[EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1995 1994 1993
Operating Revenues $164,649 $166,259 $166,261
Cost of gas sold 83,631 87,458 90,915
Operating Margin 81,018 78,801 75,346
Operating Expenses:
Operations 31,309 33,004 32,957
Maintenance 4,401 5,074 4,726
Depreciation and amortization 10,225 9,235 6,831
Local property taxes 3,020 2,740 2,496
Other taxes 2,130 2,182 2,055
Restructuring charge - 3,185 -
Total Operating Expenses 51,085 55,420 49,065
Income Taxes:
Federal income tax 6,912 4,806 6,111
State franchise tax 1,447 1,058 1,280
Total Income Taxes 8,359 5,864 7,391
Utility Operating Income 21,574 17,517 18,890
Other Operating Income (Expense):
Truck transportation revenues 7,576 12,066 7,558
Truck transportation expenses,
including income taxes and interest (6,972) (10,579) (7,163)
Truck Transportation Net Income 604 1,487 395
Other, net of income taxes (8) (151) (186)
Total Other Operating Income 596 1,336 209
Non-Operating Income, Net of Income 864 565 1,064
Taxes
Income Before Interest and Debt 23,034 19,418 20,163
Expense
Interest and Debt Expense 9,270 8,409 8,141
Net Income $13,764 $11,009 $12,022
Average Common Shares Outstanding 8,294 8,119 7,931
Income per Average Common Share $1.66 $1.36 $1.52
Dividends Paid per Common Share $1.275 $1.255 $1.235
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF INCOME]
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1995 1994
Utility Property:
At original cost $308,191 $287,158
Accumulated depreciation (72,636) (65,473)
Net Utility Property 235,555 221,685
Non-Utility Property - Net 5,036 3,479
Net Property 240,591 225,164
Capital Leases - Net 2,253 2,948
Current Assets:
Cash and cash equivalents 7,541 9,026
Accounts receivable 19,069 13,846
Allowance for doubtful accounts (2,205) (1,670)
Accrued utility revenues 8,924 6,148
Unbilled gas costs 9,688 12,178
Fuel inventory - at average cost 10,516 12,959
Materials and supplies - at average 3,132 3,537
cost
Prepayments and other current assets 4,337 9,544
Total Current Assets 61,002 65,568
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 10,562 11,471
Unrecovered demand side management costs 4,977 3,120
Unrecovered environmental costs incurred 4,761 4,577
Unrecovered environmental costs accrued 2,300 3,800
Unrecovered pension costs 3,917 2,607
Unrecovered transition costs accrued 3,600 4,700
Excess cost of investments over net assets 2,798 2,798
acquired
Other 5,660 4,595
Total Deferred Charges and Other 38,575 37,668
Assets
Total Assets $342,421 $331,348
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1995 1994
Capitalization:
Common Equity:
Common Stock $27,863 $27,397
Premium on Common Stock 51,447 49,211
Retained earnings 25,760 22,567
Total Common Equity 105,070 99,175
Long-Term Debt 75,418 77,923
Total Capitalization 180,488 177,098
Capital Lease Obligations 1,359 2,237
Current Liabilities:
Current maturities of long-term debt 6,141 8,449
Current capital lease obligations 894 712
Notes payable 61,835 49,500
Gas inventory purchase obligations 12,340 13,860
Accounts payable 12,150 9,635
Accrued interest 1,065 1,085
Pipeline refunds due customers 1,310 2,289
Current deferred income taxes 314 2,139
Other current liabilities 5,617 3,713
Total Current Liabilities 101,666 91,382
Deferred Credits and Reserves:
Deferred income taxes - Funded 32,299 29,373
Deferred income taxes - Unfunded 10,562 11,471
Deferred income taxes - Due customers 112 378
Accrued environmental costs 2,300 3,800
Accrued transition costs 3,600 4,700
Unamortized investment tax credits 3,940 4,215
Pension reserve 4,929 5,510
Other deferred credits and reserves 1,166 1,184
Total Deferred Credits and Reserves 58,908 60,631
Total Capitalization and Liabilities $342,421 $331,348
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED BALANCE SHEETS]
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1995 1994 1993
Cash Flows From Operating Activities:
Net Income $13,764 $11,009 $12,022
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 11,211 10,150 7,703
Deferred income taxes 1,159 3,555 2,139
Amortization of investment tax credits (275) (234) (255)
Provision for uncollectible accounts 1,829 1,803 2,102
Other, net 973 811 190
28,661 27,094 23,901
Changes in current assets and
liabilities:
Accounts receivable (6,517) 495 773
Accrued utility revenues (2,776) 1,022 (1,678)
Unbilled gas costs 2,490 4,581 2,122
Fuel inventory 2,443 758 (285)
Materials and supplies 405 275 56
Prepayments and other current assets 5,207 (3,290) 2,055
Accounts payable 2,515 (2,526) (382)
Accrued interest (20) 68 (7)
Pipeline refunds due customers (979) 213 620
Accrued pipeline charges - (305) (606)
Current deferred income taxes (1,825) (73) (2,111)
Other current liabilities 1,904 (13) 933
Net Cash Provided by Operating 31,508 28,299 25,391
Activities
Cash Flows From Investing Activities:
Utility capital expenditures (24,096) (28,195) (25,703)
Non-utility capital expenditures (1,974) (876) (453)
Sale of non-utility assets - - 586
Change in deferred accounts (2,077) (716) (354)
Net Cash Used in Investing Activities (28,147) (29,787) (25,924)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,571) (10,187) (9,793)
Issuance of Common Stock 2,702 4,070 4,283
Issuance of long-term debt, net of
issuance costs 19,685 741 -
Retirement of long-term debt, (27,477) (5,119) (1,500)
including premiums
Change in notes payable 12,335 16,900 8,100
Change in gas inventory purchase (1,520) (1,373) 492
obligations
Net Cash (Used in) Provided by (4,846) 5,032 1,582
Financing Activities
Net (Decrease) Increase in Cash and (1,485) 3,544 1,049
Cash Equivalents
Cash and Cash Equivalents at Beginning 9,026 5,482 4,433
of Year
Cash and Cash Equivalents at End $ 7,541 $ 9,026 $ 5,482
of Year
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 9,867 $ 9,283 $ 8,891
Income and state franchise taxes $ 3,444 $ 7,282 $ 4,939
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF CASH FLOWS]
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1995 1994 1993
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,367 in 1995, 8,227 in 1994,
and 8,030 in 1993
Beginning of year $27,397 $26,739 $26,122
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (140 shares
in 1995, 197 shares in 1994 and 186
shares in 1993) 466 658 617
End of year $27,863 $27,397 $26,739
Premium on Common Stock
Beginning of year $49,211 $45,799 $42,133
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 2,236 3,412 3,666
End of year $51,447 $49,211 $45,799
Retained Earnings
Beginning of year $22,567 $21,745 $19,516
Net income 13,764 11,009 12,022
Cash dividends on Common Stock ($1.275
a share in 1995, $1.255 a share in
1994 and $1.235 a share in 1993) (10,571)(10,187) (9,793)
End of year $25,760 $22,567 $21,745
Total Common Equity $105,070 $99,175 $94,283
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF COMMON EQUITY]
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 141,000 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 Public Utilities
(DPU) 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 $568,000,
$294,000 and $227,000 in 1995, 1994 and 1993, 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 DPU. The composite
depreciation rate which was approximately 2.91% through October
31, 1993, was increased to approximately 3.77% effective with a
rate increase as approved by the DPU on November 1, 1993. The
composite depreciation rate 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 $8,924,000 and
$6,148,000, as reported in the Consolidated Balance Sheets at
December 31, 1995 and 1994, 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 and approved by the
DPU. In September 1995, the Company received approval from the DPU
to recover financial incentives and lost margins associated with
the residential DSM programs. Based on this approval, the Company
recorded $900,000 of lost margins and $220,000 of financial
incentives as revenue in 1995. No lost margins or incentives for
the commercial DSM programs have been recorded to date.
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 DPU.
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 DPU, 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 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 and additional
contributions to fund the unqualified individual retirement
agreements.
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 $81,559,000 and $86,372,000 as of December 31, 1995
and 1994, respectively. The fair value of long-term debt was
$89,724,000 and $88,425,000 as of December 31, 1995 and 1994,
respectively.
Under current regulatory treatment, any premiums paid to
refinance long-term debt, would be recovered over the life of the
new debt, and would not have a significant impact on the Company's
results of operations.
Reclassifications - Reclassifications are made periodically to
previously issued financial statements to conform to the current
year presentation.
New Accounting Standard - In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards
No. 121 "Accounting for the Impairment of Long-Lived Assets and
Long-Lived Assets to be Disposed Of", which will be effective for
the Company's fiscal year ending December 31, 1996. This statement
requires the Company to review long-lived assets for impairment
whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. The Company
intends to adopt this statement prospectively. The impact of this
standard is not expected to have a material impact on the
Company's financial condition or results of operations.
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 DPU, the Company did
not record deferred income taxes but rather "flowed through" tax
benefits to utility customers. At December 31, 1995, the Company
has a liability of $10,562,000 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, 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.
The Company has a liability (Deferred Income Taxes- Due
Customers) of $112,000 at December 31, 1995, representing the
amount of pre-July 1, 1987 deferred income taxes that were
recorded in excess of the Federal statutory income tax rate of
34%. This liability is being returned to utility customers over
the remaining book life of utility property. This liability is
also charged for any Federal income taxes at rates above 34%.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1995 1994 1993
Charged (credited) to operations:
Current $6,455 $2,157 $5,191
Deferred:
Unbilled gas costs (1,523) (106) (1,753)
Accelerated depreciation 2,005 2,167 2,157
Demand side management costs (32) 1,115 -
Pension (38) (840) 141
Recovery of unfunded deferred taxes 398 398 556
Debt expense 848 (21) (20)
Transition costs (871) (55) -
Miscellaneous (57) 221 84
Amortization of investment tax (273) (230) (245)
credits
Total 6,912 4,806 6,111
Charged to other income 477 1,014 578
Total Federal income tax expense $7,389 $5,820 $6,689
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1995 1994 1993
Statutory Federal income tax rate 35% 35% 35%
Increases (reductions) in taxes
resulting from:
Amortization of investment tax (1) (1) (1)
credit
Recovery of unfunded deferred taxes 2 2 3
Miscellaneous items (1) (1) (1)
Effective Federal income tax rate 35% 35% 36%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1995 1994
Construction contributions $ 1,060 $ 1,117
Other 1,468 943
Total deferred tax assets 2,528 2,060
Accelerated depreciation (36,949) (34,698)
Cost of removal (2,554) (2,364)
Unbilled gas costs (315) (3,184)
Environmental response costs (1,865) (1,839)
Demand side management costs (1,764) (1,803)
Other (2,256) (1,155)
Total deferred tax liabilities (45,703) (45,043)
Total deferred taxes $(43,175) $(42,983)
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. 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: Retained Earnings
The Company's ability to pay dividends on its Common Stock from
retained earnings is restricted by the first mortgage bond
indenture and by the bank line of credit. Under the most
restrictive covenant, approximately $23,943,000 of retained
earnings was available to pay dividends on Common Stock as of
December 31, 1995.
Note E: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1995 1994
First mortgage bonds:
14.00% Series CC due 1999 $ - $ 500
8.86% Series CD due 2001 6,000 7,000
9.40% Series CE due 1997 10,000 15,000
10.25% Series CF due 2004 - 18,182
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
6.85% Series MTA-1 due 2025 10,000 -
6.45% Series MTA-2 due 2025 10,000 -
Total 81,000 85,682
Note payable 559 690
Less: Long-term debt due within (6,141) (8,449)
one year
Total long-term debt $75,418 $77,923
The aggregate amount of maturities and sinking fund requirements
for the years 1996, 1997, 1998, 1999, and 2000 are $6,141,000,
$6,152,000, $1,164,000, $21,102,000, and $1,000,000, respectively.
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.
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. It is anticipated that the remaining bonds under the MTN
program will be issued in several series over the next two years.
On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.
Note F: Short-Term Debt
In July 1994, the Company established a three-year bank line of
credit of $75 million with a consortium of four banks. 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 four
alternative rates: prime rate, certificate of deposit rate,
eurodollar rate (LIBOR), and a competitive bid option. At December
31, 1995, the credit available under the bank line of credit was
$825,000. The weighted average interest rates for short-term debt
were 6.03% and 6.25% at December 31, 1995 and 1994, 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 DPU 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 1995, 1994 and
1993 approximately $529,000, $504,000 and $390,000, respectively,
of financing costs were incurred by the trust.
Note G: Lease Obligations
The Company leases certain facilities and 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
$7,291,000 and $7,230,000 at December 31, 1995 and 1994,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $5,038,000 and $4,282,000
at December 31, 1995 and 1994, respectively.
The most significant agreements which meet the criteria for
capital lease classification are a lease which expires in 1998 for
a liquefied natural gas storage tank in South Yarmouth,
Massachusetts and a lease which expires in 2002 for office
facilities in Lowell, Massachusetts. Both leases have fair market
renewal options at the end of their initial terms.
Total rental expense for the years 1995, 1994 and 1993
approximated $1,429,000, $2,049,000 and $1,808,000, respectively.
At December 31, 1995, the future minimum payments (including
interest) under the Company's lease agreements are: $894,000 in
1996; $742,000 in 1997; $605,000 in 1998; $296,000 in 1999;
$254,000 in 2000; and $355,000 thereafter.
Note H: 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 $459,000, $387,000 and $418,000 for
1995, 1994 and 1993, 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) 1995 1994 1993
Benefits earned during the period $ 836 $ 1,195 $ 1,031
Interest cost on projected 3,279 2,803 2,690
benefit obligation
Actual return on plan assets (5,515) 77 (2,656)
Net amortization and deferral 2,757 (2,657) 325
Net periodic pension cost $1,357 $1,418 $1,390
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1995 1994 1993
Weighted average discount rate 7.50% 8.50% 7.25%
Future compensation increases 4.00% 5.00% 5.00%
Expected long-term rate of return 9.00% 9.00% 9.00%
on assets
The funded status of the plans at December 31, 1995 and 1994 is as
follows:
1995 1994
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(28,993) $(10,388) $(21,897) $(8,544)
Nonvested (628) (869) (2,988) (563)
Accumulated (29,621) (11,257) (24,885) (9,107)
Due to recognition of
future salary increases (4,173) (88) (4,664) (42)
Total (33,794) (11,345) (29,549) (9,149)
Plan assets at fair 31,168 6,420 27,715 5,259
value
Projected benefit (2,626) (4,925) (1,834) (3,890)
obligation
in excess of
plan assets
Unrecognized net loss 1,758 1,232 (227) 513
(gain)
Unrecognized 1,572 1,247 2,059 1,430
transition amount
Unrecognized prior 347 1,493 448 706
service cost
Additional liability - (3,885) - (2,607)
accrued
Prepaid (accrued) $1,051 $(4,838) $ 446 $(3,848)
pension costs
Assets of the employee benefit plans are invested in domestic and
international equities, medium-term domestic fixed income
securities, international fixed income securities, real estate and
other short-term debt instruments.
Additional benefits upon retirement were given to 47 employees who
accepted the voluntary early retirement program in 1994. The
additional loss of $2,537,000 as a result of this program was
recorded as a restructuring charge in the fourth quarter of 1994.
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. As permitted by SFAS 106,
the Company will record the transition obligation over a twenty-
year period. The Company's cost under this plan for 1995, 1994 and
1993 was $672,000, $694,000 and $817,000, respectively. A
regulatory asset of $431,000 was recorded in 1993, leaving a net
expense of $386,000. This regulatory asset represents 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 DPU's approval of the Company's new
rates. Currently, the DPU 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 a trust under Section 501(c)(9)
of the Internal Revenue Code and separate accounts of the trust
under Section 401(h) of the Internal Revenue Code. The Company is
currently funding an amount each year equal to the maximum tax
deductible amount.
The following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1995 and 1994:
(In Thousands) 1995 1994
Accumulated postretirement
benefit obligation:
Retirees $(3,816) $(2,416)
Fully eligible active plan (1,047) (1,457)
participants
Other active plan (1,275) (1,782)
participants
(6,138) (5,655)
Plan assets at fair value 4,102 3,135
Accumulated postretirement (2,036) (2,520)
benefit obligation
in excess of plan assets
Unrecognized net (gain) from (1,310) (1,016)
past experience
different from that assumed
and from changes in assumptions
Unrecognized transition obligation 4,584 4,854
Prepaid postretirement benefit $1,238 $1,318
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended December 31,
(In Thousands) 1995 1994 1993
Service cost - benefits $145 $202 $268
attributable to service
during the period
Interest cost on accumulated 505 455 478
postretirement
benefit obligation
Actual return on plan assets (639) 143 (202)
Net amortization and deferral 661 (106) 273
Net periodic postretirement $672 $694 $817
benefit cost
For measurement purposes, a 7% (4.5% for dental costs) annual
rate of increase in the per capita cost of covered health care
benefits was assumed for 1996; the rate of increase for medical
costs was assumed to decrease gradually from 7% to 4.5% in 2001
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,
1995 by $706,000 and the aggregate of the service and the interest
cost components of net periodic postretirement benefit cost for
the year then ended by $84,000.
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5% and 8.5%
for 1995 and 1994, respectively. The expected long-term rate of
return on plan assets was 9% for assets in the Section 401(h)
accounts and, after estimated taxes, was 6% for assets in the
Section 501(c)(9) trust for all years presented.
Postemployment Benefits - During 1994, the Company adopted
Statement of Financial Accounting Standards No. 112 "Employer's
Accounting for Postemployment Benefits" (SFAS 112). This statement
requires accrual accounting for benefits to former or inactive
employees after employment but before retirement. The adoption of
SFAS 112 did not have a significant effect on the Company's
results of operations.
Note I: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2012, for the acquisition 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 expected to be 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 transition cost liabilities are estimated to range from
$11,600,000 to $16,400,000, of which the Company has paid
$8,000,000 through December 31, 1995. The Company is recovering
these costs from its customers, as approved by the DPU in October
1994. As of December 31, 1995, the Company has recorded on the
balance sheet a long-term liability of $3,600,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $3,600,000 ("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 J: Contingencies
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 DPU 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, 1995, the
Company had incurred environmental response costs of $10,418,000
of which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects to
continue incurring costs arising from these environmental matters.
As of December 31, 1995, the Company has recorded on the balance
sheet a long-term liability of $2,300,000 representing estimated
future response costs for these sites based on the Company's
preferred methods of remediation, of which $1,700,000 relates to
the gas manufacturing site. Based upon the DPU order approving
rate recovery of environmental response costs, a regulatory asset
of $2,300,000 has been recorded on the balance sheet ("Unrecovered
Environmental Costs Accrued"). 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.
As of December 31, 1995, the Company had settled claims relating
to these matters with all liability insurers and other known
potentially responsible parties (PRP). In accordance with the DPU
order referred to above, half the costs incurred in pursuing
insurers and other PRP are recovered from the ratepayers through
the CGAC and half are initially borne by the Company. Also, per
this order, any insurance and other proceeds are applied first to
the Company's costs of pursuing recovery from insurers and other
PRP, with the remainder divided equally between the ratepayers and
shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Thousands) Response Costs Insurance and Other Proceeds
Recovered Period Recorded as
from of Rate Returned to Non-Operating
Year Incurred Customers Recovery Customers Income Net of
Taxes
1988 $ 853 $ 732 1990-1997 - -
1989 4,031 3,455 1990-1997 - -
1990 639 457 1991-1998 - -
1991 374 213 1992-1999 $ 851 $ 525
1992 617 264 1993-2000 1,121 673
1993 1,226 350 1994-2001 469 290
1994 1,321 189 1995-2002 122 75
1995 1,357 - 1996-2003 - -
Total $10,418 $5,660 $2,563 $1,563
Note K: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)
Income
Utility (Loss) Per Dividends
Operating Net Average Paid Per
Operating Income Income Common Common
Quarter Ended Revenues (Loss) (Loss) Share Share
1995
December 31 $56,625 $10,283 $8,530 $1.02 $.320
September 30 14,911 (2,251) (3,932) (.47) .320
June 30 22,760 (925) (3,283) (.40) .320
March 31 70,353 14,467 12,449 1.51 .315
1994
December 31 $48,077 $6,741 $4,782 $ .58 $.315
September 30 13,026 (3,132) (4,834) (.59) .315
June 30 19,073 (1,849) (3,338) (.41) .315
March 31 86,083 15,757 14,399 1.79 .310
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 L: Restructuring Charge
In the fourth quarter of 1994, the Company recorded a
restructuring charge of $3,185,000 ($1,965,000 after-tax or $.24
per share). This amount includes $2,537,000 for the cost of a
voluntary early retirement program which was accepted by 47
employees and $648,000 for costs accrued by the Company in
connection with the closure of two retail appliance stores.
[END OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS]
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, 1995 and
1994, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and 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, 1995 and 1994, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
GRANT THORNTON LLP
Boston, Massachusetts
January 17, 1996
[END OF REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS]
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income and Dividends
Net income and income per average common share were $13,764,000
($1.66), $11,009,000 ($1.36) and $12,022,000 ($1.52) for the three
years ended December 31, 1995, 1994, and 1993, respectively.
Before a restructuring charge after-tax of $1,965,000 or $.24 per
share, 1994 net income and income per average common share were
$12,974,000 ($1.60).
Net income was favorably impacted by colder-than-normal
temperatures in 1995, 1994 and 1993, although at declining
percentages over the periods. This is summarized as follows:
1995 1994 1993
Percent colder than normal 2.7% 5.3% 6.7%
Percent (warmer) colder than prior year (2.5)% (1.3)% 3.3%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.275 in 1995, $1.255 in
1994 and $1.235 in 1993. The Company has paid dividends for 59
consecutive years, and has increased dividends each year for the
past 16 years.
Operating Revenues
Operating revenues were $164,649,000 in 1995, $166,259,000 in 1994
and $166,261,000 in 1993. Operating revenues are impacted by the
volumes of gas sold and transported, changes in base rates as
approved by the Massachusetts Department of Public Utilities
(DPU), and the pass-through of gas costs to customers via a cost
of gas adjustment clause (CGAC).
The volumes of gas sold are affected by fluctuations in weather
and the number of customers being served. Firm sales customers
increased by 13,395 over the last three years from 127,964 in 1992
to 141,359 in 1995, an increase of 10.5%, which has added to firm
sales volume. The chart below summarizes volumes of gas sold and
transported and number of firm sales customers:
1995 1994 1993
(In MMcf)
Gas sold
Firm 18,560 18,716 18,935
Non-Firm 1,148 729 1,030
Gas transported
Firm 2,537 6,090 4,163
Non-Firm 3,224 4,185 4,026
Total gas sold and
transported (In MMcf) 25,469 29,720 28,154
Firm Sales Customers 141,359 136,636 132,187
Operating revenues decreased $1,610,000, or 1.0%, from 1994 to
1995. This decrease resulted primarily from weather that was 2.5%
warmer than the prior year (although 2.7% colder than normal)
partially offset by a growing customer base and additional revenue
of $1,120,000 resulting from regulatory approval to recover lost
margins and financial incentives associated with the Company's
residential conservation programs.
Operating revenues were unchanged from 1993 to 1994. Utility
revenues were positively impacted during 1994 by a 3.4% customer
growth and a 4.9% rate increase which became effective in November
1993. Weather, although 5.3% colder than normal, was 1.3% warmer
than 1993.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.22 in 1995, $4.48 in 1994
and $4.53 in 1993. Cost of gas sold is based upon the sales
volumes, the price and mix of gas purchased and used to satisfy
demand, and profits on non-firm sales and transportation, which
flow back to firm sales customers as a credit through the CGAC.
The Company distributes natural gas purchased under long-term
contracts as well as gas purchased on the spot market. The
following table summarizes the sources of gas purchased by the
Company:
(In MMcf) 1995 1994 1993
Gas purchased
Pipeline 14,659 14,392 14,983
Underground storage 3,270 3,112 3,501
LNG/Other 2,426 2,390 1,832
Total gas purchased 20,355 19,894 20,316
Underground storage consists primarily of spot gas purchased and
injected into storage during the summer and fall for use during
the following winter.
Operating Expenses
Operations expense was $31,309,000 in 1995, a decrease of
$1,695,000 or 5.1%, from 1994, and $33,004,000 in 1994, an
increase of $47,000, or 0.1%, from 1993. In 1994, the Company
conducted a self-examination to reduce its cost structure. The
decrease in 1995 was primarily due to less payroll and related
benefits as a result of the early retirement program and other
cost saving initiatives. The Company has budgeted no increase in
operations and maintenance costs in 1996.
Maintenance expense decreased $673,000, or 13.3%, in 1995 from
1994 and increased $348,000, or 7.4%, in 1994 from 1993. The
decrease in 1995 was primarily due to cost controls resulting from
the Company's self-examination in 1994. The increase in 1994 was
primarily due to increased labor resulting from colder weather
during the first quarter.
Depreciation and amortization expense increased 10.7% or
$990,000 in 1995 and 35.2% or $2,404,000 in 1994. The increase in
1995 was due to an increase in utility property. The increase in
1994 was primarily due to the increased depreciation rates as a
result of the Company's 1993 rate order and an increase in utility
property.
Local property and other taxes increased 4.6% in 1995 from 1994
and 8.2% in 1994 from 1993. The increase in 1995 was due to higher
property taxes and additional property subject to property subject
to property taxes. The increase in 1994 was due to higher property
and payroll taxes, and additional property subject to property
taxes.
A restructuring charge of $3,185,000 ($1,965,000 after-tax or
$.24 per share) was recorded during the fourth quarter of 1994.
This amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.
Income Taxes
Total Federal income and state franchise taxes increased 42.5% or
$2,495,000 in 1995 as a result of a higher level of income. Total
Federal income and state franchise taxes decreased 20.7% or
$1,527,000 in 1994 as a result of less income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $596,000
in 1995, $1,336,000 in 1994 and $209,000 in 1993. Other operating
income primarily includes the results of the Company's wholly-
owned energy trucking subsidiary (Transgas). Also included are
heating and water heating equipment sales and installations. As
discussed previously, the Company's retail appliance sales
operation was discontinued as of December 31, 1994.
Transgas' 1994 financial results were driven by extremely cold
weather in the first quarter of 1994 which generated a significant
increase in demand for the truck transportation of liquefied
natural gas (LNG) and propane throughout the first three quarters
of 1994. This accounts for the sharp increase in 1994 other
operating income.
Factors affecting the future financial results of Transgas
include the amount of LNG used by local distribution companies
throughout the northeast United States to satisfy requirements of
their customers; the price of domestic and Canadian natural gas
compared to imported LNG; the continued availability of imported
LNG; and the level of construction and major maintenance projects
of interstate pipeline companies which drives the demand for
portable pipeline services.
Non-Operating Income
Non-operating income, net of income taxes, was $864,000 in 1995,
$565,000 in 1994 and $1,064,000 in 1993. Non-operating income
includes interest income and miscellaneous other income. Included
in non-operating income for 1994 and 1993 were recoveries of
$75,000 and $290,000, respectively, resulting from settlements
reached with insurers and other potentially responsible parties
relating to environmental response costs as described under
"Environmental Matters". Also included in non-operating income for
1993 is an insurance recovery of $509,000 relating to a line of
business that was discontinued in 1979.
Interest and Debt Expense
Interest and debt expense increased 10.2% and 3.3% in 1995 and
1994, respectively. The increase in 1995 was due to increased
levels of short-term debt and higher short-term interest rates
partially offset by a decrease in interest on long-term debt. The
increase in 1994 was due to increased levels of short-term debt
and higher short-term interest rates partially offset by a
decrease in interest on long-term debt due to paydowns in 1993.
Effects of Inflation
Inflation generally has a negative impact upon the Company's
profitability since the rates charged to the Company's utility
customers, excluding changes in the cost of gas sold, cannot be
increased without formal proceedings before the DPU. Changes in
the cost of gas sold are automatically reflected in customer rates
pursuant to semi-annual adjustments under the CGAC. In the absence
of authorized rate increases, the Company must look to increased
productivity and higher sales volumes to offset inflationary
increases in its other costs of operations. The present regulatory
process permits the Company to earn a rate of return based on the
historical cost of utility property without recognition of the
current replacement cost. The Company's policy is to file for an
increase in rates only when increases in productivity and
customers are not sufficient to counteract the impact of
inflation. The Company has set a goal to defer its next base rate
increase until at least the year 2000.
Regulatory Matters
Environmental response costs, transition costs and demand side
management (DSM) program costs are recovered through the CGAC, as
approved by the DPU. The environmental response costs recovered
through the CGAC relate to the Company's former gas manufacturing
operations, as described under "Environmental Matters". Transition
costs relate to FERC approved pipeline charges resulting from
Order 636. In addition to full recovery of the installed
conservation measures, the Company is allowed to recover the
margins lost as a result of the DSM programs and financial
incentives based on the attainment of performance goals. In
September 1995, the Company received approval from the DPU to
recover lost margins and financial incentives associated with the
residential DSM programs. Based on this approval, the Company
recorded as operating revenues $900,000 of lost margins and
$220,000 of financial incentives in 1995. The Company anticipates
recording as operating revenues approximately $1 million of lost
margins and incentives associated with the residential and
commercial DSM programs in 1996.
In 1993, the Company applied for what was only its second base
rate increase request since 1984. Effective November 1, 1993, the
Company received DPU approval of a settlement agreement that
called for a base rate increase designed to produce additional
revenues of $6.7 million or 4.9% annually. In addition to this
rate increase, the DPU approved a proposal to expand the
eligibility criteria for Colonial's discount rate for low-income
residential heating customers and allowed the Company to retain
10% of the revenues generated from releasing the Company's
interstate pipeline transportation capacity to third parties above
an initial threshold of $2,500,000. In 1995, the Company received
$2,818,000 of capacity release revenue, $2,786,000 of which was
credited back to firm customers and $32,000 of which was retained
by the Company.
The table below summarizes the Company's last three requests to
increase base revenue:
Increase Requested Increase Approved
Date Effective Amount Percentage Amount Percentage
November 1, 1984 $ 4.30 million 3.73% $2.8 million 2.4%
November 1, 1990 $12.80 million 9.86% $7.9 million 5.6%
November 1, 1993 $10.75 million 7.87% $6.7 million 4.9%
In 1993, Colonial began unbundling its firm sales service to
commercial and industrial customers by offering a tariffed firm
transportation-only service. Pursuant to this service, a customer
procures its own gas supply and contracts with Colonial for firm
transportation service through Colonial's distribution system. As
of December 31, 1995, 11 customers had opted for tariffed firm
transportation service, representing less than 2% of the Company's
annual firm load.
Two 1994 DPU industry-wide proceedings may result in the further
unbundling and deregulation of the Company's business. One of
those proceedings addresses whether and how the traditional cost-
of-service/rate-of-return method of regulating gas and electric
utilities might be replaced with some type of alternative
"incentive" method. In a ruling issued in February 1995, the DPU
indicated that it has the authority to implement incentive
regulation and would be receptive to various types of proposals.
The Company continues to analyze specific incentive regulation and
unbundling options which it could propose to the DPU as a means of
benefiting its customers and shareholders. The other proceeding
addresses whether interruptible transportation and interruptible
sales service on local distribution company (LDC) systems, and the
release of interstate pipeline capacity by LDCs, should be
structured or priced differently. The Company expects DPU rulings
containing general guidelines on these matters in 1996.
Environmental Matters
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 DPU 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, 1995, the
Company had incurred environmental response costs of $10,418,000,
of which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects to
continue incurring costs arising from these environmental matters.
As of December 31, 1995, the Company had recovered $5,660,000 from
customers and $1,563,000 from liability insurers and other known
potentially responsible parties.
As of December 31, 1995, the Company has recorded on the balance
sheet a long-term liability of $2,300,000 and, based upon rate
recovery, has recorded a corresponding regulatory asset. The
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation, of which
$1,700,000 relates to the gas manufacturing site. 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.
Accounting Standards
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of", which will be effective for the Company's fiscal
year ending December 31, 1996. This statement requires the Company
to review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company intends to adopt this
statement prospectively. The impact of this standard is not
expected to have a material impact on the Company's financial
condition or results operations.
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. As permitted by SFAS 106, the Company will
record the transition obligation over a twenty-year period. The
Company's cost under this plan for 1995, 1994 and 1993 was
$672,000, $694,000 and $817,000, respectively. A regulatory asset
of $431,000 was recorded in 1993, leaving a net expense of
$386,000. This regulatory asset represents 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 DPU's approval of the Company's new rates.
Currently the DPU allows Massachusetts utilities to recover the
tax deductible portion of these postretirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
The Company's liquidity is affected by its ability to generate
funds from operations and to access capital markets. The Company's
operations are seasonal with its cash flow reflecting this
seasonality. The Company typically generates approximately 70
percent of its annual operating revenues during the November
through April heating season, which results in a high level of
cash flow from operations from late winter through early summer.
As a result of this seasonality, the Company's liquidity can be
affected by significant variations in weather. Short-term
borrowings are highest during the fall and early winter months due
to the completion of the annual construction program and seasonal
working capital requirements.
Investing Activities
The Company invests in property, plant and equipment to improve
and protect its distribution system, and to expand its system to
meet customer demand. Utility capital expenditures were
$24,096,000 in 1995, $28,195,000 in 1994 and $25,703,000 in 1993.
The Company's long-range plan calls for annual utility
expenditures, of which over 40% is budgeted for new business,
averaging $27,000,000 over the next five years as follows:
(In Thousands) 1996 1997 1998 1999 2000
Distribution $20,700 $22,700 $22,300 $26,500 $24,800
Production 1,400 1,000 1,000 700 750
Information Systems 4,300 1,000 700 500 140
Automated Meter 1,100 1,100 $1,100 1,100 30
Reading
General 300 700 300 400 380
Total Capital $27,800 $26,500 $25,400 $29,200 $26,100
Expenditures
Financing Activities
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. In February 1996, the Company issued $10 million of 30-
year bonds with an interest rate of 6.94%. It is anticipated that
the remaining bonds under the MTN program will be issued in several
series over the next two years.
On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.
The Company has a $75 million credit facility which allows it to
meet its seasonal working capital needs. The present facility
expires in June 1997. Up to $30 million of the credit facility can
be used by the Company's gas inventory trust. The credit facility
allows the Company the option to borrow under any one of four
alternative rates.
The Company has raised permanent capital during the last three
years as follows:
(In Thousands) 1995 1994 1993
Common Stock Under Dividend Reinvestment
and Common Stock Purchase Plan and
Employee Savings Plan $2,702 $4,070 $4,283
Long-Term Debt
Note Payable - $ 741 -
MTA-1, 6.85%, due 2025 * $10,000 - -
MTA-2, 6.45%, due 2025 * $10,000 - -
* Subject to redemption in 2005 at the option of the holder
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1995 1994 1993
Equity 58% 56% 52%
Long-Term Debt 42% 44% 48%
As of April 1995, the quarterly dividend paid on the Company's
Common Stock was increased to $.32 per share or an annualized
dividend rate of $1.28 per share.
[END OF MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS]
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)
1995 1994 1993 1992 1991
Balance Sheet Data:
Assets:
Utility property-net $235,555 $221,685 $202,713 $183,815 $162,736
Non-Utility property-net 5,036 3,479 3,235 4,039 4,767
Capital leases-net 2,253 2,948 3,914 4,366 4,557
Current assets 61,002 65,568 67,668 71,763 53,472
Deferred charges and 38,575 37,668 34,588 38,939 38,789
other assets
Total $342,421 $331,348 $312,118 $302,922 $264,321
Capitalization and
Liabilities:
Capitalization:
Common equity $105,070 $ 99,175 $ 94,283 $ 87,771 $ 82,221
Long-term debt 75,418 77,923 87,432 90,750 50,410
Total Capital-
ization 180,488 177,098 181,715 178,521 132,631
Capital lease 1,359 2,237 3,149 3,591 3,838
obligations
Current liabilities 101,666 91,382 73,413 64,567 73,993
Deferred credits and 58,908 60,631 53,841 56,243 53,859
reserves
Total $342,421 $331,348 $312,118 $302,922 $264,321
Income Statement Data:
Operating revenues $164,649 $166,259 $166,261 $145,054 $137,719
Cost of gas sold (83,631) (87,458) (90,915) (75,143) (73,288)
Operating margin 81,018 78,801 75,346 69,911 64,431
Operating expenses (59,444) (61,284) (56,456) (52,760) (48,009)
(including income
taxes)
Utility operating 21,574 17,517 18,890 17,151 16,422
income
Other income- 1,460 1,901 1,273 958 36
net of income taxes
Interest and (9,270) (8,409) (8,141) (7,466) (8,141)
debt expense
Accounting change - - - - -
Preferred stock - - - - -
dividends
Net income applicable $13,764 $11,009 $12,022 $10,643 $8,317
to common stock
Capitalization Ratios:
Common equity 58% 56% 52% 49% 62%
Long-term debt 42% 44% 48% 51% 38%
Common Stock Data:
Average shares 8,294 8,119 7,931 7,728 7,529
outstanding
Income per share $1.66 $1.36(a) $1.52 $1.38 $1.10
Dividends paid per share:
Common Stock $1.275 $1.255 $1.235 $1.213 $1.193
Class A Common Stock - - - - -
Per weighted average $1.275 $1.255 $1.235 $1.213 $1.193
common share
Dividend payout rate 77% 92% 81% 88% 108%
Book value per share $12.56 $12.05 $11.74 $11.19 $10.78
Dividends as a percent 10% 10% 11% 11% 11%
of book value
Market price per share $20.25 $19.25 $22.50 $21.25 $17.50
Market price as a 161% 160% 192% 190% 162%
percent of book value
Return on average 13.5% 11.4% 13.2% 12.5% 10.2%
common equity
(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting change
of $.33 per share.
SELECTED FINANCIAL DATA - Continued
(For the Years Ending December 31)
(In Thousands Except Per Share Amount)
1990 1989 1988 1987 1986
Balance Sheet Data:
Assets:
Utility property-net $151,480 $139,764 $131,450 $121,034 $111,214
Non-Utility property-net 5,076 3,893 2,793 3,167 3,665
Capital leases-net 4,962 5,853 6,679 6,563 9,201
Current assets 46,393 56,753 50,414 36,757 37,234
Deferred charges and 29,925 27,464 21,050 20,376 4,235
other assets
Total $237,836 $233,727 $212,386 $187,897 $165,549
Capitalization and
Liabilities:
Capitalization:
Common equity $ 80,109 $ 66,568 $ 63,027 $ 58,238 $ 54,569
Long-term debt 64,604 69,512 55,102 58,572 47,528
Total Capital- 144,713 136,080 118,129 116,810 102,097
ization
Capital lease 4,233 4,714 5,457 5,556 8,258
obligations
Current liabilities 47,729 54,590 53,375 34,781 41,151
Deferred credits and 41,161 38,343 35,425 30,750 14,043
reserves
Total $237,836 $233,727 $212,386 $187,897 $165,549
Income Statement Data:
Operating revenues $134,298 $139,892 $115,851 $117,947 $126,099
Cost of gas sold (78,930) (82,189) (63,401) (65,093) (75,157)
Operating margin 55,368 57,703 52,450 52,854 50,942
Operating expenses (42,853) (41,525) (38,844) (38,343) (37,938)
(including income
taxes)
Utility operating 12,515 16,178 13,606 14,511 13,004
income
Other income- 1,625 956 1,046 233 383
net of income taxes
Interest and (8,445) (8,217) (7,369) (6,740) (5,861)
debt expense
Accounting change - - 2,014 - -
Preferred stock - - - - (312)
dividends
Net income applicable $ 5,695 $ 8,917 $ 9,297 $ 8,004 $ 7,214
to common stock
Capitalization Ratios:
Common equity 55% 49% 53% 50% 53%
Long-term debt 45% 51% 47% 50% 47%
Common Stock Data:
Average shares 6,963 6,200 6,065 5,948 5,588
outstanding
Income per share $0.82 $1.44 $1.53(b) $1.35 $1.29
Dividends paid per share:
Common Stock $1.167 $1.140 $1.113 $1.087 $1.060
Class A Common Stock - - $ .800 $ .760 $ .720
Per weighted average $1.167 $1.140 $1.013 $ .987 $ .960
common share
Dividend payout rate 142% 79% 66% 73% 74%
Book value per share $10.75 $10.62 $10.27 $ 9.69 $ 9.25
Dividends as a percent 11% 11% 11% 11% 11%
of book value
Market price per share $15.00 $14.67 $13.00 $11.83 $14.33
Market price as a 139% 138% 127% 122% 155%
percent of book value
Return on average 7.8% 13.8% 15.3% 14.2% 14.3%
common equity
(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting change
of $.33 per share.
[END OF SELECTED FINANCIAL DATA]
SHAREHOLDER INFORMATION
Corporate Headquarters
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
(508) 458-3171
FAX: (508) 459-2314
Stock Listing
The Company's Common Stock trades on the Nasdaq Stock Market
under the symbol: CGES. Stock trading activity is reported in
financial publications under the abbreviation of ColGas or
ClnGas.
Annual Meeting
The Annual Meeting of Stockholders will be held on April 17, 1996
at 10:00 A.M. at The First National Bank of Boston, 100 Federal
Street, Boston, Massachusetts.
Annual Report - Form 10-K
A copy of the Company's 1995 Annual Report on Form 10-K as filed
with the Securities and Exchange Commission will be sent free of
charge to any shareholder who contacts the Investor Relations
Department at the corporate headquarters address above.
Transfer Agent
The First National Bank of Boston
c/o Boston EquiServe, L.P.
P.O. Box 644
Mail Stop: 45-02-64
Boston, MA 02102-0644
(800) 736-3001
(617) 575-3100
Independent Certified Public Accountants
Grant Thornton LLP
98 North Washington Street
Boston, MA 02114
(617) 723-7900
Corporate Counsel
Palmer & Dodge
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 59 consecutive
years and has increased dividends each year for the past 16
years. Common Stock dividends are payable when declared by the
Board of Directors.
Anticipated Record Date Anticipated Payment Date
March 1, 1996 March 15, 1996
May 31, 1996 June 14, 1996
August 30, 1996 September 13, 1996
November 29, 1996 December 13, 1996
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock Purchase
Plan (DRIP) provides shareholders of record with an economical
and convenient method for purchasing additional shares of the
Company's Common Stock without paying any brokerage fees.
Participants in the plan may elect to purchase additional
Colonial shares at a 5% discount from the market price by
reinvesting all or a portion of their dividends with no brokerage
fees. Participants in the plan may also make optional cash
purchases of Common Stock at the market price in amounts ranging
from a minimum of $10 to a maximum of $5,000 per calendar
quarter, with no brokerage fees.
Features of the plan at no charge to shareholders include:
- Direct deposit of dividends by electronic deposit
- Automatic monthly investments by electronic funds transfer
- Safekeeping of stock certificates
Additional information describing the plan, including a
prospectus and enrollment information, can be obtained by
contacting the Company's Transfer Agent or Investor Relations
Department.
Investment Dates
The investment date for optional cash investments under the DRIP
will be the fifteenth day of each month or, if that day is not a
business day, the preceding business day. Optional cash
investments must be received by the Company's Transfer Agent five
business days before the investment date. The dates below will
help you plan for any optional cash investments during 1996.
Date Investment Must Be Investment
Received By Transfer Agent Dates
April 8 April 15
May 8 May 15
June 7 June 14
July 8 July 15
August 8 August 15
September 6 September 13
October 7 October 15
November 8 November 15
December 6 December 13
SHAREHOLDER INFORMATION
Market Prices and Dividends
The following table reflects the high and low sales prices as reported
by the Nasdaq Stock Market, for shares of the Company's Common Stock
for 1995 and 1994, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
1995
The Year $21.50 $18.00 $1.275
4th Quarter 21.50 19.50 .320
3rd Quarter 20.75 18.75 .320
2nd Quarter 21.25 18.00 .320
1st Quarter 21.25 18.25 .315
1994
The Year $23.75 $18.25 $1.255
4th Quarter 21.75 18.25 .315
3rd Quarter 22.00 20.50 .315
2nd Quarter 21.75 18.50 .315
1st Quarter 23.75 18.75 .310
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1995, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,592
shareholders of record.
Market Makers
Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; First Albany Corporation;
Herzog, Heine, Geduld, Inc.; S. J. Wolfe & Co.; and Tucker
Anthony Incorporated.
Investment Information
Colonial Gas Company is a corporate member of the National
Association of Investors Corporation (NAIC). The Company is also
a participant in NAIC's Low Cost Investment Plan.
[END OF SHAREHOLDER INFORMATION]
[END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]