SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 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)
(800) 760-7776
(Registrant's Telephone Number, Including Area Code)
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last
Report)
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 [ ]
APPLICABLE ONLY TO ISSUERS 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 ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding at August 6, 1999
-------------------------- -----------------------------
Common Stock, $1 par value 10,389,232
PART 1. FINANCIAL INFORMATION
CONNECTICUT ENERGY CORPORATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share)
(Unaudited)
Three Months Ended Nine Months Ended
June 30, June 30,
---------------------------- ----------------------------
1999 1998 1999 1998
---- ---- ---- ----
Operating Revenues ............................. $ 35,377 $ 38,002 $ 203,135 $ 215,282
Purchased gas .................................. 12,461 17,847 89,414 108,497
------------ ------------ ------------ ------------
Gross margin ................................... 22,916 20,155 113,721 106,785
Operating Expenses:
Operations ................................ 12,166 11,517 38,020 37,688
Maintenance ............................... 817 903 2,745 2,887
Depreciation .............................. 4,338 4,081 13,371 12,561
Federal and state income taxes ............ (2,851) (1,806) 12,581 12,604
Municipal, gross earnings and other taxes . 3,390 3,238 12,319 11,081
------------ ------------ ------------ ------------
Total operating expenses ....................... 17,860 17,933 79,036 76,821
------------ ------------ ------------ ------------
Operating income ............................... 5,056 2,222 34,685 29,964
Other deductions (income), net ................. 978 (8) 947 (259)
Merger-related expenses ........................ 1,537 --- 1,537 ---
------------ ------------ ------------ ------------
Income before interest expense ................. 2,541 2,230 32,201 30,223
------------ ------------ ------------ ------------
Interest Expense:
Interest on long-term debt and amortization
of debt issue costs .................... 3,199 2,984 9,608 9,091
Other interest, net ....................... 108 265 518 735
------------ ------------ ------------ ------------
Total interest expense ......................... 3,307 3,249 10,126 9,826
------------ ------------ ------------ ------------
Net (Loss) Income .............................. $ (766) $ (1,019) $ 22,075 $ 20,397
============ ============ ============ ============
Net (loss) income per share - basic ............ $ (0.07) $ (0.10) $ 2.15 $ 2.04
============ ============ ============ ============
Net (loss) income per share - diluted .......... $ (0.07) $ (0.10) $ 2.13 $ 2.03
============ ============ ============ ============
Dividends paid per share ....................... $ 0.335 $ 0.335 $ 1.005 $ 0.995
------------ ------------ ------------ ------------
Weighted average common shares outstanding
during period - basic ..................... 10,283,429 10,197,554 10,260,586 9,995,647
------------ ------------ ------------ ------------
Weighted average common shares outstanding
during period - diluted ................... 10,375,443 10,249,801 10,352,600 10,047,894
------------ ------------ ------------ ------------
See Notes to Consolidated Financial Statements.
CONNECTICUT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended Nine Months Ended
June 30, June 30,
-------------------- --------------------
1999 1998 1999 1998
---- ---- ---- ----
Net (Loss) Income ...................... $ (766) $ (1,019) $ 22,075 $ 20,397
-------- -------- -------- --------
Other comprehensive income, net of tax:
Minimum pension liability adjustment (473) (427) (473) (427)
-------- -------- -------- --------
Total other comprehensive income ....... (473) (427) (473) (427)
-------- -------- -------- --------
Comprehensive (Loss) Income ............ $ (1,239) $ (1,446) $ 21,602 $ 19,970
======== ======== ======== ========
See Notes to Consolidated Financial Statements.
CONNECTICUT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share)
June 30, Sept. 30,
1999 1998
--------- ---------
(Unaudited)
Assets
- ------
Utility Plant:
Gross utility plant ................................................... $421,971 $412,715
Less: accumulated depreciation ....................................... 145,411 137,493
-------- --------
Net utility plant ..................................................... 276,560 275,222
Nonutility property, net ................................................. 9,842 4,526
-------- --------
Net utility plant and other property ..................................... 286,402 279,748
-------- --------
Current Assets:
Cash and cash equivalents ............................................ 5,966 10,091
-------- --------
Accounts receivable .................................................. 35,530 28,986
Less: allowance for doubtful accounts ............................... 2,752 2,065
-------- --------
Net accounts receivable .............................................. 32,778 26,921
-------- --------
Accrued utility revenues, net ........................................ 2,548 2,511
Unrecovered purchased gas costs ...................................... --- 2,529
Inventories .......................................................... 6,260 10,491
Prepaid expenses ..................................................... 1,086 5,863
-------- --------
Total current assets ..................................................... 48,638 58,406
-------- --------
Deferred Charges and Other Assets:
Unamortized debt expenses ........................................... 10,601 10,841
Unrecovered deferred income taxes ................................... 49,832 49,800
Other ............................................................... 68,154 60,606
-------- --------
Total deferred charges and other assets .................................. 128,587 121,247
-------- --------
Total assets ............................................................. $463,627 $459,401
======== ========
See Notes to Consolidated Financial Statements.
CONNECTICUT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share)
June 30, Sept. 30,
1999 1998
--------- ---------
(Unaudited)
Capitalization and Liabilities
- ------------------------------
Common Shareholders' Equity:
Common stock: authorized--30,000,000
shares, par value $1 per share, issued and
outstanding--10,387,615 shares; 10,289,692
shares ............................................................... $ 10,388 $ 10,290
Capital in excess of par value ....................................... 123,715 119,961
Unearned compensation ................................................ (1,550) (310)
Retained earnings .................................................... 59,340 47,685
Adjustment for minimum pension liability (net of
income taxes) .................................................... (473) (473)
--------- ---------
Total common shareholders' equity ....................................... 191,420 177,153
--------- ---------
Long-term debt .......................................................... 148,458 150,007
--------- ---------
Total capitalization .................................................... 339,878 327,160
--------- ---------
Current Liabilities:
Short-term borrowings ............................................... 4,150 22,400
Current maturities of long-term debt ................................ 1,629 1,321
Accounts payable .................................................... 9,553 10,499
Federal, state and deferred income taxes ............................ 5,969 1,537
Other accrued taxes ................................................. 2,878 2,024
Interest payable .................................................... 2,548 3,386
Customers' deposits ................................................. 1,667 1,627
Refunds due customers ............................................... 118 454
Refundable purchased gas costs ...................................... 3,764 ---
Other ............................................................... 6,053 4,886
--------- ---------
Total current liabilities ............................................... 38,329 48,134
--------- ---------
Deferred Credits:
Deferred income taxes and investment
tax credits ...................................................... 76,231 75,568
Other ............................................................... 9,101 8,389
--------- ---------
Total deferred credits .................................................. 85,332 83,957
--------- ---------
Commitments and contingencies ........................................... 88 150
--------- ---------
Total capitalization and liabilities .................................... $ 463,627 $ 459,401
========= =========
See Notes to Consolidated Financial Statements.
CONNECTICUT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Nine Months Ended
June 30,
--------------------
1999 1998
---- ----
Net cash provided by operating activities ...................................... $ 45,999 $ 22,305
-------- --------
Cash Flows from Investing Activities:
Capital expenditures ....................................................... (20,165) (18,773)
Contributions in aid of construction ....................................... 1,160 39
Payments for retirement of utility plant ................................... (236) (110)
Investment in special contract distribution main ........................... (1,211) ---
Energy ventures ............................................................ (2,373) 42
-------- --------
Net cash used by investing activities .......................................... (22,825) (18,802)
-------- --------
Cash Flows from Financing Activities:
Dividends paid on common stock ............................................. (10,420) (10,181)
Issuance of common stock ................................................... 2,612 26,090
Repayments of long-term debt ............................................... (1,241) (4,200)
Decrease in short-term borrowings .......................................... (18,250) (16,217)
-------- --------
Net cash used by financing activities .......................................... (27,299) (4,508)
-------- --------
Net decrease in cash and cash equivalents ...................................... (4,125) (1,005)
Cash and cash equivalents at beginning of period ............................... 10,091 6,644
-------- --------
Cash and cash equivalents at end of period ..................................... $ 5,966 $ 5,639
======== ========
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest ................................................................... $ 10,458 $ 10,634
Income taxes ............................................................... $ 7,250 $ 8,350
Supplemental Schedule of Noncash
Investing and Financing Activities:
On January 31, 1999, 700 shares of unregistered common stock were issued
pursuant to the Company's Non-Employee Director Stock Plan.
On October 1, 1998, 39,767 shares of unregistered common stock were issued
pursuant to the Company's Restricted Stock Award Plan.
See Notes to Consolidated Financial Statements.
CONNECTICUT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
(Unaudited)
Note 1 - Summary of Significant Accounting Policies
General
The unaudited consolidated financial statements presented herein should be
read in conjunction with the consolidated financial statements of Connecticut
Energy Corporation ("Connecticut Energy" or "Company") for the fiscal year ended
September 30, 1998 as presented in its Annual Report on Form 10-K. In the
opinion of management, the accompanying financial information reflects all
adjustments that are necessary to provide a fair presentation of the interim
periods shown. All such adjustments are of a normal recurring nature.
In preparing the financial statements in conformity with generally
accepted accounting principles, 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.
Accounting for the Effects of Regulation
The Company's principal subsidiary, The Southern Connecticut Gas Company
("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 Connecticut Department
of Public Utility Control's ("DPUC") 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 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 June 30, 1999 and September 30,
1998 of $75,429 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 local gas distribution companies
("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 the 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.
Deferred Charges and Other Assets
Deferred charges and other assets include amounts related to the
following:
June 30, Sept. 30,
As of 1999 1998
- -----------------------------------------------------------------------------
Conservation costs ..................................... $ 3,869 $ 5,004
Energy assistance funding shortfall .................... --- 262
Environmental evaluation costs ......................... 947 684
Gas holder costs ....................................... --- 62
Hardship heating customer accounts receivable arrearages 19,461 16,399
Hardship heating customer assistance grant program ..... 3,493 1,748
Investment in energy ventures .......................... 6,568 4,195
Investment in special contract distribution main, net .. 11,976 11,394
Liquefied natural gas, net ............................. 209 207
Nonqualified benefit plans ............................. 3,703 3,023
Prepaid pension and postretirement medical contributions 14,207 14,207
Other .................................................. 3,721 3,421
-------- --------
$ 68,154 $ 60,606
======== ========
Southern has been allowed to recover various deferred charges in rates
over periods ranging from three to five years in accordance with the DPUC's
Decision in Southern's latest rate case.
Deferred Credits
Deferred credits include amounts related to the following:
June 30, Sept. 30,
As of 1999 1998
- -----------------------------------------------------------------------------
Economic development initiatives ....................... $ 371 $ 397
Insurance reserves ..................................... 1,545 1,153
Interruptible margin sharing ........................... 477 1,210
Nonqualified benefit plans ............................. 4,041 3,522
Other .................................................. 2,667 2,107
------- -------
$ 9,101 $ 8,389
======= =======
Utility Operating Results
Due to the seasonal nature of gas sales for space heating purposes by
Southern, the results of operations for the nine months ended June 30, 1999 are
not indicative of the results to be expected for the fiscal year ending
September 30, 1999.
Common Shareholders' Equity
On October 1, 1998, 39,767 shares of unregistered common stock were issued
to six senior officers pursuant to the Company's Restricted Stock Award Plan.
The purpose of the Restricted Stock Award Plan is 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 the objectives. The total number of shares that may be issued
under the Restricted Stock Award Plan may not exceed 300,000. 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.
Recent Accounting Developments
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. The effective date of SFAS
133 has been amended to 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.
Effective October 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 130, "Reporting Comprehensive Income." This Statement
establishes standards for reporting and presentation of comprehensive income and
its components in general purpose financial statements and requires that all
items required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements.
Note 2 - 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. See section in Management's
Discussion and Analysis entitled "Environmental Matters" for further details.
Note 3 - Merger Agreement
On April 23, 1999, the Boards of Directors of Energy East Corporation
("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. See section in Management's
Discussion and Analysis entitled "Connecticut Energy Corporation/Energy East
Corporation Merger" for further details.
ITEM 2: 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, 1998 and this
quarterly report on Form 10-Q, 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 quarterly 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 for the three and nine months ended
June 30, 1999 and 1998 is detailed below:
Three Months Ended Nine Months Ended
June 30, June 30,
-------------------- -------------------
(in thousands, except per share) 1999 1998 1999 1998
---- ---- ---- ----
Net (loss) income $ (766) $ (1,019) $ 22,075 $ 20,397
======== ======== ======== ========
Net (loss) income per share - diluted $ (0.07) $ (0.10) $ 2.13 $ 2.03
======== ======== ======== ========
Weighted average common shares outstanding - diluted 10,375 10,250 10,353 10,048
-------- -------- -------- --------
The net loss for the three months ended June 30, 1999 was approximately
25% lower than the net loss recorded in the corresponding 1998 period. This was
primarily 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"), and
higher credits for state and federal income taxes. The reduction in net
loss for the 1999 quarter was partially offset by lower interruptible
margins, higher operations and depreciation expenses, higher gross earnings tax,
higher other deductions, merger-related expenses and higher interest expense
on long-term debt.
Net income for the nine months ended June 30, 1999 was 8% higher compared
to the nine months ended June 30, 1998 primarily due to higher firm margins
earned by Southern and CNE Energy. The increase in net income was partially
offset by lower interruptible margins, higher operations and depreciation
expenses, higher property taxes, higher other deductions, merger-related
expenses and higher interest expense on long-term debt.
Total Sales and Transportation Volumes
- --------------------------------------
Total volumes of gas sold and transported for the three months ended June
30, 1999 were approximately 5,866 MMcf, or approximately 7% higher, compared to
the corresponding 1998 period primarily due to an increase in firm contract and
off-system transportation volumes. Lower off-system sales volumes for the 1999
quarter were partially offsetting.
Total volumes of gas sold and transported for the nine months ended June
30, 1999 were approximately 28,420 MMcf, or approximately 3% lower, compared to
the nine months ended June 30, 1998. Lower interruptible volumes for the nine
months ended June 30, 1999 were partially offset by an increase in firm volumes.
Firm Sales, Firm Transportation and Firm Contract Volumes
- ---------------------------------------------------------
The Company's firm volumes for the three and nine months ended June 30,
1999 increased approximately 12% and 13%, respectively, compared to the
corresponding 1998 periods. This was primarily due to firm volumes generated by
a contract to transport natural gas to an electric generating plant in
Bridgeport and the continued growth in Southern's residential customer base. The
increase in firm volumes for the nine months ended June 30, 1999 was also
attributed to higher firm transportation volumes and was partially offset by
lower industrial firm sales primarily due to customers' switching to firm
transportation services.
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. Gross margin
retained represents the difference between gross margin earned and margin to be
allocated through the margin sharing mechanism.
The chart below depicts 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 for
the three and nine months ended June 30, 1999 and 1998:
Three Months Ended Nine Months Ended
June 30, June 30,
------------------ ------------------
(dollars in thousands) 1999 1998 1999 1998
---- ---- ---- ----
Gross margin earned $1,419 $2,068 $5,345 $7,267
====== ====== ====== ======
Gross margin retained $1,266 $1,618 $3,299 $4,536
====== ====== ====== ======
Volumes sold and transported (MMcf) 2,247 2,280 6,728 9,921
------ ------ ------ ------
Gross margins earned and retained by Southern were lower for the three and
nine months ended June 30, 1999 compared to the corresponding 1998 periods
principally due to the competitive price of certain other energy sources
compared to natural gas.
For the nine months ended June 30, 1999, interruptible volumes sold and
transported were lower for all interruptible categories, with the exception of
on-system transportation. Lower off-system sales and 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 for the three and nine months ended June 30,
1999 was approximately 14% and 6% higher, respectively, compared to the
corresponding 1998 periods. The increase in the 1999 periods was principally
attributed to higher firm margins earned by Southern and CNE Energy resulting
from revenues generated by a contract to transport natural gas to an electric
generating plant in Bridgeport, which began operations in July 1998; increases
in firm transportation revenues; and increases in Southern's residential
customer base. Also contributing to the increase in gross margin, to a lesser
extent, were the Company's other nonutility operations. Lower interruptible
margins for the three and nine months ended June 30, 1999 partially offset the
overall increase in gross margin compared to the same periods last year.
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. Because weather during the three and
nine months ended June 30, 1999 was approximately 13% and 9% warmer than normal,
respectively, the operation of the WNA collected approximately $1,434,000 and
$5,977,000, respectively, from firm customers. This compares to a collection
from firm customers during the three and nine months ended June 30, 1998 of
approximately $1,140,000 and $6,017,000, respectively.
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. The
operation of Southern's PGA decreased revenues and gas costs for the three
months ended June 30, 1999 by approximately $77,000 and increased revenues and
gas costs for the nine months ended June 30, 1999 by approximately $1,405,000.
For the three and nine months ended June 30, 1998, PGA adjustments increased
revenues and gas costs by approximately $1,275,000 and $10,576,000,
respectively.
Operations Expense
- ------------------
Operations expense for the three months ended June 30, 1999 increased
approximately 6% compared to the corresponding 1998 period. The increase was
primarily due to higher costs for health insurance, collection agency fees and
the Company's Restricted Stock Award Plan. A lower provision for uncollectibles
and lower costs for outside services partially offset the increase in
operations expense in the 1999 period.
Depreciation Expense
- --------------------
Depreciation expense for the three and nine months ended June 30, 1999
increased approximately 6% compared to the corresponding 1998 periods. The
increase in the 1999 periods was primarily due to additions to plant in service
by Southern.
Federal and State Income Taxes
- ------------------------------
The federal and state income tax credit for the three months ended June
30, 1999 was approximately 58% higher compared to the corresponding 1998 period
primarily due to a reduction during the 1999 quarter of the Company's accrual
for prior years' taxes.
Municipal, Gross Earnings and Other Taxes
- -----------------------------------------
Municipal, gross earnings and other taxes for the three and nine months
ended June 30, 1999 were approximately 5% and 11% higher, respectively, compared
to the corresponding 1998 periods. The increase in the 1999 quarter compared to
last year was primarily due to higher gross earnings tax. Lower gross earnings
tax for the nine months ended June 30, 1999 was more than offset by the absence
of a reduction to property tax expense which occurred in the corresponding 1998
period as a result of a DPUC Decision which 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 and the remaining 50% refunded to firm customers through the
operation of the PGA in three equal amounts during the quarter ended March 31,
1998.
Other Deductions (Income), Net
- ------------------------------
The increase in other deductions for the three and nine months ended June
30, 1999 was primarily due to a reduction in equity earnings in CNE Energy due
to its joint venture, Conectiv/CNE Energy Services, LLC, and, to a lesser
extent, higher promotional expenses recorded by Southern.
Merger-Related Expenses
- -----------------------
In the quarter ended June 30, 1999, the Company began recording
merger-related expenses. As of June 30, 1999, the Company has recorded
$1,537,000 of such expenses which are primarily comprised of investment banking
and legal fees. See section entitled "Connecticut Energy Corporation/Energy
East Corporation Merger" for further details.
Interest Expense
- ----------------
Total interest expense increased approximately 2% and 3% for the three and
nine months ended June 30, 1999, respectively, compared to the corresponding
1998 periods primarily due to an increase in long-term debt related to the
financing of the construction of distribution facilities to transport natural
gas to an electric generating plant in Bridgeport. In the 1999 quarter, the
increase in total interest expense was partially offset by lower interest
expense on short-term borrowings and lower interest expense on deferred
purchased gas cost balances. For the nine months ended June 30, 1999, the
increase in total interest expense was partially offset by lower interest
expense on short-term borrowings and lower interest expense related to pipeline
refunds not yet returned to firm customers.
Year 2000 Readiness Disclosure
- ------------------------------
General
Before the Company's Year 2000 program began, many of its software
programs and computing infrastructure used two-digit years, rather than
four-digit years, to define the applicable year. Computer hardware and software
using two-digit years may recognize a date using "00" as the year 1900 rather
than the year 2000. This so-called Year 2000 issue could result in the computer
or device shutting down, performing incorrect computations or performing
inconsistently. If not corrected, those systems could cause the Company to
experience service problems, report inaccurate data or issue inaccurate bills.
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's Year 2000 project is proceeding on schedule and is nearing completion.
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 system inventory and analysis,
business-application system remediation, business-application system
replacement, and embedded systems inventory and analysis.
Southern is subject to regulation from the DPUC, among other governmental
agencies. At the DPUC's request, Southern has previously reported the progress
of its Year 2000 program to the DPUC on multiple occasions. In January 1999, the
DPUC retained the services of an information technology consultant to perform a
due diligence study of Year 2000 readiness at each of Connecticut's
investor-owned utilities, including Southern. On June 9, 1999, the DPUC released
the consultant's report, which favorably comments on Southern's Year 2000
program. The DPUC opened Docket No. 99-06-22 and is scheduled to hold a hearing
on August 16, 1999 at which Southern will testify as to its Year 2000
readiness. The final decision is expected on September 22, 1999.
Southern separately expects the DPUC's auditors to 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.
Business-Application Systems
In March 1997, the Company completed its inventory and assessment of all
of its business-application systems. This assessment has assisted management in
developing a remediation plan consisting of replacing certain equipment;
modifying certain software to recognize the turn of the century; replacing
certain software systems with new systems that, in addition to providing
additional business management information, recognize four-digit years;
and eliminating certain software and equipment.
By July 31, 1998, the Company had completed modifications to all of its
Financial, Accounting, Purchasing, Inventory Control and Work Management
business applications targeted for version upgrade by use of internal staff and
outside resources. The Company has tested and placed back into the production
environment business applications for the above-mentioned business functions.
While the Company is conducting additional testing, the Company remains
confident that these applications are Year 2000 ready.
The Company initiated a project to update the Payroll and Human Resources
business-application systems to the Year 2000 Compliant versions of the
software. This project is completed and the system is Year 2000 ready.
In December 1997, the Company began a project to replace its Customer
Information System with a vendor supplied business-application system. The
project is completed. The project team completed Year 2000 testing of the new
system and determined that the Customer Information System is Year 2000 ready.
In September 1998, the Company began a project to upgrade the existing
System Control and Data Acquisition System, which is used to monitor the flow of
gas throughout the Company's distribution system, with a version that is Year
2000 compliant. The project is complete, tested and the system is Year 2000
ready.
In August 1998, the Company began a project to upgrade the existing Field
Service Management system, which is used to assign and dispatch service
technicians, with a version that is Year 2000 compliant. The project is complete
and the system is Year 2000 ready.
In January 1998, the Company completed a project to upgrade all of the
Personal Computer ("PC") software and Network software with versions that are
Year 2000 compliant. As part of this project, all of the Company's PCs were
upgraded or replaced and all of the Company's servers were upgraded or replaced.
In January 1999, all of the Company's PCs were checked for Year 2000 readiness
and some software modifications were completed as needed. The Company's supplier
of desktop and network operating systems, Microsoft, has been releasing multiple
updates to various products that must be installed to make them Year 2000 ready.
All of the announced upgrades have been installed and all of the Company's PCs
will be checked again for Year 2000 readiness in August 1999. The Company will
continue to update its programs as required by any subsequent Year 2000-related
releases.
Embedded Systems
The Company performed a review of its equipment that includes embedded
systems. This review identified a number of components that are potentially date
sensitive. The Company has contacted manufacturers of those components that it
has identified as critical to operations and continues to contact other
manufacturers of embedded components to determine whether their components are
Year 2000 compliant. The Company tested mission critical functions related to
gas control and distribution and confirmed that the embedded systems related to
measuring and monitoring gas flow are Year 2000 compliant. In April 1999, the
Company tested the gas control and distribution systems' ability to function
without computers, in the event of a power failure, telecommunications failure
or computer system failure. The test demonstrated that even without back-up
electric power, which the Company does have but chose not to use for this test,
and telecommunications, the gas continued to flow through the distribution
system and the system integrity was maintained.
The Company's test of the gas control and distribution systems also
verified that equipment associated with its LNG operations can function even
without back-up electric power, telecommunications or computers, which the
Company has but chose not to use for this test.
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. As part of its
normal business practice, the Company maintains plans to follow during emergency
circumstances, some of which could arise from Year 2000-related problems. The
Company has completed its contingency plan for the Year 2000. This contingency
plan, which will be coordinated with various parties including critical vendors
and revised as needed during the remainder of 1999, addresses various
alternatives and includes plans for a variety of scenarios that could emerge
which will require the Company to react.
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 currently expects to generate nonrecurring expenses of
approximately $300,000 to $500,000 over the three fiscal-year period ending
September 30, 1999 for business-application systems remediation, embedded
systems replacement and certain existing business-applications system
replacement. Over the same time period, the Company will capitalize costs of
approximately $11,000,000 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 or
nearing completion 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.
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 below:
Shared
Connecticut Connecticut
Energy Southern Energy/Southern Total
- ---------------------------------------------------------------------------------------
As of June 30, 1999:
Committed lines $ 5,000,000 $32,000,000 $20,000,000 $57,000,000
Uncommitted lines --- $10,000,000 $10,000,000 $20,000,000
Effective January 1, 1998, Connecticut Energy and Southern entered into an
agreement with one bank for a shared committed line of credit in the amount of
$20,000,000. The credit line has been extended until December 31, 1999. This
term may be further extended from year to year thereafter dependent upon the
operating cash requirements of the Company and its subsidiary and approval by
the bank. As of June 30, 1999, unused lines of credit totaled $72,850,000.
Operating cash flows were higher for the nine months ended June 30, 1999
compared to the corresponding 1998 period primarily due to a decrease in prepaid
expenses, a higher comparative decrease in gas inventories, a lower comparative
increase in other deferred assets, a higher comparative increase in accrued
taxes and lower comparative decreases in accounts payable balances and
refunds due customers. Partially offsetting the increase in operating cash
flows for the 1999 period were lower 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, net of contributions in aid of construction,
approximated $19,005,000 and $18,734,000 for the nine months ended June 30, 1999
and 1998, respectively. On an annual basis, 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.
Regulatory Matters
- ------------------
In accordance with Connecticut statutes, Southern has undergone a
periodic review of 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. Public hearings are held to determine whether
Southern's current rates are unreasonably discriminatory or more or less than
just, reasonable and adequate.
On July 8, 1998 Southern received a Decision in Docket No. 97-12-21,
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. In this Decision, 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 20-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.
In its Decision, the DPUC 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 has
filed an appeal in Connecticut Superior Court regarding the claimed disallowance
of the 20-inch gas trunkline from rate base and has opted to file a
comprehensive rate case, which includes proposals for incentive-based rates.
Additionally, 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, 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 rate case is expected to take between 150 to 180 days to conclude
following the application date of July 15, 1999. If new rates are approved, they
would become effective by January 2000.
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 reached a Settlement Agreement which results in an
immediate rate reduction for firm sales customers. In accordance with the
Agreement, which was approved by the DPUC, Southern will 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.
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 will manage certain of Southern's gas assets and
Southern will transfer to Sempra the ability to make off-system sales and
receive capacity release funds. In return, Sempra will pay a management fee to
Southern, which will be 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 will
replace the current margin sharing mechanism 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 does not affect Southern's existing on-system
interruptible margin sharing mechanism.
Connecticut Energy Corporation/Energy East Corporation Merger
- -------------------------------------------------------------
On April 23, 1999, the Boards of Directors of Energy East Corporation
("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 pro-ration. Connecticut Energy 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 20-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 shareholders to the
extent they receive common stock of Energy East. The combination will be
accounted for using the purchase method of accounting.
The merger is conditioned on, among other things, the approval of
Connecticut Energy shareholders and various regulatory agencies, including the
DPUC and the Securities and Exchange Commission. The companies anticipate that
these approvals can be obtained within 12 months. A special meeting of
Connecticut Energy shareholders is scheduled on September 14, 1999 to vote on
this matter.
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, Connecticut, may be of particular interest to the state of
Connecticut because of its proximity to the Connecticut Department of
Transportation expansion project of the U.S. Highway Route Number 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 Number 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 located in Bridgeport. 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 this 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 investigation is complete, management
cannot predict the cost, if any, of any appropriate remediation for the Pine
Street site.
Neither can management, at this time, predict the costs 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.
ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
PART II. OTHER INFORMATION
Items 1, 2, 3, 4 and 5 are inapplicable.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Exhibit 3 - Certificate of Incorporation and By-Laws
(i) The Amended and Restated Certificate of Incorporation of Connecticut
Energy Corporation is filed herewith at pages 30 to 40.
Exhibit 10 - Material Contracts
(i) 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.
(ii) 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.
(iii) 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.
Exhibit 27 - Financial Data Schedule
Submitted only in electronic format to the Securities and Exchange
Commission.
(b) Reports on Form 8-K:
There were no reports filed on Form 8-K during the quarter.
SIGNATURE
Pursuant to the requirements 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)
Date: August 10, 1999 By: /s/ Vincent L. Ammann, Jr.
--------------- ---------------------------
Vincent L. Ammann, Jr.
Vice President and
Chief Accounting Officer