[EXHIBIT 13a TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1997]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1997 1996 1995
Operating Revenues $187,140 $169,878 $163,668
Cost of gas sold 102,455 87,188 83,631
Operating Margin 84,685 82,690 80,037
Operating Expenses:
Operations 30,044 30,372 30,410
Maintenance 4,503 4,476 4,401
Depreciation and amortization 12,049 11,228 10,225
Local property taxes 3,139 3,189 3,020
Other taxes 2,122 2,183 2,130
Total Operating Expenses 51,857 51,448 50,186
Income Taxes:
Federal income tax 8,264 7,001 6,879
State franchise tax 1,708 2,087 1,447
Total Income Taxes 9,972 9,088 8,326
Utility Operating Income 22,856 22,154 21,525
Other Operating Income (Expense):
Energy Trucking revenues 5,529 11,031 7,576
Energy Trucking expenses, including
income taxes and interest (5,202) (9,005) (6,972)
Energy Trucking Net Income 327 2,026 604
Other, net of income taxes 318 250 41
Total Other Operating Income 645 2,276 645
Non-Operating Income, Net of Income Taxes 573 757 864
Income Before Interest and
Debt Expense 24,074 25,187 23,034
Interest and Debt Expense 8,034 8,709 9,270
Net Income $16,040 $16,478 $13,764
Average Common Shares Outstanding 8,598 8,432 8,294
Income per Average Common Share $1.87 $1.95 $1.66
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1997 1996
Utility Property:
At original cost $362,742 $333,319
Accumulated depreciation (88,210) (82,336)
Net Utility Property 274,532 250,983
Non-Utility Property - Net 7,312 5,925
Net Property 281,844 256,908
Capital Leases - Net 2,630 1,811
Current Assets:
Cash and cash equivalents 259 3,541
Accounts receivable 21,788 17,719
Allowance for doubtful accounts (3,203) (2,715)
Accrued utility revenues 7,417 6,333
Unbilled gas costs 19,266 19,238
Fuel inventory - at average cost 12,959 11,958
Materials and supplies -
at average cost 2,950 2,891
Prepayments and other current assets 6,531 8,593
Total Current Assets 67,967 67,558
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 9,014 9,774
Unrecovered demand side management
costs 8,273 7,075
Unrecovered environmental costs
incurred 3,833 4,011
Unrecovered environmental costs accrued 707 1,183
Unrecovered pension costs 3,455 3,135
Unrecovered transition costs accrued 2,800 4,500
Excess cost of investments over
net assets acquired 2,798 2,798
Other 5,670 5,659
Total Deferred Charges and
Other Assets 36,550 38,135
Total Assets $388,991 $364,412
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1997 1996
Capitalization:
Common Equity:
Common Stock $ 28,932 $28,366
Premium on Common Stock 57,277 54,221
Retained earnings 35,923 31,319
Total Common Equity 122,132 113,906
Long-Term Debt 100,102 95,266
Total Capitalization 222,234 209,172
Capital Lease Obligations 1,617 930
Current Liabilities:
Current maturities of long-term debt 10,164 5,152
Current capital lease obligations 1,013 881
Notes payable 49,400 50,400
Gas inventory purchase obligations 14,895 13,039
Accounts payable 15,674 14,544
Accrued interest 2,375 1,815
Current deferred income taxes 3,654 5,090
Other current liabilities 5,333 3,248
Total Current Liabilities 102,508 94,169
Deferred Credits and Reserves:
Deferred income taxes - Funded 41,443 35,886
Deferred income taxes - Unfunded 9,014 9,774
Accrued environmental costs 707 1,183
Accrued transition costs 2,800 4,500
Unamortized investment tax credits 3,372 3,672
Pension reserve 4,507 4,174
Other deferred credits and reserves 789 952
Total Deferred Credits and
Reserves 62,632 60,141
Total Capitalization and Liabilities $388,991 $364,412
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1997 1996 1995
Cash Flows From Operating Activities:
Net Income $16,040 $16,478 $13,764
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 13,334 12,361 11,211
Deferred income taxes 3,208 7,968 1,159
Amortization of investment tax
credits (300) (268) (275)
Provision for uncollectible accounts 1,955 2,146 1,829
Other, net 109 171 973
34,346 38,856 28,661
Changes in current assets and liabilities:
Accounts receivable and accrued
utility revenues (6,620) 2,305 (9,293)
Unbilled gas costs (28) (9,550) 2,490
Fuel inventory (1,001) (1,442) 2,443
Prepayments and other current assets 2,003 (4,015) 5,612
Accounts payable 1,130 2,394 2,515
Other current liabilities 2,645 (2,929) (920)
Net Cash Provided by Operating
Activities 32,475 25,619 31,508
Cash Flows From Investing Activities:
Utility capital expenditures (35,788) (26,875) (24,096)
Non-utility capital expenditures (1,888) (1,367) (1,974)
Change in deferred accounts (842) (1,502) (2,077)
Net Cash Used in Investing Activities (38,518) (29,744) (28,147)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (11,435) (10,919) (10,571)
Issuance of Common Stock 3,622 3,277 2,702
Issuance of long-term debt, net
of issuance costs 14,870 29,787 19,685
Retirement of long-term debt,
including premiums (5,152) (11,284) (27,477)
Change in notes payable (1,000) (11,435) 12,335
Change in gas inventory
purchase obligations 1,856 699 (1,520)
Net Cash Provided by (Used in)
Financing Activities 2,761 125 (4,846)
Net Decrease in Cash and Cash
Equivalents (3,282) (4,000) (1,485)
Cash and Cash Equivalents at
Beginning of Year 3,541 7,541 9,026
Cash and Cash Equivalents at
End of Year $ 259 $ 3,541 $ 7,541
Supplemental Disclosures of Cash
Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 9,465 $9,149 $ 9,867
Income and state franchise taxes $ 7,509 $8,489 $ 3,444
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1997 1996 1995
Common Stock
$3.33 par value; authorized 15,000
shares; outstanding, 8,688 in 1997,
8,518 in 1996, and 8,367 in 1995
Beginning of year $28,366 $27,863 $27,397
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (170 shares
in 1997, 151 shares in 1996
and 140 shares in 1995) 566 503 466
End of year $28,932 $28,366 $27,863
Premium on Common Stock
Beginning of year $54,221 $51,447 $49,211
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 3,056 2,774 2,236
End of year $57,277 $54,221 $51,447
Retained Earnings
Beginning of year $31,319 $25,760 $22,567
Net income 16,040 16,478 13,764
Cash dividends on Common
Stock ($1.33 a share in
1997, $1.295 a share in
1996 and $1.275 a share
in 1995) (11,435) (10,919) (10,571)
End of year $35,923 $31,319 $25,760
Total Common Equity $122,132 $113,906 $105,070
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A: Summary of Significant Accounting Policies
Nature of Operations - Colonial Gas Company, a Massachusetts
corporation formed in 1849, is primarily a regulated natural gas
distribution utility. The Company serves over 151,000 utility
customers in 24 municipalities located northwest of Boston and on
Cape Cod. Through its subsidiary, Transgas Inc., the Company also
provides over-the-road transportation of liquefied natural gas,
propane, and other commodities.
Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its
subsidiaries. All material intercompany items have been eliminated
in consolidation.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
Utility Regulation - The Company's utility operations are subject
to regulation by the Massachusetts Department of
Telecommunications & Energy ("DTE"), formerly known as the
Massachusetts Department of Public Utilities, 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 $594,000,
$437,000, and $568,000 in 1997, 1996 and 1995, respectively.
The original cost of depreciable utility property retired,
together with the cost of removal, net of salvage, is charged to
accumulated depreciation. Depreciation applicable to the Company's
utility property in service is calculated in accordance with
depreciation rates as approved by the DTE. A composite
depreciation rate of approximately 3.8% is applied to the utility
property balance at the beginning of each year. Depreciation on
non-utility property is computed by various methods.
Operating Revenues - Operating revenues are accrued based upon the
amount of gas delivered to utility customers through the end of
the accounting period. Accrued utility revenues of $7,417,000 and
$6,333,000, as reported in the Consolidated Balance Sheets at
December 31, 1997 and 1996, respectively, represent the accrual of
unbilled operating revenues net of related gas costs. The
Company's policy is to record lost margins and financial
incentives relating to the Company's demand side management
("DSM") programs as revenue when earned by the Company and
approved by the DTE.
Unbilled Gas Costs - The Company charges or credits its utility
customers for increases or decreases in gas costs from those
reflected in its base tariffs by applying a cost of gas adjustment
clause ("CGAC"). In accordance with the CGAC, any under or over
recoveries of gas costs are charged or credited to the unbilled
gas cost account and recorded as a current asset or liability.
Such under or over recoveries are collected or refunded, with
interest accrued at the prime rate, in subsequent periods.
Pipeline Refunds Due Customers - The Company periodically receives
refunds from interstate pipeline companies related to rate
adjustments ordered by the Federal Energy Regulatory Commission
("FERC"). Refunds are returned to utility customers under methods
approved by the DTE.
Excess Cost of Investments over Net Assets Acquired - This asset
arose principally from the pre-1971 acquisitions of utility
operations. No amortization has been provided since, in the
opinion of management, there has been no diminution in value of
the applicable investments.
Income Taxes - The Company records deferred income taxes for the
income tax effect of the difference between book and tax
depreciation and all other temporary book and tax differences, in
accordance with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" ("SFAS 109"). Unamortized
investment tax credits, which were allowed under Federal income
tax laws prior to 1987, have been deferred and are being amortized
as a credit to income tax expense over the estimated service lives
of the corresponding assets.
Interest and Debt Expense - Interest and debt expense includes
interest on long-term debt, interest on short-term notes payable
and regulatory interest. As approved by the DTE, regulatory
interest is interest income credited on regulatory assets or
interest expense charged on regulatory liabilities.
Pension Plans - The Company and its subsidiaries have defined
benefit pension plans covering substantially all employees. These
include two qualified union plans, one qualified plan for non-
union employees, and various unqualified individual retirement
agreements covering certain key employees and retirees. The
Company's funding policy for the qualified plans is to contribute
annually an amount at least equal to the normal cost plus a 30-
year amortization of the unfunded actuarially calculated accrued
liability.
Cash and Cash Equivalents - For the purposes of the Consolidated
Balance Sheets and Statements of Cash Flows, the Company considers
cash investments with an original maturity of three months or less
to be cash equivalents.
Fair Value of Financial Instruments - In accordance with Statement
of Financial Accounting Standards No. 107 "Disclosures About Fair
Values of Financial Instruments", the fair value amounts are
disclosed below. These fair value amounts are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.
The carrying amount of cash and cash equivalents and short-
term debt approximates fair value. The fair value of long-term debt
is estimated based on the rates available to the Company at the end
of each respective year for debt of the same remaining maturities.
The carrying amount of long-term debt (including current
maturities) was $110,266,000 and $100,418,000 as of December 31,
1997 and 1996, respectively. The fair value of long-term debt was
$115,700,000 and $102,000,000 as of December 31, 1997 and 1996,
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.
Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of". This statement requires the Company to review
long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. The adoption of this standard did not have a
material impact on the Company's financial condition or 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 DTE, the Company did
not record deferred income taxes but rather "flowed through" tax
benefits to utility customers. At December 31, 1997, the Company
has a liability of $9,014,000 on the Consolidated Balance Sheet as
Deferred Income Taxes - Unfunded and a corresponding unrecovered
deferred asset. The liability represents the tax effect of pre-
1981 timing differences for which deferred income taxes had not
been provided and was increased in accordance with SFAS 109 for
the tax effect of future revenue requirements. The Company is
recovering these unfunded deferred taxes from utility customers
over the remaining book life of utility property.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1997 1996 1995
Charged (credited) to
operations:
Current $5,188 $1,104 $6,422
Deferred:
Accelerated depreciation 1,688 2,202 2,005
Unbilled gas costs (98) 2,929 (1,523)
Demand side management costs 88 747 (32)
Pension costs 301 449 (38)
Recovery of unfunded
deferred taxes 398 398 398
Debt expense (53 (53) 848
Transition costs -- (1) (871)
Environmental Response Costs (58) (246) 22
Bad debt 889 (167) (175)
Miscellaneous 221 (93) 96
Amortization of investment tax
credits (300) (268) 273
Total 8,264 7,001 6,879
Charged to other income 312 1,599 510
Total Federal income
tax expense $8,576 $8,600 $7,389
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1997 1996 1995
Statutory Federal income tax rate 35% 35% 35%
Increases (reductions) in taxes
resulting from:
Amortization of investment
tax credits (1) (1) (1)
Recovery of unfunded deferred
taxes 2 2 2
Miscellaneous items (1) (2) (1)
Effective Federal income
tax rate 35% 34% 35%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1997 1996
Deferred Tax Assets:
Construction contributions $ 891 $ 974
Other 227 335
Total deferred tax assets 1,118 1,309
Deferred Tax Liabilities:
Accelerated depreciation (41,345) (39,580)
Unbilled gas costs (3,654) (3,990)
Demand side management costs (2,765) (2,659)
Environmental response costs (1,502) (1,571)
Cost of removal (3,033) (2,792)
Other (2,930) (1,467)
Total deferred tax
liabilities (55,229) (52,059)
Total deferred taxes $(54,111) $(50,750)
Note C: Capital Stock
Pursuant to the Company's dividend reinvestment and common stock
purchase plan, shareholders can automatically reinvest their cash
dividends and can invest optional limited amounts of cash payments
in newly issued shares.
The Company has authorized and unissued 547,559 shares of Class
A Preferred Stock, $25 par value, of which 100,000 shares have
been designated a Junior Preferred Stock series and reserved for
issuance under the Rights Plan described below, and 370,000 shares
of Class B Preferred Stock, $1 par value.
A Shareholder Rights Plan provides one right ("Right") to
purchase one one-hundredth of a share of the Company's Series A-1
Junior Participating Preferred Stock, par value $25 per share, at
a price of $60 per share, subject to adjustment. The Rights expire
on December 1, 2003 and only become exercisable, or separately
transferable, 10 days after a person or group acquires, or
announces an intention to acquire, beneficial ownership of 20% or
more of the Company's Common Stock. The Rights are redeemable by
the Board at a price of $.01 per Right at any time prior to the
expiration of ten days after the acquisition by a person or group
of beneficial ownership of 20% or more of the Company's Common
Stock.
Note D: Long-Term Debt
The composition of long-term debt is as follows:
Maturity Put December 31,
(In Thousands) Date Date 1997 1996
First mortgage bonds:
9.40% Series CE due 1997 $ - $ 5,000
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
6.85% Series MTA-1 due 2025 2005 10,000 10,000
6.45% Series MTA-2 due 2025 2005 10,000 10,000
6.94% Series MTA-3 due 2026 10,000 10,000
6.20% Series MTA-4 due 1998 10,000 10,000
6.88% Series MTA-5 due 2008 10,000 10,000
6.81% Series MTA-6 due 2027 2002 15,000 0
Total 110,000 100,000
Note payable 266 418
Less: Long-term debt due within one year (10,164) (5,152)
Total long-term debt $100,102 $95,266
The aggregate amount of maturities for the years 1998 through 2002
are $10,164,000 in 1998, and $20,102,000 in 1999. Bonds of
$15,000,000 due in 2027 can be redeemed by the holder in 2002.
The first mortgage bonds are collateralized by utility property.
The Company's first mortgage bond indenture includes, among other
provisions, limitations on the issuance of long-term debt, leases
and the payment of dividends from retained earnings. The note
payable is collateralized by equipment.
The Company has a medium term note ("MTN") program which permits
the issuance of up to $75 million of MTN's as bonds under its
indenture of which $65 million has been issued as of December 1997.
The bonds with a put date noted above can be redeemed by the holder
within a 30 day period in the year indicated.
Interest Rate Instruments: - The Company has entered into
treasury rate locks in order to hedge the interest rate on long-
term debt anticipated to be issued in early 1998. The treasury rate
locks are for $10 million at a 10 year treasury rate of 5.88% and
for $20 million at a 15 year treasury rate of 5.88%. Upon issuance
of the debt, any gain or loss realized on the treasury rate locks
will be amortized to interest expense over the term of the related
debt.
Note E: Short-Term Debt
In September 1997, the Company established a three-year bank line
of credit of $75 million with a consortium of five banks. The bank
line of credit allows the Company to borrow on a demand basis up
to $75 million, less whatever amount has been borrowed through the
Company's gas inventory trust (described below). The line of
credit allows the Company the option to borrow under three
alternative rates: based on eurodollar rate (LIBOR), prime rate,
or a competitive bid option. At December 31, 1997, the credit
available under the bank line of credit was $10,705,000. The
weighted average interest rates for short-term debt were 6.18% and
5.87% at December 31, 1997 and 1996, respectively.
The Company has an agreement with a single-purpose Massachusetts
trust, the Company's gas inventory trust, under which the Company
sells supplemental gas inventory to the trust at the Company's
cost. The Company's agreement with the trust requires it to
repurchase such inventory at cost when needed and reimburse the
trust for expenses incurred to finance the gas inventory. The
trust finances such purchases of inventory by borrowing under a
bank line of credit with a maximum borrowing commitment of $30
million that is complementary to and on similar terms as the
Company's bank line of credit described above. The DTE has
approved the inventory trust arrangement and has permitted the
cost of such gas inventory, including fees and financing costs, to
be recovered through the Company's CGAC. During 1997, 1996 and
1995 approximately $564,000, $500,000 and $662,000, respectively,
of interest costs were incurred by the trust.
Note F: 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
$7,703,000 and $7,685,000 at December 31, 1997 and 1996,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $5,072,000 and $5,874,000
at December 31, 1997 and 1996, 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 1997, 1996 and 1995
approximated $1,527,000, $1,493,000 and $1,429,000, respectively.
At December 31, 1997, the future minimum payments (including
interest) under the Company's lease agreements are: $1,069,000 in
1998; $749,000 in 1999; $619,000 in 2000; $544,000 in 2001;
$201,000 in 2002; and $0 thereafter.
Note G: Employee Benefit Plans
Savings Plan - The Company sponsors an employee 401(k) Savings
Plan. The Company's matching contribution, exclusive of plan
administration costs, was $625,000, $570,000 and $459,000 for
1997, 1996 and 1995, 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) 1997 1996 1995
Benefits earned during the period $1,042 $1,036 $ 836
Interest cost on projected
benefit obligation 3,427 3,267 3,279
Actual return on plan assets (6,711) (4,710) (5,515)
Net amortization and deferral 3,673 1,882 2,757
Net periodic pension cost $1,431 $1,475 $1,357
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1997 1996 1995
Weighted average discount rate 7.00% 7.75% 7.50%
Future compensation increases 4.00% 4.00% 4.00%
Expected long-term rate of return
on assets 9.00% 9.00% 9.00%
The funded status of the plans at December 31, 1997 and 1996 is as
follows:
1997 1996
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(32,420) $(12,020) $(28,612) $(10,381)
Nonvested (828) (1,088) (703) (956)
Accumulated (33,248) (13,108) (29,315) (11,337)
Due to recognition of
future salary increases (4,497) (136) (4,248) (116)
Total (37,745) (13,244) (33,563) (11,453)
Plan assets at fair 38,765 9,567 33,743 7,715
value
Projected benefit
obligation 1,020 (3,677) 180 (3,738)
less than (in
excess of)
plan assets
Unrecognized net (gain) 78 729 (457) 188
loss
Unrecognized 1,223 331 1,398 2,020
transition amount
Unrecognized prior (60) 2,424 487 1,064
service cost
Additional liability
accrued - (3,350) - (3,157)
Prepaid (accrued)
pension costs $2,261 $ (3,543) $ 1,608 (3,623)
Assets of the employee benefit plans are invested in domestic and
international equities, medium-term domestic fixed income
securities, international fixed income securities, real estate and
other short-term debt instruments.
Postretirement Life and Health Benefit Plan - The Company sponsors
a postretirement benefit plan that covers substantially all
employees. The plan provides medical, dental and life insurance
benefits. The plan is contributory for retirees, with respect to
postretirement medical and dental benefits; the plan is
noncontributory with respect to life insurance benefits.
During 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). Prior to
1993, expense was recognized when benefits were paid. In
accordance with SFAS 106, the Company began recording the cost for
this plan on an accrual basis in 1993. The Company amortizes the
transition obligation over a twenty-year period. The Company's
cost under this plan for 1997, 1996 and 1995 was $410,000,
$501,000 and $672,000 respectively. A regulatory asset of $431,000
was recorded in 1993 representing the excess of postretirement
benefits on the accrual basis over the paid amounts for the period
of January 1, 1993 until November 1, 1993, the effective date of
the DTE's approval of the Company's new rates. Currently, the DTE
allows Massachusetts utilities to recover the tax deductible
portion of these postretirement benefits.
Beginning in 1990, the Company has funded a portion of these
costs through the combination of 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 following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1997 and 1996:
(In Thousands) 1997 1996
Accumulated postretirement
benefit obligation:
Retirees $(4,564) $(3,957)
Fully eligible active plan
participants (1,192) (1,033)
Other active plan
participants (1,423) (1,239)
Total (7,179) (6,229)
Plan assets at fair value 5,163 4,563
Accumulated postretirement
benefit obligation
in excess of plan assets (2,016) (1,666)
Unrecognized net (gain) from
past experience different
from that assumed and from
changes in assumptions (1,351) (1,679)
Unrecognized transition
obligation 4,045 4,315
Prepaid postretirement benefit
cost $ 678 $ 970
Net periodic postretirement benefit cost included the following
components:
Year Ended December 31,
(In Thousands) 1997 1996 1995
Service cost - benefits
attributable to service $113 $137 $145
during the period
Interest cost on accumulated
postretirement 477 461 505
benefit obligation
Actual return on plan assets (779) (507) (639)
Net amortization and deferral 599 410 661
Net periodic postretirement $410 $501 $672
benefit cost
For measurement purposes, a 6% (4.5% for dental costs) annual
rate of increase in the per capita cost of covered health care
benefits was assumed for 1998; the rate of increase for medical
costs was assumed to decrease gradually to 4.5% for 2001 and
remain at that level thereafter. The health care cost trend rate
assumption has a significant effect on the amounts reported. To
illustrate, increasing the assumed health care cost trend rates by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1997 by
$979,000 and the aggregate of the service and the interest cost
components of net periodic postretirement benefit cost for the
year then ended by $81,000.
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.0%, 7.75% and
7.5% for 1997, 1996 and 1995, 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.
Note H: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2013, for the acquisition and
delivery of gas supplies and the storage and delivery of natural
gas stored underground. The contracts contain minimum payment
provisions which correspond to gas purchases that, in the opinion
of management, are not in excess of the Company's requirements.
FERC Order 636 Transition Costs - As a result of FERC Order 636,
the Company's interstate pipeline service providers have been
required to unbundle their supply and transportation services.
This unbundling has caused the interstate pipeline companies to
incur substantial costs in order to comply with Order 636. These
transition costs include four types: (1) unrecovered gas costs
(gas costs that had been incurred but not yet recovered by the
pipelines when they were providing bundled service to local
distribution companies); (2) gas supply realignment costs (the
cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that
can not be assigned to customers of unbundled services); and (4)
new facilities costs (costs of new facilities required to
physically implement Order 636).
Pipelines are 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 additional transition cost liabilities are estimated to
range from $2,800,000 to $3,300,000. The Company is recovering
these costs from its customers, as approved by the DTE in October
1994. As of December 31, 1997, the Company has recorded on the
balance sheet a long-term liability of $2,800,000 ("Accrued
Transition Costs") and, based upon expected rate recovery, has
recorded a regulatory asset of $2,800,000 ("Unrecovered Transition
Costs Accrued"). Actual transition costs to be incurred depends on
various factors, and therefore future costs may differ from the
amounts discussed above.
Note I: Contingencies
The Company is involved in various legal actions and claims
arising in the normal course of business. Management does not
believe the outcome of any action or claim will have a material
adverse effect upon the Company's financial position or results of
operations.
Working with the Massachusetts Department of Environmental
Protection, the Company is engaged in site assessments and
evaluation of remedial options for contamination that has been
attributed to the Company's former gas manufacturing site and at
various related disposal sites. During 1990, the DTE ruled that
Colonial and eight other Massachusetts gas distribution companies
can recover environmental response costs related to former gas
manufacturing operations over a seven-year period, without
carrying costs, through the CGAC. Through December 31, 1997, the
Company had incurred environmental response costs of $11,875,000
of which $8,042,000 has been recovered from customers to date.
As of December 31, 1997, the Company has recorded on the balance
sheet a long-term liability of $707,000 and, based upon expected
rate recovery, has recorded a corresponding regulatory asset. This
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation. Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
Note J: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts) Income
Utility (Loss) Per Dividends
Operating Net Average Paid Per
Operating Income Income Common Common
Quarter Ended Revenues (Loss) (Loss) Share Share
1997
December 31 $62,275 $9,481 $7,814 $.90 $.335
September 30 14,877 (3,043) (4,566) (.53) .335
June 30 26,927 (556) (2,501) (.29) .335
March 31 83,061 16,974 15,293 1.79 .325
1996
December 31 $53,612 $9,289 $7,035 $.83 $.325
September 30 14,983 (2,613) (3,580) (.42) .325
June 30 23,973 (714) (2,205) (.26) .325
March 31 77,310 16,192 15,228 1.82 .320
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.
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, 1997 and
1996, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1997. 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, 1997 and 1996, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles.
GRANT THORNTON LLP
Boston, Massachusetts
January 14, 1998
REPORT OF MANAGEMENT
To the Shareholders of Colonial Gas Company
Management is responsible for the preparation and integrity of the
Company's financial statements. The financial statements have been
prepared in accordance with generally accepted accounting
principles as applied to regulated public utilities and
necessarily include some amounts that are based on management's
best estimates and judgment.
The Company maintains a system of internal accounting and
administrative controls and an ongoing program of internal audits
that management believes provide reasonable assurance that assets
are safeguarded and that transactions are properly recorded and
executed in accordance with management's authorization. The
Company's financial statements have been audited by the
independent public accounting firm, Grant Thornton LLP, who also
conducts a review of internal controls to the extent required by
generally accepted auditing standards.
The Audit Committee of the Board of Directors, composed solely
of outside directors, meets with management, internal auditors and
Grant Thornton LLP to review planned audit scope and results and
to discuss other matters affecting internal accounting controls
and financial reporting. The independent accountants and internal
auditors have direct access to the Audit Committee and
periodically meet with its members without management
representatives present.
F. L. Putnam, III Nickolas Stavropoulos
President and Chief Executive Vice President-
Executive Officer Finance, Marketing and
Chief Financial Officer
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 $16,040,000
($1.87), $16,478,000 ($1.95), and $13,764,000 ($1.66) for the
years ended December 31, 1997, 1996, and 1995, respectively.
Net income was favorably impacted by colder than 20-year average
temperatures in 1997, 1996 and 1995. This is summarized as
follows:
1997 1996 1995
Percent colder than 20-year average 1.8% 3.0% 2.4%
Percent colder (warmer) than prior year (1.2)% 0.6% (2.5)%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.33 in 1997, $1.295 in
1996 and $1.275 in 1995. The Company has paid dividends for 61
consecutive years, and has increased dividends each year for the
past 18 years.
Operating Revenues
Operating revenues were $187,140,000 in 1997, $169,878,000 in 1996
and $163,668,000 in 1995. Operating revenues are impacted by the
volumes of gas sold and transported, changes in base rates as
approved by the Massachusetts Department of Telecommunications &
Energy (DTE), formerly known as the Massachusetts Department of
Public Utilities, 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 14,900 over the last three years from 136,700 in December 1994
to 151,600 in December 1997, an increase of 10.9%. The chart
below summarizes volumes of gas sold and transported and number of
firm customers:
1997 1996 1995
(In MMcf)
Gas sold
Firm 19,997 19,56 318,560
Non-Firm 62 648 1,148
Gas transported
Firm 3,278 3,918 2,537
Non-Firm 3,791 2,671 3,224
Total gas sold and
transported (In MMcf) 27,128 26,800 25,469
Firm Customers 151,600 145,400 141,400
Operating revenues increased $17,262,000 or 10.2% from 1996 to
1997. This increase resulted from customer growth of 4.2% and
higher gas costs, which offset weather which was 1.2% warmer than
the prior year.
Operating revenues increased $6,210,000, or 3.8% from 1995 to
1996. This increase resulted from weather that was 0.6% colder
than the prior year and customer growth of 2.9%.
Cost of Gas Sold
Average cost of gas sold per Mcf was $5.08 in 1997, $4.29 in 1996
and $4.22 in 1995. Cost of gas sold is based upon the sales
volumes, the price and mix of gas purchased and used to satisfy
demand, and profits on non-firm sales and transportation, which
flow back to firm sales customers as a credit through the CGAC.
The Company distributes natural gas purchased under long-term
contracts as well as gas purchased on the spot market. The
following table summarizes the sources of gas purchased by the
Company:
(In MMcf) 1997 1996 1995
Gas purchased
Pipeline 14,763 15,115 14,659
Underground storage 3,605 3,346 3,270
LNG/Other 2,365 2,596 2,426
Total gas purchased 20,733 21,057 20,355
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 $30,044,000 in 1997, a decrease of $328,000
or 1.1%, from 1996, and $30,372,000 in 1996, a decrease of
$38,000, or 0.1%, from 1995.
Maintenance expense increased $27,000, or 0.6%, in 1997 from
1996 and increased $75,000, or 1.7%, in 1996 from 1995.
Depreciation and amortization expense increased $821,000 or 7.3%
in 1997 and $1,003,000 or 9.8% in 1996. The increases in 1997 and
1996 were due to increases in utility property.
Local property and other taxes decreased 2.1% in 1997 from 1996
due to reduced property taxes. Local property and other taxes
increased 4.3% in 1996 from 1995. The increase in 1996 was due to
higher property taxes and additional property subject to property
taxes.
Income Taxes
Total Federal income and state franchise taxes increased $884,000
or 9.7% in 1997 from 1996 and increased $762,000 or 9.2% in 1996
from 1995 as a result of a higher level of income for the utility
operations.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $645,000
in 1997, $2,276,000 in 1996 and $645,000 in 1995. Other operating
income primarily includes the results of the Company's wholly-
owned energy trucking subsidiary (Transgas). Also included are
heating and water heating equipment sales and installations.
Transgas' 1997 financial results were driven by a 50% decrease
in liquefied natural gas ("LNG") hauls leading to a $5,502,000
decrease in energy trucking revenue and a $1,699,000 decrease in
energy trucking net income. This decrease in demand of
transportation of LNG occurred for most of the year and was
primarily due to the warmer than normal weather in the first
quarter of 1997.
Transgas' 1996 financial results were driven by a 68% increase
in LNG hauls leading to a $3,455,000 increase in energy trucking
revenue and a $1,422,000 increase in energy trucking net income.
This increase in demand of transportation of LNG occurred for most
of the year and was primarily due to the colder than normal
weather in the fourth quarter of 1995 and the first quarter of
1996.
Factors affecting the future financial results of Transgas, in
addition to the impact of weather variations, include the amount
of LNG used by local distribution companies throughout the
northeast United States to satisfy requirements of their
customers; the price of domestic and Canadian natural gas compared
to imported LNG; the continued availability of imported LNG; and
the level of construction and major maintenance projects of
interstate pipeline companies which drives the demand for portable
pipeline services.
Non-Operating Income
Non-operating income, net of income taxes, was $573,000 in 1997,
$757,000 in 1996 and $864,000 in 1995. Non-operating income
includes interest income and miscellaneous other income.
Interest and Debt Expense
Interest and debt expense decreased $675,000 or 7.7% in 1997 from
1996. The decrease in 1997 was due to decreased levels of short-
term debt and greater interest income on higher balances of
regulatory assets, which offset interest expense. These were
partially offset by an increase in interest on long-term debt.
Interest and debt expense decreased $561,000 or 6.1% in 1996. The
decrease in 1996 was due to a decrease in interest on long-term
debt resulting from the early retirement of higher interest debt
in December 1995 offset by increased levels of short-term debt,
although at 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 DTE. Changes in
the cost of gas sold are automatically reflected in customer rates
pursuant to semi-annual adjustments under the CGAC. In the absence
of authorized rate increases, the Company must look to increased
productivity and higher sales volumes to offset inflationary
increases in its other costs of operations. The present regulatory
process permits the Company to earn a rate of return based on the
historical cost of utility property without recognition of the
current replacement cost. The Company's policy is to file for an
increase in rates only when increases in productivity and
customers are not sufficient to counteract the impact of
inflation. The Company has set a goal to defer its next base rate
increase until at least the year 2000.
Regulatory Matters
The Company is a public utility subject to the jurisdiction and
regulatory authority of the DTE with respect to its rates as well
as to the issuance of securities, franchise territory and other
related matters. On July 18, 1997, the DTE directed the Company
and the other investor-owned gas utilities in Massachusetts to
collaborate on developing common principles to unbundle their
services to provide customers with broader supplier choice. The
DTE further directed that all gas utilities have unbundled rates
in effect by November 1, 1998 for all customer classes.
Unbundled service separates (i) the part of the service
involving procuring the gas and transporting it to the city-gate
(i.e. the point where the Company takes gas from the interstate
pipeline into its distribution systems); and (ii) the delivery of
the gas to the customer's facility through the local distribution
system. The Company presently offers an unbundled service to
commercial and industrial customers who seek to have other
suppliers procure their gas which the Company then delivers to
them through its distribution system. The Company's proposal for
further rate unbundling is being developed and is expected to be
filed in the spring of 1998. In addition, the Company continues
to participate in the DTE-directed Unbundling Collaborative. The
Company cannot predict the outcome of the unbundling collaborative
process or the other regulatory changes that may take place, but
at this time, the Company does not anticipate that the unbundling
of its services will have a material financial impact on its
business.
Under the present regulatory system, the DTE permits
Massachusetts gas companies to utilize a CGAC through which firm
sales customers pay, via their monthly gas bill, the costs
incurred by the companies in procuring and transporting gas to the
companies distribution systems. Changes in non-gas or base rates
charged to customers are subject to approval by the DTE after
formal proceedings.
Environmental response costs, transition costs and demand side
management ("DSM") program costs are recovered through the CGAC,
as approved by the DTE. The environmental response costs recovered
through the CGAC relate to the Company's former gas manufacturing
operations, as described under "Environmental Matters". Transition
costs relate to Federal Energy Regulatory Commission ("FERC")
approved pipeline charges resulting from Order 636. In addition to
full recovery of the installed conservation measures, the Company
is allowed to recover, under methodologies approved in 1995 for
its residential DSM programs and in 1996 for its commercial and
industrial programs resulting lost margins and financial
incentives based on the attainment of performance goals.
The Company has made only two requests for base rate increases
since 1984. Its most recent request was made in 1993. In response
to that request, the DTE approved a base rate increase that was
designed to produce additional revenues of $6.7 million or 3.9%
annually, effective November 1, 1993. Based upon continued strong
customer growth, cost control and improved productivity, the
Company's goal remains to postpone the filing of a request for its
next base rate increase until at least the year 2000, while
maintaining an adequate return to shareholders. Under a 1995
industry wide ruling of the DTE, the Company will be required in
its next base rate filing either to present an alternative
incentive based method of pricing or to justify continuation of
the traditional cost of service/rate of return method.
On the same July 18, 1997 date that the DTE issued its directive
to the Massachusetts investor-owned gas utilities to collaborate
on unbundling their services, the DTE issued its order declining
to approve the Company's proposed joint venture with Cabot LNG
Corporation. The proposed joint venture would have combined
certain LNG assets and resources of the two companies, including
the Company's Tewksbury LNG facility and its LNG trucking
subsidiary, Transgas Inc. The DTE's decision declining to approve
the joint venture appeared to be based in large part on its
unwillingness to allow a supply asset like the Tewksbury LNG
facility to be used as proposed until the issues related to
unbundling were resolved.
The Company follows the provisions of Statement of Financial
Accounting Standards No. 71 "Accounting for the Effects of Certain
Types of Regulation" ("SFAS 71") requiring the Company to record
the financial statement effects of the rate regulation to which
the Company is currently subject. Future regulatory changes could
result in the Company no longer meeting the provisions of SFAS 71
for all or part of its business, thereby requiring the elimination
of the financial statement effects of regulation for that portion
of its business.
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 DTE ruled that
Colonial and eight other Massachusetts gas distribution companies
can recover environmental response costs related to former gas
manufacturing operations over a seven-year period, without
carrying costs, through the CGAC. Through December 31, 1997, the
Company had incurred environmental response costs of $11,875,000
of which $8,042,000 has been recovered from customers to date.
As of December 31, 1997, the Company has recorded on the balance
sheet a long-term liability of $707,000 and, based upon expected
rate recovery, has recorded a corresponding regulatory asset. This
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation. Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
Accounting Standards
Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of". This statement requires the Company to review
long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. The adoption of this standard did not have a
material impact on the Company's financial condition or results of
operations.
The Year 2000 Issue
The Company's principal computer systems are currently capable of
processing the year 2000 or are in the process of being upgraded
or replaced by systems that are similarly capable. The Company
does not expect the cost of addressing this issue to have a
material impact on the Company's financial results.
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 to
80 percent of its annual operating revenues during the November
through April heating season, which results in a high level of
cash flow from operations from late winter through early summer.
As a result of this seasonality, the Company's liquidity can be
affected by significant variations in weather. Short-term
borrowings are highest during the fall and early winter months due
to the completion of the annual construction program and seasonal
working capital requirements.
Investing Activities
The Company invests in property, plant and equipment to improve
and protect its distribution system, and to expand its system to
meet customer demand. Utility capital expenditures were
$35,788,000 in 1997, $26,875,000 in 1996 and $24,096,000 in 1995.
The Company's long-range plan calls for annual utility
expenditures, of which over 52% is budgeted for new business,
averaging $28,000,000 over the next five years as follows:
(In Thousands) 1998 1999 2000 2001 2002
Distribution $22,500 $23,100 $23,800 $24,700 $25,600
Production 1,800 100 400 300 900
Information Systems 5,000 3,100 2,400 500 400
Automated Meter
Reading 3,100 300 300 300 200
General 300 300 300 300 300
Total Capital
Expenditures $32,700 $26,900 $27,200 $26,100 $27,400
Financing Activities
The Company has raised permanent capital during the last three
years as follows:
(In Thousands) 1997 1996 1995
Common Stock Under Dividend
Reinvestment and Common Stock
Purchase Plan and Employee
Savings Plan $3,621 $3,277 $2,702
Medium term notes under
the first mortgage
indenture $15,000 $30,000 $20,000
The aggregate amount of maturities of Long-Term Debt for the
years 1998 through 2002 are $10,164,000 in 1998, and $20,102,000
in 1999. Series MTA-6 Bonds due in 2027 can be redeemed by the
holder in 2002. The Company has entered into treasury rate locks
in order to hedge the interest rate on long-term debt anticipated
to be issued in early 1998. The treasury rate locks are for $10
million at a 10-year treasury rate of 5.88% and for $20 million at
a 15-year treasury rate of 5.88%.
The Company has a $75 million credit facility expiring in
September 2000, which allows it to meet its seasonal working
capital needs. 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 three
alternative rates.
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1997 1996 1995
Equity 55% 54% 58%
Long-Term Debt 45% 46% 42%
As of April 1997, the quarterly dividend paid on the Company's
Common Stock was increased to $.335 per share or an annualized
dividend rate of $1.34 per share.
Forward Looking Information
This report and other Company reports contain forward looking
statements which are subject to the inherent uncertainties in
predicting future results and conditions. Certain factors that
could cause actual results to differ materially from those
projected in these forward looking statements include, but are not
limited to, variations in weather, changes in the regulatory
environment, customers' preferences on energy sources, general
economic condition, increased competition and other uncertainties,
all of which are difficult to predict, and many of which are
beyond the control of the Company.
FINANCIAL AND OPERATING STATISTICS
(For the Years Ending
December 31) 1997 1996 1995 1994 1993
Operating
Revenues
(In Thousands)
Residential $121,649 $108,879 $103,991 $104,812 $106,362
Commercial and
industrial 59,163 54,324 52,926 56,358 53,933
Firm transportation 1,941 1,843 1,294 1,210 816
Non-firm sales 2,530 2,985 3,745 2,429 3,613
Non-firm
transportation 631 453 424 401 409
Other 1,226 1,394 1,288 1,017 233
Total operating
revenues $187,140 $169,878 $163,668 $165,327 $165,366
Gas Sold (MMcf)
Residential 12,492 12,094 11,361 11,190 11,492
Commercial and
industrial 7,505 7,469 7,199 7,526 7,443
Non-firm 62 648 1,148 729 1,030
Total gas
sales 20,059 20,211 19,708 19,445 19,965
Gas Transported (MMcf)
Firm 3,278 3,918 2,537 6,090 4,163
Non-firm 3,791 2,671 3,224 4,185 4,026
Total gas
transported 7,069 6,589 5,761 10,275 8,189
Total gas sold
and trans-
ported 27,128 26,800 25,469 29,720 28,154
Gas Purchased (MMcf)
Pipeline 14,763 15,115 14,659 14,392 14,983
Underground storage 3,605 3,346 3,270 3,112 3,501
LNG - as liquid 680 1,067 844 1,129 907
LNG - as vapor 1,680 1,528 1,574 1,236 917
Propane 5 1 8 25 8
Total gas
purchased 20,733 21,057 20,355 19,894 20,316
Company use and
other (674) (846) (647) (449) (351)
Available for
sale 20,059 20,211 19,708 19,445 19,965
Customers - End of
period
Residential 136,826 131,286 127,419 123,077 118,918
Commercial and
industrial 14,697 14,136 13,940 13,559 13,269
Firm transportation 30 19 11 8 1
Non-firm sales 22 25 27 21 21
Non-firm transportation 15 5 2 2 2
Total customers -
end of period 151,590 145,471 141,399 136,667 132,211
Average Annual Mcf
Sold/Customer
Residential 96 96 94 96 101
Commercial and
industrial 519 533 531 569 575
Average Annual
Bill/Customer
Residential $935 $868 $858 $897 $939
Commercial and
industrial $4,093 $3,880 $3,901 $4,260 $4,167
Average Revenue/Mcf
Residential $9.74 $9.00 $9.15 $9.37 $9.26
Commercial and
industrial $7.88 $7.27 $7.35 $7.49 $7.25
Residential Heating
Customers as a
% of all Residential
Customers 91% 90% 90% 90% 90%
Highest Daily
Sendout (Mcf) 183,063 170,984 199,275 204,896 184,303
Percent Colder
(Warmer) than
20-year average 1.8% 3.0% 2.4% 5.0% 6.3%
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except
Per Share Amounts) 1997 1996 1995 1994 1993
Balance Sheet Data:
Assets:
Utility property - net $274,532 $250,983 $235,555 $221,685 $202,713
Non-utility property
- net 7,312 5,925 5,036 3,479 3,235
Capital leases - net 2,630 1,811 2,253 2,948 3,914
Current assets 67,967 67,558 61,002 65,568 67,668
Deferred charges and
other assets 36,550 38,135 38,575 37,668 34,588
Total $388,991 $364,412 $342,421 $331,348 $312,118
Capitalization and
Liabilities:
Capitalization:
Common equity $122,132 $113,906 $105,070 $ 99,175 $ 94,283
Long-term debt 100,102 95,266 75,418 77,923 87,432
Total
Capitalization 222,234 209,172 180,488 177,098 181,715
Capital lease obligations 1,617 930 1,359 2,237 3,149
Current liabilities 102,508 94,169 101,666 91,382 73,413
Deferred credits and
reserves 62,632 60,141 58,908 60,631 53,841
Total $388,991 $364,412 $342,421 $331,348 $312,118
Income Statement Data:
Operating revenues $187,140 $169,878 $163,668 $165,327 $165,366
Cost of gas sold (102,455) (87,188) (83,631) (87,458) (90,915)
Operating margin 84,685 82,690 80,037 77,869 74,451
Operating expenses
(including income
taxes) (61,829) (60,536) (58,512) (60,331) (55,736)
Utility operating income 22,856 22,154 21,525 17,538 18,715
Other income - net of
income taxes 1,218 3,003 1,509 1,880 1,448
Interest and debt
expense (8,034) (8,709) (9,270) (8,409) (8,141)
Accounting change - - - - -
Net income $16,040 $ 16,478 $13,764 $11,009 $ 12,022
Capitalization Ratios:
Common equity 55% 54% 58% 56% 52%
Long-term debt 45% 46% 42% 44% 48%
Common Stock Data:
Average shares
outstanding 8,598 8,432 8,294 8,119 7,931
Income per share $1.87 $1.95 $1.66 $1.36(a) $1.52
Dividends paid per share:
Common Stock $1.33 $1.295 $1.275 $1.255 $1.235
Class A Common Stock - - - - -
Per weighted average
common share $1.33 $1.295 $1.275 $1.255 $1.235
Dividend payout rate 71% 66% 77% 92% 81%
Book value per share $14.06 $13.37 $12.56 $12.05 $11.74
Dividends as a percent
of book value 9% 10% 10% 10% 11%
Market price per share $28.81 $21.25 $20.25 $19.25 $22.50
Market price as a
percent of book value 205% 159% 161% 160% 192%
Return on average common
equity 13.6% 15.1% 13.5% 11.4% 13.2%
(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting
change of $.33 per share.
SHAREHOLDER INFORMATION
Corporate Headquarters
Colonial Gas Company
40 Market Street
P. O. Box 3064
Lowell, MA 01853-3064
(978) 322-3000
FAX: (978) 459-2314
www.colonialgas.com
Annual Meeting
The Annual Meeting of Stockholders will be held on April
15, 1998 at 10:00 a.m. at BankBoston, 100 Federal Street,
Boston, Massachusetts.
Stock Listing
The Company's Common Stock began trading on the New York
Stock Exchange under the symbol "CLG" on September 18,
1997. Prior to that date, the Company traded on the NASDAQ
Stock Market under the symbol "CGES". Stock trading
activity is reported in financial publications under the
abbreviation of ColonlGas or ColnlGa.
Annual Report - Form 10-K
A copy of the Company's 1997 Annual Report on Form 10-K as
filed with the Securities and Exchange Commission will be
sent free of charge to any shareholder who contacts the
Investor Relations Department at the corporate
headquarters address above. Many of the Company's
financial statements are also available on its website.
Transfer Agent
BankBoston, N.A.
c/o Boston EquiServe, L.P.
P. O. Box 8040
Mail Stop: 45-02-64
Boston, MA 02266-8040
(800) 736-3001
(781) 575-3100
Independent Certified Public Accountants
Grant Thornton LLP
98 North Washington Street
Boston, MA 02114
(617) 723-7900
Corporate Counsel
Palmer & Dodge LLP
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 61
consecutive years and has increased dividends each year
for the past 18 years. Common Stock dividends are payable
if and when declared by the Board of Directors.
Anticipated Record Date Anticipated Payment Date
February 27, 1998 March 13, 1998
June 1, 1998 June 15, 1998
September 1, 1998 September 15, 1998
December 1, 1998 December 15, 1998
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock
Purchase Plan ("DRIP") provides shareholders of record
with an economical and convenient method for purchasing
additional shares of the Company's Common Stock without
paying any brokerage fees.
Participants in the plan may elect to purchase additional
Colonial shares at a 5% discount from the market price by
reinvesting all or a portion of their dividends with no
brokerage fees. Participants in the plan may also make
optional cash purchases of Common Stock at the market
price in amounts ranging from a minimum of $10 to a
maximum of $5,000 per calendar quarter, with no brokerage
fees.
Features of the plan at no charge to shareholders
include:
- Direct deposit of dividends by electronic deposit
- Automatic monthly investments by electronic funds
transfer
- Safekeeping of stock certificates
Additional information describing the plan, including a
prospectus and enrollment information, can be obtained by
contacting the Company's Transfer Agent or Investor
Relations Department.
Investment Dates
The investment date for optional cash investments under
the DRIP will be the fifteenth day of each month or, if
that day is not a business day, the preceding business
day. Optional cash investments must be received by the
Company's Transfer Agent five business days before the
investment date. The dates below will help you plan for
any optional cash investments during 1998.
Date Investment Must Be Investment
Received By Transfer Agent Dates
April 8 April 15
May 8 May 15
June 8 June 15
July 8 July 15
August 7 August 14
September 8 September 15
October 7 October 15
November 6 November 13
December 8 December 15
Equity Research
Equity research reports are independently prepared and
distributed by the following firms: A. G. Edwards & Sons, Inc.;
Edward Jones; First Dallas Securities; Merill Lynch; 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.
SHAREHOLDER INFORMATION
Market Prices and Dividends
The following table reflects the high and low sales prices as reported
by the New York Stock Exchange (since the third quarter of 1997) and
NASDAQ Stock Market, for shares of the Company's Common Stock for 1997
and 1996, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
1997 __________________________________
The Year $30-1/16 $19-1/4 $1.330
4th Quarter 30-1/16 23-11/16 .335
3rd Quarter 25-1/4 20-1/2 .335
2nd Quarter 22-3/4 19-1/4 .335
1st Quarter 24 20 .325
1996 __________________________________
The Year $24-1/4 $20 $1.295
4th Quarter 24 21-1/4 .325
3rd Quarter 24-1/4 20-1/4 .325
2nd Quarter 24-1/4 20 .325
1st Quarter 24 20-1/4 .320
Shareholders and Record Holders
At December 31, 1997, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,111
shareholders of record.
[END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1997]