[EXHIBIT 13a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1996]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1996 1995 1994
Operating Revenues $170,929 $164,649 $166,259
Cost of gas sold 87,188 83,631 87,458
Operating Margin 83,741 81,018 78,801
Operating Expenses:
Operations 31,383 31,309 33,004
Maintenance 4,476 4,401 5,074
Depreciation and amortization 11,228 10,225 9,235
Local property taxes 3,189 3,020 2,740
Other taxes 2,183 2,130 2,182
Restructuring charge - - 3,185
Total Operating Expenses 52,459 51,085 55,420
Income Taxes:
Federal income tax 7,001 6,912 4,806
State franchise tax 2,087 1,447 1,058
Total Income Taxes 9,088 8,359 5,864
Utility Operating Income 22,194 21,574 17,517
Other Operating Income (Expense):
Truck transportation revenues 11,031 7,576 12,066
Truck transportation expenses,including
income taxes and interest (9,005) (6,972) (10,579)
Truck Transportation Net Income 2,026 604 1,487
Other, net of income taxes 210 (8) (151)
Total Other Operating Income 2,236 596 1,336
Non-Operating Income,
Net of Income Taxes 757 864 565
Income Before Interest
and Debt Expense 25,187 23,034 19,418
Interest and Debt Expense 8,709 9,270 8,409
Net Income $16,478 $13,764 $11,009
Average Common Shares Outstanding 8,432 8,294 8,119
Income per Average Common Share $1.95 $1.66 $1.36
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1996 1995
Utility Property:
At original cost $333,319 $308,191
Accumulated depreciation (82,336) (72,636)
Net Utility Property 250,983 235,555
Non-Utility Property - Net 5,925 5,036
Net Property 256,908 240,591
Capital Leases - Net 1,811 2,253
Current Assets:
Cash and cash equivalents 3,541 7,541
Accounts receivable 17,719 19,069
Allowance for doubtful accounts (2,715) (2,205)
Accrued utility revenues 6,333 8,924
Unbilled gas costs 19,238 9,688
Fuel inventory - at average cost 11,958 10,516
Materials and supplies
-at average cost 2,891 3,132
Prepayments and other current assets 8,593 4,337
Total Current Assets 67,558 61,002
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 9,774 10,562
Unrecovered demand
side management costs 7,075 4,977
Unrecovered environmental
costs incurred 4,011 4,761
Unrecovered environmental
costs accrued 1,183 2,300
Unrecovered pension costs 3,135 3,917
Unrecovered transition costs accrued 4,500 3,600
Excess cost of investments over
net assets acquired 2,798 2,798
Other 5,659 5,660
Total Deferred
Charges and Other Assets 38,135 38,575
Total Assets $364,412 $342,421
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1996 1995
Capitalization:
Common Equity:
Common Stock $28,366 $27,863
Premium on Common Stock 54,221 51,447
Retained earnings 31,319 25,760
Total Common Equity 113,906 105,070
Long-Term Debt 95,266 75,418
Total Capitalization 209,172 180,488
Capital Lease Obligations 930 1,359
Current Liabilities:
Current maturities of long-term debt 5,152 6,141
Current capital lease obligations 881 894
Notes payable 50,400 61,835
Gas inventory purchase obligations 13,039 12,340
Accounts payable 14,544 12,150
Accrued interest 1,815 1,065
Current deferred income taxes 5,090 314
Other current liabilities 3,248 6,927
Total Current Liabilities 94,169 101,666
Deferred Credits and Reserves:
Deferred income taxes - Funded 35,886 32,299
Deferred income taxes - Unfunded 9,774 10,562
Accrued environmental costs 1,183 2,300
Accrued transition costs 4,500 3,600
Unamortized investment tax credits 3,672 3,940
Pension reserve 4,174 4,929
Other deferred credits and reserves 952 1,278
Total Deferred Credits and Reserves 60,141 58,908
Total Capitalization and
Liabilities $364,412 $342,421
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1996 1995 1994
Cash Flows From Operating Activities:
Net Income $16,478 $13,764 $11,009
Adjustments to reconcile net income to net cash:
Depreciation and amortization 12,361 11,211 10,150
Deferred income taxes 7,968 1,159 3,555
Amortization of investment
tax credits (268) (275) (234)
Provision for uncollectible
accounts 2,146 1,829 1,803
Other, net 171 973 811
Total adjustments 38,856 28,661 27,094
Changes in current assets and liabilities:
Accounts receivable (286) (6,517) 495
Accrued utility revenues 2,591 (2,776) 1,022
Unbilled gas costs (9,550) 2,490 4,581
Fuel inventory (1,442) 2,443 758
Materials and supplies 241 405 275
Prepayments and other
current assets (4,256) 5,207 (3,290)
Accounts payable 2,394 2,515 (2,526)
Accrued interest 750 (20) 68
Pipeline refunds due customes (2,077) (979) 213
Accrued pipeline charges - - (305)
Other current liabilities (1,602) 79 (86)
Net Cash Provided by
operating activity 25,619 31,508 28,299
Cash Flows From Investing Activities:
Utility capital expenditures (26,875) (24,096) (28,195)
Non-utility capital expenditures (1,367) (1,974) (876)
Change in deferred accounts (1,502) (2,077) (716)
Net Cash Used in
Investing Activities (29,744) (28,147) (29,787)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,919) (10,571) (10,187)
Issuance of Common Stock 3,277 2,702 4,070
Issuance of long-term debt,
net of issuance costs 29,787 19,685 741
Retirement of long-term debt,
including premiums (11,284) (27,477) (5,119)
Change in notes payable (11,435) 12,335 16,900
Change in gas inventory
purchase obligations 699 (1,520) (1,373)
Net Cash Provided by (Used in)
Financing Activities 125 (4,846) 5,032
Net (Decrease) Increase in Cash
and Cash Equivalents (4,000) (1,485) 3,544
Cash and Cash Equivalents
at Beginning of Year 7,541 9,026 5,482
Cash and Cash Equivalents
at End of Year $3,541 $7,541 $9,026
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $9,149 $9,867 $9,283
Income and state franchise taxes $8,489 $3,444 $7,282
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)
1996 1995 1994
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,518 in 1996, 8,367 in 1995,
and 8,227 in 1994
Beginning of year $27,863 $27,397 $26,739
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (151 shares
in 1996, 140 shares in 1995
and 197 shares in 1994) 503 466 658
End of year $28,366 $27,863 $27,397
Premium on Common Stock
Beginning of year $51,447 $49,211 $45,799
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 2,774 2,236 3,412
End of year $54,221 $51,447 $49,211
Retained Earnings
Beginning of year $25,760 $22,567 $21,745
Net income 16,478 13,764 11,009
Cash dividends on Common
Stock ($1.295 a share in 1996,
$1.275 a share in 1995 and
$1.255 a share in 1994) (10,919) (10,571) (10,187)
End of year $31,319 $25,760 $22,567
Total Common Equity $113,906 $105,070 $99,175
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 145,000 utility
customers in 24 municipalities located northwest of Boston and on
Cape Cod. Through its subsidiary, Transgas Inc., the Company also
provides over-the-road transportation of liquefied natural gas,
propane, and other commodities.
Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its
subsidiaries. All material intercompany items have been eliminated
in consolidation.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
Utility Regulation - The Company's utility operations are subject
to regulation by the Massachusetts Department of Public Utilities
(DPU) with respect to rates charged for natural gas sales and
transportation, among other things. The Company's policies conform
with generally accepted accounting principles, as applied to
regulated public utilities.
Utility Property and Non-Utility Property - Utility property and
non-utility property are stated at original cost, including labor,
materials, taxes and overheads. The amount of interest capitalized
as a component of construction overheads amounted to $437,000,
$568,000, and $294,000 in 1996, 1995 and 1994, 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 is approximately 3.79%. The composite
depreciation rate is applied to the utility property balance at
the beginning of each year. Depreciation on non-utility property
is computed by various methods.
Operating Revenues - Operating revenues are accrued based upon the
amount of gas delivered to utility customers through the end of
the accounting period. Accrued utility revenues of $6,333,000 and
$8,924,000, as reported in the Consolidated Balance Sheets at
December 31, 1996 and 1995, respectively, represent the accrual of
unbilled operating revenues net of related gas costs. The
Company's policy is to record lost margins and financial
incentives relating to the Company's demand side management (DSM)
programs as revenue when earned by the Company and approved by the
DPU. Under methodologies approved in 1995 for its residential DSM
programs and in 1996 for its commercial and industrial programs,
the Company recorded as revenue $1,034,000 of lost margins and
$142,000 of financial incentives in 1996 and $900,000 of lost
margins and $220,000 of financial incentives in 1995.
Unbilled Gas Costs - The Company charges or credits its utility
customers for increases or decreases in gas costs from those
reflected in its base tariffs by applying a cost of gas adjustment
clause (CGAC). In accordance with the CGAC, any under or over
recoveries of gas costs are charged or credited to the unbilled
gas cost account and recorded as a current asset or liability.
Such under or over recoveries are collected or refunded, with
interest accrued at the prime rate, in subsequent periods.
Pipeline Refunds Due Customers - The Company periodically receives
refunds from interstate pipeline companies related to rate
adjustments ordered by the Federal Energy Regulatory Commission
(FERC). Refunds are returned to utility customers under methods
approved by the DPU.
Excess Cost of Investments over Net Assets Acquired - This asset
arose principally from the pre-1971 acquisitions of utility
operations. No amortization has been provided since, in the
opinion of management, there has been no diminution in value of
the applicable investments.
Income Taxes - The Company records deferred income taxes for the
income tax effect of the difference between book and tax
depreciation and all other temporary book and tax differences, in
accordance with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" (SFAS 109). Unamortized
investment tax credits, which were allowed under Federal income
tax laws prior to 1987, have been deferred and are being amortized
as a credit to income tax expense over the estimated service lives
of the corresponding assets.
Interest and Debt Expense - Interest and debt expense includes
interest on long-term debt, interest on short-term notes payable
and regulatory interest. As approved by the DPU, regulatory
interest is interest income credited on regulatory assets or
interest expense charged on regulatory liabilities.
Pension Plans - The Company and its subsidiaries have defined
benefit pension plans covering substantially all employees. These
include two qualified union plans, one qualified plan for non-
union employees, and various unqualified individual retirement
agreements covering certain key employees and retirees. The
Company's funding policy for the qualified plan 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 $100,418,000 and $81,559,000 as of December 31,
1996 and 1995, respectively. The fair value of long-term debt was
$102,016,000 and $89,724,000 as of December 31, 1996 and 1995,
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 DPU, the Company did not
record deferred income taxes but rather "flowed through" tax
benefits to utility customers. At December 31, 1996, the Company has
a liability of $9,774,000 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) 1996 1995 1994
Charged (credited) to operations:
Current $1,104 $6,455 $2,157
Deferred:
Unbilled gas costs 2,929 (1,523) (106)
Accelerated depreciation 2,202 2,005 2,167
Demand side management costs 747 (32) 1,115
Pension 449 (38) (840)
Recovery of unfunded deferred taxes 398 398 398
Debt expense (53) 848 (21)
Transition costs (1) (871) (55)
Environmental (246) 22 137
Miscellaneous (260) (79) 84
Amortization of investment
tax credits (268) (273) (230)
Total 7,001 6,912 4,806
Charged to other income 1,599 477 1,014
Total Federal income tax expense $8,600 $7,389 $5,820
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1996 1995 1994
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 (2) (1) (1)
Effective Federal
income tax rate 34% 35% 35%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1996 1995
Construction contributions $974 $1,060
Other 335 1,468
Total deferred tax assets 1,309 2,528
Accelerated depreciation (39,580) (36,949)
Cost of removal (2,792) (2,554)
Unbilled gas costs (3,990) (315)
Environmental response costs (1,571) (1,865)
Demand side management costs (2,659) (1,764)
Other (1,467) (2,256)
Total deferred tax liabilities (52,059) (45,703)
Total deferred taxes $(50,750) $(43,175)
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:
December 31,
(In Thousands) 1996 1995
First mortgage bonds:
8.86% Series CD due 2001 $ - $6,000
9.40% Series CE due 1997 5,000 10,000
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 10,000 10,000
6.45% Series MTA-2 due 2025 10,000 10,000
6.94% Series MTA-3 due 2026 10,000 -
6.20% Series MTA-4 due 1998 10,000 -
6.88% Series MTA-5 due 2008 10,000 -
Total 100,000 81,000
Note payable 418 559
Less: Long-term debt due
within one year (5,152) (6,141)
Total long-term debt $95,266 $75,418
The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
respectively.
The first mortgage bonds are collateralized by utility property.
The Company's first mortgage bond indenture includes, among other
provisions, limitations on the issuance of long-term debt, leases
and the payment of dividends from retained earnings. The note
payable is collateralized by equipment.
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In 1995, the Company issued $10 million of 30-year bonds
(MTA-1) with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years) and
$10 million of 30-year bonds (MTA-2) with an average effective
interest rate of 6.45% (6.08% during the first ten years and 6.90%
in the next twenty years). Both issues of bonds can be redeemed by
the holder within a 30 day period at the end of ten years. During
1996, the Company issued three separate medium term notes totalling
$30 million at various rates and terms. It is anticipated that the
remaining bonds under the MTN program will be issued in 1997.
In June 1996, the Company redeemed prior to maturity $5 million
of Series CD, 8.86%, first mortgage bonds.
Note E: Short-Term Debt
In July 1994, the Company established a three-year bank line of
credit of $75 million with a consortium of four banks. The bank
line of credit allows the Company to borrow on a demand basis up
to $75 million, less whatever amount has been borrowed through the
Company's gas inventory trust (described below). The line of
credit allows the Company the option to borrow under four
alternative rates: prime rate, certificate of deposit rate,
eurodollar rate (LIBOR), and a competitive bid option. At December
31, 1996, the credit available under the bank line of credit was
$11,561,000. The weighted average interest rates for short-term
debt were 5.87% and 6.03% at December 31, 1996 and 1995,
respectively.
The Company has an agreement with a single-purpose Massachusetts
trust, the Company's gas inventory trust, under which the Company
sells supplemental gas inventory to the trust at the Company's
cost. The Company's agreement with the trust requires it to
repurchase such inventory at cost when needed and reimburse the
trust for expenses incurred to finance the gas inventory. The
trust finances such purchases of inventory by borrowing under a
bank line of credit with a maximum borrowing commitment of $30
million that is complementary to and on similar terms as the
Company's bank line of credit described above. The DPU has
approved the inventory trust arrangement and has permitted the
cost of such gas inventory, including fees and financing costs, to
be recovered through the Company's CGAC. During 1996, 1995 and
1994 approximately $500,000, $662,000 and $504,000, 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
$7,685,000 and $7,291,000 at December 31, 1996 and 1995,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $5,874,000 and $5,038,000
at December 31, 1996 and 1995, 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 1996, 1995 and 1994
approximated $1,493,000, $1,429,000 and $2,049,000, respectively.
At December 31, 1996, the future minimum payments (including
interest) under the Company's lease agreements are: $881,000 in
1997; $737,000 in 1998; $420,000 in 1999; $300,000 in 2000;
$255,000 in 2001; and $100,000 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 $570,000, $459,000 and $387,000 for
1996, 1995 and 1994 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) 1996 1995 1994
Benefits earned during the period $1,036 $836 $1,195
Interest cost on projected
benefit obligation 3,267 3,279 2,803
Actual return on plan assets (4,710) (5,515) 77
Net amortization and deferral 1,882 2,757 (2,657)
Net periodic pension cost $1,475 $1,357 $1,418
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1996 1995 1994
Weighted average discount rate 7.75% 7.50% 8.50%
Future compensation increases 4.00% 4.00% 5.00%
Expected long-term rate of
return on assets 9.00% 9.00% 9.00%
The funded status of the plans at December 31, 1996 and 1995 is as
follows:
1996 1995
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(28,612) $(10,381) $(28,993) $(10,388)
Nonvested (703) (956) (628) (869)
Accumulated (29,315) (11,337) (29,621) (11,257)
Due to recognition
of future salary
increases (4,248) (116) (4,173) (88)
Total (33,563) (11,453) (33,794) (11,345)
Plan assets at
fair value 33,743 7,715 31,168 6,420
Projected benefit
obligation:
Less than (in 180 (3,738) (2,626) (4,925)
excess of)
plan assets
Unrecognized net (457) 188 1,758 1,232
(gain) loss
Unrecognized 1,398 2,020 1,572 1,247
transition amount
Unrecognized prior 487 1,064 347 1,493
service cost
Additional liability - (3,157) - (3,885)
accrued
Prepaid (accrued) $1,608 $(3,623) $1,051 $(4,838)
pension costs
Assets of the employee benefit plans are invested in domestic
and international equities, medium-term domestic fixed income
securities, international fixed income securities, real estate and
other short-term debt instruments.
Additional benefits upon retirement were given to 47 employees
who accepted the voluntary early retirement program in 1994. The
additional cost of $2,537,000 as a result of this program was
recorded as a restructuring charge in the fourth quarter of 1994.
Postretirement Life and Health Benefit Plan - The Company sponsors
a postretirement benefit plan that covers substantially all
employees. The plan provides medical, dental and life insurance
benefits. The plan is contributory for retirees, with respect to
postretirement medical and dental benefits; the plan is
noncontributory with respect to life insurance benefits.
During 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 "Employers" Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). Prior to
1993, expense was recognized when benefits were paid. In
accordance with SFAS 106, the Company began recording the cost for
this plan on an accrual basis in 1993. The Company amortizes the
transition obligation over a twenty-year period. The Company's
cost under this plan for 1996, 1995 and 1994 was $502,000,
$672,000 and $694,000 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 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 following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1996 and 1995:
(In Thousands) 1996 1995
Accumulated postretirement
benefit obligation:
Retirees $(3,957) $(3,816)
Fully eligible active plan
participants (1,033) (1,047)
Other active plan
participants (1,239) (1,275)
Total (6,229) (6,138)
Plan assets at fair value 4,563 4,102
Accumulated postretirement
benefit obligation
in excess of plan assets: (1,666) (2,036)
Unrecognized net (gain) from (1,339) (1,310)
past experience different from
that assumed and from changes
in assumptions
Unrecognized transition 4,315 4,584
obligation
Prepaid postretirement benefit $1,310 $1,238
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended December 31,
(In Thousands) 1996 1995 1994
Service cost - benefits
attributable to service $137 $145 $202
during the period
Interest cost on accumulated 461 505 455
postretirement
benefit obligation
Actual return on plan assets (507) (639) 143
Net amortization and deferral 410 661 (106)
Net periodic postretirement $501 $672 $694
benefit cost
For measurement purposes, a 6.5% (4.5% for dental costs)
annual rate of increase in the per capita cost of covered health
care benefits was assumed for 1997; the rate of increase for
medical costs was assumed to decrease gradually from 6.5% to 4.5%
in 2001 and remain at that level thereafter. The health care cost
trend rate assumption has a significant effect on the amounts
reported. To illustrate, increasing the assumed health care cost
trend rates by one percentage point in each year would increase
the accumulated postretirement benefit obligation as of December
31, 1996 by $755,000 and the aggregate of the service and the
interest cost components of net periodic postretirement benefit
cost for the year then ended by $71,000.
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.75%, 7.5% and
8.5% for 1996, 1995 and 1994, respectively. The expected long-term
rate of return on plan assets was 9% for assets in the Section
401(h) accounts and, after estimated taxes, was 6% for assets in
the Section 501(c)(9) trust for all years presented.
Note H: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2013, for the acquisition of gas
supplies and the storage and delivery of natural gas stored
underground. The contracts contain minimum payment provisions
which correspond to gas purchases that, in the opinion of
management, are not in excess of the Company's requirements.
FERC Order 636 Transition Costs - As a result of FERC Order 636,
the Company's interstate pipeline service providers have been
required to unbundle their supply and transportation services.
This unbundling has caused the interstate pipeline companies to
incur substantial costs in order to comply with Order 636. These
transition costs include four types: (1) unrecovered gas costs
(gas costs that had been incurred but not yet recovered by the
pipelines when they were providing bundled service to local
distribution companies); (2) gas supply realignment costs (the
cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that
can not be assigned to customers of unbundled services); and (4)
new facilities costs (costs of new facilities required to
physically implement Order 636).
Pipelines are expected to be allowed to recover prudently
incurred transition costs from customers such as the Company,
primarily through a demand charge, after approval by FERC. The
Company's additional transition cost liabilities are estimated to
range from $4,500,000 to $6,500,000. The Company is recovering
these costs from its customers, as approved by the DPU in October
1994. As of December 31, 1996, the Company has recorded on the
balance sheet a long-term liability of $4,500,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $4,500,000 ("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
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, 1996, the
Company had incurred environmental response costs of $11,156,000
of which $7,148,000 has been recovered from customers to date. The
Company expects to continue incurring costs arising from these
environmental matters.
As of December 31, 1996, the Company has recorded on the balance
sheet a long-term liability of $1,183,000 and, based upon 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
1996
December 31 $53,869 $9,236 $7,035 $.83 $.325
September 30 15,245 (2,566) (3,580) (.42) .325
June 30 24,237 (689) (2,205) (.26) .325
March 31 77,578 16,213 15,228 1.82 .320
1995
December 31 $56,625 $10,283 $8,530 $1.02 $.320
September 30 14,911 (2,251) (3,932) (.47) .320
June 30 22,760 (925) (3,283) (.40) .320
March 31 70,353 14,467 12,449 1.51 .315
In the opinion of management, the quarterly financial data includes
all adjustments, consisting only of normal recurring accruals,
necessary for a fair presentation of such information. The Company
typically reports profits during the first and fourth quarters of
each year while incurring losses during the second and third
quarters. This is due to significantly higher natural gas sales
during the colder months to satisfy customers' heating needs.
Note K: Restructuring Charge
In the fourth quarter of 1994, the Company recorded a restructuring
charge of $3,185,000 ($1,965,000 after-tax or $.24 per share). This
amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.
Note L: Subsequent Event
In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the LNG storage joint venture is
subject to certain regulatory approvals. Colonial will recognize a
one-time gain, net of taxes, of approximately $.35 per share at the
time of the sale, expected to occur in the first half of 1997.
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, 1996 and
1995, and the related consolidated statements of income, cash flows,
and common equity for each of the three years in the period ended
December 31, 1996. 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 financialstatements referred to above present
fairly, in all material respects, the consolidated financial
position of Colonial Gas Company and subsidiaries as of December 31,
1996 and 1995, and the consolidated results of their operations and
their consolidated cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally
accepted accounting principles.
GRANT THORNTON LLP
Boston, Massachusetts
January 13, 1997
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 Officer Executive Vice President-
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 $16,478,000
($1.95), $13,764,000 ($1.66) and $11,009,000 ($1.36) for the three
years ended December 31, 1996, 1995, and 1994, respectively. Before
a restructuring charge of $1,965,000 after-tax or $.24 per share,
1994 net income and income per average common share were $12,974,000
($1.60).
Net income was favorably impacted by colder than 20-year average
temperatures in 1996, 1995 and 1994. This is summarized as follows:
1996 1995 1994
Percent colder than
20-year average 3.0% 2.3% 5.0%
Percent colder (warmer)
than prior year 0.7% (2.5)% (1.3)%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.295 in 1996, $1.275 in 1995
and $1.255 in 1994. The Company has paid dividends for 60
consecutive years, and has increased dividends each year for the
past 17 years.
Operating Revenues
Operating revenues were $170,929,000 in 1996, $164,649,000 in 1995
and $166,259,000 in 1994. Operating revenues are impacted by the
volumes of gas sold and transported, changes in base rates as
approved by the Massachusetts Department of Public Utilities (DPU),
and the pass-through of gas costs to customers via a cost of gas
adjustment clause (CGAC).
The volumes of gas sold are affected by fluctuations in weather and
the number of customers being served. Firm sales customers increased
by 13,235 over the last three years from 132,187 in December 1993 to
145,422 in December 1996, an increase of 10%, which has added to
firm sales volume. The chart below summarizes volumes of gas sold
and transported and number of firm sales customers:
1996 1995 1994
(In MMcf)
Gas sold
Firm 19,563 18,560 18,716
Non-Firm 648 1,148 729
Gas transported
Firm 3,918 2,537 6,090
Non-Firm 2,671 3,224 4,185
Total gas sold and transported 26,800 25,469 29,720
(In MMcf)
Firm Sales Customers 145,422 141,359 136,636
Operating revenues increased $6,280,000, or 3.8% from 1995 to 1996.
This increase resulted from weather that was 0.7% colder than last
year and customer growth of 2.9%.
Operating revenues decreased $1,610,000, or 1.0%, from 1994 to 1995.
This decrease resulted primarily from weather that was 2.5% warmer
than the prior year (although 2.3% colder than the 20-year average)
partially offset by a growing customer base and additional revenue
of $1,120,000 resulting from regulatory approval to recover lost
margins and financial incentives associated with the Company's
residential conservation programs.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.29 in 1996, $4.22 in 1995
and $4.48 in 1994. 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) 1996 1995 1994
Gas purchased
Pipeline 15,115 14,659 14,392
Underground storage 3,346 3,270 3,112
LNG/Other 2,596 2,426 2,390
Total gas purchased 21,057 20,355 19,894
Underground storage consists primarily of spot gas purchased and
injected into storage during the summer and fall for use during
the following winter.
Operating Expenses
Operations expense was $31,383,000 in 1996, an increase of $74,000
or 0.2%, from 1995, and $31,309,000 in 1995, a decrease of
$1,695,000, or 5.1%, from 1994. In 1996, the Company was able to
maintain operations expense at prior years level. The decrease in
1995 was primarily due to less payroll and related benefits as a
result of the early retirement program and cost saving initiatives
resulting from the Company's self-examination in 1994. Maintenance
expense increased $75,000, or 1.7%, in 1996 from 1995 and decreased
$673,000, or 13.3%, in 1995 from 1994. The decrease in 1995 was
primarily due to cost saving initiatives.
Depreciation and amortization expense increased 9.8% or $1,003,000
in 1996 and 10.7% or $990,000 in 1995. The increases in 1996 and
1995 were due to an increase in utility property.
Local property and other taxes increased 4.3% in 1996 from 1995 and
4.6% in 1995 from 1994. The increases in 1996 and 1995 were due to
higher property taxes and additional property subject to property
taxes.
A restructuring charge of $3,185,000 ($1,965,000 after-tax or $.24
per share) was recorded during the fourth quarter of 1994. This
amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.
Income Taxes
Total Federal income and state franchise taxes increased 8.7% or
$729,000 in 1996 as a result of a higher level of income. Total
Federal income and state franchise taxes increased 42.5% or
$2,495,000 in 1995 as a result of more income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $2,236,000
in 1996, $596,000 in 1995 and $1,336,000 in 1994. Other operating
income primarily includes the results of the Company's wholly-owned
energy trucking subsidiary (Transgas). Also included are heating and
water heating equipment sales and installations. As discussed
previously, the Company's retail appliance sales operation was
discontinued as of December 31, 1994.
Transgas' 1996 financial results were driven by a 68% increase in
liquefied natural gas (LNG) hauls leading to a $3,455,000 increase
in trucking revenue and a $1,422,000 increase in truck
transportation net income. This increase in demand of truck
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.
Transgas' 1994 financial results were driven by extremely cold
weather in the first quarter of 1994 which generated a significant
increase in demand for the truck transportation of liquefied natural
gas (LNG) and propane throughout the first three quarters of 1994.
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.
As discussed in "LNG Joint Ventures", the Company has agreed to sell
a 50% interest in Transgas. Effective upon such sale, the Company
will be recognizing 50% of the net income of Transgas on an equity
basis.
Non-Operating Income
Non-operating income, net of income taxes, was $757,000 in 1996,
$864,000 in 1995 and $565,000 in 1994. Non-operating income
includes interest income and miscellaneous other income.
Interest and Debt Expense
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. Interest and debt expense
increased 10.2% in 1995 from 1994. The increase in 1995 was due to
increased levels of short-term debt and higher short-term interest
rates partially offset by a decrease in interest on long-term debt.
Effects of Inflation
Inflation generally has a negative impact upon the Company's
profitability since the rates charged to the Company's utility
customers, excluding changes in the cost of gas sold, cannot be
increased without formal proceedings before the DPU. Changes in the
cost of gas sold are automatically reflected in customer rates
pursuant to semi-annual adjustments under the CGAC. In the absence
of authorized rate increases, the Company must look to increased
productivity and higher sales volumes to offset inflationary
increases in its other costs of operations. The present regulatory
process permits the Company to earn a rate of return based on the
historical cost of utility property without recognition of the
current replacement cost. The Company's policy is to file for an
increase in rates only when increases in productivity and customers
are not sufficient to counteract the impact of inflation. The
Company has set a goal to defer its next base rate increase until at
least the year 2000.
Regulatory Matters
Environmental response costs, transition costs and demand side
management (DSM) program costs are recovered through the CGAC, as
approved by the DPU. The environmental response costs recovered
through the CGAC relate to the Company's former gas manufacturing
operations, as described under "Environmental Matters". Transition
costs relate to FERC approved pipeline charges resulting from Order
636. In addition to full recovery of the installed conservation
measures, the Company is allowed to recover, 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.
In 1996, the Company recorded as operating revenues $1,034,000 of
lost margins and $142,000 of financial incentives associated with
the residential and commercial DSM programs and in 1995, recorded as
operating revenues $900,000 of lost margins and $220,000 of
financial incentives.
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 DPU approved a base rate increase designed to produce
additional revenues of $6.7 million or 4.9% annually, effective
November 1, 1993.
The Company's goal is to postpone the filing of a request for its
next base rate increase until at least the year 2000 through
cost-cutting and other measures, such as the LNG joint venture with
Cabot LNG Corporation described below, while maintaining an adequate
return to shareholders. Under a 1995 industry-wide ruling of the
DPU, 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. The Company has reviewed alternative
incentive-based pricing methods but has not yet determined
what method of regulation will be of greatest benefit to its
customers and shareholders.
During 1996, the DPU ordered all Massachusetts gas companies to
offer only "unbundled" gas service to interruptible and special
contract customers, as a means of promoting greater competition at
the city-gate. 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 had previously offered both
bundled and unbundled service to interruptible and special contract
customers.
Since 1993, the Company also has been offering unbundled service
as an alternative to its firm commercial and industrial customers.
As of December 31, 1996, 19 customers had opted for the firm
transportation service, representing less than 2% of the Company's
annual firm load. The Company is analyzing methods for making
unbundled service viable for the greater number of firm customers,
and anticipates DPU rulings containing additional unbundling
guidelines in 1997.
In its 1996 order, the DPU continued to allow Massachusetts gas
companies to price interruptible services at negotiated rates based
on the value of that service to the customer. Additionally,
Massachusetts gas companies will now be permitted to retain 25% of
the net margins earned on interruptible sales, interruptible
transportation and capacity release transactions, to the extent
those margins exceed thresholds based on previous activity. The
Company had previously been allowed to retain 10% of capacity
release revenues above an initial threshold of $2,500,000 under its
1993 base rate proceeding. The amounts retained by the Company from
interruptible sales, interruptible transportation and capacity
release transactions in 1996, 1995 and 1994 totaled $0, $81,000 and
$32,000 respectively. All other revenues from these transactions
flow back to firm sales customers through the CGAC.
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, 1996, the Company had
incurred environmental response costs of $11,156,000 of which
$7,148,000 has been recovered from customers to date. The Company
expects to continue incurring costs arising from these environmental
matters.
As of December 31, 1996, the Company has recorded on the balance
sheet a long-term liability of $1,183,000 and, based upon 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.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
The Company's liquidity is affected by its ability to generate
funds from operations and to access capital markets. The Company's
operations are seasonal with its cash flow reflecting this
seasonality. The Company typically generates approximately 70
percent of its annual operating revenues during the November through
April heating season, which results in a high level of cash flow
from operations from late winter through early summer. As a result
of this seasonality, the Company's liquidity can be affected by
significant variations in weather. Short-term borrowings are
highest during the fall and early winter months due to the
completion of the annual construction program and seasonal working
capital requirements.
Investing Activities
The Company invests in property, plant and equipment to improve
and protect its distribution system, and to expand its system to meet
customer demand. Utility capital expenditures were $26,875,000 in
1996, $24,096,000 in 1995 and $28,195,000 in 1994. The Company's
long-range plan calls for annual utility expenditures, of which over
50% is budgeted for new business, averaging $28,000,000 over the
next five years as follows:
(In Thousands) 1997 1998 1999 2000 2001
Distribution $22,900 $22,500 $23,100 $23,800 $24,700
Production 3,200 200 100 400 300
Information Systems 7,400 4,100 400 400 400
Automated Meter 1,100 1,100 1,200 300 300
Reading
General
200 300 300 300 300
Total Capital $34,800 $28,200 $25,100 $25,200 $26,000
Expenditures
Financing Activities
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its indenture.
In 1995, the Company issued $10 million of 30-year bonds (MTA-1)
with an average effective interest rate of 6.85% (6.44% during the
first ten years and 7.38% in the next twenty years) and $10 million
of 30-year bonds (MTA-2) with an average effective interest rate of
6.45% (6.08% during the first ten years and 6.90% in the next twenty
years). Both issues of bonds can be redeemed by the holder within a
30 day period at the end of ten years. During 1996, the Company
issued three separate medium term notes totaling $30 million at
various rates and terms. It is anticipated that the remaining bonds
under the MTN program will be issued in 1997.
In June 1996, the Company redeemed prior to maturity the $5 million
of Series CD, 8.86%, first mortgage bonds.
The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
respectively.
The Company has a $75 million credit facility which allows it to
meet its seasonal working capital needs. The present facility
expires in June 1997. Up to $30 million of the credit facility can
be used by the Company's gas inventory trust. The credit facility
allows the Company the option to borrow under any one of four
alternative rates. The Company 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) 1996 1995 1994
Common Stock Under
Dividend Reinvestment
and Common Stock Purchase
Plan and
Employee Savings Plan $3,277 $2,702 $4,070
Note Payable - - $741
Medium term notes under the
first mortgage indenture $30,000 $20,000 -
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1996 1995 1994
Equity 54% 58% 56%
Long-Term Debt 46% 42% 44%
As of April 1996, the quarterly dividend paid on the Company's
Common Stock was increased to $.325 per share or an annualized
dividend rate of $1.30 per share.
LNG Joint Ventures
In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the joint venture is subject to
certain regulatory approvals. Colonial will recognize a one-time
gain, net of taxes, of approximately $.35 per share at the time of
the sale, expected to occur in the first half of 1997. The Company
has agreed to sell a 50% interest in Transgas. Effective upon such
sale, the Company will be recognizing 50% of the net income of
Transgas on an equity basis.
FINANCIAL AND OPERATING STATISTICS
(For the Years Ending December 31)
Operating Revenues (In Thousands)
1996 1995 1994 1993 1992
Residential $108,879 $103,991 $104,812 $106,362 $91,412
Commercial and
industrial 54,324 52,926 56,358 53,933 46,951
Firm transportation 1,843 1,294 1,210 816 585
Non-firm sales 2,985 3,745 2,429 3,613 4,860
Non-firm trans
- -portation 453 424 401 409 254
Other 2,445 2,269 1,049 1,128 992
Total operating
revenues $170,929 $164,649 $166,259 $166,261 $145,054
Gas Sold (MMcf)
Residential 12,094 12,734 11,190 11,492 11,097
Commercial and
industrial 7,469 5,826 7,526 7,443 7,445
Non-firm 648 1,148 729 1,030 1,508
Total gas sales 20,211 19,708 19,445 19,965 20,050
Gas Transported (MMcf)
Firm 3,918 2,537 6,090 4,163 1,997
Non-firm 2,671 3,224 4,185 4,026 2,820
Total gas transported 6,589 5,761 10,275 8,189 4,817
Total gas sold and
transported 26,800 25,469 29,720 28,154 24,867
Gas Purchased (MMcf)
Pipeline 15,115 14,659 14,392 14,983 16,633
Underground storage 3,346 3,270 3,112 3,501 2,666
LNG - as liquid 1,067 844 1,129 907 564
LNG - as vapor 1,528 1,574 1,236 917 1,095
Propane/SNG 1 8 25 8 9
Total gas purchased 21,057 20,355 19,894 20,316 20,967
Company use and other (846) (647) (449) (351) (917)
Available for sale 20,211 19,708 19,445 19,965 20,050
Customers - End of period
Residential 131,286 127,419 123,077 118,918 115,115
Commercial and
industrial 14,136 13,940 13,559 13,269 12,849
Firm transportation 19 11 8 1 1
Non-firm sales 25 27 21 21 21
Non-firm transportation 5 2 2 2 2
Total customers
- end of period 145,471 141,399 136,667 132,211 127,988
Average Annual Mcf Sold/Customer
Residential 96 94 96 101 103
Commercial and
industrial 533 531 569 575 595
Average Annual Bill/Customer
Residential $868 $858 $897 $939 $839
Commercial and
industrial $3,880 $3,901 $4,260 $4,167 $3,732
Average Revenue/Mcf
Residential $9.00 $9.15 $9.37 $9.26 $8.16
Commercial and
industrial $7.27 $7.35 $7.49 $7.25 $6.27
Residential Heating
Customers as a
% of all Residential
Customers 90% 90% 90% 90% 90%
Highest Daily
Sendout
(Mcf) 170,984 199,275 204,896 184,303 157,567
Percent Colder
(Warmer) than
20-year average 3.0% 2.3% 5.0% 6.3% 3.0%
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)
1996 1995 1994 1993 1992
Balance Sheet Data:
Assets:
Utility property-net $250,983 $235,555 $221,685 $202,713 $183,815
Non-utility property
-net 5,925 5,036 3,479 3,235 4,039
Capital leases-net 1,811 2,253 2,948 3,914 4,366
Current assets 67,558 61,002 65,568 67,668 71,763
Deferred charges
and other assets 38,135 38,575 37,668 34,588 38,939
Total $364,412 $342,421 $331,348 $312,118 $302,922
Capitalization and Liabilities:
Capitalization:
Common equity $113,906 $105,070 $99,175 $94,283 $87,771
Long-term debt 95,266 75,418 77,923 87,432 90,750
Total Capitalization 209,172 180,488 177,098 181,715 178,521
Capital lease obligations 930 1,359 2,237 3,149 3,591
Current liabilities 94,169 101,666 91,382 73,413 64,567
Deferred credits
and reserves 60,141 58,908 60,631 53,841 56,243
Total $364,412 $342,421 $331,348 $312,118 $302,922
Income Statement Data:
Operating revenues $170,929 $164,649 $166,259 $166,261 $145,054
Cost of gas sold (87,188) (83,631) (87,458) (90,915) (75,143)
Operating margin 83,741 81,018 78,801 75,346 69,911
Operating expenses
(including income
taxes) (61,547) (59,444) (61,284) (56,456) (52,760)
Utility operating
income 22,194 21,574 17,517 18,890 17,151
Other income-net
of income taxes 2,993 1,460 1,901 1,273 958
Interest and debt
expense (8,709) (9,270) (8,409) (8,141) (7,466)
Accounting change - - - - -
Net income $16,478 $13,764 $11,009 $12,022 $10,643
Capitalization Ratios:
Common equity 54% 58% 56% 52% 49%
Long-term debt 46% 42% 44% 48% 51%
Common Stock Data:
Average shares
outstanding 8,432 8,294 8,119 7,931 7,728
Income per share $1.95 $1.66 $1.36(a) $1.52 $1.38
Dividends paid per share:
Common Stock $1.295 $1.275 $1.255 $1.235 $1.213
Class A Common Stock - - - - -
Per weighted average
common share $1.295 $1.275 $1.255 $1.235 $1.213
Dividend payout rate 66% 77% 92% 81% 88%
Book value per share $13.37 $12.56 $12.05 $11.74 $11.19
Dividends as a percent
of book value 10% 10% 10% 11% 11%
Market price per share $21.25 $20.25 $19.25 $22.50 $21.25
Market price as a percent
of book value 159% 161% 160% 192% 190%
Return on average
common equity 15.1% 13.5% 11.4% 13.2% 12.5%
(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 Headquaters
Colonial Gas Company
40 Market Street
P. O. Box 3064
Lowell, MA 01853-3064
(508) 322-3000
FAX: (508) 459-2314
Stock Listing
The Company's Common Stock trades on the Nasdaq Stock Market
under the symbol: CGES. Stock trading activity is reported in
financial publications under the abbreviation of ColGas or ClnGas.
Annual Meeting
The Annual Meeting of Stockholders will be held on
April 16, 1997 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 1996 Annual Report on Form 10-K as filed
with the Securities and Exchange Commission will be sent free of
charge to any shareholder who contacts the Investor Relations
Department at the corporate headquarters address above.
Transfer Agent:
The First National Bank of
Boston
c/o Boston EquiServe, L.P.
P. O. Box 644
Mail Stop: 45-02-64
Boston, MA 02102-0644
(800) 736-3001
(617) 575-3100
Independent Certified Public
Accountants:
Grant Thornton LLP
98 North Washington Street
Boston, MA 02114
(617) 723-7900
Corporate Counsel:
Palmer & Dodge LLP
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 60 consecutive
years and has increased dividends each year for the past 17 years.
Common Stock dividends are payable when declared by the Board of
Directors.
Anticipated Record Date Anticipated Payment Date
February 28, 1997 March 14, 1997
May 30, 1997 June 13, 1997
August 29, 1997 September 15, 1997
December 1, 1997 December 15, 1997
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock Purchase Plan
(DRIP) provides shareholders of record with an economical and
convenient method of 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 calender quater, 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 contracting 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 preceeding business day. Optional cash
investments must be receiced 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 1997.
Date Investment Must Be Investment
Received By Transfer Agent Dates
April 8 April 15
May 8 May 15
June 6 June 13
July 8 July 15
August 8 August 15
September 8 September 15
October 7 October 15
November 7 November 14
December 8 December 15
SHAREHOLDER INFORMATION
Market Prices and Dividends
The following table reflects the high and low sales prices as reported
by the Nasdaq Stock Market, for shares of the Company's Common Stock
for 1996 and 1995, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
_________________________________________________________________
1996 __________________________________
The Year $24.25 $20.00 $1.295
4th Quarter 24.00 21.25 .325
3rd Quarter 24.25 20.25 .325
2nd Quarter 24.25 20.00 .325
1st Quarter 24.00 20.25 .320
1995 __________________________________
The Year $21.50 $18.00 $1.275
4th Quarter 21.50 19.50 .320
3rd Quarter 20.75 18.75 .320
2nd Quarter 21.25 18.00 .320
1st Quarter 21.25 18.25 .315
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1996, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,361
shareholders of record.
Market Makers
Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; Herzog, Heine, Geduld, Inc.;
S. J. Wolfe & Co.; and Tucker Anthony Incorporated.
Investment Information
Colonial Gas Company is a corporate member of the National
Association of Investors Corporation (NAIC). The Company is also
a participant in NAIC's Low Cost Investment Plan.
[END OF EXHIBIT 13a]