (4) of Item 12.
(4) Amounts included in this column are the accrued dividends on target awards
granted under the Restricted Stock Award Plan since the date the awards
were granted through the date the awards vested, and 6% interest on the
accrued dividends accrued according to the terms of the Plan. These
amounts were paid out in September 1999.
(5) The amounts appearing in this column represent the sum of (i) matching
contributions by Southern or another Company subsidiary to a Section
401(k) plan for each of the named individuals; (ii) transportation
allowances for 1998 for Messrs. McGaughy and Bowlby and Ms. Forest; and
(iii) premium payments for the years 1999, 1998 and 1997 of $7,534, $7,661
and $5,238, respectively, for a renewable term life insurance policy for
Mr. Crespo.
Pension and Retirement Benefits
The approximate annual retirement benefits payable under Southern's Pension Plan
and its supplemental retirement plans to an individual whose compensation as
defined in the Pension Plans is in the classification indicated would be as
follows:
PENSION PLAN TABLE
Years of Service
Remuneration 5 15 25 35 45
- ------------ -------- -------- -------- -------- --------
$175,000 $105,000 $105,000 $105,000 $105,000 $105,000
200,000 120,000 120,000 120,000 120,000 120,000
225,000 135,000 135,000 135,000 135,000 135,000
250,000 150,000 150,000 150,000 150,000 150,000
300,000 180,000 180,000 180,000 180,000 180,000
400,000 240,000 240,000 240,000 240,000 240,000
450,000 270,000 270,000 270,000 270,000 270,000
500,000 300,000 300,000 300,000 300,000 300,000
550,000 330,000 330,000 330,000 330,000 330,000
600,000 360,000 360,000 360,000 360,000 360,000
650,000 390,000 390,000 390,000 390,000 390,000
700,000 420,000 420,000 420,000 420,000 420,000
750,000 450,000 450,000 450,000 450,000 450,000
850,000 510,000 510,000 510,000 510,000 510,000
Remuneration covered for pension purposes is defined as the employee's average
annual compensation (which includes taxable compensation and pre-tax employee
contributions to Southern's Section 401(k) plan) for the five consecutive years
of the employee's last ten years of service yielding the highest such average.
Remuneration for pension purposes is the sum of the amounts shown in the Salary
and Bonus columns of the Summary Compensation Table above.
The projected years of service for each of the five highest paid executive
officers at age 65 are: Mr. Crespo, 19 years; Mr. Trotta, 48 years; Mr.
McGaughy, 22 years; Mr. Bowlby, 7 years; and Ms. Forest, 34 years. The benefits
illustrated are payable as life annuities. With two exceptions, the benefits for
the named individuals are not subject to any offset. Mr. McGaughy's and
Mr. Bowlby's benefits are subject to Social Security offset and, based on
years of service, will be approximately 68% and 22%, respectively, of the
amounts listed in the table above at retirement at age 65.
Share Performance Chart
The following chart compares the total cumulative return on an investment in the
Company's Common Stock with the cumulative total return of the Standard & Poor's
500 C+Stock Index and the Standard & Poor's Utilities Index (which includes
telephone, electric, gas pipeline and gas distribution companies) over the last
five fiscal years in accordance with the rules of the Securities and Exchange
Commission(1):
Chart: The chart (included in the hard copy only) plots the following numbers
over time.
Years Ended September 30, 1994 1995 1996 1997 1998 1999
- ---------------------------------------------------------------------
Connecticut
Energy 100 96 105 138 158 236
S&P 500 100 130 156 219 239 305
S&P Utilities 100 128 137 157 203 201
(1) Total return assumes reinvestment of all dividends on the payment date.
The changes displayed are not necessarily indicative of future returns
measured by this, or any method.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth, as of September 30, 1999, information with
respect to the beneficial ownership of Common Stock of the Company by the
Directors of the Company, as well as executive officers named in the Summary
Compensation Table appearing under "Executive Compensation." Unless otherwise
indicated, each holder has sole voting and investment powers as to shares
listed.
Amount and Nature
of Beneficial
Ownership(1)
------------
Henry Chauncey, Jr ............................................... 3,593
Dr. James P. Comer ............................................... 2,181
J. R. Crespo ..................................................... 47,356(2)
Richard F. Freeman ............................................... 12,046
Richard M. Hoyt .................................................. 1,350
Newman Marsilius, III ............................................ 1,777
Samuel M. Sugden ................................................. 3,300(3)
Christopher D. Turner ............................................ 1,825
Thomas A. Trotta ................................................. 7,108
Larry S. McGaughy ................................................ 8,234(4)
Carol A. Forest .................................................. 4,543
Samuel W. Bowlby ................................................. 604
Directors and executive officers as a group (22 individuals) ..... 116,446(5)
(1) No Director or Executive Officer owns more than 1.0% of the Common Stock of
the Company.
(2) Mr. Crespo received awards of 32,795 and 23,676 restricted shares on
October 1, 1996 and October 1, 1998, respectively, under the Company's
Restricted Stock Award Plan. These shares vested on September 13, 1999
when the Nominating and Salary Committee of the Company's Board
certified the achievement of certain performance goals under the Plan.
On September 23, 1999, 25,948 of these shares were retired to pay
withholding tax on the value of the award. The value of the award
appears in the "LTIP Payouts," "Stock" column of the Summary
Compensation Table. A discussion of the Restricted Stock Award Plan
appears in "Executive Compensation" under the heading "Restricted Stock
Award Plan."
(3) All of these shares are held jointly by Mr. Sugden and his wife.
(4) Mr. McGaughy received awards of 6,261 and 4,541 restricted shares on
October 1, 1996 and October 1, 1998, respectively, under the Company's
Restricted Stock Award Plan. These shares vested on September 13, 1999
when the Nominating and Salary Committee of the Company's Board
certified the achievement of certain performance goals under the Plan.
On September 23, 1999, 3,915 of these shares were retired to pay
withholding tax on the value of the award. The value of the award
appears in the "LTIP Payouts," "Stock" column of the Summary
Compensation Table.
(5) Constituting approximately 1.1% of the Company's issued and outstanding
shares.
To the knowledge of the Company, except for Brinson Partners, Incorporated and
Harvard Management, no person or group of persons is the beneficial owner of
more than 5% of the Company's Common Stock. The following table sets forth as of
October 29, 1999, certain information as to the number of shares of Common Stock
beneficially owned by persons in excess of 5% based on reports filed with the
Securities and Exchange Commission or other reliable information:
Title Number Percent
of of of
Name and Address Class Shares Class
- ---------------- ----- ------ -----
Brinson Partners, Inc. Common 631,000 6.1%
209 South LaSalle
Chicago, IL 60604
Harvard Management Common 1,037,000 10%
600 Atlantic Avenue
Boston, MA 02210-2211
Item 13. Certain Relationships and Related Transactions
Restricted Stock Award Plan
Effective November 26, 1996, the Company has a Restricted Stock Award Plan (the
"Plan"). The Plan is administered by the Nominating and Salary Committee, which
can establish rules and regulations consistent with the terms of the Plan.
Any officer or senior salaried employee of the Company or any of its affiliates,
including the executive officers named in the Summary Compensation Table, may be
selected by the Committee to become a participant in the Plan. No participant
may be awarded more than 180,000 shares of stock, nor may a participant receive
more than $250,000 in dividends or distributions with respect to shares of stock
actually awarded for any one performance period. Awards consist initially of
target awards, actual receipt of some, all or up to 150% of which is conditioned
upon satisfaction of performance and vesting conditions. After satisfaction of
performance conditions, an award is immediately vested.
The purpose of the Plan is to motivate participants to work to achieve corporate
objectives beneficial to the Company and its shareholders by awarding to them
shares of the Common Stock of the Company which become vested upon or after
achievement of the objectives. The Plan should assist the Company to retain
capable officers and other key employees who are eligible to participate in the
Plan and to attract and retain others who may reasonably expect to become
participants in the Plan after a reasonable period of employment with the
Company or its affiliates. Five senior officers received the initial target
awards for the three-year performance period beginning October 1, 1996. These
same five officers plus one additional officer received target awards for the
performance period beginning October 1, 1998. Both the October 1, 1996 and
October 1, 1998 target awards vested on September 13, 1999.
Other
The Boards of Directors have approved employment and deferred compensation
agreements with Mr. Crespo. Pursuant to these agreements, Mr. Crespo's base
salary was set at the rate of $225,000 per year, subject to upward revision when
the salaries of other officers of Southern are revised. The term of the
employment agreement is for three years commencing March 24, 1992 and shall be
automatically extended on the first day of each succeeding month to end three
years from such extension. Mr. Crespo also participates in the Company's
Management Incentive Compensation Plan ("Compensation Plan"). His agreements
with the Company and Southern provide for certain compensation and benefits to
be paid if his employment is terminated without "Cause," or terminated by him
for "Good Reason," or if there is a "Change in Control" of the Company as those
terms are defined in the agreements. If there is a "Change in Control," the
Company will pay Mr. Crespo his full base salary through the date of termination
and all benefits and awards to which he is entitled under benefits plans and
policies in effect prior to the "Change in Control." Additionally, the Company
will pay Mr. Crespo three times (1) his annual base salary on the effective day
of the termination or, if higher, immediately prior to a "Change in Control,"
(2) the highest bonus he received in the previous five fiscal years or, if
higher, during the year in which a "Change in Control" took place, and (3)
amounts paid by the Company to Southern's Section 401(k) Plan on Mr. Crespo's
behalf plus an amount equal to 35% of his annual base salary on the date of
termination or, if higher, immediately prior to the "Change in Control" as
compensation for medical, life insurance and other benefits lost as a result of
termination. If any of the foregoing payments result in the imposition of an
excise tax under the Internal Revenue Code, the amount paid to Mr. Crespo will
not be reduced because of the imposition of such excise tax.
If Mr. Crespo terminates his employment for "Good Reason" or if the Company and
Southern terminate his employment without "Cause," Mr. Crespo will continue to
receive his base salary for the remaining term of the agreement and any amounts
payable under the Compensation Plan within twelve months of termination to which
he is entitled unless he is receiving payments because of a "Change in Control."
Mr. Crespo's deferred compensation agreement provides for compensation payments
upon retirement or termination of his employment. Under the agreement, if
employed by the Company until December 1, 2004, he would be entitled to receive,
on retirement or termination of his employment, 65% of the average of his total
base pay plus any incentive compensation paid in those five highest paid
consecutive years out of the ten years preceding his retirement or termination,
less amounts paid under Southern's retirement plans. He will receive lesser
amounts if he retires or his termination occurs prior to December 1, 2004. The
deferred compensation agreement also contains provisions relating to the
election of benefits for his spouse, the receipt of deferred compensation prior
to attaining the age of 65, payments in the event of his death or disability,
and provisions for supplemental term life insurance.
The Company and Southern entered into agreements with Mr. Trotta and Ms. Forest
in 1996 and with Mr. Bowlby in 1997, which, among other things, provide for
certain payments to these executives similar to those that Mr. Crespo would
receive in the event of a "Change of Control" of the Company. Ms. Forest expects
to sign an employment agreement with Energy East and Connecticut Energy to
become effective at the effective time of the merger. At the effective time of
the merger, this employment agreement will replace and terminate her existing
agreement with Southern and Connecticut Energy.
Energy East and Connecticut Energy have signed an employment agreement with Mr.
Crespo. This agreement will become effective at the effective time of the
merger. At the effective time of the merger, this employment agreement will
replace and terminate his existing agreement with Southern and Connecticut
Energy.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) List of documents filed as part of this Report:
1. Financial Statements
Among the responses to this Item 14(a) are the following financial statements
which are incorporated by reference herein in Item 8 above:
(i) Consolidated Statements of Income and Comprehensive Income for
the years ended September 30, 1999, 1998 and 1997.
(ii) Consolidated Balance Sheets as of September 30, 1999 and 1998.
(iii) Consolidated Statements of Changes in Common Shareholders'
Equity for the years ended September 30, 1999, 1998 and 1997.
(iv) Consolidated Statements of Cash Flows for the years ended
September 30, 1999, 1998 and 1997.
(v) Notes to Consolidated Financial Statements.
(vi) Report of Independent Accountants.
2. Financial Statements and Supplementary Data Required by Item 8
(A) Schedule Description Page
-------- ----------- ----
Report of Independent Accountants on
Financial Statement Schedule 34
II Valuation and Qualifying Accounts 35
All other schedules are omitted because they are not required, are inapplicable,
or the information is otherwise shown in the financial statements or notes
thereto.
3. Exhibits Required by Item 601 of Securities and Exchange Commission
Regulation S-K
(A) The following such exhibits are filed as a separate section of this
report.
Exhibits
(3) Certificate of Incorporation and By-Laws
(i) The Amended and Restated Certificate of Incorporation of Connecticut
Energy Corporation is incorporated by reference to Item 6 of the Company's Form
10-Q filed for the quarter ended June 30, 1999. The Amended and Restated By-Laws
of Connecticut Energy Corporation are incorporated by reference to Item 6
of the Company's Form 10-Q filed for the quarter ended December 31, 1998.
(ii) The Amended and Restated Certificate of Incorporation of The
Southern Connecticut Gas Company is incorporated by reference to Item 6
of Form 10-Q filed for the quarter ended June 30, 1990 at pages 40 through 51.
The Amended and Restated By-Laws of The Southern Connecticut Gas Company are
incorporated by reference to Item 6 of the Company's Form 10-Q filed for
the quarter ended December 31, 1998.
(4) Instruments Defining Rights of Security Holders, Including
Indentures
(i) Indenture between The Bridgeport Gas Light Company and The
Bridgeport City Trust Company, as Trustee, dated as of March 1, 1948.
Incorporated by reference to Exhibit 4(b)(1) to Connecticut Energy Corporation
Registration Statement 2-10566.
(ii) In addition to the Indenture referred to in 4(i) hereof, there
have been twenty-seven indentures supplemental thereto, copies of all of
which the Company agrees to furnish to the Commission upon request.
(iii) Shareholder Rights Plan, dated July 28, 1998, incorporated by
reference to Form 8-K dated July 28, 1998.
(10) Material Contracts
(i) Gas Sales Agreement No. 1 by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference to Exhibit 10.33 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(ii) Gas Sales Agreement No. 2 by and between Alberta Northeast Gas
Limited and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference to Exhibit 10.34 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(iii) Gas Sales Agreement by and between Alberta Northeast Gas Limited
and The Southern Connecticut Gas Company, dated February 7, 1991, incorporated
by reference to Exhibit 10.35 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(iv) Gas Sales Agreement by and between Alberta Northeast Gas Limited and
The Southern Connecticut Gas Company, dated February 7, 1991, incorporated by
reference to Exhibit 10.36 to Connecticut Energy Corporation's Registration
Statement No. 33-40232.
(v) Gas Sales Agreement by and between Alberta Northeast Gas Limited
and The Southern Connecticut Gas Company, dated February 7, 1991, incorporated
by reference to Exhibit 10.37 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(vi) Storage Service Transportation Contract between Tennessee Gas
Pipeline Company and The Southern Connecticut Gas Company, Contract No.
542, dated September 1, 1993, incorporated by reference to Form 10-K for
the fiscal year ended September 30, 1996 at pages 33 to 42.
(vii) Storage Service Agreement (GSS-TE) between CNG Transmission
Corporation and The Southern Connecticut Gas Company, dated October 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1996 at pages 43 to 50.
(viii) Storage Service Agreement (GSS-II) between CNG Transmission
Corporation and The Southern Connecticut Gas Company, dated September 1, 1993,
incorporated by reference to Form 10-K for the fiscal year ended September 30,
1996 at pages 51 to 56.
(ix) Gas Storage Contract and Amendment No. 1, thereto, between Tennessee
Gas Pipeline Company and The Southern Connecticut Gas Company, dated December 1,
1994 and July 1, 1995, respectively, incorporated by reference to Form 10-K for
the fiscal year ended September 30, 1996 at pages 57 to 63.
(x) Interruptible Gas Transportation Contract and Amendment No. 1,
thereto, among Tenngasco Corporation, The Southern Connecticut Gas Company and
The United Illuminating Company, dated May 14, 1987 and August 1, 1989,
respectively, incorporated by reference to Form 10-K for the fiscal year ended
December 31, 1989 at pages 238 to 258.
(xi) Amendment No. 2 to Interruptible Gas Transportation Contract and
Amendment No. 1, thereto, among Tenngasco Corporation, The Southern Connecticut
Gas Company and The United Illuminating Company, dated November 1, 1990,
incorporated by reference to Form 10-K for the transition period from January 1,
1990 to September 30, 1990 at pages 90 to 91.
(xii) Gas Transportation Contract between Iroquois Gas Transmission
System, L.P. and The Southern Connecticut Gas Company, dated February 7, 1991,
incorporated by reference to Exhibit 10.32 to Connecticut Energy Corporation's
Registration Statement No. 33-40232.
(xiii) Gas Transportation Agreement between Tennessee Gas Pipeline Company
and The Southern Connecticut Gas Company, dated August 19, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 143
to 151.
(xiv) Gas Transportation Agreement between Tennessee Gas Pipeline Company
and The Southern Connecticut Gas Company, dated August 19, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 152
to 159.
(xv) Gas Transportation Contract between Tennessee Gas Pipeline Company
and The Southern Connecticut Gas Company, Contract No. 10783, dated June 1,
1995, incorporated by reference to Form 10-K for the fiscal year ended
September 30, 1996 at pages 24 to 32.
(xvi) Service Agreement between Texas Eastern Transmission Corporation
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated
by reference to Form 10-K for the fiscal year ended September 30, 1993 at pages
160 to 170.
(xvii) Service Agreement between Texas Eastern Transmission Corporation and
The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 171
to 180.
(xviii) Service Agreement between Texas Eastern Transmission Corporation
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 181
to 192.
(xix) Service Agreement between Texas Eastern Transmission Corporation
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated
by reference to Form 10-K for the fiscal year ended September 30, 1993 at pages
193 to 204.
(xx) Service Agreement between Texas Eastern Transmission Corporation
and The Southern Connecticut Gas Company, dated June 1, 1993, incorporated
by reference to Form 10-K for the fiscal year ended September 30, 1993 at pages
214 to 220.
(xxi) Service Agreement between Algonquin Gas Transmission Company and
The Southern Connecticut Gas Company, dated June 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 228
to 235.
(xxii) Service Agreement between Algonquin Gas Transmission Company and The
Southern Connecticut Gas Company, dated October 1, 1993, incorporated by
reference to Form 10-K for the fiscal year ended September 30, 1993 at pages 258
to 277.
(xxiii) Service Agreement (Rate Schedule AFT-E) between Algonquin Gas
Transmission Company and The Southern Connecticut Gas Company, dated October 31,
1997, is filed herewith.
(xxiv) Service Agreement (Rate Schedule AFT-1) between Algonquin Gas
Transmission Company and The Southern Connecticut Gas Company, dated October 31,
1997, is filed herewith.
(xxv) Service Agreement (Rate Schedule AFT-1) between Algonquin Gas
Transmission Company and The Southern Connecticut Gas Company, dated December
17, 1998, is filed herewith.
(xxvi) Service Agreement (Rate Schedule FT-1) between Texas Eastern
Transmission Corporation and The Southern Connecticut Gas Company, dated
December 17, 1998, is filed herewith.
(xxvii) On July 15, 1999, Connecticut Energy Corporation, Energy East
Corporation and Merger Co. executed the First Amendment to the Agreement and
Plan of Merger by and among Connecticut Energy Corporation, Energy East
Corporation and Merger Co. The text of this amendment is included in the
Agreement and Plan of Merger by and among Connecticut Energy Corporation, Energy
East Corporation and Merger Co., which is incorporated by reference to Appendix
A to the proxy statement/prospectus filed as part of Energy East Corporation's
Registration Statement No. 333-83437.
Executive Compensation Plans and Arrangements
(xxviii) Agreement between The Southern Connecticut Gas Company and Henry
Chauncey, Jr. related to deferred compensation as a director, dated December 31,
1988, incorporated by reference to Form 10-K for the fiscal year ended December
31, 1988 at pages 63 to 67.
(xxix) Employment Agreement between The Southern Connecticut Gas Company
and J. R. Crespo, dated March 24, 1992, incorporated by reference to Form 10-K
for the fiscal year ended September 30, 1992 at pages 213 to 229.
(xxx) The Southern Connecticut Gas Company, Management Compensation Plan,
dated October 1, 1992, incorporated by reference to Form 10-K for the fiscal
year ended September 30, 1992 at pages 251 to 253.
(xxxi) Supplemental Retirement Benefits Plan, dated October 1, 1993,
incorporated by reference to Form 10-Q for the quarter ended December 31, 1993
at pages 25 to 28.
(xxxii) Amended and Restated Deferred Compensation Agreement between The
Southern Connecticut Gas Company and Connecticut Energy Corporation and J. R.
Crespo, dated November 8, 1996, incorporated by reference to Form 10-K for the
fiscal year ended September 30, 1996 at pages 64 to 73.
(xxxiii) Agreement between The Southern Connecticut Gas Company and
Connecticut Energy Corporation and Carol A. Forest related to change in control,
dated October 1, 1996, incorporated by reference to Form 10-K for the fiscal
year ended September 30, 1996 at pages 74 to 83.
(xxxiv) Agreement between The Southern Connecticut Gas Company and
Connecticut Energy Corporation and Thomas A. Trotta related to change in
control, dated October 1, 1996, incorporated by reference to Form 10-K for the
fiscal year ended September 30, 1996 at pages 94 to 104.
(xxxv) Connecticut Energy Corporation 1997 Restricted Stock Award Plan,
dated January 28, 1997, incorporated by reference to Form 10-Q for the quarter
ended March 31, 1997 at pages 23 to 35.
(xxxvi) Connecticut Energy Corporation Non-Employee Director Stock Plan,
dated January 28, 1997, incorporated by reference to Form 10-Q for the quarter
ended March 31, 1997 at pages 36 to 40.
(xxxvii) The Southern Connecticut Gas Company Board of Directors Retirement
Plan, dated October 1, 1997, incorporated by reference to Form 10-Q for the
quarter ended December 31, 1997 at pages 20 to 23.
(xxxviii) Agreement between The Southern Connecticut Gas Company and
Connecticut Energy Corporation and Samuel W. Bowlby related to change in
control, dated July 1, 1997, incorporated by reference to Form 10-Q for the
quarter ended March 31, 1998 at pages 21 to 31.
(xxxix) Agreement between The Southern Connecticut Gas Company and
Connecticut Energy Corporation and David Silverstone related to change in
control, dated April 1, 1998, incorporated by reference to Form 10-Q for the
quarter ended June 30, 1998 at pages 21 to 30.
(xxxx) Employment Agreement by and among Energy East Corporation,
Connecticut Energy Corporation, or its successor, and J. R. Crespo, dated April
23, 1999, incorporated by reference to Exhibit 10.1 to Energy East Corporation's
Registration Statement No. 333-83437.
(xxxxi) First Amendment to Employment Agreement by and among Energy East
Corporation, Connecticut Energy Corporation, or its successor, and J. R. Crespo,
dated July 15, 1999, incorporated by reference to Exhibit 10.2 to Energy East
Corporation's Registration Statement No. 333-83437.
(13) Annual Report to Security Holders
The Company's 1999 Annual Report to Shareholders is filed herewith. Such exhibit
includes only those portions thereof which are expressly incorporated by
reference in this Form 10-K.
(21) Subsidiaries of the Registrant
A list of the Company's subsidiaries is filed herewith.
(27) Financial Data Schedule
Financial Data Schedule UT is submitted only in electronic format to the
Securities and Exchange Commission.
(B) Reports on Form 8-K filed during the last quarter of 1999:
None.
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Shareholders
of Connecticut Energy Corporation:
Our audits of the consolidated financial statements referred to in our report
dated October 29, 1999 appearing on page 37 of the 1999 Annual Report to
Shareholders of Connecticut Energy Corporation (which report and consolidated
financial statements are incorporated by reference in this Annual Report on Form
10-K) also included an audit of the financial statement schedule listed in Item
14(a)(2) of this Form 10-K. In our opinion, the financial statement schedule
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
Hartford, Connecticut
October 29, 1999
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Prospectus constituting part
of the Registration Statements on Form S-3 (No. 333-25691) and Form S-8 (Nos.
33-39245, 33-51763 and 333-85587) of Connecticut Energy Corporation of our
report dated October 29, 1999, on our audits of the consolidated financial
statements and financial statement schedule of Connecticut Energy Corporation
as of September 30, 1999 and 1998, and for the years ended September 30, 1999,
1998 and 1997, appearing on page 37 of the 1999 Annual Report to Shareholders
of Connecticut Energy Corporation which is incorporated by reference in this
Annual Report on Form 10-K.
/s/ PricewaterhouseCoopers LLP
Hartford, Connecticut
December 1, 1999
<TABLE>
<CAPTION>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
CONNECTICUT ENERGY CORPORATION
Years Ended September 30, 1999, 1998 and 1997
(in thousands)
<S> <C> <C> <C> <C> <C>
Col. A Col. B Col. C Col. D Col. E
Additions
Balance at Charged to Charged to Balance
Beginning Costs and Other at End of
Description of Period Expenses Accounts Deductions Period
- ----------- --------- -------- -------- ---------- ------
Allowance for
Doubtful Accounts (1)
1999 $2,065 $6,020 $1,898 (2) $ 7,645 $2,338
1998 2,948 7,735 1,946 (2) 10,564 (3) 2,065
1997 2,742 7,297 2,851 (2) 9,942 2,948
</TABLE>
(1) Reserve deducted in the Consolidated Balance Sheet from the asset to
which it applies
(2) Recoveries on accounts previously charged off
(3) Accounts charged off as uncollectible
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CONNECTICUT ENERGY CORPORATION
(Registrant)
By: /s/ J. R. Crespo
J. R. Crespo, Chairman,
President and Chief Executive Officer
Dated: November 23, 1999
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
By: /s/ Henry Chauncey, Jr. By: /s/ Newman M. Marsilius
Henry Chauncey, Jr., Director Newman M. Marsilius, Director
Dated: November 23, 1999 Dated: November 23, 1999
By: /s/ James P. Comer By: /s/ Samuel M. Sugden
James P. Comer, M.D., Director Samuel M. Sugden, Director
Dated: November 23, 1999 Dated: November 23, 1999
By: /s/ J. R. Crespo By: /s/ Christopher D. Turner
J. R. Crespo, Chairman, Christopher D. Turner, Director
President and Chief Executive Officer Dated: November 23, 1999
Dated: November 23, 1999
By: /s/ Richard F. Freeman By: /s/ Vincent L. Ammann, Jr.
Richard F. Freeman, Director Vincent L. Ammann, Jr.
Dated: November 23, 1999 Vice President and Chief
Accounting Officer (Principal
Accounting Officer)
Dated: November 23, 1999
By: /s/ Richard M. Hoyt By: /s/ Carol A. Forest
Richard M. Hoyt, Director Carol A. Forest
Dated: November 23, 1999 Vice President, Finance, Chief
Financial Officer, Treasurer
and Assistant Secretary
(Principal Financial Officer)
Dated: November 23, 1999
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:
<TABLE>
<CAPTION>
(in thousands, except per share)
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income $16,688 $19,011 $16,441
- -------------------------------------------------------------------------------------------------------------------
Net income, excluding merger-related expenses $20,222 $19,011 $16,441
- -------------------------------------------------------------------------------------------------------------------
Net income per share - diluted $ 1.61 $ 1.88 $ 1.81
- -------------------------------------------------------------------------------------------------------------------
Net income per share, excluding merger-related expenses - diluted $ 1.95 $ 1.88 $ 1.81
- -------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 10,361 10,104 9,096
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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
9
- --------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------
Gross margin earned $6,330 $9,867 $12,872
- ------------------------------------------------------------------------------
Gross margin retained $4,230 $5,981 $ 7,242
- ------------------------------------------------------------------------------
Volumes sold and transported (MMcf) 9,563 13,690 23,794
- ------------------------------------------------------------------------------
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
10
- --------------------------------------------------------------------------------
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.
11
- --------------------------------------------------------------------------------
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
15
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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:
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Connecticut Energy Corporation
<TABLE>
<CAPTION>
Shared
Connecticut
As of September 30, 1999 Southern Energy/Southern Total
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Committed lines $50,000,000 $20,000,000 $70,000,000
Uncommitted lines -- 5,000,000 5,000,000
</TABLE>
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.
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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)
<TABLE>
<CAPTION>
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
Consolidated Statements of Comprehensive Income
(dollars in thousands)
<TABLE>
<CAPTION>
Years ended September 30, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
20
- -------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Balance Sheets
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
21
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Statements of Changes
in Common Shareholders' Equity
(dollars in thousands, except per share)
<TABLE>
<CAPTION>
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
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
22
- -------------------------------------------------------------------------------
Connecticut Energy Corporation
Consolidated Statements of Cash Flows
(dollars in thousands)
<TABLE>
<CAPTION>
Years ended September 30, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
</TABLE>
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
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
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
- --------------------------------------------------------------------------------
Connecticut Energy Corporation
Notes to Consolidated Financial Statements
(dollars in thousands, except per share)
DEFERRED CREDITS
Deferred credits include amounts related to the following:
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Years ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
27
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
Years ended September 30, 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
Deferred income tax liabilities (assets) are composed of the following:
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
28
- -------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
As of September 30, 1999 1998
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Outstanding $21,800 $22,400
Weighted average interest rate 5.84% 5.73%
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
As of September 30, 1999, Connecticut Energy and Southern have credit lines
with a number of banks as detailed below:
<TABLE>
<CAPTION>
Shared
Connecticut
Energy/
Southern Southern Total
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Committed lines $50,000 $20,000 $70,000
Uncommitted lines -- 5,000 5,000
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
Pension Other Benefits
- ------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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)
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
31
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
Pension Other Benefits
----------------------------------- ---------------------------------
1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
Key assumptions used in the determination of the projected benefit
obligations and the fair value of plan assets were:
<TABLE>
<CAPTION>
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
1% Increase 1% Decrease
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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)
- -------------------------------------------------------------------------------------------------------------
</TABLE>
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.
32
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
Years ending September 30, 2000 2001 2002 2003 2004 Thereafter
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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 -- -- --
- ----------------------------------------------------------------------------------------------------------------------------
Total commitment $2,822 $2,817 $2,807 $2,827 $2,871 $30,697
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
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)
<TABLE>
<CAPTION>
Dec. 31, March 31, June 30, Sept. 30,
1999 Quarters ended 1998 1999 1999 1999
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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)
- -----------------------------------------------------------------------------------------------------------------------------
<CAPTION>
Dec. 31, March 31, June 30, Sept. 30,
1998 Quarters ended 1997 1998 1998 1998
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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)
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
*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
- -----------------------------------------------------------------------------
33
- --------------------------------------------------------------------------------
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:
<TABLE>
<CAPTION>
Reportable Segments Consolidated
Utility Nonutility Other* Total
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
*The Other category includes the assets and unallocated administrative expenses
of the Company and intersegment eliminations.
34
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
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
93012EC
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
This Agreement ("Agreement") is made and entered into this 31st day of
October, 1997, by and between Algonquin Gas Transmission Company, a
Delaware Corporation (herein called "Algonquin"), and The Southern
Connecticut Gas Company (herein called "Customer" whether one or more
persons).
WHEREAS, pursuant to a settlement agreement approved on July 8, 1994,
by the Federal Energy Regulatory Commission in Docket Nos. RP93-14-000,
et al., Algonquin and Customer entered into two Service Agreements
(93012E and 9W010E) dated September 1, 1994, for service under Rate
Schedule AFT-E; and
WHEREAS, to enhance both parties' ability to administer, among other
things, nominations and capacity releases, Algonquin and Customer
desire to combine the two aforementioned Service Agreements into a
single service agreement for service under Rate Schedule AFT-E
WHEREAS, Algonquin and Customer desire to execute a superseding
combined service agreement under Rate Schedule AFT-E;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations hereof and of
Algonquin's Rate Schedule AFT-E, Algonquin agrees to receive
from or for the account of Customer for transportation on a
firm basis quantities of natural gas tendered by Customer on
any day at the Point(s) of Receipt; provided, however,
Customer shall not tender without the prior consent of
Algonquin, at any Point of Receipt on any day a quantity of
natural gas in excess of the applicable Maximum Daily Receipt
Obligation for such Point of Receipt plus the applicable Fuel
Reimbursement Quantity; and provided further that Customer
shall not tender at all Point(s) of Receipt on any day or in
any year a cumulative quantity of natural gas, without
the prior consent of Algonquin, in excess of the following
quantities of natural gas plus the applicable Fuel Reimbursement
Quantities:
Maximum Daily Transportation Quantity (MMBtu)
Nov 16 - Apr 15 45,593*
Apr 16 - May 31 39,196
Jun 1 - Sep 30 26,403
Oct 1 - Nov 15 39,196
*MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 13,711,741 MMBtu
1.2 Algonquin agrees to transport and deliver to or for the
account of Customer at the Point(s) of Delivery and Customer
agrees to accept or cause acceptance of delivery of the
quantity received by Algonquin on any day, less the Fuel
Reimbursement Quantities; provided, however, Algonquin shall
not be obligated to deliver at any Point of Delivery on any
day a quantity of natural gas in excess of the applicable
Maximum Daily Delivery Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective as of the date set forth
hereinabove and shall continue in effect for a term ending on
and including October 31, 2012 ("Primary Term") and shall
remain in force from year to year thereafter unless terminated
by either party by written notice one year or more prior to
the end of the Primary Term or any successive term thereafter.
Algonquin's right to cancel this Agreement upon the expiration
of the Primary Term hereof or any succeeding term shall be
subject to Customer's rights pursuant to Sections 8 and 9 of
the General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in
the event Customer fails to pay part or all of the amount of
any bill for service hereunder and such failure continues for
thirty days after payment is due; provided Algonquin gives ten
days prior written notice to Customer of such termination and
provided further such termination shall not be effective if,
prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety
bond guaranteeing payment to Algonquin of such outstanding
bill; provided that Algonquin shall not be entitled to
terminate service pending the resolution of a disputed bill if
Customer complies with the billing dispute procedure currently
on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered
hereunder and for the availability of such service under
Algonquin's Rate Schedule AFT-E as filed with the Federal
Energy Regulatory Commission and as the same may be hereafter
revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum
rate under Rate Schedule AFT-E, nor less than the minimum rate
under Rate Schedule AFT-E.
3.2 This Agreement and all terms and provisions contained or
incorporated herein are subject to the provisions of
Algonquin's applicable rate schedules and of Algonquin's
General Terms and Conditions on file with the Federal Energy
Regulatory Commission, or other duly constituted authorities
having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and
Conditions are by this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right
to file with the appropriate regulatory authority and make
changes effective in (a) the rates and charges applicable to
service pursuant to Algonquin's Rate Schedule AFT-E, (b)
Algonquin's Rate Schedule AFT-E, pursuant to which service
hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-E.
Algonquin agrees that Customer may protest or contest the
aforementioned filings, or may seek authorization from duly
constituted regulatory authorities for such adjustment of
Algonquin's existing FERC Gas Tariff as may be found necessary
to assure that the provisions in (a), (b), or (c) above are
just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer
hereunder shall be received at the outlet side of the measuring
station(s) at or near the Primary Point(s) of Receipt set forth in
Exhibit A of the service agreement, with the Maximum Daily Receipt
Obligation and the receipt pressure obligation indicated for each such
Primary Point of Receipt. Natural gas to be received by Algonquin for
the account of Customer hereunder may also be received at the outlet
side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-E.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer
hereunder shall be delivered on the outlet side of the measuring
station(s) at or near the Primary Point(s) of Delivery set forth in
Exhibit B of the service agreement, with the Maximum Daily Delivery
Obligation and the delivery pressure obligation indicated for each such
Primary Point of Delivery.
Natural gas to be delivered by Algonquin for the account of Customer
hereunder may also be delivered at the outlet side of any other
measuring station on the Algonquin system, subject to reduction
pursuant to Section 6.4 of Rate Schedule AFT-E.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms
and Conditions of Algonquin's FERC Gas Tariff, any notice, request,
demand, statement, bill or payment provided for in this Agreement, or
any notice which any party may desire to give to the other, shall be in
writing and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post office address
of the parties hereto, as the case may be, as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
Attn: Danielle Kappus
Contract Administration
(b) Customer: The Southern Connecticut Gas Company
855 Main Street
Bridgeport, CT 06604
Attn: Salvatore A. Ardigliano
Vice President, Gas Supply & Marketing Services
or such other address as either party shall designate by formal written
notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in
accordance with the laws of the Commonwealth of Massachusetts,
excluding conflicts of law principles that would require the
application of the laws of a different jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto.
Service Agreements 93012E and 9W010E executed by Customer and Algonquin
under Rate Schedule AFT-E dated September 1, 1994.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective agents thereunto duly authorized, the day
and year first above written.
ALGONQUIN GAS TRANSMISSION COMPANY
By: /s/ Robert B. Evans
Title: Senior Vice President
THE SOUTHERN CONNECTICUT GAS COMPANY
By: /s/ Sal A. Ardigliano
Title: Vice President, Gas Supply &
Marketing Services
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit A
Point(s) of Receipt
Dated: October 31, 1997
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
The Southern Connecticut Gas Company (Customer) concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Hanover, NJ (TETCO) At any pressure requested
Nov 16 - Apr 15 21,122 by Algonquin but not in
Apr 16 - May 31 17,437 excess of 750 Psig.
Jun 1 - Sep 30 10,068
Oct 1 - Nov 15 17,437
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 24,471 by Algonquin but not in
Apr 16 - May 31 21,759 excess of 750 Psig.
Jun 1 - Sep 30 16,335
Oct 1 - Nov 15 21,759
Signed for Identification
Algonquin: /s/ Robert B. Evans
Customer: /s/ Sal A. Ardigliano
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit B
Point(s) of Delivery
Dated: October 31, 1997
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
The Southern Connecticut Gas Company (Customer) concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
On the outlet side
of meter stations
located at:
North Haven, CT 199
Nov 16 - Apr 15 29,037
Apr 16 - May 31 24,606
Jun 1 - Sep 30 15,745
Oct 1 - Nov 15 24,606
Defco Industrial Park
North Haven, CT 50
Nov 16 - Apr 15 1,696
Apr 16 - May 31 1,630
Jun 1 - Sep 30 1,497
Oct 1 - Nov 15 1,630
Signed for Identification
Algonquin: /s/ Robert B. Evans
Customer: /s/ Sal A. Ardigliano
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 31, 1997
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
The Southern Connecticut Gas Company (Customer) concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
Milford, New Haven
County, CT 100
Nov 16 - Apr 15 7,474 (Not to
Apr 16 - May 31 7,181 exceed 312
Jun 1 - Sep 30 6,595 MMBtu per
Oct 1 - Nov 15 7,181 hour)
Guilford, CT 100
Nov 16 - Apr 15 11,551
Apr 16 - May 31 9,781
Jun 1 - Sep 30 6,241
Oct 1 - Nov 15 9,781
Signed for Identification
Algonquin: /s/ Robert B. Evans
Customer: /s/ Sal A. Ardigliano
93208C
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 31st day of
October, 1997, by and between Algonquin Gas Transmission Company, a
Delaware Corporation (herein called "Algonquin"), and The Southern
Connecticut Gas Company (herein called "Customer" whether one or more
persons).
In consideration of the premises and of the mutual covenants herein
contained, the parties do agree as follows:
WHEREAS, Algonquin and Customer entered into two Service Agreements
(93208 and 93308) dated June 1, 1993, for service under Rate Schedule
AFT-1; and WHEREAS, to enhance both parties' ease in administering
nominations and capacity releases, among other things, Algonquin and
Customer desire to combine the two aforementioned service agreements into a
single service agreement;
WHEREAS, Algonquin and Customer desire to combine the two
aforementioned service agreements into a single Service Agreement.
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations hereof and of
Algonquin's Rate Schedule AFT-1, Algonquin agrees to receive
from or for the account of Customer for transportation on a
firm basis quantities of natural gas tendered by Customer on
any day at the Point(s) of Receipt; provided, however,
Customer shall not tender without the prior consent of
Algonquin, at any Point of Receipt on any day a quantity of
natural gas in excess of the applicable Maximum Daily Receipt
Obligation for such Point of Receipt plus the applicable Fuel
Reimbursement Quantity; and provided further that Customer
shall not tender at all Point(s) of Receipt on any day or in
any year a cumulative quantity of natural gas, without the
prior consent of Algonquin, in excess of the following
quantities of natural gas plus the applicable Fuel
Reimbursement Quantities:
Maximum Daily Transportation Quantity 6,379 MMBtu
Maximum Annual Transportation Quantity 2,328,335 MMBtu
1.2 Algonquin agrees to transport and deliver to or for the account of
Customer at the Point(s) of Delivery and Customer agrees to accept
or cause acceptance of delivery of the quantity received by
Algonquin on any day, less the Fuel Reimbursement Quantities;
provided, however, Algonquin shall not be obligated to deliver at
any Point of Delivery on any day a quantity of natural gas in
excess of the applicable Maximum Daily Delivery Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective as of the date set forth
hereinabove and shall continue in effect for a term ending on
and including October 31, 2012 ("Primary Term") and shall
remain in force from year to year thereafter unless terminated
by either party by written notice one year or more prior to
the end of the Primary Term or any successive term thereafter.
Algonquin's right to cancel this Agreement upon the expiration
of the Primary Term hereof or any succeeding term shall be
subject to Customer's rights pursuant to Sections 8 and 9 of
the General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in
the event Customer fails to pay part or all of the amount of
any bill for service hereunder and such failure continues for
thirty days after payment is due; provided Algonquin gives ten
days prior written notice to Customer of such termination and
provided further such termination shall not be effective if,
prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety
bond guaranteeing payment to Algonquin of such outstanding
bill; provided that Algonquin shall not be entitled to
terminate service pending the resolution of a disputed bill if
Customer complies with the billing dispute procedure currently
on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered
hereunder and for the availability of such service under
Algonquin's Rate Schedule AFT-1 as filed with the Federal
Energy Regulatory Commission and as the same may be hereafter
revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum
rate under Rate Schedule AFT-1, nor less than the minimum rate
under Rate Schedule AFT-1.
3.2 This Agreement and all terms and provisions contained or
incorporated herein are subject to the provisions of
Algonquin's applicable rate schedules and of Algonquin's
General Terms and Conditions on file with the Federal Energy
Regulatory Commission, or other duly constituted authorities
having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and
Conditions are by this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right
to file with the appropriate regulatory authority and make
changes effective in (a) the rates and charges applicable to
service pursuant to Algonquin's Rate Schedule AFT-1, (b)
Algonquin's Rate Schedule AFT-1, pursuant to which service
hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-1.
Algonquin agrees that Customer may protest or contest the
aforementioned filings, or may seek authorization from duly
constituted regulatory authorities for such adjustment of
Algonquin's existing FERC Gas Tariff as may be found necessary
to assure that the provisions in (a), (b), or (c) above are
just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer
hereunder shall be received at the outlet side of the measuring
station(s) at or near the Primary Point(s) of Receipt set forth in
Exhibit A of the service agreement, with the Maximum Daily Receipt
Obligation and the receipt pressure obligation indicated for each such
Primary Point of Receipt. Natural gas to be received by Algonquin for
the account of Customer hereunder may also be received at the outlet
side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer
hereunder shall be delivered on the outlet side of the measuring
station(s) at or near the Primary Point(s) of Delivery set forth in
Exhibit B of the service agreement, with the Maximum Daily Delivery
Obligation and the delivery pressure obligation indicated for each such
Primary Point of Delivery. Natural gas to be delivered by Algonquin for
the account of Customer hereunder may also be delivered at the outlet
side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms
and Conditions of Algonquin's FERC Gas Tariff, any notice, request,
demand, statement, bill or payment provided for in this Agreement, or
any notice which any party may desire to give to the other, shall be in
writing and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post office address
of the parties hereto, as the case may be, as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
Attn: Danielle Kappus
Contract Administration
(b) Customer: The Southern Connecticut Gas Company
855 Main Street
Bridgeport, CT 06604
Attn: Salvatore A. Ardigliano
Vice President, Gas Supply & Marketing Services
or such other address as either party shall designate by formal written
notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in
accordance with the laws of the Commonwealth of Massachusetts,
excluding conflicts of law principles that would require the
application of the laws of a different jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto, except that in the case of
conversions from former Rate Schedules F-2 and F-3, the parties'
obligations under Article II of the service agreements pertaining to
such rate schedules shall continue in effect.
Service Agreements Nos. 93208 and 93308 executed by Customer and
Algonquin under Rate Schedule AFT-1 both dated June 1, 1993.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective agents thereunto duly authorized, the day
and year first above written.
ALGONQUIN GAS TRANSMISSION COMPANY
By: /s/ Robert B. Evans
Title: Senior Vice President
THE SOUTHERN CONNECTICUT GAS COMPANY
By: /s/ Sal A. Ardigliano
Title: Vice President, Gas Supply &
Marketing Services
Exhibit A
Point(s) of Receipt
Dated: October 31, 1997
To the service agreement under Rate Schedule AFT-1
between Algonquin Gas Transmission Company (Algonquin)
and The Southern Connecticut Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Centerville, NJ 1,457 At any pressure
requested by
Algonquin not in
excess of 750 Psig.
Lambertville, NJ 4,922 At any pressure
requested by
Algonquin not in
excess of 750 Psig.
Signed for Identification
Algonquin: /s/ Robert B. Evans
Customer: /s/ Sal A. Ardigliano
Exhibit B
Point(s) of Delivery
Dated: October 31, 1997
To the service agreement under Rate Schedule AFT-1
between Algonquin Gas Transmission Company (Algonquin)
and The Southern Connecticut Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
On the outlet side
of meter station
located at:
North Haven, CT 6,379 199
Defco Industrial Park
North Haven, CT 0 -
Milford, CT 0 -
Guilford, CT 0 -
Signed for Identification
Algonquin: /s/ Robert B. Evans
Customer: /s/ Sal A. Ardigliano
Contract No. 934005R
SERVICE AGREEMENT
(APLLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 17th day of
December, 1998, by and between Algonquin Gas Transmission Company, a
Delaware Corporation (herein called "Algonquin"), and The Southern
Connecticut Gas Company (herein called "Customer" whether one or more
persons).
WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated January 25, 1994, under Pipeline's Rate Schedule AFT-1
(Pipeline's Contract No. 934005); and
WHEREAS, Pipeline and Customer desire to enter into this Service
Agreementto supersede Pipeline's currently effective Contract No.
934005;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations hereof and of
Algonquin's Rate Schedule AFT-1, Algonquin agrees to receive
from or for the account of Customer for transportation on a
firm basis quantities of natural gas tendered by Customer on
any day at the Point(s) of Receipt; provided, however,
Customer shall not tender without the prior consent of
Algonquin, at any Point of Receipt on any day a quantity of
natural gas in excess of the applicable Maximum Daily Receipt
Obligation for such Point of Receipt plus the applicable Fuel
Reimbursement Quantity; and provided further that Customer
shall not tender at all Point(s) of Receipt on any day or in
any year a cumulative quantity of natural gas, without the
prior consent of Algonquin, in excess of the following
quantities of natural gas plus the applicable Fuel
Reimbursement Quantities:
Maximum Daily Transportation Quantity (MDTQ) 16,853 MMBtu
Maximum Annual Transportation Quantity (MATQ) 6,151,345 MMBtu;
provided, however, subject to the provision of one
(1) year prior written notice, either Pipeline or
Customer shall have the option to reduce the MDTQ of
this Service Agreement by up to 8,427 MMBtu with such
reduction to be effective on November 1, 2004 or any
November 1 thereafter.
1.2 Algonquin agrees to transport and deliver to or for the
account of Customer at the Point(s) of Delivery and Customer
agrees to accept or cause acceptance of delivery of the
quantity received by Algonquin on any day, less the Fuel
Reimbursement Quantities; provided, however, Algonquin shall
not be obligated to deliver at any Point of Delivery on any
day a quantity of natural gas in excess of the applicable
Maximum Daily Delivery Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective as of the first day of
the first month after Customer fully executes this Agreement
and shall continue in effect for a term ending on and
including October 31, 2005 ("Primary Term") and shall remain
in force from year to year thereafter unless terminated by
either party by written notice one year or more prior to the
end of the Primary Term or any successive term thereafter.
Algonquin's right to cancel this Agreement upon the expiration
of the Primary Term hereof or any succeeding term shall be
subject to Customer's rights pursuant to Sections 8 and 9 of
the General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in
the event Customer fails to pay part or all of the amount of
any bill for service hereunder and such failure continues for
thirty days after payment is due; provided Algonquin gives ten
days prior written notice to Customer of such termination and
provided further such termination shall not be effective if,
prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety
bond guaranteeing payment to Algonquin of such outstanding
bill; provided that Algonquin shall not be entitled to
terminate service pending the resolution of a disputed bill if
Customer complies with the billing dispute procedure currently
on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered
hereunder and for the availability of such service under
Algonquin's Rate Schedule AFT-1 as filed with the Federal
Energy Regulatory Commission and as the same may be hereafter
revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum
rate specified under Rate Schedule AFT-1 for service resulting
from the conversion of entitlements under former Rate Schedule
FTP, nor less than the minimum rate under Rate Schedule AFT-1.
3.2 This Agreement and all terms and provisions contained or
incorporated herein are subject to the provisions of
Algonquin's applicable rate schedules and of Algonquin's
General Terms and Conditions on file with the Federal Energy
Regulatory Commission, or other duly constituted authorities
having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and
Conditions are by this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right
to file with the appropriate regulatory authority and make
changes effective in (a) the rates and charges applicable to
service pursuant to Algonquin's Rate Schedule AFT-1, (b)
Algonquin's Rate Schedule AFT-1, pursuant to which service
hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-1.
Algonquin agrees that Customer may protest or contest the
aforementioned filings, or may seek authorization from duly
constituted regulatory authorities for such adjustment of
Algonquin's existing FERC Gas Tariff as may be found necessary
to assure that the provisions in (a), (b), or (c) above are
just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer
hereunder shall be received at the outlet side of the measuring
station(s) at or near the Primary Point(s) of Receipt set forth in
Exhibit A of the service agreement, with the Maximum Daily Receipt
Obligation and the receipt pressure obligation indicated for each such
Primary Point of Receipt. Natural gas to be received by Algonquin for
the account of Customer hereunder may also be received at the outlet
side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer
hereunder shall be delivered on the outlet side of the measuring
station(s) at or near the Primary Point(s) of Delivery set forth in
Exhibit B of the service agreement, with the Maximum Daily Delivery
Obligation and the delivery pressure obligation indicated for each such
Primary Point of Delivery. Natural gas to be delivered by Algonquin for
the account of Customer hereunder may also be delivered at the outlet
side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms
and Conditions of Algonquin's FERC Gas Tariff, any notice, request,
demand, statement, bill or payment provided for in this Agreement, or
any notice which any party may desire to give to the other, shall be in
writing and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post office address
of the parties hereto, as the case may be, as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
Attn: Vice President, Marketing
(b) Customer: The Southern Connecticut Gas Company
855 Main Street
Bridgeport, CT 06604
Attn: Salvatore A. Ardigliano
V.P., Gas Supply & Energy Services
or such other address as either party shall designate by formal written
notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in
accordance with the laws of the Commonwealth of Massachusetts,
excluding conflicts of law principles that would require the
application of the laws of a different jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto.
service agreement dated January 25, 1994, between Pipeline and
Customer under Algonquin's Rate Schedule AFT-1 (Pipeline's Contract
No. 934005).
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective agents thereunto duly authorized, the day
and year first above written.
ALGONQUIN GAS TRANSMISSION COMPANY
By: /s/ Tom O'Connor PMT
RMF
Title: V.P., East Coast Marketing
THE SOUTHERN CONNECTICUT GAS COMPANY
By: /s/ Sal A. Ardigliano
Title: Group Vice President
Exhibit A
Point(s) of Receipt
Dated: December 17, 1998
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
The Southern Connecticut Gas Company (Customer) concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Lambertville, NJ 16,853 At any pressure
requested by
Algonquin but not in
excess of 750 Psig.
Signed for Identification
Algonquin: /s/ Tom O'Connor JMM
Customer: /s/ Sal A. Ardigliano
Exhibit B
Point(s) of Delivery
Dated: December 17, 1998
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
The Southern Connecticut Gas Company (Customer) concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
North Haven, CT 15,813 199
Cheshire, CT 1,040 Algonquin's line
pressure as may
exist from time
to time.
Signed for Identification
Algonquin: /s/ Tom O'Connor JMM
Customer: /s/ Sal A. Ardigliano
Contract #: 800269R
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 17th day of December,
1998, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and THE SOUTHERN CONNECTICUT GAS COMPANY
(herein called "Customer", whether one or more),
W I T N E S S E T H:
WHEREAS, Customer and Pipeline are parties to an executed service agreement
dated June 1, 1993, under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No.
800269); and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
to supersede Pipeline's currently effective Contract No. 800269;
NOW, THEREFORE, in consideration of the premises and of the mutual covenants
and agreements herein contained, the parties do covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of Pipeline's Rate
Schedule FT-1, and of the General Terms and Conditions, transportation service
hereunder will be firm. Subject to the terms, conditions and limitations hereof
and of Pipeline's Rate Schedule FT-1, Pipeline agrees to deliver for Customer's
account quantities of natural gas up to the following quantity:
Maximum Daily Quantity (MDQ) 16,853 dth;
provided, however, subject to the provision of three (3) years
prior written notice, either Pipeline or Customer shall have the
option to reduce the MDQ of this Service Agreement by up to 8,427
dth with such reduction to be effective on November 1, 2004 or any
November 1 thereafter.
Pipeline shall receive for Customer's account, at those points on Pipeline's
system as specified in Article IV herein or available to Customer pursuant to
Section 14 of the General Terms and Conditions (hereinafter referred to as
Point(s) of Receipt) for transportation hereunder daily quantities of gas up to
Customer's MDQ, plus Applicable Shrinkage. Pipeline shall transport and deliver
for Customer's account, at those points on Pipeline's system as specified in
Article IV herein or available to Customer pursuant to Section 14 of the General
Terms and Conditions (hereinafter referred to as Point(s) of Delivery), such
daily quantities tendered up to such Customer's MDQ.
Pipeline shall not be obligated to, but may at its discretion, receive at any
Point of Receipt on any day a quantity of gas in excess of the applicable
Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall
not receive in the aggregate at all Points of Receipt on any day a quantity of
gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any Point of Delivery
on any day a quantity of gas in excess of the applicable Maximum Daily Delivery
Obligation (MDDO), but shall not deliver in the aggregate at all Points of
Delivery on any day a quantity of gas in excess of the applicable MDQ.
In addition to the MDQ and subject to the terms, conditions and limitations
hereof, Rate Schedule FT-1 and the General Terms and Conditions, Pipeline shall
deliver within the Access Area under this and all other service agreements under
Rate Schedules CDS, FT-1, and/or SCT, quantities up to Customer's Operational
Segment Capacity Entitlements, excluding those Operational Segment Capacity
Entitlements scheduled to meet Customer's MDQ, for Customer's account, as
requested on any day.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on the first day of the
first month after Customer fully executes this Service Agreement and shall
continue in force and effect until October 31, 2005 and year to year thereafter
unless this Service Agreement is terminated as hereinafter provided. This
Service Agreement may be terminated by either Pipeline or Customer upon three
(3) years prior written notice to the other specifying a termination date of
October 31, 2005 or any October 31 thereafter. Subject to Section 22 of
Pipeline's General Terms and Conditions and without prejudice to such rights,
this Service Agreement may be terminated at any time by Pipeline in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty (30) days after payment is due;
provided, Pipeline gives thirty (30) days prior written notice to Customer of
such termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such outstanding bill
or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline
of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR THE
PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED ABANDONMENT
UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE
TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND
CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
Any portions of this Service Agreement necessary to correct or cash-out
imbalances under this Service Agreement as required by the General Terms and
Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other
parts of this Service Agreement until such time as such balancing has been
accomplished.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain subject to the
applicable provisions of Rate Schedule FT-1 and of the General Terms and
Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy
Regulatory Commission, all of which are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered hereunder and for the
availability of such service in the period stated, the applicable prices
established under Pipeline's Rate Schedule FT-1 as filed with the Federal Energy
Regulatory Commission, and as same may hereafter be legally amended or
superseded.
Customer agrees that Pipeline shall have the unilateral right to file with
the appropriate regulatory authority and make changes effective in (a) the rates
and charges applicable to service pursuant to Pipeline's Rate Schedule FT-1, (b)
Pipeline's Rate Schedule FT-1 pursuant to which service hereunder is rendered or
(c) any provision of the General Terms and Conditions applicable to Rate
Schedule FT-1. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall
receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B
of the executed service agreement. Customer's Zone Boundary Entry Quantity and
Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in
Exhibit C of the executed service agreement.
Exhibit(s) A, B and C are hereby incorporated as part of this
Service Agreement for all intents and purposes as if fully copied and set forth
herein at length.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account shall conform to
the quality specifications set forth in Section 5 of Pipeline's General Terms
and Conditions. Customer agrees that in the event Customer tenders for service
hereunder and Pipeline agrees to accept natural gas which does not comply with
Pipeline's quality specifications, as expressly provided for in Section 5 of
Pipeline's General Terms and Conditions, Customer shall pay all costs associated
with processing of such gas as necessary to comply with such quality
specifications. Customer shall execute or cause its supplier to execute, if such
supplier has retained processing rights to the gas delivered to Customer, the
appropriate agreements prior to the commencement of service for the
transportation and processing of any liquefiable hydrocarbons and any PVR
quantities associated with the processing of gas received by Pipeline at the
Point(s) of Receipt under such Customer's service agreement. In addition,
subject to the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered for
transportation hereunder.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Service Agreement, or any notice
which any party may desire to give to the other, shall be in writing and shall
be considered as duly delivered when mailed by registered, certified, or regular
mail to the post office address of the parties hereto, as the case may be, as
follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: THE SOUTHERN CONNECTICUT GAS COMPANY
855 MAIN STREET
P. O. BOX 1540 (06601-1540)
BRIDGEPORT, CT 06604-4918
or such other address as either party shall designate by formal written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or consolidation to the
properties, substantially as an entirety, of Customer, or of Pipeline, as the
case may be, shall be entitled to the rights and shall be subject to the
obligations of its predecessor in title under this Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement under the
provisions of any mortgage, deed of trust, indenture, bank credit agreement,
assignment, receivable sale, or similar instrument which it has executed or may
execute hereafter; otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first shall have
obtained the consent thereto in writing of the other; provided further, however,
that neither Customer nor Pipeline shall be released from its obligations
hereunder without the consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms and Conditions.
To the extent Customer so desires, when it releases capacity pursuant to Section
3.14 of the General Terms and Conditions, Customer may require privity between
Customer and the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement shall be in
accordance with the laws of the State of Texas without recourse to the law
governing conflict of laws.
This Service Agreement and the obligations of the parties are subject to all
present and future valid laws with respect to the subject matter, State and
Federal, and to all valid present and future orders, rules, and regulations of
duly constituted authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the effective date of
this Service Agreement, the contract(s) between the parties hereto as described
below:
service agreement dated June 1, 1993, between Pipeline and Customer
under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 800269).
IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to
be signed by their respective Presidents, Vice Presidents or other duly
authorized agents and their respective corporate seals to be hereto affixed and
attested by their respective Secretaries or Assistant Secretaries, the day and
year first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By /s/ Tom O'Connor PMT
RMF
ATTEST:
/s/ Alan N. Harris
THE SOUTHERN CONNECTICUT GAS COMPANY
By /s/ Sal A. Ardigliano
ATTEST:
/s/ Lori Coyne
<TABLE>
<CAPTION>
Contract #800269R
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED December 17th, 1998
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND THE SOUTHERN CONNECTICUT GAS COMPANY ("Customer"), DATED December 17, 1998:
(1) Customer's firm Point(s) of Receipt:
<S> <C> <C> <C> <C> <C>
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) Responsibilities Owner Operator
None
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published by
Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as set
forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s)
of Receipt.
Transportation
Transportation Path Path Quantity (Dth/D)
M1 to M3 16853
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ Tom O'Connor, V.P. Alan N. Harris
JMM
CUSTOMER: /s/ Sal A. Ardiliano
SUPERSEDES EXHIBIT A DATED: _________
<TABLE>
<CAPTION>
Contract #: 800269
EXHIBIT B, POINT(S) OF DELIVERY, DATED December 17, 1998,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
THE SOUTHERN CONNECTICUT GAS COMPANY ("Customer"),
DATED December 17, 1998:
<S> <C> <C> <C> <C> <C> <C> <C>
Maximum Daily Delivery
Point of Delivery Pressure Measurement
Delivery Description Obligation Obligation Responsibilities Owner Operator
(dth)
1. 70087 ALGONQUIN - LAMBERTVILLE, NJ HUNTERDON 16,853 AT ANY PRESSURE TX EAST TRAN TX EAST TRAN ALGONQUIN
CO., NJ REQUESTED BY
ALGONQUIN,
PROVIDED HOWEVER,
THE MAXIMUM
DELIVERY PRESSURE
SHALL NOT EXCEED
750 POUNDS PER
SQUARE INCH GAUGE
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ Tom O'Connor Alan N. Harris
JMM
CUSTOMER: /s/ Sal A. Ardigliano
SUPERSEDES EXHIBIT B DATED: _________
<TABLE>
<CAPTION>
Contract #:800269R1
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED December 17, 1998, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
SOUTHERN CONNECTICUT GAS COMPANY ("CUSTOMER"), DATED December 17, 1998:
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
To
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
STX 478
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
ETX 2031 723
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
WLA 220 478
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
ELA 13196
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-24 2031
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-30 13196
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-TXG 943
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-TGC 956
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-24
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-30
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-TXG
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-TGC
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2 16853
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M3
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
</TABLE>
<TABLE>
<CAPTION>
Contract #:800269R
EXHIBIT C (Continued)
SOUTHERN CONNECTICUT GAS COMPANY
ZONE BOUNDARY EXIT QUANTITY
Dth/D
To
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
STX
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
ETX
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
WLA
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
ELA
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-24 2031
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-30 13196
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-TXG 943
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M1-TGC 956
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-24
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-30
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-TXG
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2-TGC
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M2 16853
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
M3
- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
</TABLE>
SIGNED FOR IDENTIFICATION:
PIPELINE: /s/ Tom O'Connor Alan N. Harris.
JMM
CUSTOMER: /s/ Sal A. Ardigliano
SUPERCEDES EXHIBIT C DATED: _________
EXHIBIT 21
SUBSIDIARIES OF
CONNECTICUT ENERGY CORPORATION
Name State of Incorporation
The Southern Connecticut Gas Company Connecticut
CNE Development Corporation Connecticut
CNE Energy Services Group, Inc. Connecticut
CNE Venture-Tech, Inc. Connecticut
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, BALANCE SHEETS AND STATEMENTS OF CASH FLOWS
OF CONNECTICUT ENERGY CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 277,881
<OTHER-PROPERTY-AND-INVEST> 13,683
<TOTAL-CURRENT-ASSETS> 50,687
<TOTAL-DEFERRED-CHARGES> 132,529
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 474,780
<COMMON> 10,362
<CAPITAL-SURPLUS-PAID-IN> 122,685
<RETAINED-EARNINGS> 50,474
<TOTAL-COMMON-STOCKHOLDERS-EQ> 183,301
0
0
<LONG-TERM-DEBT-NET> 148,062
<SHORT-TERM-NOTES> 21,800
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,585
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 120,032
<TOT-CAPITALIZATION-AND-LIAB> 474,780
<GROSS-OPERATING-REVENUE> 228,296
<INCOME-TAX-EXPENSE> 7,931
<OTHER-OPERATING-EXPENSES> 184,915
<TOTAL-OPERATING-EXPENSES> 192,846
<OPERATING-INCOME-LOSS> 35,450
<OTHER-INCOME-NET> (1,843)
<INCOME-BEFORE-INTEREST-EXPEN> 30,073
<TOTAL-INTEREST-EXPENSE> 13,385
<NET-INCOME> 16,688
0
<EARNINGS-AVAILABLE-FOR-COMM> 16,688
<COMMON-STOCK-DIVIDENDS> 13,899
<TOTAL-INTEREST-ON-BONDS> 12,804
<CASH-FLOW-OPERATIONS> 43,959
<EPS-BASIC> 1.62
<EPS-DILUTED> 1.61
</TABLE>
