Exhibit 99.2
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
(In Thousands Except Per Share Amounts) 1998 1997 1996
---- ---- ---
Operating Revenues ......................... $167,978 $187,140 $169,878
Cost of gas sold ........................... 88,127 102,455 87,188
------ ------- ------
Operating Margin ........................ 79,851 84,685 82,690
------ ------ ------
Operating Expenses:
Operations .............................. 27,793 30,044 30,372
Maintenance ............................. 4,794 4,503 4,476
Depreciation and amortization ........... 13,435 12,049 11,228
Local property taxes .................... 3,074 3,139 3,189
Other taxes ............................. 2,081 2,122 2,183
----- ----- -----
Total Operating Expenses .............. 51,177 51,857 51,448
------ ------ ------
Income Taxes:
Federal income tax ...................... 6,482 8,264 7,001
State franchise tax ..................... 1,334 1,708 2,087
----- ----- -----
Total Income Taxes .................... 7,816 9,972 9,088
----- ----- -----
Utility Operating Income ................... 20,858 22,856 22,154
------ ------ ------
Other Operating Income (Expense):
Energy Trucking revenues ................ 3,723 5,529 11,031
Energy Trucking expenses, including
income taxes and interest ............. (3,690) (5,202) (9,005)
------ ------ ------
Energy Trucking Net Income ............ 33 327 2,026
Other, net of income taxes .............. 360 318 250
--- --- ---
Total Other Operating Income .......... 393 645 2,276
--- --- -----
Non-Operating Income, Net of Income Taxes .. 897 573 757
--- --- ---
Merger Related Expenses, Net of Income Taxes (1,126) -- --
------ -------- -------
Income Before Interest and Debt Expense .... 21,022 24,074 25,187
------ ------ ------
Interest and Debt Expense .................. 8,734 8,034 8,709
----- ----- -----
Net Income .............................. $12,288 $ 16,040 $16,478
======= ======== =======
Average Common Shares Outstanding ....... 8,781 8,598 8,432
===== ===== =====
Basic Earnings per Share ................ $1.40 $1.87 $1.95
===== ===== =====
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1998 1997
---- ----
Utility Property:
At original cost $394,222 $362,742
Accumulated depreciation (102,009) (88,210)
-------- -------
Net Utility Property 292,213 274,532
Non-Utility Property - Net 7,129 7,312
----- -----
Net Property 299,342 281,844
-------- --------
Capital Leases - Net 1,583 2,630
----- -----
Current Assets:
Cash and cash equivalents 3,125 259
Accounts receivable 14,591 21,788
Allowance for doubtful accounts (1,350) (3,203)
Accrued utility revenues 7,876 7,417
Unbilled gas costs 18,195 19,266
Fuel inventory - at average cost 12,712 12,959
Materials and supplies - at average cost 2,906 2,950
Prepayments and other current assets 9,513 6,531
----- -----
Total Current Assets 67,568 67,967
------ ------
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 8,349 9,014
Unrecovered demand side management costs 6,661 8,273
Unrecovered environmental costs incurred 3,633 3,833
Unrecovered environmental costs accrued 200 707
Unrecovered pension costs 3,307 3,455
Unrecovered transition costs accrued 700 2,800
Excess cost of investments over net
assets acquired 2,798 2,798
Other 6,863 5,670
----- -----
Total Deferred Charges and Other Assets 32,511 36,550
------ ------
Total Assets $401,004 $388,991
======== ========
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1998 1997
- ------------------------------------------------------------------
Capitalization:
Common Equity:
Common Stock $29,669 $28,931
Premium on Common Stock 63,080 57,277
Retained earnings 36,173 35,924
------ ------
Total Common Equity 128,922 122,132
Long-Term Debt 120,000 100,102
------- -------
Total Capitalization 248,922 222,234
------- -------
Long-Term Capital Lease Obligations 963 1,617
--- -----
Current Liabilities:
Current maturities of long-term debt 102 10,164
Current capital lease obligations 620 1,013
Notes payable 52,000 49,400
Gas inventory purchase obligations 14,125 14,895
Accounts payable 12,186 15,674
Accrued interest 2,698 2,375
Current deferred income taxes 3,830 3,654
Other current liabilities 4,022 5,333
----- -----
Total Current Liabilities 89,583 102,508
------ -------
Deferred Credits and Reserves:
Deferred income taxes - Funded 44,555 41,443
Deferred income taxes - Unfunded 8,349 9,014
Unamortized investment tax credits 3,072 3,372
Pension reserve 4,424 4,507
Accrued environmental costs 200 707
Accrued transition costs 700 2,800
Other deferred credits and reserves 236 789
--- ---
Total Deferred Credits and Reserves 61,536 62,632
------ ------
Total Capitalization and Liabilities $401,004 $388,991
======== ========
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1998 1997 1996
- ------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net Income $12,288 $16,040 $16,478
Adjustments to reconcile net income to net cash:
Depreciation and amortization 14,764 13,334 12,361
Deferred income taxes 3,157 3,208 7,968
Amortization of investment tax credits (300) (300) (268)
Provision for uncollectable accounts (601) 1,955 2,146
Other, net (227) 109 171
---- --- ---
29,081 34,346 38,856
Changes in current assets and liabilities:
Accounts receivable and accrued utility
revenues 5,486 (6,620) 2,305
Unbilled gas costs 1,071 (28) (9,550)
Fuel inventory 247 (1,001) (1,442)
Prepayments and other current assets (2,938) 2,003 (4,015)
Accounts payable (3,488) 1,130 2,394
Other current liabilities (988) 2,645 (2,929)
---- ----- ------
Net Cash Provided by Operating Activities 28,471 32,475 25,619
------ ------ ------
Cash Flows From Investing Activities:
Utility capital expenditures (31,093) (35,788) (26,875)
Non-utility capital expenditures (364) (1,888) (1,367)
Change in deferred accounts 972 (842) (1,502)
--- ---- ------
Net Cash Used in Investing Activities (30,485) (38,518) (29,744)
------- ------- -------
Cash Flows From Financing Activities:
Dividends paid on Common Stock (12,039) (11,435) (10,919)
Issuance of Common Stock 6,541 3,621 3,277
Issuance of long-term debt, net of
issuance costs 39,116 14,871 29,787
Retirement of long-term debt, including
premiums (30,568) (5,152) (11,284)
Change in notes payable 2,600 (1,000) (11,435)
Change in gas inventory purchase obligations (770) 1,856 699
---- ----- ---
Net Cash Provided by Financing Activities 4,880 2,761 125
----- ----- ---
Net Increase (Decrease) in Cash and Cash
Equivalents 2,866 (3,282) (4,000)
Cash and Cash Equivalents at Beginning of Year 259 3,541 7,541
--- ----- -----
Cash and Cash Equivalents at End of Year $ 3,125 $ 259 $ 3,541
======= ======= =======
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $10,229 $ 9,465 $ 9,149
Income and state franchise taxes $ 7,238 $ 7,509 $ 8,489
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1998 1997 1996
---- ---- ----
Common Stock
$3.33 par value; authorized 15,000
shares; outstanding, 8,910 in 1998,
8,688 in 1997, and 8,518 in 1996
Beginning of year $28,931 $28,366 $27,863
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (222
shares in 1998, 170 shares
in 1997 and 151
shares in 1996) 738 565 503
---- --- --- ---
End of year $29,669 $28,931 $28,366
------- ------- -------
Premium on Common Stock
Beginning of year $57,277 $54,221 $51,447
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 5,803 3,056 2,774
----- ----- -----
End of year $63,080 $57,277 $54,221
------- ------- -------
Retained Earnings
Beginning of year $35,924 $31,319 $25,760
Net income 12,288 16,040 16,478
Cash dividends on Common Stock
($1.37 a share in 1998, $1.33
a share in 1997 and $1.295
a share in 1996) (12,039) (11,435) (10,919)
---- ------- ------- -------
End of year $36,173 $35,924 $31,319
------- ------- -------
Total Common Equity $128,922 $122,132 $113,906
======== ======== ========
The accompanying notes are an integral part of these statements.
Notes to Consolidated Financial Statements
Note A: Summary of Significant Accounting Policies
Nature of Operations - Colonial Gas Company, a Massachusetts corporation formed
in 1849, is primarily a regulated natural gas distribution utility. The Company
serves over 154,500 utility customers in 24 municipalities located northwest of
Boston and on Cape Cod. Through its subsidiary, Transgas Inc., the Company also
provides over-the-road transportation of liquefied natural gas, propane, and
other commodities.
Principles of Consolidation - The consolidated financial statements include the
accounts of the Company and its subsidiaries. All material intercompany items
have been eliminated in consolidation.
Use of Estimates - The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Regulation - The Company's utility operations are subject to regulation
by the Massachusetts Department of Telecommunications & Energy ("DTE"), with
respect to rates charged for natural gas sales and transportation, among other
things. The Company's policies conform with generally accepted accounting
principles, as applied to regulated public utilities.
Utility Property and Non-Utility Property - Utility property and non-utility
property are stated at original cost, including labor, materials, taxes and
overheads. The amount of interest capitalized as a component of construction
overheads amounted to $805,000, $594,000, and $437,000 in 1998, 1997 and 1996,
respectively.
The original cost of depreciable utility property retired, together with
the cost of removal, net of salvage, is charged to accumulated depreciation.
Depreciation applicable to the Company's utility property in service is
calculated in accordance with depreciation rates as approved by the DTE. A
composite depreciation rate of approximately 3.8% is applied to the utility
property balance at the beginning of each year. Depreciation on non-utility
property is computed by various methods.
Operating Revenues - Operating revenues are accrued based upon the amount of gas
delivered to utility customers through the end of the accounting period. Accrued
utility revenues of $7,876,000 and $7,417,000, as reported in the Consolidated
Balance Sheets at December 31, 1998 and 1997, respectively, represent the
accrual of unbilled operating revenues net of related gas costs. The Company's
policy is to record lost margins and financial incentives relating to the
Company's demand side management ("DSM") programs as revenue when earned by the
Company. (See Note I).
Unbilled Gas Costs - The Company charges or credits its utility customers for
increases or decreases in gas costs from those reflected in its base tariffs by
applying a cost of gas adjustment clause ("CGAC"). In accordance with the CGAC,
any under or over recoveries of gas costs are charged or credited to the
unbilled gas cost account and recorded as a current asset or liability. Such
under or over recoveries are collected or refunded, with interest accrued at the
prime rate, in subsequent periods.
Pipeline Refunds Due Customers - The Company periodically receives refunds from
interstate pipeline companies related to rate adjustments ordered by the Federal
Energy Regulatory Commission ("FERC"). Refunds are returned to utility customers
under methods approved by the DTE.
Excess Cost of Investments over Net Assets Acquired - This asset arose
principally from the pre-1971 acquisitions of utility operations. No
amortization has been provided since, in the opinion of management, there has
been no diminution in value of the applicable investments.
Income Taxes - The Company records deferred income taxes for the income tax
effect of the difference between book and tax depreciation and all other
temporary book and tax differences, in accordance with Statement of Financial
Accounting Standards No. 109 "Accounting for Income Taxes" ("SFAS 109").
Unamortized investment tax credits, which were allowed under Federal income tax
laws prior to 1987, have been deferred and are being amortized as a credit to
income tax expense over the estimated service lives of the corresponding assets.
Interest and Debt Expense - Interest and debt expense includes interest on
long-term debt, interest on short-term notes payable and regulatory interest. As
approved by the DTE, regulatory interest is interest income credited on
regulatory assets or interest expense charged on regulatory liabilities.
Pension Plans - The Company and its subsidiaries have defined benefit pension
plans covering substantially all employees. These include two qualified union
plans, one qualified plan for non-union employees, and various unqualified
individual retirement agreements covering certain key employees and retirees.
The Company's funding policy for the qualified plans is to contribute annually
an amount at least equal to the normal cost plus a 30-year amortization of the
unfunded actuarially calculated accrued liability.
Cash and Cash Equivalents - For the purposes of the Consolidated Balance Sheets
and Statements of Cash Flows, the Company considers cash investments with an
original maturity of three months or less to be cash equivalents.
Fair Value of Financial Instruments - In accordance with Statement of Financial
Accounting Standards No. 107 "Disclosures About Fair Values of Financial
Instruments", the fair value amounts are disclosed below. These fair value
amounts are not necessarily indicative of the amounts that the Company could
realize in a current market exchange.
The carrying amount of cash and cash equivalents and short-term debt
approximates fair value. The fair value of long-term debt is estimated based on
the rates available to the Company at the end of each respective year for debt
of the same remaining maturities. The carrying amount of long-term debt
(including current maturities) was $120,102,000 and $110,266,000 as of December
31, 1998 and 1997, respectively. The fair value of long-term debt was
$129,302,000 and $115,700,000 as of December 31, 1998 and 1997, respectively.
Under current regulatory treatment, any premiums paid to refinance
long-term debt, would be recovered over the life of new debt, and would not have
a significant impact on the Company's results of operations.
Earnings Per Share - The Company determines earnings per share in
accordance with the provisions of Statement of Financial Accounting Standards
No. 128 "Earnings Per Share" ("SFAS 128"). Earnings per share in computed by
dividing net income by the average number of common shares outstanding during
the period. The Company has no dilutive shares.
Reclassifications - Reclassifications are made periodically to
previously issued financial statements to conform to the current year
presentation.
Note B: Federal Income Tax
The Company records deferred income taxes for the income tax effect of the
difference between book and tax depreciation and all other temporary book and
tax differences, in accordance with SFAS 109. Prior to October 1981 as approved
by the DTE, the Company did not record deferred income taxes but rather "flowed
through" tax benefits to utility customers. At December 31, 1998, the Company
has a liability of $8,349,000 on the Consolidated Balance Sheet as Deferred
Income Taxes - Unfunded and a corresponding unrecovered deferred asset. The
liability represents the tax effect of pre-1981 timing differences for which
deferred income taxes had not been provided and was increased in accordance with
SFAS 109 for the tax effect of future revenue requirements. The Company is
recovering these unfunded deferred taxes from utility customers over the
remaining book life of utility property.
Federal income tax expense is comprised of the following components:
Year Ended December 31,
(In Thousands) 1998 1997 1996
---- ---- ----
Charged (credited) to operations:
Current $4,396 $5,188 $1,104
Deferred:
Accelerated depreciation 1,933 1,688 2,202
Unbilled gas costs 146 (98) 2,929
Demand side management costs (394) 88 747
Pension costs 124 301 449
Recovery of unfunded deferred taxes 398 398 398
Debt expense (53) (53) (53)
Environmental response costs (65) (58) (246)
Bad debt 355 889 (167)
Miscellaneous (57) 221 (94)
Amortization of investment tax credits (301) (300) (268)
---- ---- ----
Total 6,482 8,264 7,001
----- ----- -----
Charged (credited) to other income (605) 312 1,599
---- --- -----
Total Federal income tax expense $5,877 $8,576 $8,600
====== ====== ======
The effective Federal income tax rate and the reasons for the difference from
the statutory Federal income tax rate are as follows:
1998 1997 1996
---- ---- ----
Statutory Federal income tax rate 35% 35% 35%
Increases (reductions) in taxes resulting
from:
Amortization of investment tax credits (2) (1) (1)
Recovery of unfunded deferred taxes 2 2 2
Miscellaneous items (3) (1) (2)
-- -- --
32% 35% 34%
== == ==
Temporary differences which gave rise to the following deferred tax assets
(liabilities) are:
December 31,
(In Thousands) 1998 1997
---- ----
Deferred Tax Assets:
Construction contributions $ 832 $ 891
Other 222 227
--- ---
Total deferred tax assets 1,054 1,118
----- -----
Deferred Tax Liabilities:
Accelerated depreciation (43,662) (41,345)
Unbilled gas costs (3,830) (3,654)
Demand side management costs (2,293) (2,765)
Environmental response costs (1,423) (1,502)
Cost of removal (3,143) (3,033)
Other (3,437) (2,930)
-------- --------
Total deferred tax liabilities (57,788) (55,229)
-------- --------
Total deferred taxes $(56,734) $(54,111)
======== ========
Note C: Capital Stock
Pursuant to the Company's dividend reinvestment and common stock purchase plan,
shareholders can automatically reinvest their cash dividends and can invest
optional limited amounts of cash payments in newly issued shares.
The Company has authorized and unissued 547,559 shares of Class A Preferred
Stock, $25 par value, of which 100,000 shares have been designated a Junior
Preferred Stock series and reserved for issuance under the Rights Plan described
below, and 370,000 shares of Class B Preferred Stock, $1 par value.
A Shareholder Rights Plan provides one right ("Right") to purchase one
one-hundredth of a share of the Company's Series A-1 Junior Participating
Preferred Stock, par value $25 per share, at a price of $60 per share, subject
to adjustment. The Rights expire on December 1, 2003 and only become
exercisable, or separately transferable, 10 days after a person or group
acquires, or announces an intention to acquire, beneficial ownership of 20% or
more of the Company's Common Stock. By vote of the Company's Board of Directors
on October 17, 1998, rights are not triggered by the Pending Merger with
Eastern. The Rights are redeemable by the Board at a price of $.01 per Right at
any time prior to the expiration of ten days after the acquisition by a person
or group of beneficial ownership of 20% or more of the Company's Common Stock.
Note D: Long-Term Debt
The composition of long-term debt is as follows:
Maturity Put December 31,
(In Thousands) Date Date 1998 1997
-------- ---- ---- ----
First mortgage bonds:
8.05% Series CG due 1999 $ --- $ 20,000
8.80% Series CH due 2022 25,000 25,000
6.85% Series MTA-1 due 2025 2005 10,000 10,000
6.45% Series MTA-2 due 2025 2005 10,000 10,000
6.94% Series MTA-3 due 2026 10,000 10,000
6.20% Series MTA-4 due 1998 --- 10,000
6.88% Series MTA-5 due 2008 10,000 10,000
6.81% Series MTA-6 due 2027 2002 15,000 15,000
6.38% Series MTA-7 due 2008 10,000 ---
6.86% Series MTB-1 due 2028 20,000 ---
5.50% Series MTB-2 due 2003 10,000 ---
------- -------
Total 120,000 110,000
Note payable 102 266
Less: Long-term debt due within one year (102) (10,164)
-------- --------
Total long-term debt $120,000 $100,102
======== ========
The aggregate amount of maturities for the years 1999 through 2003 are $102,000
in 1999, and $10,000,000 in 2003. Bonds of $15,000,000 due in 2027 can be
redeemed by the holder in 2002.
The first mortgage bonds are collateralized by utility property. The
Company's first mortgage bond indenture includes, among other provisions,
limitations on the issuance of long-term debt, leases and the payment of
dividends from retained earnings. The note payable is collateralized by
equipment.
The Company has in place a medium term note ("MTN") program which permits the
issuance of up to $75 million of MTN's as bonds under its indenture of which $30
million has been issued as of December 1998. The bonds with a put date noted
above can be redeemed by the holder within a 30 day period in the year
indicated.
Note E: Short-Term Debt
In September 1997, the Company established a three-year bank line of credit of
$75 million with a consortium of four banks which expires in September 2000. The
bank line of credit allows the Company to borrow on a demand basis up to $75
million, less whatever amount has been borrowed through the Company's gas
inventory trust (described below). The line of credit allows the Company the
option to borrow under three alternative rates: Eurodollar (LIBOR), prime, or a
competitive bid option. At December 31, 1998, the credit available under the
bank line of credit was $8,875,000. The weighted average interest rates for
short-term debt were 5.80% and 6.18% at December 31, 1998 and 1997,
respectively.
The Company has an agreement with a single-purpose Massachusetts trust, the
Company's gas inventory trust, under which the Company sells supplemental gas
inventory to the trust at the Company's cost. The Company's agreement with the
trust requires it to repurchase such inventory at cost when needed and reimburse
the trust for expenses incurred to finance the gas inventory. The trust finances
such purchases of inventory by borrowing under a bank line of credit with a
maximum borrowing commitment of $30 million that is complementary to and on
similar terms as the Company's bank line of credit described above. The DTE has
approved the inventory trust arrangement and has permitted the cost of such gas
inventory, including fees and financing costs, to be recovered through the
Company's CGAC. During 1998, 1997 and 1996 approximately $620,000, $564,000, and
$500,000, respectively, of interest costs were incurred by the trust.
Note F: Lease Obligations
The Company leases certain equipment used in its operations. In accordance with
accounting for regulated public utilities, the Company has capitalized certain
of these leases and reflects lease payments as rental expense in the periods to
which they relate. This capitalization has no impact on the Company's net
income.
Assets held under capital leases amounted to approximately $2,510,000, and
$7,702,000 at December 31, 1998 and 1997, respectively. In 1998, the Company
purchased certain facilities used in its operations which were previously
leased. Accumulated amortization on assets held under capital leases amounted to
approximately $927,000 and $5,072,000 at December 31, 1998 and 1997,
respectively.
Total rental expense for the years 1998, 1997 and 1996 approximated
$1,150,000 and $1,527,000, and $1,493,000, respectively. At December 31, 1998,
the future minimum payments (including interest) under the Company's lease
agreements are: $641,000 in 1999; $489,000 in 2000; $390,000 in 2001; $195,000
in 2002; $21,000 in 2003; and $0 thereafter.
Note G: Employee Benefit Plans
Savings Plan - The Company sponsors an employee 401(k) Savings Plan. The
Company's matching contribution, exclusive of plan administration costs, was
$689,000, $625,000 and $570,000 for 1998, 1997 and 1996, respectively.
Pension Plans - The Company and its subsidiaries have various defined benefit
pension plans covering substantially all employees.
Net periodic pension cost is comprised of the following components:
Year Ended December 31,
(In Thousands) 1998 1997 1996
---- ---- ----
Service cost $1,220 $1,042 $1,036
Interest cost on projected benefit
obligation 3,492 3,427 3,267
Expected return on plan assets (4,170) (6,711) (4,710)
Net amortization and deferral 625 3,673 1,882
--- ----- -----
Net periodic pension cost $1,167 $1,431 $1,475
====== ====== ======
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1998 1997 1996
---- ---- ----
Weighted average discount rate 7.00% 7.00% 7.75%
Future compensation increases 4.00% 4.00% 4.00%
Expected long-term rate of return on
assets 9.50% 9.00% 9.00%
The following tables set forth the reconciliation of the plans' benefit
obligation and fair value of assets for the years ended December 31, 1998 and
1997:
(In Thousands) 1998 1997
- ----------------------------------------------------------------------
Reconciliation of benefit obligation:
Obligation at January 1 $50,989 $45,016
Service cost 1,220 1,042
Interest cost 3,492 3,427
Amendments 176 (497)
Actuarial (gain) loss 393 5,067
Benefit payments (3,138) (3,066)
------ ------
Obligation at December 31 $53,132 $50,989
======= =======
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 $48,332 $41,458
Actual return on plan assets 5,161 7,583
Employer contributions 1,484 2,357
Benefit payments (3,138) (3,066)
------ ------
Fair value of plan assets at December 31 $51,839 $48,332
======= =======
The funded status of the plans at December 31, 1998 and 1997 is as follows:
1998 1997
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
- --------------------------------------------------------------------------------
Projected benefit
obligations:
Vested ...................... $(33,064) $(12,823) $(32,420) $(12,020)
Nonvested ................... (952) (1,194) (828) (1,088)
---- ------ ---- ------
Accumulated .................... (34,016) (14,017) (33,248) (13,108)
Due to recognition of future ... (4,814) (285) (4,497) (136)
------ ---- ------ ----
salary increases
Total .............. (38,830) (14,302) (37,745) (13,244)
Plan assets at fair value ...... 41,050 10,789 38,765 9,567
------ ------ ------ -----
Projected benefit obligation less than (in excess of)..
plan assets 2,220 (3,513) 1,020 (3,677)
Unrecognized net (gain) loss ... (793) 895 78 729
Unrecognized transition amount . 1,048 699 1,223 331
Unrecognized prior service cost. (33) 1,863 (60) 2,424
Additional liability accrued ... - (3,172) - (3,350)
------ ------ ------ ------
Prepaid (accrued) pension costs $ 2,442 $ (3,228) $ 2,261 $ (3,543)
======== ======== ======== ========
Assets of the employee benefit plans are invested in domestic and international
equities, domestic and international fixed income securities, real estate and
other short-term debt instruments.
Postretirement Life and Health Benefit Plan - The Company sponsors a
postretirement benefit plan that covers substantially all employees. The plan
provides medical, dental and life insurance benefits. The plan is contributory
for retirees, with respect to postretirement medical and dental benefits; the
plan is noncontributory with respect to life insurance benefits.
During 1993, the Company adopted Statement of Financial Accounting
Standards No. 106 "Employers' Accounting for Postretirement Benefits Other Than
Pensions" ("SFAS 106"). Prior to 1993, expense was recognized when benefits were
paid. In accordance with SFAS 106, the Company began recording the cost for this
plan on an accrual basis in 1993. The Company amortizes the transition
obligation over a twenty-year period. The Company's cost under this plan for
1998, 1997 and 1996 was $509,000, $410,000, and $501,000, respectively. A
regulatory asset of $431,000 was recorded in 1993 representing the excess of
postretirement benefits on the accrual basis over the paid amounts for the
period of January 1, 1993 until November 1, 1993, the effective date of the
DTE's approval of the Company's new rates. Currently, the DTE allows
Massachusetts utilities to recover the tax deductible portion of these
postretirement benefits.
Beginning in 1990, the Company has funded a portion of these costs through
the combination of trusts under Section 501(c)(9) and Section 401(h) of the
Internal Revenue Code.
The following tables set forth the reconciliation of the plans' benefit
obligation and fair value of plan assets for the years ended December 31, 1998
and 1997:
(In Thousands) 1998 1997
- ----------------------------------------------------------------------
Reconciliation of benefit obligation:
Obligation at January 1 $7,179 $6,229
Service cost 138 113
Interest cost 534 477
Amendments (314) 0
Actuarial (gain) loss 1,272 685
Benefit payments (251) (325)
---- ----
Obligation at December 31 $8,558 $7,179
====== ======
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 $5,163 $4,614
Actual return on plan assets 527 779
Employer contributions 0 95
Benefit payments (251) (325)
---- ----
$5,439 $5,163
====== ======
The following table sets forth the plan's funded status reconciled with the
amounts recognized in the Company's financial statements at December 31, 1998
and 1997:
(In Thousands) 1998 1997
- ----------------------------------------------------------------------
Accumulated postretirement benefit
obligation:
Retirees $(4,579) $(4,564)
Fully eligible active plan (1,767) (1,192)
participants
Other active plan participants (2,212) (1,423)
------ ------
Total (8,558) (7,179)
Plan assets at fair value 5,439 5,163
----- -----
Accumulated postretirement benefit
obligation (3,119) (2,016)
in excess of plan assets
Unrecognized net (gain) from past experience
different from that assumed and from
changes in assumptions (193) (1,351)
Unrecognized transition obligation 3,481 4,045
----- -----
$ 169 $ 678
====== ======
Net periodic postretirement benefit cost included the following components:
Year Ended December 31,
(In Thousands) 1998 1997 1996
- ----------------------------------------------------------------------------
Service cost - benefits attributable
to service during the period $138 $113 $137
Interest cost on accumulated
postretirement benefit obligation 534 477 461
Expected return on plan assets (412) (375) (507)
Net amortization and deferral 249 195 410
--- --- ---
Net periodic postretirement benefit $509 $410 $501
cost ==== ==== ====
For measurement purposes, a 6% (4.5% for dental costs) annual rate of
increase in the per capita cost of covered health care benefits was assumed for
1999; the rate of increase for medical costs was assumed to decrease gradually
to 4.5% for 2002 and remain at that level thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported. To illustrate,
increasing the assumed health care cost trend rates by one percentage point in
each year would increase the accumulated postretirement benefit obligation as of
December 31, 1998 by $1,175,000 and the aggregate of the service and the
interest cost components of net periodic postretirement benefit cost for the
year then ended by $111,000.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.0%, 7.0%, and 7.75% for 1998, 1997 and
1996, respectively. The expected long-term rate of return on plan assets was
9.5%, 9.0%, and 9.0% for 1998, 1997, and 1996, respectively, for assets in the
Section 401(h) accounts and, after estimated taxes, was 6.25%, 6.0%, and 6.0%
for 1998, 1997, and 1996, respectively, for assets in the Section 501(c)(9)
trust.
Note H: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at various dates
through the year 2013, for the acquisition and delivery of gas supplies and the
storage and delivery of natural gas stored underground. The contracts contain
minimum payment provisions which correspond to gas purchases that, in the
opinion of management, are not in excess of the Company's requirements.
FERC Order 636 Transition Costs - As a result of FERC Order 636, the Company's
interstate pipeline service providers have been required to unbundle their
supply and transportation services. This unbundling has caused the interstate
pipeline companies to incur substantial costs in order to comply with Order 636.
These transition costs include four types: (1) unrecovered gas costs (gas costs
that had been incurred but not yet recovered by the pipelines when they were
providing bundled service to local distribution companies); (2) gas supply
realignment costs (the cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that can not be
assigned to customers of unbundled services); and (4) new facilities costs
(costs of new facilities required to physically implement Order 636).
Pipelines are allowed to recover prudently incurred transition costs from
customers such as the Company, primarily through a demand charge, after approval
by FERC. The Company's additional transition cost liabilities are estimated to
be approximately $700,000. The Company is recovering these costs from its
customers, as approved by the DTE in October 1994. As of December 31, 1998, the
Company has recorded on the balance sheet a long-term liability of $700,000
("Accrued Transition Costs") and, based upon expected rate recovery, has
recorded a regulatory asset of $700,000 ("Unrecovered Transition Costs
Accrued"). Actual transition costs to be incurred depends on various factors,
and therefore future costs may differ from the amounts discussed above.
Note I: Contingencies
The Company is involved in various legal actions and claims arising in the
normal course of business. Management does not believe the outcome of any action
or claim will have a material adverse effect upon the Company's financial
position or results of operations.
Working with the Massachusetts Department of Environmental Protection, the
Company is engaged in site assessments and evaluation of remedial options for
contamination that has been attributed to the Company's former gas manufacturing
site and at various related disposal sites. During 1990, the DTE ruled that
Colonial and eight other Massachusetts gas distribution companies can recover
environmental response costs related to former gas manufacturing operations over
a seven-year period, without carrying costs, through the CGAC. Through December
31, 1998, the Company had incurred environmental response costs of $12,582,000
of which $8,949,000 has been recovered from customers to date.
As of December 31, 1998, the Company has recorded on the balance sheet a
long-term liability of $200,000 and, based upon expected rate recovery, has
recorded a corresponding regulatory asset. This amount represents estimated
future response costs for these sites based on the Company's preferred methods
of remediation. Actual environmental response costs to be incurred depends on
various factors, and therefore future costs may differ from the amount currently
recorded as a liability.
In 1998, the DTE conducted an industry-wide proceeding on the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs. The Company has been
using a calculation method, approved by the DTE in previous individual Company
filings, based on the useful life of installed conservation measures. As of this
date, the DTE has not yet issued its decision in the industry-wide proceeding.
The decision could result in a shortening of the time period for calculating
lost DSM margins to less than the full useful life of installed measures. A
shortening of the period would result in some decrease in operating revenues,
but it is uncertain at this time whether or by how much the period would be
shortened and, therefore, what impact it would have on the Company.
Note J: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts) Basic
Utility Earnings Dividends
Operating Net (Loss) Paid Per
Operating Income Income Per Common
Quarter Ended Revenues (Loss) (Loss) Share Share
1998
December 31 $52,125 $7,773 $5,060 $.57 $.345
September 30 12,347 (3,246) (5,213) (.59) .345
June 30 25,684 256 (1,771) (.20) .345
March 31 77,822 16,075 14,212 1.63 .335
1997
December 31 $62,275 $9,481 $7,814 $.90 $.335
September 30 14,877 (3,043) (4,566) (.53) .335
June 30 26,927 (556) (2,501) (.29) .335
March 31 83,061 16,974 15,293 1.79 .325
In the opinion of management, the quarterly financial data includes all
adjustments, consisting only of normal recurring accruals, necessary for a fair
presentation of such information. The Company typically reports profits during
the first and fourth quarters of each year while incurring losses during the
second and third quarters. This is due to significantly higher natural gas sales
during the colder months to satisfy customers' heating needs.
Note K: Merger
On October 17, 1998, the Company entered into an Agreement and Plan of
Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"), a
Massachusetts business trust which owns all of the outstanding stock of two
other Massachusetts LDC's, Boston Gas Company ("Boston Gas") and Essex Gas
Company ("Essex Gas"). The Merger Agreement provides for the merger of the
Company with and into a subsidiary of Eastern, as a result of which the Company
will become a wholly-owned subsidiary of Eastern (the "Pending Merger").
Pursuant to the Pending Merger, the outstanding shares of the Company's common
stock would convert into the right to receive cash and Eastern common stock as
set forth in the Merger Agreement. The Pending Merger was approved by
shareholders of Colonial and Eastern at separate special shareholder meetings
which were held on February 10, 1999. Completion of the Pending Merger is
subject to receipt of satisfactory regulatory approvals, including approval of
the Massachusetts Department of Telecommunications and Energy, the Securities
and Exchange Commission, and antitrust clearance.
Report of Independent Certified Public Accountants
To the Shareholders of Colonial Gas Company
We have audited the accompanying consolidated balance sheets of Colonial Gas
Company and subsidiaries as of December 31, 1998 and 1997, and the related
consolidated statements of income, cash flows, and common equity for each of the
three years in the period ended December 31, 1998. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and the significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Colonial Gas
Company and subsidiaries as of December 31, 1998 and 1997, and the consolidated
results of their operations and their consolidated cash flows for each of the
three years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
Boston, Massachusetts sGrant Thornton LLP
January 15, 1999 Grant Thornton LLP
REPORT OF MANAGEMENT
To the Shareholders of Colonial Gas Company
Management is responsible for the preparation and integrity of the Company's
financial statements. The financial statements have been prepared in accordance
with generally accepted accounting principles as applied to regulated public
utilities and necessarily include some amounts that are based on management's
best estimates and judgment.
The Company maintains a system of internal accounting and administrative
controls and an ongoing program of internal audits that management believes
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with management's
authorization. The Company's financial statements have been audited by the
independent public accounting firm, Grant Thornton LLP, who also conducts a
review of internal controls to the extent required by generally accepted
auditing standards.
The Audit Committee of the Board of Directors, composed solely of outside
directors, meets with management, internal auditors and Grant Thornton LLP to
review planned audit scope and results and to discuss other matters affecting
internal accounting controls and financial reporting. The independent
accountants and internal auditors have direct access to the Audit Committee and
periodically meet with its members without management representatives present.
sF. L. Putnam, III sNickolas Stavropoulos
F. L. Putnam, III Nickolas Stavropoulos
President and Chief Executive Executive Vice President-Finance,
Officer Marketing and Chief Financial Officer