[EXHIBIT 13a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1994]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1994 1993 1992
Operating Revenues $166,259 $166,261 $145,054
Cost of gas sold 87,458 90,915 75,143
Operating Margin 78,801 75,346 69,911
Operating Expenses:
Operations 32,823 32,748 31,481
Maintenance 5,996 5,631 5,477
Depreciation and amortization 9,235 6,831 5,914
Local property taxes 2,740 2,496 2,059
Other taxes 1,441 1,359 1,300
Restructuring charge 3,185 - -
Total Operating Expenses 55,420 49,065 46,231
Income Taxes:
Federal income tax 4,806 6,111 5,390
State franchise tax 1,058 1,280 1,139
Total Income Taxes 5,864 7,391 6,529
Utility Operating Income 17,517 18,890 17,151
Other Operating Income (Expense):
Truck transportation revenues 12,066 7,558 9,799
Truck transportation expenses, including
income taxes and interest (10,579) (7,163) (9,622)
Truck Transportation Net Income 1,487 395 177
Other, net of income taxes (151) (186) (141)
Total Other Operating Income 1,336 209 36
Non-Operating Income, Net of 565 1,064 922
Income Taxes
Income Before Interest and Debt 19,418 20,163 18,109
Expenses
Interest and Debt Expense 8,409 8,141 7,466
Net Income $11,009 $12,022 $10,643
Average Common Shares Outstanding 8,119 7,931 7,728
Income per Average Common Share $1.36 $1.52 $1.38
Dividends Paid per Common Share $1.255 $1.235 $1.213
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF INCOME]
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1994 1993
Utility Property:
At original cost $287,158 $260,570
Accumulated depreciation (65,473) (57,857)
Net Utility Property 221,685 202,713
Non-Utility Property - Net 3,479 3,235
Net Property 225,164 205,948
Capital Leases - Net 2,948 3,914
Current Assets:
Cash and cash equivalents 9,026 5,482
Accounts receivable 13,846 16,156
Allowance for doubtful accounts (1,670) (1,682)
Accrued utility revenues 6,148 7,170
Unbilled gas costs 12,178 16,759
Fuel inventory - at average cost 12,959 13,717
Materials and supplies-at average cost 3,537 3,812
Prepayments and other current assets 9,544 6,254
Total Current Assets 65,568 67,668
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 11,471 12,689
Unrecovered environmental costs incurred4,577 4,062
Unrecovered environmental costs accrued 3,800 5,300
Unrecovered transition costs accrued 4,700 2,000
Unrecovered pension costs 2,607 3,215
Excess cost of investments over net
assets acquired 2,798 2,798
Other 7,715 4,524
Total Deferred Charges and
Other Assets 37,668 34,588
Total Assets $331,348 $312,118
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1994 1993
Capitalization:
Common Equity:
Common Stock $27,397 $26,739
Premium on Common Stock 49,211 45,799
Retained earnings 22,567 21,745
Total Common Equity 99,175 94,283
Long-Term Debt 77,923 87,432
Total Capitalization 177,098 181,715
Capital Lease Obligations 2,237 3,149
Current Liabilities:
Current maturities of long-term debt 8,449 3,318
Current capital lease obligations 712 765
Notes payable 49,500 32,600
Gas inventory purchase obligations 13,860 15,233
Accounts payable 9,635 12,161
Accrued interest 1,085 1,017
Pipeline refunds due customers 2,289 2,076
Accrued pipeline charges - 305
Current deferred income taxes 2,139 2,212
Other current liabilities 3,713 3,726
Total Current Liabilities 91,382 73,413
Deferred Credits and Reserves:
Deferred income taxes - Funded 29,373 23,395
Deferred income taxes - Unfunded 11,471 12,689
Deferred income taxes - Due customers 378 1,238
Accrued environmental costs 3,800 5,300
Accrued transition costs 4,700 2,000
Unamortized investment tax credits 4,215 4,449
Pension reserve 2,973 3,586
Other deferred credits and reserves 3,721 1,184
Total Deferred Credits and
Reserves 60,631 53,841
Total Capitalization and Liabilities $331,348 $312,118
[END OF CONSOLIDATED BALANCE SHEETS]
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1994 1993 1992
Cash Flows From Operating Activities:
Net Income $11,009 $12,022 $10,643
Adjustments to reconcile net income to net cash:
Depreciation and amortization 10,150 7,703 6,995
Deferred income taxes 3,555 2,139 6,264
Amortization of investment tax
credits (234) (255) (259)
Provision for uncollectible accounts 1,803 2,102 1,697
Other, net 811 190 832
27,094 23,901 26,172
Changes in current assets and liabilities:
Accounts receivable 495 773 (5,133)
Accrued utility revenues 1,022 (1,678) 1,366
Unbilled gas costs 4,581 2,122 (9,183)
Fuel inventory 758 (285) (1,664)
Materials and supplies 275 56 (199)
Prepayments and other current assets (3,290) 2,055 (3,027)
Accounts payable (2,526) (382) 35
Accrued interest 68 (7) (135)
Pipeline refunds due customers 213 620 (20)
Accrued pipeline charges (305) (606) (2,189)
Current deferred income taxes (73) (2,111) 4,323
Other current liabilities (13) 933 (39)
Net Cash Provided by Operating
Activities 28,299 25,391 10,307
Cash Flows From Investing Activities:
Utility capital expenditures (28,195)(25,703)(26,948)
Non-utility capital expenditures (876) (453) (218)
Sale of non-utility assets - 586 -
Change in deferred accounts (716) (354) (4,781)
Net Cash Used in Investing
Activities (29,787)(25,924)(31,947)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,187) (9,793) (9,379)
Issuance of Common Stock 4,070 4,283 4,286
Issuance of long-term debt 741 - 45,000
Retirement of long-term debt (5,119) (1,500)(15,634)
Change in notes payable 16,900 8,100 (3,500)
Change in gas inventory purchase
obligations (1,373) 492 3,015
Net Cash Provided by Financing
Activities 5,032 1,582 23,788
Net Increase in Cash and Cash
Equivalents 3,544 1,049 2,148
Cash and Cash Equivalents at
Beginning of Year 5,482 4,433 2,285
Cash and Cash Equivalents at
End of Year $9,026 $ 5,482 $4,433
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 9,283 $8,891 $ 8,390
Income and state franchise taxes $ 7,282 $4,939 $ 3,639
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENT OF CASH FLOWS]
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1994 1993 1992
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,227 in 1994, 8,030 in 1993,
and 7,844 in 1992
Beginning of year $26,739 $26,122 $25,391
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (197 shares
in 1994, 186 shares in 1993 and 219
shares in 1992) 658 617 731
End of year $27,397 $26,739 $26,122
Premium on Common Stock
Beginning of year $45,799 $42,133 $38,578
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 3,412 3,666 3,555
End of year $49,211 $45,799 $42,133
Retained Earnings
Beginning of year $21,745 $19,516 $18,252
Net income 11,009 12,022 10,643
Cash dividends on Common Stock
($1.255 a share in 1994, $1.235
a share in 1993 and $1.213 a share
in 1992) (10,187) (9,793) (9,379)
End of year $22,567 $21,745 $19,516
Total Common Equity $99,175 $94,283 $87,771
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
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.
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 $294,000,
$227,000 and $181,000 in 1994, 1993 and 1992, 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 was approximately 2.91% through October 31,
1993, which 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 $6,148,000 and
$7,170,000, as reported in the Consolidated Balance Sheets at
December 31, 1994 and 1993, 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
programs as revenue when earned by the Company and approved by the
DPU. No lost margins or incentives 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). All of the 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 $86,372,000 and
$90,750,000 as of December 31, 1994 and 1993, respectively. The
fair value of long-term debt was $88,425,000 and $104,562,000 as of
December 31, 1994 and 1993, 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.
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, 1994, the Company
has a liability of $11,471,000 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 $378,000 at December 31, 1994, 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) 1994 1993 1992
Charged (credited) to operations:
Current $2,157 $5,191 $(362)
Deferred:
Unbilled gas costs (106) (1,753) 3,590
Accelerated depreciation 2,167 2,157 2,092
Cost of removal 173 190 149
Demand side management costs 1,115 - -
Early retirement pension costs (830) - -
Environmental response costs 137 (33) (223)
Pension (10) 141 131
Recovery of unfunded deferred
taxes 398 556 578
Miscellaneous (165) (93) (316)
Amortization of investment tax
credits (230) (245) (249)
Total 4,806 6,111 5,390
Charged to other income 1,014 578 486
Total Federal income tax
expense $5,820 $6,689 $5,876
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1994 1993 1992
Statutory Federal income tax rate 35% 35% 34%
Increases (reductions) in taxes resulting from:
Amortization of investment tax credits (1) (1) (2)
Recovery of unfunded deferred taxes 2 3 4
Miscellaneous items (1) (1) -
Effective Federal income tax rate 35% 36% 36%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1994 1993
Construction contributions $1,117 $ 1,176
Early retirement pension costs 995 -
Other 943 940
Total deferred tax assets 3,055 2,116
Accelerated depreciation (34,698) (32,333)
Cost of removal (2,364) (2,105)
Unbilled gas costs (2,139) (2,212)
Environmental response costs (1,839) (1,634)
Transition costs (1,045) -
Demand side management costs (1,803) -
Pension (915) -
Other (1,235) (2,128)
Total deferred tax
liabilities (46,038) (40,412)
Total deferred taxes $(42,983) $(38,296)
Note C: Capital Stock
As a result of the 3 for 2 stock split effective July 29, 1992,
the par value of the Company's Common Stock changed from $5.00 per
share to $3.33 per share. Also during 1992, the number of
authorized shares was increased from 8,000,000 to 15,000,000.
Pursuant to the Company's dividend reinvestment and common stock
purchase plan, stockholders 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.
The Company has a Shareholder Rights Plan pursuant to which one
share purchase right (a "Right") for each outstanding share of the
Company's Common Stock was issued to stockholders of record on
December 1, 1993. Each Right entitles the holder 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 exercise of the
Rights is subject to obtaining DPU approval. The description and
terms of the Rights are set forth in a Rights Agreement between
the Company and The First National Bank of Boston. The Rights
attach to each outstanding share issued and to be issued and
expire on December 1, 2003. The Rights do not carry voting or
dividend rights, have no dilutive effect and do not impact the
earnings of the Company.
The Rights 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 $19,027,000 of retained
earnings was available to pay dividends on Common Stock as of
December 31, 1994.
Note E: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1994 1993
First mortgage bonds:
14.00% Series CC due 1999 $ 500 $ 2,750
8.86% Series CD due 2001 7,000 8,000
9.40% Series CE due 1997 15,000 15,000
10.25% Series CF due 2004 18,182 20,000
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
Total 85,682 90,750
Note payable 690 -
Less: Long-term debt due within one
year (8,449) (3,318)
Total long-term debt $77,923 $87,432
The aggregate amount of maturities and sinking fund requirements
for the years 1995, 1996, 1997, 1998, and 1999 are $8,449,000,
$7,959,000, $7,970,000, $2,982,000, and $22,920,000, 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.
Note F: Short-Term Debt
In July 1994, the Company established a three-year bank line of
credit of $75,000,000 with a consortium of four banks. The bank
line of credit allows the Company to borrow on a demand basis up
to $75,000,000, 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, 1994, the credit available under the bank line of credit was
$11,640,000. The weighted average interest rates for short-term
debt were 6.25% and 3.59% at December 31, 1994 and 1993,
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
$30,000,000 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 1994, 1993 and
1992 approximately $504,000, $390,000 and $433,000, 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
$7,230,000 and $7,475,000 at December 31, 1994 and 1993,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $4,282,000 and $3,561,000
at December 31, 1994 and 1993, 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 1994, 1993 and 1992
approximated $2,049,000, $1,808,000 and $1,984,000, respectively.
At December 31, 1994, the future minimum payments (including
interest) under the Company's lease agreements are: $937,000 in
1995; $754,000 in 1996; $612,000 in 1997; $381,000 in 1998;
$255,000 in 1999; and $609,000 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 $387,000, $418,000 and $316,000 for
1994, 1993 and 1992, 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) 1994 1993 1992
Benefits earned during the
period $1,195 $1,031 $958
Interest cost on projected
benefit obligation 2,803 2,690 2,500
Actual return on plan assets 77 (2,656) (469)
Net amortization and deferral (2,657) 325 (1,760)
Net periodic pension cost $1,418 $1,390 $1,229
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1994 1993 1992
Weighted average discount rate 8.50% 7.25% 8.00%
Future compensation increases 5.00% 5.00% 5.50%
Expected long-term rate of
return on assets 9.00% 9.00% 9.00%
The funded status of the plans at December 31, 1994 and 1993 is as
follows:
1994 1993
Assets Accumu- Assets Accumu-
Exceed lated Exceed lated
Accumu- Benefits Accumu- Benefits
lated Exceed lated Exceed
Benefits Assets Benefits Assets
(In Thousands)
Projected benefit
obligations:
Vested $(21,897) $(8,544) $(23,689) $(9,208)
Nonvested (2,988) (563) (562) (356)
Accumulated (24,885) (9,107) (24,251) (9,564)
Due to recognition of
future (4,664) (42) (5,665) (6)
salary increases
Total (29,549) (9,149) (29,916) (9,570)
Plan assets at fair 27,715 5,259 28,250 5,186
value
Projected benefit
obligation
(in excess of) (1,834) (3,890) (1,666) (4,384)
less than
plan assets
Unrecognized net loss (227) 513 1,695 909
(gain)
Unrecognized 2,059 1,430 2,265 1,612
transition amount
Unrecognized prior 448 706 553 700
service cost
Additional liability - (2,607) - (3,215)
accrued
Prepaid (accrued) $446 $(3,848) $2,847 $(4,378)
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 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, which was
$148,000 in 1992. 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 1994 and 1993 was $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, 1994 and 1993:
(In Thousands) 1994 1993
Accumulated postretirement
benefit obligation:
Retirees $(2,416) $(2,523)
Fully eligible active plan (1,457) (1,629)
participants
Other active plan (1,782) (2,388)
participants
(5,655) (6,540)
Plan assets at fair value 3,135 2,940
Accumulated postretirement
benefit obligation (2,520) (3,600)
in excess of plan assets
Unrecognized net (gain) from
past experience
different from that assumed (1,016) (60)
and from changes in assumptions
Unrecognized transition 4,854 5,123
obligation
Prepaid postretirement benefit $1,318 $1,463
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended
December 31,
(In Thousands) 1994 1993
Service cost - benefits
attributable to service $202 $268
during the period
Interest cost on accumulated
postretirement 455 478
benefit obligation
Actual return on plan assets 143 (202)
Net amortization and deferral (106) 273
Net periodic postretirement 694 817
benefit cost
Regulatory asset - (431)
Net expense $694 $386
For measurement purposes, an 8.5% (8% for medical costs after
age 65 and 4.5% for dental costs) annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1995; the rate for medical costs was assumed to decrease gradually
to 4.5% for 2001 (to 4.5% for 2004 for medical costs after age 65)
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 1% point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by
$748,000 and the aggregate of the service and the interest cost
components of net periodic postretirement benefit cost for 1994 by
$100,000.
The weighted-average discount rate used in determining the
accumulated postretirement benefit obligation was 8.5% and 7.25%
for 1994 and 1993, 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,
several of 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 have 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
$10,200,000 to $14,900,000, of which the Company has paid
$5,500,000 through December 31, 1994. The Company is recovering
these costs from its customers, as approved by the DPU on October
20, 1994. As of December 31, 1994, the Company has recorded on the
balance sheet a long-term liability of $4,700,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $4,700,000 ("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 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, 1994, the
Company had incurred environmental response costs of $2,608,000
related to the former gas manufacturing site and $6,463,000 on the
related disposal sites. The Company expects to continue incurring
costs arising from these environmental matters.
As of December 31, 1994, the Company has recorded on the balance
sheet a long-term liability of $3,800,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation, of which $2,038,000
relates to the gas manufacturing site. Based upon the DPU order
approving rate recovery of environmental response costs, a
regulatory asset of $3,800,000 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, 1994, 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 Non-
from of Rate Returned to Operating Income
Year Incurred Customers Recovery Customers Net of Taxes
1988 $ 853 $ 610 1990-1997 - -
1989 4,031 2,879 1990-1997 - -
1990 639 365 1991-1998 - -
1991 374 160 1992-1999 $ 851 $ 525
1992 617 176 1993-2000 1,121 673
1993 1,236 175 1994-2001 469 290
1994 1,321 - 1995-2002 122 75
Total $9,071 $4,365 $2,563 $1,563
Note K: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)
Income
Utility (Loss) Per
Operating Net Average Dividends
Operating Income Income Common Paid
Quarter Ended Revenues (Loss) (Loss) Share Per Share
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
1993
December 31 $55,289 $8,780 $6,945 $ .87 $.310
September 30 12,259 (2,738) (3,722) (.47) .310
June 30 20,587 (1,417) (3,235) (.41) .310
March 31 78,126 14,265 12,034 1.53 .305
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, 1994 and
1993, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1994. 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, 1994 and 1993, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1994, in conformity with
generally accepted accounting principles.
As discussed in Note H to the Consolidated Financial Statements,
in 1993 the Company changed its method of accounting for
postretirement benefits other than pensions.
Grant Thornton LLP
Boston, Massachusetts
January 18, 1995
[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 $11,009,000
($1.36), $12,022,000 ($1.52) and $10,643,000 ($1.38) for the three
years ended December 31, 1994, 1993, and 1992, 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 impacted by significantly colder-than-normal
temperatures in 1994, 1993 and 1992, which is summarized as
follows:
1994 1993 1992
Percent colder (warmer) than normal
Peak Season (January - April and
November - December) 4.3% 7.5% 2.2%
Off-Peak Season (May - October) 7.5% 4.2% 18.6%
Year Average 4.8% 7.0% 4.6%
Percent colder (warmer) than prior year
Peak Season (January - April and
November - December) (2.9)% 5.2% 11.7%
Off-Peak Season (May - October) 3.2% (12.1)% 39.4%
Year Average (2.1)% 2.4% 15.5%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.255 in 1994, $1.235 in
1993 and $1.213 in 1992. The Company has paid dividends for 58
consecutive years, and has increased dividends each year for the
past 15 years.
Operating Revenues
Operating revenues were $166,259,000 in 1994, $166,261,000 in 1993
and $145,054,000 in 1992. 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 customers increased
by 13,459 over the last three years, an increase of 10.9%, which
increase has added to sales volume. The chart below summarizes
volumes of gas sold and transported and number of firm customers:
1994 1993 1992
(In MMcf)
Gas sold
Firm 18,716 18,935 18,542
Non-Firm 729 1,030 1,508
Gas transported
Firm 6,090 4,163 1,997
Non-Firm 4,185 4,026 2,820
Total gas sold and
transported (In MMcf) 29,720 28,154 24,867
Firm Customers 136,644 132,188 127,965
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 4.8% colder than normal, was 2.1% warmer
than 1993.
Operating revenues increased $21,207,000, or 14.6%, from 1992 to
1993. This increase resulted primarily from weather that was
colder than the prior year, a growing customer base, a 4.9% rate
increase effective November 1, 1993 and increased gas costs passed
on to customers through the CGAC. Temperatures were 2.4% colder
than the comparable 1992 period and 7.0% colder than normal. This
cooler weather pattern, together with continued customer growth,
helped raise firm gas sales by 2.1% or 393,000 Mcf.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.48 in 1994, $4.53 in 1993
and $3.73 in 1992. 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, which flow back to the
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) 1994 1993 1992
Gas purchased
Pipeline 14,392 14,983 16,633
Underground storage 3,112 3,501 2,666
LNG/Other 2,390 1,832 1,668
Total gas purchased 19,894 20,316 20,967
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 $32,823,000 in 1994, an increase of $75,000
or 0.2%, from 1993, and $32,748,000 in 1993, an increase of
$1,267,000, or 4.0%, from 1992. In 1994, the Company conducted a
self-examination to fundamentally downshift its cost structure.
The Company expects to lower its operations and maintenance costs
by approximately 6% in 1995. The increase in 1993 was primarily
due to increased labor and medical insurance costs and and an
increase in bad debt expense.
Maintenance expense increased $365,000, or 6.5%, in 1994 from
1993 and increased $154,000, or 2.8%, in 1993 from 1992. The
increase in 1994 was primarily due to increased labor resulting
from colder weather during the first quarter.
Depreciation and amortization expense increased 35.2% or
$2,404,000 in 1994 and 15.5% or $917,000 in 1993. The increase in
1994 and 1993 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 8.5% in 1994 from 1993
and 14.8% in 1993 from 1992 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 decreased 20.7% or
$1,527,000 in 1994 as a result of less income. Total Federal
income and state franchise taxes inceased 13.2% or $862,000 in
1993 as a result of a higher level of income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was
$1,336,000 in 1994, $209,000 in 1993 and $36,000 in 1992. Other
operating income includes results from the Company's wholly-owned
energy trucking subsidiary (Transgas) and appliance sales. 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.
Transgas' improved financial results in 1993 are attributable to
the closing of its unprofitable bulk cement trucking operation
during the first half of the year. The closing of this operation
permitted Transgas to reduce overhead expenses. In addition,
trucking equipment associated with this operation was sold at
prices exceeding net book value. Transgas' LNG transportation
revenue in 1993 increased due to renewed demand from natural gas
distribution companies as a result of colder than normal weather
throughout the Northeast during the winter of 1992/1993. However,
this increase was more than offset by the decline in its portable
pipeline business.
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; 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 $565,000 in 1994,
$1,064,000 in 1993 and $922,000 in 1992. Non-operating income
includes interest income and miscellaneous other income. Included
in non-operating income were recoveries of $75,000, $290,000 and
$673,000 in 1994, 1993 and 1992, respectively, resulting from
settlements reached with insurers and other potentially
responsible parties relating to enviromental 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 3.3% and 9.0% in 1994 and
1993, respectively. 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. The increase in 1993 was due to the issuance
of $45 million of long-term debt in June 1992 partially offset by
a decrease in interest expense on regulatory assets and decreased
levels of short-term debt and lower short-term interest rates.
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 to and perhaps beyond the year 2000.
Regulatory Matters
Environmental response 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". The Company's DSM
programs are in their third year and are expected, based on
methodology approved by the DPU, to save approximately $25.5
million in gas costs that would have been incurred over the lives
of the installed conservation measures. In order to achieve these
savings, Colonial and its participating customers will have
invested approximately $14 million over the three-year period in
customer conservation measures such as insulation, heating systems
controls and water heating conservation devices. As a result,
Colonial expects to reduce customer bills by approximately $11.5
million from the levels they would have been at if no conservation
occurred. In addition, the Company is allowed to recover the
margins lost as a result of this program and financial incentives
based on the attainment of performance goals. The Company
anticipates filing in 1995 for approximately $400,000 of financial
incentives.
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 1994, the Company received
$3,313,000 of capacity release revenue, $3,232,000 of which was
credited back to firm customers and $81,000 of which was retained
by the Company.
The table below summarizes the Company's recent requests to
increase base revenue:
Increase Requested Increase Approved
Date Effective Amount Percen- Amount Percen-
tage tage
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, 1994, six customers had opted for tariffed firm
transportation service, representing less than 1.5% of the
Company's annual firm load.
In 1994, the DPU opened two industry-wide proceedings which may
result in guidelines for the further unbundling and/or
deregulation of the Company's business. One of those proceedings
is addressing 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 other is
addressing 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. The DPU
has stated that it intends to issue rulings in these two
proceedings early in 1995. The Company anticipates that, when
issued, the rulings may contain general guidelines on the matters
covered by the proceedings. Until issued, the Company cannot
predict what changes might be required or permitted in the
Company's interruptible transportation service, interruptible
sales service, capacity release policies or overall rate
practices. In the interim, the Company is analyzing specific
incentive regulation options which it could propose to the DPU as
a means of benefiting its customers and shareholders.
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, 1994, the
Company had incurred environmental response costs of $2,608,000
related to the former gas manufacturing site and $6,463,000 on the
related disposal sites. The Company expects to continue incurring
costs arising from these environmental matters.
As of December 31, 1994, the Company has recorded on the balance
sheet a long-term liability of $3,800,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation, of which $2,038,000
relates to the gas manufacturing site. Based upon the DPU order
approving rate recovery of environmental response costs, a
regulatory asset of $3,800,000 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, 1994, 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 Response Costs Insurance and Other
Thousands) Proceeds
Recovered Period Returned Recorded as
from of Rate to Non-Operating
Year Incurred Customers Recovery Customers Income Net of Taxes
1988 $ 853 $ 610 1990-1997 - -
1989 4,031 2,879 1990-1997 - -
1990 639 365 1991-1998 - -
1991 374 160 1992-1999 $ 851 $ 525
1992 617 176 1993-2000 1,121 673
1993 1,236 175 1994-2001 469 290
1994 1,321 - 1995-2002 122 75
Total $9,071 $4,365 $2,563 $1,563
Accounting Standards
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, which was $148,000 in
1992. 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 1994
and 1993 was $694,000 and $817,000, respectively. A regulatory
asset of $431,000 was been 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. Capital expenditures were $28,195,000 in
1994, $25,703,000 in 1993 and $26,948,000 in 1992. The Company's
long-range plan calls for annual utility expenditures, of which
over 40% is budgeted for new business, averaging $27,140,000 over
the next five years as set forth below:
(In Thousands) 1995 1996 1997 1998 1999
Distribution $20,200 $20,700 $22,700 $22,300 $26,500
Production 1,000 1,400 1,000 1,000 700
Information Systems 4,200 4,300 1,000 700 500
Automated Meter 1,200 1,100 1,100 $1,100 1,100
Reading
General 200 300 700 300 400
Total Capital $26,800 $27,800 $26,500 $25,400 $29,200
Expenditures
Financing Activities
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) 1994 1993 1992
Common Stock Under
Dividend Reinvestment
and Common Stock
Purchase Plan and
Employee Savings Plan $4,070 $4,283 $ 4,286
Long-Term Debt
Series CG, 8.05%, due
entirely in 1999 - - $20,000
Series CH, 8.80%, due
entirely in 2022 - - $25,000
Note Payable $ 741 - -
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1994 1993 1992
Equity 56% 52% 49%
Long-Term Debt 44% 48% 51%
As of April 1994, the quarterly dividend paid on the Company's
Common Stock was increased to $.315 per share or an annualized
dividend rate of $1.26 per share.
[END OF MANAGEMENT'S DISCUSSION AND ANALYSIS]
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1994 1993 1992 1991 1990
Balance Sheet Data:
Assets:
Utility property - net $221,685 $202,713 $183,815 $162,736 $151,480
Non-utility property - net 3,479 3,235 4,039 4,767 5,076
Capital leases - net 2,948 3,914 4,366 4,557 4,962
Current assets 65,568 67,668 71,763 53,472 46,393
Deferred charges and other 37,668 34,588 38,939 38,789 29,925
assets
Total $331,348 $312,118 $302,922 $264,321 $237,836
Capitalization and Liabilities:
Capitalization:
Common equity $ 99,175 $ 94,283 $ 87,771 $ 82,221 $ 80,109
Preferred stock - - - - -
Long-term debt 77,923 87,432 90,750 50,410 64,604
Total Capitalization 177,098 181,715 178,521 132,631 144,713
Capital lease obligations 2,237 3,149 3,591 3,838 4,233
Current liabilities 91,382 73,413 64,567 73,993 47,729
Deferred credits and reserves 60,631 53,841 56,243 53,859 41,161
Total $331,348 $312,118 $302,922 $264,321 $237,836
Income Statement Data:
Operating revenues $166,259 $166,261 $145,054 $137,719 $134,298
Cost of gas sold (87,458) (90,915) (75,143) (73,288) (78,930)
Operating margin 78,801 75,346 69,911 64,431 55,368
Operating expenses (including
income taxes) (61,284) (56,456) (52,760) (48,009) (42,853)
Utility operating income 17,517 18,890 17,151 16,422 12,515
Other income - net of income 1,901 1,273 958 36 1,625
taxes
Interest and debt expense (8,409) (8,141) (7,466) (8,141) (8,445)
Accounting change - - - - -
Preferred stock dividends - - - - -
Net income applicable to
common stock $11,009 $ 12,022 $ 10,643 $ 8,317 $ 5,695
Capitalization Ratios:
Common equity 56.0% 51.9% 49.2% 62.0% 55.4%
Preferred stock - - - - -
Long-term debt 44.0% 48.1% 50.8% 38.0% 44.6%
Common Stock Data (a):
Average shares outstanding 8,119 7,931 7,728 7,529 6,963
Income per share (b) $ 1.36 $1.52 $1.38 $1.10 $0.82
Dividends paid per share:
Common Stock $ 1.255 $1.235 $1.213 $1.193 $1.167
Class A Common Stock - - - - -
Per weighted average $ 1.255 $1.235 $1.213 $1.193 $1.167
common share
Dividend payout rate 92% 81% 88% 108% 142%
Book value per share (a) $ 12.05 $11.74 $11.19 $10.78 $10.75
Dividends as a percent of 10% 11% 11% 11% 11%
of book value
Market price per share (a) $ 19.25 $22.50 $21.25 $17.50 $15.00
Market price as a percent of
book value 160% 192% 190% 162% 139%
Return on average common equity 11.4% 13.2% 12.5% 10.2% 7.8%
___________________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992.
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.33 per share).
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1989 1988 1987
Balance Sheet Data:
Assets:
Utility property - net $139,764 $131,450 $121,034
Non-utility property - net 3,893 2,793 3,167
Capital leases - net 5,853 6,679 6,563
Current assets 56,753 50,414 36,757
Deferred charges and other assets 27,464 21,050 20,376
Total $233,727 $212,386 $187,897
Capitalization and Liabilities:
Capitalization:
Common equity $ 66,568 $ 63,027 $ 58,238
Preferred stock - - -
Long-term debt 69,512 55,102 58,572
Total Capitalization 136,080 118,129 116,810
Capital lease obligations 4,714 5,457 5,556
Current liabilities 54,590 53,375 34,781
Deferred credits and reserves 38,343 35,425 30,750
Total $233,727 $212,386 $187,897
Income Statement Data:
Operating revenues $139,892 $115,851 $117,947
Cost of gas sold (82,189) (63,401) (65,093)
Operating margin 57,703 52,450 52,854
Operating expenses (including
income taxes) (41,525) (38,844) (38,343)
Utility operating income 16,178 13,606 14,511
Other income - net of income taxes 956 1,046 233
Interest and debt expense (8,217) (7,369) (6,740)
Accounting change - 2,014 -
Preferred stock dividends - - -
Net income applicable to
common stock $ 8,917 $ 9,297 $ 8,004
Capitalization Ratios:
Common equity 48.9% 53.4% 49.9%
Preferred stock - - -
Long-term debt 51.1% 46.6% 50.1%
Common Stock Data (a):
Average shares outstanding 6,200 6,065 5,948
Income per share (b) $1.44 $1.53 $1.35
Dividends paid per share:
Common Stock $1.140 $1.113 $1.087
Class A Common Stock - $ .80 $ .76
Per weighted average common share $1.140 $1.013 $ .987
Dividend payout rate 79% 66% 73%
Book value per share (a) $10.62 $10.27 $9.69
Dividends as a percent of book value 11% 11% 11%
Market price per share (a) $14.67 $13.00 $11.83
Market price as a percent of
book value 138% 127% 122%
Return on average common equity 13.8% 15.3% 14.2%
____________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992.
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.33 per share).
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1986 1985
Balance Sheet Data:
Assets:
Utility property - net $111,214 $102,959
Non-utility property - net 3,665 3,834
Capital leases - net 9,201 8,432
Current assets 37,234 45,411
Deferred charges and other assets 4,235 4,676
Total $165,549 $165,312
Capitalization and Liabilities:
Capitalization:
Common equity $ 54,569 $ 46,053
Preferred stock - 6,672
Long-term debt 47,528 40,007
Total Capitalization 102,097 92,732
Capital lease obligations 8,258 9,533
Current liabilities 41,151 50,413
Deferred credits and reserves 14,043 12,634
Total $165,549 $165,312
Income Statement Data:
Operating revenues $126,099 $128,165
Cost of gas sold (75,157) (80,623)
Operating margin 50,942 47,542
Operating expenses (including
income taxes) (37,938) (35,312)
Utility operating income 13,004 12,230
Other income - net of income taxes 383 1,201
Interest and debt expense (5,861) (6,010)
Accounting change - -
Preferred stock dividends (312) (724)
Net income applicable to common stock $7,214 $6,697
Capitalization Ratios:
Common equity 53.4% 49.7%
Preferred stock - 7.2%
Long-term debt 46.6% 43.1%
Common Stock Data (a):
Average shares outstanding 5,588 5,193
Income per share (b) $1.29 $1.29
Dividends paid per share:
Common Stock $1.060 $1.033
Class A Common Stock $ .72 $ .68
Per weighted average common share $ .960 $ .920
Dividend payout rate 74% 71%
Book value per share (a) $9.25 $8.73
Dividends as a percent of book value 11% 12%
Market price per share (a) $14.33 $11.59
Market price as a percent of
book value 155% 133%
Return on average common equity 14.3% 15.2%
_____________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.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 19, 1995
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 1994 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 Lisa Lynch, Manager of
Financial Services, at the corporate headquarters address above.
Transfer Agent
The First National Bank of Boston
P.O. Box 644
Mail Stop: 45-02-09
Boston, MA 02102-0644
1-800-736-3001
1-617-575-3100
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 58 consecutive
years and has increased dividends each year for the past 15
years. Common Stock dividends are payable when declared by the
Board of Directors.
Anticipated Record Date Anticipated Payment Date
March 1, 1995 March 15, 1995
June 1, 1995 June 15, 1995
September 1, 1995 September 15, 1995
December 1, 1995 December 15, 1995
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.
New features of the plan at no charge to shareholders include:
Direct depost of dividends by electronic deposit
Automatic monthly investments by electronic funds transfer
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.
Date Investment Must Be Received By Transfer Agent
April 7, 1995
May 8, 1995
June 8, 1995
July 7, 1995
August 8, 1995
September 8, 1995
October 5, 1995
November 8, 1995
December 8, 1995
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 1994 and 1993, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
_________________________________________________________________
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
1993 __________________________________
The Year $26.50 $20.00 $1.235
4th Quarter 25.00 21.75 .310
3rd Quarter 26.50 24.00 .310
2nd Quarter 25.00 20.00 .310
1st Quarter 25.25 21.25 .305
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1994, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,777
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
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1994]