[EXHIBIT 13a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDING DECEMBER 31, 1993]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1993 1992 1991
Operating Revenues $166,261 $145,054 $137,719
Cost of gas sold 90,915 75,143 73,288
Operating Margin 75,346 69,911 64,431
Operating Expenses:
Operations 32,748 31,481 29,764
Maintenance 5,631 5,477 5,124
Depreciation and amortization 6,831 5,914 5,488
Local property taxes 2,496 2,059 1,683
Other taxes 1,359 1,300 1,184
Total Operating Expenses 49,065 46,231 43,243
Income Taxes:
Federal income tax 6,111 5,390 3,803
State franchise tax 1,280 1,139 963
Total Income Taxes 7,391 6,529 4,766
Utility Operating Income 18,890 17,151 16,422
Other Operating Income (Expense):
Truck transportation revenues 7,558 9,799 8,087
Truck transportation expenses,
including income taxes and interest (7,163) (9,622) (8,678)
Truck Transportation Net Income(Loss) 395 177 (591)
Other, net of income taxes (186) (141) (142)
Total Other Operating Income(Expense) 209 36 (733)
Non-Operating Income, Net of Income Taxes 1,064 922 769
Income Before Interest and Debt Expense 20,163 18,109 16,458
Interest and Debt Expense 8,141 7,466 8,141
Net Income $ 12,022 $ 10,643 $ 8,317
Average Common Shares Outstanding 7,931 7,728 7,529
Income per Average Common Share $ 1.52 $ 1.38 $ 1.10
Dividends Paid per Common Share $ 1.235 $ 1.213 $ 1.193
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF INCOME]
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1993 1992
Utility Property:
At original cost $260,570 $236,515
Accumulated depreciation (57,857) (52,700)
Net Utility Property 202,713 183,815
Non-Utility Property - Net 3,235 4,039
Net Property 205,948 187,854
Capital Leases - Net 3,914 4,366
Current Assets:
Cash and cash equivalents 5,482 4,433
Accounts receivable 16,156 18,535
Allowance for doubtful accounts (1,682) (1,187)
Accrued utility revenues 7,170 5,492
Unbilled gas costs 16,759 18,881
Fuel inventory - at average cost 13,717 13,432
Materials and supplies - at average cost 3,812 3,868
Prepayments and other current assets 6,254 8,309
Total Current Assets 67,668 71,763
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 12,689 12,928
Unrecovered environmental costs incurred 4,062 3,119
Unrecovered environmental costs accrued 5,300 13,800
Unrecovered transition costs accrued 2,000 -
Unrecovered pension costs 3,215 2,962
Excess cost of investments over net
assets acquired 2,798 2,798
Other 4,524 3,332
Total Deferred Charges and
Other Assets 34,588 38,939
Total Assets $312,118 $302,922
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1993 1992
Capitalization:
Common Equity:
Common Stock $ 26,739 $ 26,122
Premium on Common Stock 45,799 42,133
Retained earnings 21,745 19,516
Total Common Equity 94,283 87,771
Long-Term Debt 87,432 90,750
Total Capitalization 181,715 178,521
Capital Lease Obligations 3,149 3,591
Current Liabilities:
Current maturities of long-term debt 3,318 1,500
Current capital lease obligations 765 776
Notes payable 32,600 24,500
Gas inventory purchase obligations 15,233 14,741
Accounts Payable 12,161 12,543
Accrued interest 1,017 1,024
Pipeline refunds due customers 2,076 1,456
Accrued pipeline charges 305 911
Current deferred income taxes 2,212 4,323
Other current liabilities 3,726 2,793
Total Current Liabilities 73,413 64,567
Deferred Credits and Reserves:
Deferred income taxes - Funded 23,395 19,054
Deferred income taxes - Unfunded 12,689 12,928
Deferred income taxes - Due customers 1,238 1,293
Accrued environmental costs 5,300 13,800
Accrued transition costs 2,000 -
Unamortized investment tax credits 4,449 4,703
Pension reserve 3,586 3,331
Other deferred credits and reserves 1,184 1,134
Total Deferred Credits and
Reserves 53,841 56,243
Total Capitalization and Liabilities $312,118 $302,922
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) 1993 1992 1991
Cash Flows From Operating Activities:
Net Income $12,022 $10,643 $ 8,317
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 7,703 6,995 6,524
Deferred income taxes 2,139 6,264 2,176
Amortization of investment tax credits (255) (259) (273)
Provision for uncollectible accounts 2,102 1,697 1,516
Other, net 190 832 893
23,901 26,172 19,153
Changes in current assets and liabilities:
Accounts receivable 773 (5,133) (1,779)
Accrued utility revenues (1,678) 1,366 (1,745)
Unbilled gas costs 2,122 (9,183) (7,494)
Fuel inventory (285) (1,664) 468
Materials and supplies 56 (199) 158
Prepayments and other current assets 2,055 (3,027) (557)
Accounts payable (382) 35 1,499
Accrued interest (7) (135) (90)
Pipeline refunds due customers 620 (20) (1,222)
Accrued pipeline charges (606) (2,189) 3,100
Current deferred income taxes (2,111) 4,323 -
Other current liabilities 933 (39) 1,076
Net Cash Provided by Operating Activities 25,391 10,307 12,567
Cash Flows From Investing Activities:
Utility capital expenditures (25,703) (26,948) (16,685)
Non-utility capital expenditures (453) (218) (629)
Sale of non-utility assets 586 - -
Change in deferred accounts (354) (4,781) 880
Net Cash Used in Investing Activities (25,924) (31,947) (16,434)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (9,793) (9,379) (8,981)
Issuance of Common Stock 4,283 4,286 2,776
Issuance of long-term debt - 45,000 -
Retirement of long-term debt (1,500) (15,634) (6,628)
Change in notes payable 8,100 (3,500) 15,900
Change in gas inventory purchase
obligations 492 3,015 (1,554)
Net Cash Provided by Financing Activitie 1,582 23,788 1,513
Net Increase (Decrease) in Cash and
Cash Equivalents 1,049 2,148 (2,354)
Cash and Cash Equivalents at Beginning
of Year 4,433 2,285 4,639
Cash and Cash Equivalents at End of Year $ 5,482 $ 4,433 $ 2,285
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 8,891 $8,390 $ 7,921
Income and state franchise taxes $ 4,939 $3,639 $ 2,455
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF CASH FLOWS]
CONSOLIDATED STATEMENTS OF COMMON EQUITY
(In Thousands Except Per Share Amounts) Year ended December 31,
1993 1992 1991
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,030 in 1993, 7,844 in 1992,
and 7,625 in 1991
Beginning of year $26,122 $25,391 $24,806
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and three
employee savings plans (186 shares
in 1993, 219 shares in 1992 and 176
shares in 1991) 617 731 585
End of year $26,739 $26,122 $25,391
Premium on Common Stock
Beginning of year $42,133 $38,578 $36,387
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and three
employee savings plans 3,666 3,555 2,191
End of year $45,799 $42,133 $38,578
Retained Earnings
Beginning of year $19,516 $18,252 $18,916
Net income 12,022 10,643 8,317
Cash dividends on Common Stock ($1.235
a share in 1993, $1.213 a share in
1992 and $1.193 a share in 1991) (9,793) (9,379) (8,981)
End of year $21,745 $19,516 $18,252
Total Common Equity $94,283 $87,771 $82,221
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 $227,000,
$181,000 and $156,000 in 1993, 1992 and 1991, 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 $7,170,000 and
$5,492,000, as reported in the Consolidated Balance Sheets at
December 31, 1993 and 1992, 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.
Unbilled gas costs as of December 31, 1993 includes $305,000 of
accrued pipeline charges relating to restructured gas supply
contracts. It also includes $2,833,000 of transition costs that
have been paid but not yet recovered from utility customers (see
Note I).
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 expense or income charged or credited on
regulatory assets or 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 deferred
compensation 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 deferred compensation plans.
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.
Note B: Federal Income Tax
During 1992, the Company adopted Statement of Financial Accounting
Standards No. 109 "Accounting for Income Taxes" (SFAS 109). During
1991, the Company recorded deferred income taxes under Statement
of Financial Accounting Standards No. 96 "Accounting for Income
Taxes" (SFAS 96). The adoption of SFAS 109 had no significant
impact on the Company's financial statements. SFAS 109 requires,
among other things, the recording of cumulative deferred income
taxes on all temporary timing differences. 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, 1993, the Company has a liability of
$12,689,000 on the Consolidated Balance Sheet as Deferred Income
Taxes - Unfunded and a corresponding unrecovered deferred charge.
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 $1,238,000 at December 31, 1993, representing the
amount of pre-July 1, 1987 deferred income taxes that were
recorded in excess of the current Federal statutory income tax
rate. This amount is being returned to utility customers over the
remaining book life of utility property.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1993 1992 1991
Charged (credited) to operations:
Current $5,191 $(362) $2,348
Deferred:
Unbilled gas costs (1,753) 3,590 -
Accelerated depreciation 2,157 2,092 1,727
Cost of removal 190 149 138
Construction contribution - - (343)
Environmental response costs (33) (223) (175)
Pension 141 131 110
Recovery of unfunded deferred taxes 556 578 572
Miscellaneous (93) (316) (311)
Amortization of investment tax credits (245) (249) (263)
Total 6,111 5,390 3,803
Charged (credited) to other income 578 486 (90)
Total Federal income tax expense $6,689 $5,876 $3,713
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1993 1992 1991
Statutory Federal income tax rate 35% 34% 34%
Increases (reductions) in taxes
resulting from:
Amortization of investment tax credits (1) (2) (2)
Construction contribution - - (3)
Recovery of unfunded deferred taxes 3 4 5
Miscellaneous items (1) - (3)
Effective Federal income tax rate 36% 36% 31%
Temporary differences which gave rise to the following deferred
tax assets and liabilities at December 31, 1993 are:
(In Thousands) Deferred Tax Assets (Liabilities)
Construction contributions $ 1,176
Other 940
Total deferred tax assets 2,116
Accelerated depreciation (32,333)
Cost of removal (2,105)
Unbilled gas costs (2,212)
Environmental response costs (1,634)
Other (2,128)
Total deferred tax liabilities (40,412)
Total deferred taxes $ (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.
On November 9, 1993, the Company's Board of Directors adopted a
Shareholder Rights Plan (the "Rights Plan") and declared a
dividend distribution of one share purchase right (a "Right") for
each outstanding share of the Company's Common Stock, 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 earliest of
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; and the final expiration date.
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 $15,776,000 of retained
earnings was available to pay dividends on Common Stock as of
December 31, 1993.
Note E: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1993 1992
First mortgage bonds:
14.00% Series CC due 1999 $ 2,750 $ 3,250
8.86% Series CD due 2001 8,000 9,000
9.40% Series CE due 1997 15,000 15,000
10.25% Series CF due 2004 20,000 20,000
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
Total 90,750 92,250
Less: Long-term debt due within one year 3,318 1,500
Total long-term debt $ 87,432 $ 90,750
The aggregate amount of maturities and sinking fund requirements
for the years 1994, 1995, 1996, 1997, and 1998 are $3,318,000,
$8,318,000, $8,318,000, $8,318,000, and $3,318,000, respectively.
In addition to these normal sinking fund requirements, the Company
will have the option to call all or a portion of the Series CC
first mortgage bonds on or after June 15, 1994.
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.
Note F: Short-Term Debt
In June 1993, the Company established a one-year bank line of
credit of $60,000,000 with a consortium of five banks to replace
its expiring $50,000,000 bank line of credit. The bank line of
credit allows the Company to borrow on a demand basis up to
$60,000,000, 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, 1993, the credit available under the bank line of credit was
$12,167,000. The weighted average interest rates for the Company's
short-term debt were 3.64% and 3.76% at December 31, 1993 and
1992, 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 1993, 1992 and
1991 approximately $390,000, $433,000 and $671,000, 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
$7,475,000 and $8,329,000 at December 31, 1993 and 1992,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $3,561,000 and $3,963,000
at December 31, 1993 and 1992, 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 1993, 1992 and 1991
approximated $1,808,000, $1,984,000 and $2,163,000, respectively.
At December 31, 1993, the future minimum payments (including
interest) under the Company's lease agreements are: $1,069,000 in
1994; $917,000 in 1995; $719,000 in 1996; $572,000 in 1997;
$389,000 in 1998; and $882,000 thereafter.
Note H: Employee Benefit Plans
Savings Plans - The Company sponsors three employee 401(k) Savings
Plans. The Company's matching contribution, exclusive of plan
administration costs, was $418,000, $316,000 and $291,000 for
1993, 1992 and 1991, 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) 1993 1992 1991
Benefits earned during the period $ 1,031 $ 958 $ 752
Interest cost on projected benefit
obligation 2,690 2,500 2,093
Actual return on plan assets (2,656) (469) (7,839)
Net amortization and deferral 325 (1,760) 6,276
Net periodic pension cost $1,390 $1,229 $1,282
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1993 1992 1991
Weighted average discount rate 7.25% 8.00% 8.00%
Future compensation increases 5.00% 5.50% 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, 1993 and 1992 is as
follows:
1993 1992
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(23,689) $(9,208) $(19,728) $(8,287)
Nonvested (562) (356) (420) (414)
Accumulated (24,251) (9,564) (20,148) (8,701)
Due to recognition of
future salary increases (5,665) (6) (4,978) -
Total (29,916) (9,570) (25,126) (8,701)
Plan assets at fair 28,250 5,186 26,226 4,799
value
Projected benefit
obligation
(in excess of) less
than plan assets (1,666) (4,384) 1,100 (3,902)
Unrecognized net loss
(gain) 1,695 909 (1,203) 281
Unrecognized
transition amount 2,818 2,312 2,665 2,681
Additional liability
accrued - (3,215) - (2,962)
Prepaid (accrued)
pension costs $2,847 $(4,378) $2,562 $(3,902)
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.
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 and $168,000 in 1992 and 1991, respectively. In
accordance with SFAS 106, the Company began recording the cost for
this plan on an accrual basis for 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 1993 was
$817,000. A regulatory asset of $431,000 has been recorded,
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, 1993:
(In Thousands)
Accumulated postretirement
benefit obligation:
Retirees $(2,523)
Fully eligible active plan participants (1,629)
Other active plan participants (2,388)
(6,540)
Plan assets at fair value 2,940
Accumulated postretirement benefit obligation
in excess of plan assets (3,600)
Unrecognized net (gain) from past experience
different from that assumed and from
changes in assumptions (60)
Unrecognized transition obligation 5,123
Prepaid postretirement benefit cost $1,463
Net periodic postretirement benefit cost for 1993 included the
following components:
(In Thousands)
Service cost - benefits attributable to service
during the period $ 268
Interest cost on accumulated postretirement
benefit obligation 478
Actual return on plan assets (202)
Net amortization and deferral 273
Net periodic postretirement benefit cost 817
Regulatory asset (431)
Net expense $ 386
For measurement purposes, a 9% (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
1994; the rate for medical costs was assumed to decrease gradually
to 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, 1993 by
$935,000 and the aggregate of the service and the interest cost
components of net periodic postretirement benefit cost for 1993 by
$124,000.
The weighted-average discount rate used in determining the
accumulated postretirement benefit obligation was 7.25%. 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.
Postemployment Benefits - The Company plans to adopt prospectively
for 1994 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 should 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. Based
on current rates, the minimum payments under these contracts total
$518,000,000 through the year 2012, of which approximately
$48,000,000 is due during each of the next five years.
FERC Order No. 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
$5,100,000 to $12,000,000. Through December 31, 1993, the Company
has paid $3,100,000 of transition costs. The Company is recovering
these costs from its customers, as approved by the DPU. As of
December 31, 1993, the Company has recorded on the balance sheet a
long-term liability of $2,000,000 ("Accrued Transition Costs") and
based upon rate recovery, has recorded a regulatory asset of
$2,000,000 ("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, 1993, the
Company had incurred $7,750,000 of environmental response costs
related to these sites, $1,521,000 for the former gas
manufacturing site and $6,229,000 for the related disposal sites.
The Company expects to continue incurring costs arising from these
environmental matters.
As of December 31, 1993 the Company has recorded on the balance
sheet a long-term liability of $5,300,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation; of this amount
$2,200,000 relates to the gas manufacturing site. Based upon the
DPU order approving rate recovery of environmental response costs,
a regulatory asset of $5,300,000 has been recorded on the balance
sheet ("Unrecovered Environmental Costs Accrued"). This amount has
decreased from the prior year estimate based upon the completion
of certain remedial actions and a lower expectation of future
costs due to changes in environmental regulations and a better
understanding of on-site exposures. 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, 1993, the Company had settled claims relating
to this matter with all liability insurers and other known
potentially responsible parties ("PRP"), except for one. The
Company expects to receive $250,000 in 1994 from that 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) Insurance and
Other Proceeds
Response Costs Recorded as
Recovered Period Returned Non-Operating
from of Rate to Income
Year Incurred Customers Recovery Customers Net of Taxes
1988 $ 853 $ 488 1990-1997 - -
1989 4,031 2,303 1990-1997 - -
1990 639 274 1991-1998 - -
1991 374 107 1992-1999 $ 851 $ 525
1992 617 88 1993-2000 1,121 673
1993 1,236 - 1994-2001 469 290
Total $7,750 $3,260 $2,441 $1,488
Note K: Fair Value of Financial Instruments
In accordance with Statement of Financial Accounting Standards No.
107 "Disclosures About Fair Values of Financial Instruments", the
following methods and assumptions were used to estimate the fair
value for the following financial instruments:
Cash and Cash Equivalents and Short-term Debt - The carrying
amount approximates fair value.
Long-Term Debt - 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 $90,750,000 and $92,250,000 as of December 31, 1993 and 1992,
respectively. The fair value of long-term debt was $104,562,000 and
$101,440,000 as of December 31, 1993 and 1992, 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.
Note L: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)
Income
Utility (Loss) Per
Operating Net Average Dividends
Operating Income Income Common Paid Per
Quarter Ended Revenues (Loss) (Loss) Share Share
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
1992
December 31 $50,261 $7,547 $5,568 $ .71 $.305
September 30 12,458 (2,713) (3,922) (.51) .305
June 30 18,251 (1,838) (3,614) (.47) .303
March 31 64,084 14,155 12,611 1.65 .300
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 M: Reclassifications
Certain amounts in the prior years have been reclassified to
conform with the 1993 financial statement presentation.
[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, 1993 and
1992, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1993. 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, 1993 and 1992, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1993, 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.
Boston, Massachusetts
January 18, 1994
[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 was $12,022,000 or $1.52 per common share in 1993
compared to $10,643,000 or $1.38 per common share in 1992, and
$8,317,000 or $1.10 per common share in 1991.
Net income was impacted by significantly colder-than-normal
temperatures in 1993 and 1992 and significantly warmer-than-normal
temperatures in 1991, which is summarized as follows:
1993 1992 1991
Percent colder (warmer) than normal
Peak Season (January - April and
November - December) 8.0% 2.6% (8.1)%
Off-Peak Season (May - October) 3.7% 17.9% (15.4)%
Year Average 7.3% 4.8% (9.2)%
Percent colder (warmer) than prior year
Peak Season (January - April and
November - December) 5.2% 11.7% 3.2%
Off-Peak Season (May - October) (12.1)% 39.4% (12.6)%
Year Average 2.4% 15.5% 0.7%
Other items which had an impact on net income are discussed in the
following sections.
Dividends per common share were $1.235 in 1993, $1.213 in 1992
and $1.193 in 1991. The Company has paid dividends for 57
consecutive years, and has increased dividends each year for the
past fourteen years.
Operating Revenues
Operating revenues were $166,261,000 in 1993, $145,054,000 in 1992
and $137,719,000 in 1991. 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 11,239 over the last three years, an increase of 9.3%, which
increase has added to sales volume. The chart below summarizes
volumes of gas sold and transported and firm customers:
1993 1992 1991
Gas sold (In MMcf)
Firm 18,935 18,542 16,689
Interruptible 1,030 1,508 1,631
Gas transported
Firm 4,163 1,997 1,133
Interruptible 4,026 2,820 3,352
Total gas sold and
transported (In MMcf) 28,154 24,867 22,805
Firm Customers 132,188 127,965 123,185
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 and a 4.9%
rate increase effective November 1, 1993. Temperatures were 2.4%
colder than the comparable 1992 period and 7.3% colder than
normal. This cooler weather pattern, together with continued
customer growth, helped raise firm gas sales by 2.1% or 393,000
Mcf.
Operating revenues increased $7,335,000, or 5.3%, from 1991 to
1992. This increase resulted primarily from weather that was
colder than the prior year and a growing customer base.
Temperatures were 15.5% colder than the comparable 1991 period and
4.8% colder than normal. This cooler weather pattern, together
with continued customer growth, helped raise firm gas sales by
11.1% or 1,853,000 Mcf.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.53 in 1993, $3.73 in 1992
and $3.98 in 1991. 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 interruptible 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) 1993 1992 1991
Gas purchased
Pipeline firm 9,804 8,292 5,053
Pipeline spot 5,179 8,341 9,604
Underground storage 3,501 2,666 3,018
LNG/Other 1,832 1,668 999
Total gas purchased 20,316 20,967 18,674
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 $32,748,000 in 1993, an increase of
$1,267,000 or 4.0%, from 1992, and $31,481,000 in 1992, an
increase of $1,717,000, or 5.8%, from 1991. The increase in 1993
was primarily due to increased labor and medical insurance costs
and and an increase in bad debt expense. The majority of the
increase in 1992 was the result of increased labor and medical
insurance costs.
Maintenance expense increased $154,000, or 2.8%, in 1993 from
1992 and increased $353,000, or 6.9%, in 1992 from 1991.
Depreciation and amortization expense increased 15.5% or
$917,000 in 1993 and 7.8% or $426,000 in 1992. The increase in
1993 was primarily due to an increase in utility property and to
increased depreciation rates as a result of the Company's 1993
rate order. The increase in 1992 was the result of an increase in
utility property.
Local property and other taxes increased 14.8% in 1993 from 1992
and 17.2% in 1992 from 1991 due to higher property and payroll
taxes, and additional property subject to property taxes.
Income Taxes
Total Federal income and state franchise taxes increased 13.2% or
$862,000 in 1993 and 37% or $1,763,000 in 1992 as a result of a
higher level of income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $209,000
in 1993, $36,000 in 1992 and $(733,000) in 1991. Other operating
income includes results from the Company's wholly-owned energy
trucking subsidiary (Transgas) and appliance sales.
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 were sold at
prices exceeding net book value. Transgas' LNG transportation
revenue 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.
Transgas returned to profitability in 1992 after a loss in 1991
due to more normal weather, which increased demand for
supplemental fuels throughout the region. In addition, portable
pipeline sales rose dramatically in 1992 due to increases in
construction and maintenance projects by pipeline companies.
Factors affecting the future financial results of Transgas
include the amount of liquefied natural gas ("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 $1,064,000 in 1993,
$922,000 in 1992 and $769,000 in 1991. Non-operating income
includes interest income and miscellaneous other income. Included
in non-operating income were recoveries of $290,000, $673,000 and
$525,000 in 1993, 1992 and 1991, 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 9.0% in 1993 and decreased
8.3% in 1992. 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. The
decrease in 1992 was primarily due to reduced levels of long-term
debt during the first six months of the year and a decrease in
interest expense on regulatory assets, offset by increased levels
of short-term debt.
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 to 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.
Regulatory Matters
During 1990, the DPU ruled that the Company and eight other
Massachusetts gas distribution companies can recover environmental
response costs related to former gas manufacturing operations
through the CGAC as described under "Environmental Matters".
In August 1992, the DPU approved the second phase of the
Company's demand side management program. When completed this
program is expected to save over $15 million in gas costs that
would have been incurred over the lives of the installed
conservation measures. In order to achieve these savings, Colonial
is investing $8 million over a two-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 a net $7 million from the
levels they would have been at if no conservation occurred.
Colonial has been authorized by the DPU to fully recover all costs
associated with the program through the CGAC. In addition, the
Company is also authorized to recover the margins lost as a result
of this program and, if certain milestones are met, to receive an
additional financial incentive of up to $400,000. In January 1994,
the Company filed a request with the DPU to extend the operation
of this program from September 1994 until September 1995. A ruling
is expected shortly.
In October 1992, the Company received authorization from the DPU
to extend natural gas service into the Town of Eastham,
Massachusetts. Eastham, located at the eastern end of Cape Cod,
provides Colonial with new growth opportunities. Colonial believes
that there are 5,000 homes and businesses in Eastham that
currently utilize other fuels such as oil, electricity and propane
which present opportunities for natural gas conversions. The
Company has added 104 customers in the town since facilities were
constructed in the fourth quarter of 1992.
In November 1992, the DPU approved Colonial's request for two
new rate schedules which are designed to overcome equipment cost
disadvantages that existed in the natural gas air conditioning and
small scale cogeneration markets. By reducing , if not
eliminating, these cost disadvantages, the Company expects to
increase sales into these markets and increase the usage of its
distribution system during off peak periods. The Company has used
these new rate schedules to make proposals to potentially large
customers and expects to continue to pursue this new market
opportunity in 1994.
In April 1993, the Company applied for a $10.75 million or 7.87%
increase in its base rates. This was only the second base rate
increase requested by Colonial 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 to be applied to
low-income residential heating customers.
The table below summarizes the Company's recent rate activity:
Results of the Company's Request to Increase Base Revenue
Requested 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 response to new marketing opportunities which may result from
the Federal Energy Regulatory Commission ("FERC") Order 636 and
the unbundling of interstate pipeline services, Colonial requested
in its 1993 rate filing and gained DPU approval to offer a firm
transportation service on the Company's distribution system in
order to provide customers with an alternative to traditional firm
sales service. The DPU order also permits the Company to retain
10% of the revenues generated from releasing the Company's
interstate pipeline transportation capacity to third parties above
a threshold of $2,500,000 for 1994. In 1993, the Company earned
$2,200,000 in capacity release revenue that was credited back to
firm customers and had no impact on earnings.
In October 1993, the DPU approved Colonial's proposal for a rate
targeted at the natural gas vehicle market. The approved rates
remain in effect over the course of a "market-development" period
that extends until January 1, 1997. To assist Colonial in selling
additional quantities of natural gas to the natural gas powered
vehicle market, the authorized rate is to be indexed $.50 below
the retail price of gasoline, provided that it cannot fall below a
floor rate equal to Colonial's marginal cost of gas plus 5%. As of
December 31, 1993, these rates are approximately equal to $0.70
per gallon equivalent for retail customers.
By the fall of 1993, two interstate pipelines serving Colonial
had implemented Order 636. Order 636, issued in 1992, required
interstate pipeline companies to "unbundle" gas supply,
transportation and storage services previously provided under a
unified tariffed service. Now, the Company is responsible for
procuring gas supplies and storage services to meet its load
requirements, with the pipelines providing transportation only
service. In general, Colonial pays negotiated rates for gas
supplies and FERC-approved tariffed rates for transportation and
storage services. On November 9, 1993, the Company filed each of
its gas supply purchase contracts to be reviewed by the DPU, which
has not previously exercised jurisdiction with respect to the
Company's base load supplies. These FERC ordered changes may
increase the contracting, supply and regulatory risk for the
Company. At the same time, they could also create a more
competitive market for gas supply which would permit the Company
to achieve savings in its cost of gas. Because the new rules have
recently been implemented, the Company cannot now predict their
impact, but it does not expect them to have a material direct
effect on its results of operations.
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, 1993, the
Company had incurred $7,750,000 of environmental response costs
related to these sites, $1,521,000 for the former gas
manufacturing site and $6,229,000 for the related disposal sites.
The Company expects to continue incurring costs arising from these
environmental matters.
As of December 31, 1993 the Company has recorded on the balance
sheet a long-term liability of $5,300,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation; of this amount
$2,200,000 relates to the gas manufacturing site. Based upon the
DPU order approving rate recovery of environmental response costs,
a regulatory asset of $5,300,000 has been recorded on the balance
sheet ("Unrecovered Environmental Costs Accrued"). This amount has
decreased from the prior year estimate based upon the completion
of certain remedial actions and a lower expectation of future
costs due to changes in environmental regulations and a better
understanding of on-site exposures. 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, 1993, the Company had settled claims relating
to this matter with all liability insurers and other known
potentially responsible parties ("PRP"), except for one. The
Company expects to receive $250,000 in 1994 from that 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) Insurance and
Other Proceeds
Response Costs Recorded as
Recovered Period Returned Non-Operating
from of Rate to Income
Year Incurred Customers Recovery Customers Net of Taxes
1988 $ 853 $ 488 1990-1997 - -
1989 4,031 2,303 1990-1997 - -
1990 639 274 1991-1998 - -
1991 374 107 1992-1999 $ 851 $ 525
1992 617 88 1993-2000 1,121 673
1993 1,236 - 1994-2001 469 290
Total $7,750 $3,260 $2,441 $1,488
Accounting Standards
During 1992, the Company adopted Statement of Financial Accounting
Standards No. 109 "Accounting for Income Taxes" (SFAS 109). During
1991, the Company recorded deferred income taxes under Statement
of Financial Accounting Standards No. 96 "Accounting for Income
Taxes" (SFAS 96). The adoption of SFAS 109 had no significant
impact on the Company's financial statements.
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 and
$168,000 in 1992 and 1991, respectively. In accordance with SFAS
106, the Company began recording the cost for this plan on an
accrual basis for 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 1993 was $817,000. A regulatory
asset of $431,000 has been recorded, 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.
The Company plans to adopt prospectively for 1994 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
should not have a significant impact on the Company's results of
operations.
LIQUIDITY AND CAPITAL RESOURCES
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.
The Company's capital additions were $26,156,000 in 1993,
$27,166,000 in 1992 and $17,314,000 in 1991. The Company's 1994
capital expenditure forecast is $27,000,000. The Company has
completed a comprehensive planning effort which resulted in the
development of a long-range capital plan. This plan calls for
annual capital expenditures averaging $28,400,000 over the next
five years as set forth in the chart below:
(In Thousands) 1994 1995 1996 1997 1998
Distribution $18,100 $19,900 $20,200 $22,500 $22,300
Production 1,400 3,800 5,900 3,200 1,000
Information Systems 4,400 4,200 4,300 700 700
Automated Meter
Reading 1,600 1,100 1,000 1,000 1,100
General 1,500 300 300 1,100 300
Total Capital
Expenditures $27,000 $29,300 $31,700 $28,500 $25,400
The Company has a $60 million credit facility that expires in
June 1994. Up to $30 million of the credit facility can be used by
the Company's gas inventory trust. This facility allows the
Company the option to borrow under any one of four alternative
rates. The Company expects to make new short-term credit
arrangements prior to the expiration of the credit facility.
The Company has raised permanent capital during the last three
years as follows:
(In Thousands) 1993 1992 1991
Common Stock Under
Dividend Reinvestment
and Common Stock
Purchase Plan and three
Employee Savings Plans $4,283 $4,286 $2,776
Long-Term Debt
Series CG, 8.05%,
due entirely in 1999 - $20,000 -
Series CH, 8.80%,
due entirely in 2022 - $25,000 -
The equity and debt components of the Company's capital structure
at the end of the year is shown in the table below:
1993 1992 1991
Equity 52% 49% 62%
Long-Term Debt 48% 51% 38%
[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) 1993 1992 1991 1990
Balance Sheet Data:
Assets:
Utility property - net $202,713 $183,815 $162,736 $151,480
Non-utility property - net 3,235 4,039 4,767 5,076
Capital leases - net 3,914 4,366 4,557 4,962
Current assets 67,668 71,763 53,472 46,393
Deferred charges and other assets 34,588 38,939 38,789 29,925
Total $312,118 $302,922 $264,321 $237,836
Capitalization and Liabilities:
Capitalization:
Common equity $ 94,283 $ 87,771 $ 82,221 $ 80,109
Preferred stock - - - -
Long-term debt 87,432 90,750 50,410 64,604
Total Capitalization 181,715 178,521 132,631 144,713
Capital lease obligations 3,149 3,591 3,838 4,233
Current liabilities 73,413 64,567 73,993 47,729
Deferred credits and reserves 53,841 56,243 53,859 41,161
Total $312,118 $302,922 $264,321 $237,836
Income Statement Data:
Operating revenues $166,261 $145,054 $137,719 $134,298
Cost of gas sold (90,915) (75,143) (73,288) (78,930)
Operating margin 75,346 69,911 64,431 55,368
Operating expenses (including
income taxes) (56,456) (52,760) (48,009) (42,853)
Utility operating income 18,890 17,151 16,422 12,515
Other income - net of income taxes 1,273 958 36 1,625
Interest and debt expense (8,141) (7,466) (8,141) (8,445)
Accounting change - - - -
Preferred stock dividends - - - -
Net income applicable to
common stock $ 12,022 $ 10,643 $ 8,317 $ 5,695
Capitalization Ratios:
Common Stockholders' equity 51.9% 49.2% 62.0% 55.4%
Preferred stocks - - - -
Long-term debt 48.1% 50.8% 38.0% 44.6%
Common Stock Data (a):
Average shares outstanding 7,931 7,728 7,529 6,963
Income per share (b) $1.52 $1.38 $1.10 $0.82
Dividends paid per share:
Common stock $1.235 $1.213 $1.193 $1.167
Class A common stock - - - -
Per weighted average common share $1.235 $1.213 $1.193 $1.167
Dividend payout rate 81% 88% 108% 142%
Book value per share $11.74 $11.19 $10.78 $10.75
Dividends as a percent of book value 11% 11% 11% 11%
Market price per share $22.50 $21.25 $17.50 $15.00
Market price as a percent of
book value 192% 190% 162% 139%
Return on average common equity 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 $2,014 ($.50 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 Stockholders' equity 48.9% 53.4% 49.9%
Preferred stocks - - -
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 $10.62 $10.27 $9.69
Dividends as a percent of book value 11% 11% 11%
Market price per share $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 $2,014 ($.50 per share).
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1986 1985 1984
Balance Sheet Data:
Assets:
Utility property - net $111,214 $102,959 $ 95,526
Non-utility property - net 3,665 3,834 3,213
Capital leases - net 9,201 8,432 9,022
Current assets 37,234 45,411 47,172
Deferred charges and other assets 4,235 4,676 4,605
Total $165,549 $165,312 $159,538
Capitalization and Liabilities:
Capitalization:
Common equity $ 54,569 $ 46,053 $ 42,300
Preferred stock - 6,672 7,227
Long-term debt 47,528 40,007 46,252
Total Capitalization 102,097 92,732 95,779
Capital lease obligations 8,258 9,533 10,292
Current liabilities 41,151 50,413 43,250
Deferred credits and reserves 14,043 12,634 10,217
Total $165,549 $165,312 $159,538
Income Statement Data:
Operating revenues $126,099 $128,165 $121,732
Cost of gas sold (75,157) (80,623) (76,851)
Operating margin 50,942 47,542 44,881
Operating expenses (including
income taxes) (37,938) (35,312) (33,214)
Utility operating income 13,004 12,230 11,667
Other income - net of income taxes 383 1,201 862
Interest and debt expense (5,861) (6,010) (6,385)
Accounting change - - -
Preferred stock dividends (312) (724) (763)
Net income applicable to common stock $7,214 $6,697 $5,381
Capitalization Ratios:
Common Stockholders' equity 53.4% 49.7% 44.3%
Preferred stocks - 7.2% 7.5%
Long-term debt 46.6% 43.1% 48.2%
Common Stock Data (a):
Average shares outstanding 5,588 5,193 4,524
Income per share (b) $1.29 $1.29 $1.19
Dividends paid per share:
Common stock $1.060 $1.033 $1.007
Class A common stock $ .72 $ .68 $ .64
Per weighted average common share $ .960 $ .920 $ .887
Dividend payout rate 74% 71% 74%
Book value per share $9.25 $8.73 $8.27
Dividends as a percent of book value 11% 12% 12%
Market price per share $14.33 $11.59 $10.50
Market price as a percent of
book value 155% 133% 127%
Return on average common equity 14.3% 15.2% 14.0%
_____________________________________________________________________
(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 $2,014 ($.50 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
Colonial Gas Company Common Stock is traded on the NASDAQ
National Market System under the trading 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 20, 1994
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 1993 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
(617) 575-2900
1-800-442-2001 (Outside MA)
1-800-827-1446 (Inside MA)
Independent Certified Public Accountants
Grant Thornton
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 57 consecutive
years and has increased dividends each year for the past fourteen
years. Common Stock dividends are payable when declared by the
Board of Directors.
Anticipated Record Date Anticipated Payment Date
March 1, 1994 March 15, 1994
June 1, 1994 June 15, 1994
September 1, 1994 September 15, 1994
December 1, 1994 December 15, 1994
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.
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, 1994
May 5, 1994
June 7, 1994
July 7, 1994
August 5, 1994
September 7, 1994
October 5, 1994
November 4, 1994
December 7, 1994
SHAREHOLDER INFORMATION
Market Prices and Dividends
The following table reflects the high and low bid prices as reported by
the NASDAQ National Market System, for shares of the Company's Common
Stock for 1993 and 1992, and the quarterly dividends paid per share.
Bid Prices Dividends
High Low Paid per Share
_________________________________________________________________
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
1992 __________________________________
The Year $23.50 $16.67 $1.213
4th Quarter 22.13 20.50 .305
3rd Quarter 23.50 18.50 .305
2nd Quarter 19.00 18.00 .303
1st Quarter 19.33 16.67 .300
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1993, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,783
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.; Kidder, Peabody, & 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 ENDING DECEMBER 31, 1993]