SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): MARCH 2, 1994
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
MAINE 0-505 01-0024370
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(State of Incorporation) (Commission File No.) (IRS Employer ID No.)
33 State Street, Bangor, Maine 04401
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (207-945-5621)
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Current Report, Form 8-K Date of Report
BANGOR HYDRO-ELECTRIC COMPANY MARCH 2, 1994
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ITEM 5. OTHER EVENTS
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The Company hereby files the following financial documents which
(exclusive of the Financial Statement Schedules) will constitute a portion of
the Company's 1993 Annual Report to Stockholders:
I. FINANCIAL STATEMENTS
1. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
2. REPORT OF INDEPENDENT ACCOUNTANTS
3. CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
1993, DECEMBER 31, 1992, AND DECEMBER 31, 1991
4. CONSOLIDATED BALANCE SHEETS - DECEMBER 31, 1993 AND DECEMBER 31,
1992
5. CONSOLIDATED STATEMENTS OF CAPITALIZATION - DECEMBER 31, 1993 AND
DECEMBER 31, 1992
6. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER
31, 1993, DECEMBER 31, 1992, AND DECEMBER 31, 1991
7. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED
DECEMBER 31, 1993, DECEMBER 31, 1992, AND DECEMBER 31, 1991
8. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
II. FINANCIAL SCHEDULES
1. REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
2. SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION IN
PROGRESS
3. SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF<PAGE>
PROPERTY, PLANT AND EQUIPMENT
4. SCHEDULE VIII - RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
BANGOR HYDRO-ELECTRIC COMPANY
by s/JOHN P. O'SULLIVAN
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John P. O'Sullivan
Vice President -
Finance & Administration
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Liquidity and Capital Resources
The Consolidated Statements of Cash Flows reflect the Company's liquidity
and its capital resource requirements for the years 1991 through 1993. The
Company's operations generated cash from operations of $33.4 million,
$25.6 million and $15.9 million for the years ended 1993, 1992 and 1991,
respectively.
Since 1987, the Company's cash flows have been affected rather
significantly by the Maine Public Utilities Commission ("MPUC") rate order
to phase-in the substantial increases in costs included in the fuel cost
adjustment rates to customers as a result of the commencement of contracts
to buy power from small power production facilities (independent,
non-utility power projects developed in accordance with the Public Utility
Regulatory Policies Act of 1978 ("PURPA")). As a result of this phase-in,
customers were not billed the entire amount of these cost increases at the
time the costs were incurred by the Company. These costs were under-billed
from 1987 through 1990 and were major cash requirements in these periods.
The accumulation of these amounts, plus interest, has been shown as
"deferred fuel and interest costs" on the Consolidated Balance Sheets
("Balance Sheets"). Since 1991 the billed amounts have exceeded the costs
incurred, and deferred fuel cost balances have been reduced and cash flow
enhanced by $9.7 million in 1993, $12.3 million in 1992 and $5.2 million
in 1991. The deferred fuel balance on the Company's Balance Sheet at
December 31, 1993 totalled $2.6 million. As explained in Note 1 to the
Consolidated Financial Statements (the "Financial Statements") deferred
fuel accounting neutralizes any impact on earnings from the over- or
under-collection of these costs. Also, as discussed in Note 1, in 1991 and
1992 certain purchased power costs were also deferred and their
under-collection in 1992 and over-collection in 1991 affected the cash
flow in these periods.
Note 1 also discloses that depreciation expense and, hence, cash flow have
been reduced by a decrease in the Company's effective depreciation rate as
a result of an independent study completed in 1989. In addition to
recommending an increase in the depreciable lives of assets currently in
service, the study also determined that the reserve for depreciation was
over-accumulated. A Stipulation among the Company, the MPUC Staff, the
Maine Public Advocate and certain other intervenors, which was approved by
the MPUC, provided new base rates effective October 1, 1990, and contained
a provision to amortize the balance of the over-accumulated reserve for
depreciation account ($11.4 million at October 1, 1990) over a six-year
period. This amortization of the over-accumulated reserve for depreciation
account has reduced depreciation expense by $1.9 million annually below
what the expense would have been without any such amortization. To the
extent depreciation expense is reduced, the Company's revenue requirement
and, therefore, cash flow will likewise be reduced. The reduction in
depreciation expense from these adjustments has been partly offset by
increases in the Company's depreciable base resulting from its
construction program.
Company construction expenditures amounted to $33.6 million in 1993 versus
$24.3 million in 1992 and $21.8 million in 1991. In 1993, $12.8 million of
the construction expenditures was related to the Company's hydroelectric
facilities, $10.4 million was for its distribution system, and $4.9
million was for its transmission system with the remainder related to
generation, other general property and equipment, and Federal Energy
Regulatory Commission ("FERC") relicensing costs pertaining to
hydroelectric projects. Construction expenditures in 1993 included $11.4
million to rebuild the Graham Lake dam and repair the Ellsworth dam, both
of which are located in Ellsworth, Maine. This work, which will be
completed in 1994, was required as a result of a FERC inspection of the
federally licensed facility. Construction expenditures including Allowance
for Funds used During Construction ( AFDC ) are expected to aggregate
about $66 million for the 1994-1996 period. It is projected that the
Company's net cash flow provided from operations (after deducting
preferred and common dividends paid) will be approximately 60% of
construction expenditures over this three-year period. Included in the
budget for 1994 is approximately $2.2 million to complete the Graham Lake
and Ellsworth dam projects.
As a result of increased uncertainty about the ultimate recoverability of
amounts invested through 1993 in licensing activities for proposed
additional hydroelectric facilities (which is discussed below), the
Company's Board of Directors voted on December 15, 1993 to establish a
reserve against those investments. The reserve amounted to $5.6 million
after taxes and has resulted in an after-tax negative impact on 1993
earnings of $.95 per common share. The projects for which the reserve has
been established are a proposed dam and 38 megawatt generating facility
that would be located at the so-called Bain Mills site on the Penobscot
River in the towns of Orono and Bradley, Maine and an 8 megawatt addition
to the Company's existing dam and power station on the Penobscot River in
the towns of Veazie and Eddington, Maine. These projects are captioned
"Basin Mills" in the Financial Statements. They would require a total
investment of about $140 million if they are constructed. The Company has
been pursuing the permitting of these facilities at Federal and State
agencies since the early 1980's.
In November 1993 the Maine Board of Environmental Protection ("BEP")
approved the Basin Mills and Veazie projects under State environmental
laws and issued the water quality certificate required by the Federal
Clean Water Act. The BEP's order is subject to a number of conditions,
some of which could prove to be costly if the projects are developed. The
BEP's decision is being appealed by the projects' opponents, and the
Company cannot predict the outcome of these proceedings. As part of the
licensing process at the FERC, a study to issue a Federal Environmental
Impact Statement ("EIS") is being conducted with respect to these
projects. The draft EIS could be issued in mid-to late-1994. The Company's
efforts and expenditures in the EIS process are expected to be minimal. If
the projects continue, further significant licensing activities can be
expected at the FERC, the U.S. Army Corps of Engineers, the MPUC, the BEP
and possibly other agencies. The Company cannot predict the outcome of the
licensing and permitting activities that are required in order for these
projects to be constructed.
In addition to the Company's inability to predict the outcome of the
requisite licensing activities, other uncertainties have arisen as a
result of changes that have developed and are continuing to develop in the
electric utility industry. In general, these changes are occurring as a
result of the infusion of competition into the industry. In Maine, the
Company and other utilities have also experienced rapidly escalating
rates, in large part as a result of the requirement to purchase power from
certain non-utility, independent power producers. In response to the rate
escalations, electricity customers in Maine have increased their
participation in the regulatory process and have organized resistance to
further rate increases. See also the section on the effect of competition
in Results and Operations below.
The changing business climate for electric utilities can affect the manner
in which utilities provide for the resources to serve its customers.
Traditionally, electric utilities have been able to invest in capital
intensive projects with long-term benefits, such as hydroelectric
projects, because of the relative certainty that there would continue to
be a stable customer base protected by regulation. Now, competitive
factors, such as the availability of energy supplies from alternative
fuels and the relaxation of restrictions against competition from other
suppliers of electricity make it increasingly difficult to increase prices
in the initial years of a project's operation as is often necessary in
order to realize the long-term benefits of capital intensive projects.
These developing concerns introduce new uncertainties with respect to the
timely recovey of the investment required to construct the Basin Mills and
Veazie projects. Accordingly, although the projects are not being
abandoned and licensing activities are continuing, there is now less
certainty that they will be constructed or that the costs for the
completed projects could be recovered under the traditional model of
utility regulation.
The Company also believes that the recoverability of the costs incurred to
date is subject to increasing uncertainty. Under Maine law and regulation,
the MPUC can authorize the recovery of prudently incurred utility
investment in abandoned or cancelled projects. However, under current MPUC
policy, recovery of plant investment cannot begin until either it becomes
operational or it is abandoned or cancelled. Since neither of these events
has occurred and since the Company cannot predict when either of them
might occur, it is impossible to forecast when a final regulatory decision
on the recoverability of the costs might be made. Moreover, given the
concerns about competitiveness described above, at the time when recovery
of those costs might be requested the Company would likely take into
consideration the impact of the inclusion of those costs in its rates, and
could conclude that it would not be in the Company's best interests to
pursue cost recovery.
At December 31, 1993, the Company had invested $3.4 million in a proposed
345 KV transmission line from its existing substation in Orrington, Maine,
to the New Brunswick border. This proposed transmission line would
increase the total transfer capability between Maine and the Canadian
province of New Brunswick from 700 MW to 1000 MW. The Company has budgeted
a minimal amount of cash expenditures for this project during the
1994-1996 period. This project is proceeding under a preliminary agreement
with New Brunswick Power. It is anticipated that long-term support
agreements with participating utilities would be established to reimburse
the Company for a portion of the preliminary costs and to provide for the
operating and capital costs of the line. The nature and extent of the
Company's obligation in such an arrangement is unknown at this time, and
there can be no assurance that such support agreements will actually be
put into place or that the transmission line will be constructed. However,
the Company is currently receiving benefits from its investment to date
through favorable power purchase arrangements with New Brunswick Power and
expects that future investments if and when undertaken will produce
concomitant benefits over the relatively short term. The Company does not
expect to adjust the carrying value of its investment in the project so
long as these benefits continue to accrue to the Company.
In order to lower the overall cost of power to its customers, in June of
1993 the Company negotiated an agreement to cancel its purchased power
agreement with the Beaver Wood Joint Venture ("Beaver Wood"), one of the
high-cost independent non-utility power producers that began providing
power to the Company in the mid 1980's. In connection with the
cancellation the Company paid Beaver Wood $24 million in cash and issued a
new series of 12.25% First Mortgage Bonds due July 15, 2001 to the holders
of Beaver Wood's debt in the amount of $14.3 million in substitution for
Beaver Wood's previously outstanding 12.25% Secured Notes. Also, in
connection with the cancellation agreement, Beaver Wood paid the Company
$1 million at the time of settling the transaction and has agreed to pay
the Company $1 million annually for the next six years in return for
retaining ownership of the facility with the intent to try to market the
power to others. The payments are secured by a mortgage on the property of
the Beaver Wood facility. The Company believes this buyout transaction
will result in significant savings to its customers over the term of the
cancelled contract compared to the continuation of payments under the
purchased power contract.
In May 1993 the Company received an accounting order from the MPUC related
to the purchased power contract buyout. The order stipulated that the
Company may seek recovery of the costs associated with the buyout in a
future base rate case, and could also record carrying costs on the
deferred balance. Consequently a regulatory asset of $40.3 million has
been recorded as of December 31, 1993. Effective with the implementation
of new base rates on March 1, 1994, the Company will begin recovering over
a nine year period the deferred balance, net of the $6 million anticipated
to be received from Beaver Wood.
The Company has nine other contracts with independent power producers.
Five are relatively small hydroelectric facilities with which the Company
has not yet explored renegotiations. One is the West Enfield project in
which the Company has a 50% interest (see Note 7 to the Financial
Statements), which is unlikely to be renegotiated. One is a
waste-to-energy plant that is a significant component in the region's
solid waste disposal strategy and is unlikely to be renegotiated. The
remaining two are the wood-fired plants in West Enfield and Jonesboro,
described in Note 7. The Company has been actively pursuing attempts to
renegotiate the contract with these facilities, without success to date.
If such negotiations were to commence, and an agreement to renegotiate or
terminate the terms of the contracts were reached, substantial resources
would be required on the part of the Company to complete the transaction.
It is possible that because of the size of the financial commitment that
would be necessary the Company and its customers would be able to realize
only a portion of the potential benefits from such contract restructuring.
External capital in 1993 was provided from the June issuance of 745,000
new shares of common stock, resulting in proceeds of $14.8 million. Also
in June 1993, the Company issued $15 million of 7.3% first mortgage bonds.
These bonds mature in 2003, and are not subject to sinking fund payments.
The Company's Dividend Reinvestment and Common Stock Purchase Plan was
modified, effective with the April 20, 992 dividend, so that dividends and
optional cash payments are now being invested in newly issued common stock
rather than in already outstanding common stock purchased in the open
market. The change resulted in the Company realizing a common stock
investment of $1.2 million through the issue of 59,439 shares in 1993. The
proceeds from the stock and bond issuances were used to partially finance
construction expenditures and a portion of the costs associated with the
buyout of the power purchase agreement with Beaver Wood, as well as
enabling the Company to redeem through mandatory and optional sinking fund
payments and through optional redemption provisions, $15.1 million of
higher cost first mortgage bonds. In addition, short-term debt was
increased by $21 million during 1993.
External capital in 1992 was provided primarily through the issuance of
two series of first mortgage bonds: a $20 million, 7.38% series maturing
in 2002 and a $20 million, 8.98% series maturing in 2022. The bonds
contain no provisions for sinking fund payments. Through the Dividend
Reinvestment and Common Stock Purchase Plan, the Company realized a common
stock investment of $914,477 through the issue of 50,271 shares. The funds
provided from these three sources enabled the Company to redeem, through
mandatory and optional sinking fund payments as well as through optional
redemption provisions, $19.86 million of higher cost first mortgage bonds.
In addition short-term debt was reduced by $13.5 million during 1992.
External capital in 1991 was provided from the June 18, 1991 issue of
920,000 new shares of common stock. The proceeds to the Company from the
common stock sale of $13.1 million were used to reduce outstanding
short-term debt. Short-term debt increased by $5.5 million in 1991.
The Company's bank borrowings, which are provided through a $25 million
revolving credit facility as well as $30 million in lines of credit, are
discussed in more detail in Note 5 to the Financial Statements. These
short-term credit arrangements are being used as interim financing for the
Company's construction program. The revolving credit facility expires in
May 1994 but may be extended through May 1995 with the unanimous consent
of the participating banks.
The Company plans to issue approximately 782,500 new shares of common
stock through a public underwriting in the first quarter of 1994. The
Company also plans to raise approximately $12 million later in 1994
through the issuance of new shares of preferred stock. Proceeds from both
of these issues will be used to reduce outstanding short-term debt, which
totalled $38 million at January 31, 1994. In 1994 shareholders will be
asked to authorize additional shares of common and preferred stock.
The Company's first mortgage bond indenture limits the issuance of first
mortgage bonds to 75% of bondable property and requires earnings coverage
of at least two times pro forma annual first mortgage bond interest
charges at the time the bonds are issued. Under these tests, at December
31, 1993, the Company could have issued approximately $30 million of
additional first mortgage bonds at an assumed interest rate of 7.5%. The
Company has $4.4 million of first mortgage bond sinking fund requirements
in the period 1994-1996. An additional $9.3 million is anticipated to be
retired as a result of optional redemption and sinking fund payments
during that period.
The issuance of authorized but unissued preferred stock is not subject to
any issuance tests contained in any of the Company's governing documents
or agreements.
RESULTS OF OPERATIONS
EFFECT OF COMPETITION ON FUTURE SALES, EARNINGS AND DIVIDEND POLICY An
important factor which will impact the Company's future profitability is
the infusion of competition into the electric utility business in the
United States. As utilities adjust to competition their abillity to
compete on price becomes increasingly important. Maine utilities,
including the Company, have been experiencing increases in their costs as
a result of legal obligations to purchase power from the non-utility power
producers, policies regarding utility-financed conservation and
demand-side management ("DSM"), expenditures for low income assistance
subsidies, and various other mandates. These costs have translated into
higher rates to customers. Over the last six years, Maine's electric
rates, on average, have increased faster than the average electric rates
in New England, exclusive of Maine. Maine's rates had been substantially
lower, on average, than elsewhere in New England, but with the rate of
increase experienced recently, the average rate in Maine is now just below
the New England average. The Company's average rates are about equal to
the New England average.
As a result of the impact of the foregoing, competition for the electric
customers' business in Maine is keen. Other utilities that purchase
electricity from Maine utilities have access to the competitive power
supply markets, which is causing Maine's utilities to reduce prices to
those customers or lose the business altogether. Although rtail electric
customers in Maine are generally unable to purchase directly from other
electricity suppliers under current law, customers are increasingly
turning to alternative methods of providing the desired end-use, or are
otherwise curtailing their purchases of electric energy. In order to meet
the competition for existing business, the Company is having to negotiate
prices for customers that have competitive alternatives for their energy
needs, or that would otherwise leave the system.
In the near term, the necessity to reduce prices to retain sales causes a
shortfall in revenues needed to satisfy the utility's overall revenue
requirement. In order to avoid an adverse impact on earnings, this revenue
shortfall must be made up by adjusting rates to other customers, or by
increasing sales, or some combination thereof. The Company believes the
MPUC will allow rate adjustments to account for this impact as necessary
as long as the Company has prudently managed this competitive factor,
although public resistance to rate increases and the possibility of
municipalization of electric service (a practice that is not widespread in
Maine) are likely to act as a constraint in making these adjustments. In
the longer term, the Company believes it could perform successfully in a
competitive market, because despite the Company's current high cost
structure the marginal cost of providing electric service is relatively
low. The Company expects that, if public and regulatory policies were
adjusted to permit the active pursuit of greater sales, the price that
could be charged in a competitive environment, while lower than many of
the Company's current rates, would recover more than the marginal cost of
providing the service. The Company also believes a strategy of greater
electrification would, in addition, produce desirable environmental
quality improvement. If the Company is successful in expanding its market
share with competitive rates, the increased revenue in excess of marginal
cost will enhance earnings and offset the need for other rate increases.
In addition, alternative regulatory methods, which are in the early stages
of exploration at the MPUC, could mitigate the impact on earnings and
accommodate greater pricing flexibility on the part of utilities.
Under current regulatory policies, the Company has only limited authority
to adjust its prices to meet the competition as described above. However,
the Company is pressing for changes in those policies to expand its
pricing flexibility. The Company has negotiated and put into effect a
number of competitive energy rate arrangements, and more negotiations are
under way. Two of those arrangements have provided for the sale of
interruptible energy to major customers of the Company. For the largest
customer, LCP Chemicals ("LCP"), a chemical manufacturer served largely on
an interruptible basis, the Company implemented a contract whereby the
price was reduced substantially. This lost revenue has been incorporated
into the rates of other customers. A second contract was entered into to
secure new revenues from a large pulp and paper company. This customer has
historically generated its own power, and the new contract provides for
the capability for the Company to sell or buy up to 20 megawatts of
interruptible energy and provides benefits to both the customer and the
Company.
More recently, the Company has been negotiating on a case-by-case basis
with customers that have demonstrated that, without rate relief, they will
curtail their purchases from the Company. The MPUC has recently authorized
the Company to enter into a five-year contract (terminable by the customer
with two years' notice) for the supply of power to one of the Company's
largest firm industrial customers at reduced rates. At the same time, the
MPUC issued an accounting order that would mitigate the negative impact on
earnings of a reduced base rate contribution from this customer.
Nevertheless, since these reduced rates were not considered in the
Company's most recent base rate proceeding, the Company expects that the
new contract will reduce the base rate contribution from that customer by
about $1 million annually from historical levels and will negatively
affect the earnings unless the Company can reduce its costs or increase
its revenues from other sources. However, the Company believes that
without the contract, its earnings would have been affected to a
significantly greater degree had the customer opted for its lower cost
energy alternatives. In authorizing the contract, the MPUC specifically
reserved for a future proceeding any determination of the Company's
prudence in entering into the arrangement. The Company believes it can
demonstrate this transaction is prudent and in the best interest of all of
its customers.
Another of the Company's largest firm industrial customers recently
contacted the Company seeking rate concessions in order to maintain
current levels of electric purchases. The Company cannot yet assess the
likelihood of rate reductions for that customer.
More generally, the impact of competition poses the challenge of
minimizing rates to the extent possible. This includes aggressive cost-
cutting in all areas, while continuing to improve the quality of service
to customers. Strategies to compete might also include the acceptance of
lower stockholder returns, forbearance from seeking rate increases, and
reconsideration of recovery of various embedded costs. Two priorities
being pursued in 1994 to cut costs and improve efficiency and
effectiveness in providing service to customers are moving toward a
centralized telephone customer service system and implementing bi-monthly
meter reading. Management is also implementing other cost-containment
measures including an early retirement program in early 1994,
reengineering business processes to provide greater efficiencies, and
identifying new areas of revenue enhancement in an effort to enhance
earnings.
Some initiatives to reduce costs and increase competitiveness will have a
short-term cost that must be recognized in order to achieve long-term
savings. One such initiative is the early retirement program, which will
produce long-term savings by reason of a reduction in the workforce, but
which will cause the Company to recognize a cost in the year of
implementation. In connection with the 1994 early retirement program, the
Company expects to record a cost of approximately $1.5 million (before
income taxes) in the first quarter of 1994, which will reduce reported
earnings for the quarter by about $.15 per common share after income
taxes. Some of this impact will be made up by reduced payroll costs for
the remainder of 1994.
The competitive factors discussed above may affect the level and
consistency of common dividend payout for the Company and other electric
utilities. Historically, a secure, geographically-protected market and a
reasonably assured ability to adjust rates to cover increases in costs
has, in general, permitted electric utilities to establish a pattern of
common dividend payment continuity at relatively high payout ratios,
reasonably free of volatility, and with an expectation of consistent
growth over time. This, in turn, has facilitated utilities' efforts to
attract, at reasonable cost, the capital to invest in the plant and
equipment necessary to provide utility service at prices explicitly capped
by a return on investment limited by regulation. With the infusion of
competition into the electric utility business, however, the continuity of
dividend payments will be less certain. As electric utilities lose the
ability to increase prices to cover increased costs, dividend policies
will have to depend more heavily on shorter term expectations for sales
and earnings. Additionally, a perception of greater investment risk in the
industry may require an increase in equity ratios and higher retention of
earnings. Therefore, it is likely that more competition in the electric
utility industry will introduce more volatility in dividend payouts than
has historically been the case. Offsetting these uncertainties, however,
is the possibility of growth in electric sales and earnings which may
result from greater pricing flexibility (depending upon MPUC actions) and
an increased emphasis on marketing and cost-control by the Company.
However, there can be no assurance that such growth in electric sales will
in fact occur in amounts sufficient to offset completely the effects of
competition or provide the ability to maintain consistent dividend levels.
Although the Company faces near-term challenges as a result of having
relatively high rates in an increasingly competitive market, and the
factors described above will play a larger role in dividend payment
considerations, the Company does not presently anticipate the need to
reduce the level of the common dividend. This judgment is based on
assumptions of at least a modest increase in sales, the ability of the
Company to control operation and maintenance ( O&M ) and capital
expenditures, and the feasibility of relatively modest rate increases in
future years. While the Company believes these assumptions to be
reasonable at this time, no assurance can be given that these assumptions
will be accurate or that developments will not change the prospects for
dividend payments. The Company expects that future growth in earnings and
dividends will be derived primarily from the growth in the business
necessary to serve an expanding economy, success in achieving a larger
share of the energy market in a competitive environment, and management's
continued commitment to improving the efficiency and effectiveness of the
Company's operations.
BASE RATE INCREASES Under Maine law and regulations issued by the MPUC,
the Company collects revenue from its customers through "base rates" that
are established from time to time by the MPUC. The Company also charges a
"fuel cost adjustment" which is a positive or negative adjustment to
reflect changes in the cost of fuel for generation and certain costs of
purchased power.
On May 18, 1993 the Company filed with the MPUC a general base rate case
proposing a $22.8 million increase in base revenues. After litigating the
case throughout 1993, the Company reduced its revenue request to $17.6
million. On February 17, 1994, the MPUC issued an order allowing the
Company, effective March 1, 1994, to increase its base rates by $11.1
million. This represents a 15.9% increase in base rates and an increase in
average overall rates of 7.9%. More than half of the rate increase is to
recover the costs associated with the buyout of the Beaver Wood purchased
power contract. That transaction contributed to the significant reduction
in the Company's fuel cost adjustment to customers which became effective
in November of 1993. The combined effect of the fuel cost adjustment
decrease and the base rate increase results in an average rate increase of
.6% over those that were in place a year ago.
The MPUC order provided an authorized return on common equity of 10.6%.
However, the Company may not earn its authorized return on equity in 1994
since the revenue allowance in the MPUC order is based on a more
optimistic view of sales growth during 1994 than is anticipated by the
Company, and the decision does not include the impact of the reduction in
annual revenue associated with the recently authorized industrial customer
contract described above, or the costs that must be recognized in 1994 as
a result of the early retirement plan described above.
On December 16, 1991, the MPUC issued an order allowing the Company to
increase its base rates on January 1, 1992 to produce a total increase in
annual revenues of about $12.2 million, which was equivalent to a 20.6%
increase in base rates or an 8.9% increase in total rates. This increase
included an interim base rate increase of $2 million which became
effective on September 1991, and reflected an allowed return on common
equity of 12.25%.
EARNINGS Earnings per common share were $.63, $1.60 and $1.33, and the
earned return on average common equity was 4.0%, 10.6% and 8.8% for the
years ended 1993, 1992 and 1991, respectively.
The 1993 reduction in earnings was primarily due to the establishment of a
reserve for the full amount of licensing costs incurred through December
31, 1993 in the Basin Mills and Veazie hydroelectric projects. This
reserve, which amounted to $8.7 million ($5.6 million after taxes),
resulted in a $.95 reduction in earnings per common share after taxes for
the year ended December 31, 1993. The establishment of this reserve is
more fully discussed above in the section on liquidity and capital
resources.
Exclusive of the impact of the foregoing reserve, the Company would have
earned $1.58 per common share, or a return on common equity of 10.6% in
1993.
The 1992 earnings improvement was due primarily to the January 1, 1992
base rate increase. However, actual kilowatt-hour ( KWH ) sales for 1992
were below the assumption used by the MPUC in setting the base rates that
went into effect at the beginning of 1992. In addition, income from LCP
was significantly below that recorded in 1991 and also below that assumed
in the new base rates. As a result of both of these items, 1992 earnings
were below the level needed to earn the then authorized return on common
equity of 12.25%.
The earnings decline in 1991 was principally due to insufficient sales
growth, growth in the costs of financing the Company's expanding property
base, and the increase in operating expenses.
REVENUES Base rate revenue increased by $998,539 or 1.4% in 1993 and $12
million or 19.4% in 1992. In 1993, this increase was due primarily to a
1.6% increase in non-interruptible (i.e., firm) KWH sales. The 1992 change
was due to the increases in base rates on January 1, 1992 and September 1,
1991.
Accounting Release 14 ("AR 14") issued by the FERC has required the
reclassification of certain sales to other utilities that the Company had
previously classified as reductions to fuel and purchased power expense to
now be shown as fuel cost adjustment revenue. These transactions are sales
related to power pool and interconnection agreements and resales of
purchased power. KWH sales from the reclassifications are shown as
"Off-System Sales" in the Six-Year Statistical Summary that accompanies
the Financial Statements.
Interruptible KWH sales increased by 22.2% in 1993 due to increased usage
by a large paper manufacturer and LCP. In June 1993, the contract rate for
LCP returned to the revenue sharing rate which had not been in effect
since the second quarter of 1992. The new rate is lower than the previous
rate at which LCP was being charged (see Note 1). While KWH sales to LCP
increased 8.2% in 1993, base revenues from those sales remained basically
unchanged for the year. Firm sales, which includes sales to residential
customers, increased 1.6%, prior to the AR 14 reclassification in 1993.
Warmer weather in the summer of 1993 tended to increase sales, but the
continued weak economy offset the weather induced sales increase.
Residential sales decreased 1.3% in 1993 compared to 1992 due principally
to reduced KWH usage per customer of approximately 2.3% offset by a 1.1%
increase in average residential customers. Firm sales also include sales
to commercial and large power customers which increased by 2.0% in 1993.
Firm sales to industrial customers increased by 1.5% in 1993.
Interruptible KWH sales increased by 2.4% in 1992 due to increased usage
by a large paper manufacturer. Firm sales to residential customers in 1992
comprised 33% of total delivered sales and increased .9% in 1992 over 1991
due to a .9% increase in the average number of residential customers. The
KWH usage per customer for this customer class was virtually unchanged as
a result of colder weather which substantially offset the results of
higher electric prices and Company-sponsored conservation programs. Firm
sales to commercial and large power customers increased by 1.5% in 1992.
This customer class experienced a 1.5% increase in customers and a .9%
decrease in KWH usage per customer. Firm sales to industrial customers
increased by 5.7% in 1992.
The decline in interruptible sales in 1991 was due to lower sales to LCP.
Residential sales were basically unchanged in 1991, as the average number
of customers increased by 1.7% while average KWH usage per customer
declined by 1.8% in response to higher electric prices as well as
Company-sponsored conservation programs and more moderate weather
conditions. Sales to commercial and large power customers increased by .4%
in 1991. This customer class experienced a 1.5% increase in customers and
a 1.5% decrease in KWH usage per customer. Firm sales to industrial
customers increased by 1.7% in 1991.
The earnings from Penobscot Hydro Co., Inc. ("PHC"), a wholly owned
subsidiary incorporated to own the Company's 50 interest in the West
Enfield hydroelectric project, contributed about $706,000, $745,000 and
$912,000 to base rate revenue in 1993, 1992 and 1991, respectively.
Fuel cost adjustment revenue increased by $15.3 million, $13.8 million and
$15.7 million in 1993, 1992 and 1991, respectively, due to the
aforementioned reclassification required by AR 14. After the
reclassification, fuel adjustment revenue increased by .2% in 1993, 2.5%
in 1992 and 10.9% in 1991. This declining trend reflects the completion of
the phase-in of the substantial increases in costs included in the fuel
cost adjustment due to the contracts with the non-utility power projects.
On November 1, 1993 the fuel cost adjustment rate was decreased by 12.5%.
In 1992 the fuel cost adjustment rate was increased on March 1 and
decreased on November 15 so that total rates were adjusted by 2% on each
of those dates. In addition to the cost of fuel itself, fuel charge
revenue also includes the cost of interest expense on deferred fuel
balances, as well as, for 1992 and 1991, the difference between actual,
non-fuel purchased power costs and the purchased power costs allowed in
base rates. Commencing with the base rates effective on October 1, 1990,
and ending with the base rates effective on January 1, 1992, with the
exception of the capacity costs related to the power entitlement from
Maine Yankee Atomic Power Company ("Maine Yankee"), substantially all
purchased power capacity costs were reported as fuel cost adjustment
revenue on the Consolidated Statements of Income ("Statements of Income").
The significance of treating purchased power costs in the same manner as
other costs included in the fuel cost adjustment is that differences
between projected costs that are the basis of any year's fuel cost
adjustment rates and costs actually incurred are deferred for
reconciliation in a subsequent fuel cost adjustment. The reconciliation
can be positive or negative, depending on actual experience. Effective
with the increased base rates at January 1, 1992, current purchased power
costs reverted to being recovered through base rates and therefore did not
have the reconciliation feature associated with the fuel cost adjustment
rate.
The components of fuel revenue are shown below:
Fuel expense $102,670,217 $101,465,555 $ 93,686,895
Interest recoverable on deferred
fuel and deferred purchased
power costs -
Recovered currently (182,965) 1,328,931 2,439,668
Deferred for future return 461,058 (523,657) (131,386)
Purchased power costs through
the fuel cost adjustment - 450,476 3,111,351
Reclass of sales for resale from
purchased power capacity - 72,399 1,139,399
Other fuel related items 15,378 (14,242) 25,315
--------------------------------------------------------------------------
Fuel revenue, as reported $102,963,688 $102,779,462 $100,271,242
--------------------------------------------------------------------------
The deferred interest credits (charges) represent the actual interest
costs required to finance deferred fuel costs in excess of (below) the
amount of such interest costs allowed in the fuel cost adjustment. This
deferred interest is included in deferred fuel costs on the Balance Sheets
for future return to customers. Deferred fuel accounting is discussed in
Note 1.
EXPENSES As a result of the deferred fuel accounting methodology
followed by the Company, whereby retail fuel expense is recorded to match
retail fuel cost adjustment revenue, fuel expense has increased in
proportion to the increases in fuel revenue.
Purchased power expense increased by approximately $239,000 in 1993 due to
greater capacity and transmission costs related to the Maine Yankee
nuclear plant. Due to the AR 14 reclassification of power sales to other
utilities explained above, purchased power expense has been increased by
$72,399 in 1992 and $1.1 million in 1991. Purchased power expense
increased in 1992 due to $1.5 million more of capacity costs associated
with open market economy purchases. This increase was somewhat offset by a
reduction of $897,000 from the 1991 level of the recovery of purchased
power expenses previously deferred. In accordance with the 1992 base rate
order, $1.8 million of refueling costs incurred in 1993 associated with a
Maine Yankee refueling shutdown has been deferred as of December 31, 1993
for collection by February 1995.
In accordance with the ratemaking process which matches revenue with
expense, purchased power expense increased in 1991 due to the inclusion of
greater amounts of purchased power costs in customer rates which allowed
expense recognition in that period.
O&M expense for 1993 increased 9.0%. In 1993 labor costs increased by $1.1
million as compared to 1992. This increase was a result of higher levels
of payroll reflected in O&M as well as an average wage rate increase of
3.5% on January 1, 1993. The increased payroll was also impacted by
certain merit and market adjustments during 1993. At the end of 1993,
1992, and 1991 the Company had 528, 524, and 545 full-time employees,
respectively. The Company has entered into a three-year collective
bargaining agreement with Local 1837 of the International Brotherhood of
Electrical Workers which provides for general wage increases of 3.25% and
3.5% in 1994 and 1995, respectively. About 39% of the Company's employees
are represented by the union. Wages and salary adjustments for other
Company employees are discretionary. The Company is aggressively pursuing
various cost containment measures.
Non-labor expense increased by $1.3 million or 11.2% in 1993. As detailed
in Note 6 to the Financial Statements, pension income decreased $336,000
in 1993 due principally to a plan amendment which provides additional
benefits to certain plan participants. In December 1993 the Company
charged to expense approximately $189,000 in costs associated with a
feasibility study for the implementation of a geographic information
system. Tree trimming expenses increased $150,000 in 1993 as compared to
1992. Non-labor expense was also impacted by $131,000 in costs incurred to
remove contaminated soil at one of the Company's hydroelectric facilities,
as well as $190,000 in additional outside services expense in 1993
(accounting, legal, and consulting costs) versus 1992. The Company also
experienced significantly higher costs of maintaining its facilities in
1993. These increases in O&M were offset by the impact of the $786,000 in
expense recorded in 1992 related to an early retirement plan (see below),
as well as a $124,000 reduction in uncollectible revenue expense in 1993.
The reduction in uncollectible revenue expense was a result of a $500,000
increase in the reserve at December 31, 1992, offset by a higher levels of
bad debt write-offs in 1993.
O&M expense for 1992 increased 7.1%. Without the expense for uncollectible
accounts, which increased from $640,000 in 1991 to $1.2 million in 1992,
O&M expense increased 4.9% in 1992. In 1992, labor costs increased by
$611,000 or 4.2% principally due to an average wage increase of 4.5%
effective January 1, 1992. The labor cost for the year was influenced by
an early retirement plan implemented during the third quarter. Thirty-seven
employees accepted the early retirement offer.
Non-labor expense exclusive of uncollectible revenue expense increased by
6.1% in 1992. Non-labor expense was also affected by the early retirement
program. Under accounting guidelines, a portion of the cost of the early
retirement plan, $786,000, was required to be expensed in 1992. Because of
the over-funded status of the Company's pension plans, as detailed in Note
6 to the Financial Statements, pension plan income of $348,214 was
recognized in 1992. This income amount was increased by about $300,000 due
to an increase in the assumption for the rate of return on pension plan
investments from 8% to 9%. This change in the assumption was made as a
result of the favorable returns of the pension plans' investments in the
past.
The increase in the uncollectible revenue expense is due to an increase in
the reserve for doubtful accounts of $500,000 from $950,000 at December
31, 1991 to $1.45 million at December 31, 1992 and an increase in the net
amount of accounts written off in 1992 of $74,000. The decision to
increase the reserve for doubtful accounts was the result of an increase
in the overall balances of accounts receivable as well as increases in the
balances of overdue accounts receivable.
LCP filed for protection under Chapter 11 of the bankruptcy law in July
1991. At the time of the bankruptcy filing, LCP owed $719,642 for electric
service, for which the Company has a general, unsecured claim. In
addition, LCP is seeking to recover from the Company certain payments for
electric service made prior to the filing as preference payments under the
bankruptcy law. Since the filing, pursuant to arrangements approved by the
Bankruptcy Court, LCP must pay for service weekly in arrears and the
Company may curtail deliveries of power three days after the presentation
of a weekly bill. Furthermore, the Company has been permitted to collect a
deposit to secure the value of approximately one week of service. As a
result, the LCP account for service rendered after the date for bankruptcy
filing is current. See Note 9 to the Financial Statements for further
information on this matter.
O&M expense for 1991 increased 5.7%. Labor costs increased as a result of
a 5% wage increase for 1991 and a greater number of employees. The
non-labor O&M expense category increased due to an $850,000 increase in
tree-trimming expense, increases in the costs of medical insurance for
union employees, increases in mailing, and other costs related to the base
rate case and other customer programs. Also, 1991 non-labor O&M expense
was increased by $220,000 due to the expensing of oil spill prevention
costs and $97,000 related to costs pertaining to a fire at one of the
hydro plants. These cost increases were somewhat offset by a $400,000
decrease in hydroelectric maintenance expense. Bad debt expense for 1991
decreased by $158,000 due to the fact that the 1990 expense had been
increased by the decision to increase the bad debt reserve by $200,000.
The level of the reserve for bad debts at December 31, 1991 was retained
at $950,000.
Over the periods reported, depreciation and amortization expense has been
affected by increases in depreciable property.
The seven-year amortization of the recoverable investment in Seabrook Unit
No. 2 was completed in 1992. In 1992 and 1991 that amortization amounted
to $968,000 and $1.1 million, respectively. The investment in Seabrook
Unit 1 is being amortized over an original period of 30 years at a rate of
$1.7 million per year.
General taxes have increased over the periods reported due to growth in
the Company's property, plant and equipment subject to property tax, and
to greater payroll taxes due to increased payroll and higher payroll tax
rates. However, in conjunction with the computations in the December 16,
1991 rate order, the Company changed its estimate of prepaid property
taxes by using each municipality's actual fiscal year instead of using the
State's date of property assessment for this purpose. This change
decreased this expense by $356,000 in 1992.
In 1993 income taxes decreased by $839,000 due to lower taxable income.
The effective federal income tax rates for the years ended 1993, 1992 and
1991 were 28%, 30% and 25%, respectively. Note 2 to the Financial
Statements gives further information on income tax expense.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION ("AFDC") AFDC increased by
121% in 1993, 26% in 1992 and 34% in 1991. The 1993 increase is due
principally to the accrual of carrying costs associated with the purchased
power contract termination as previously discussed. In 1993 approximately
$2.3 million in associated carrying costs were recorded on these costs.
The AFDC increases for 1991-1993 are also due to larger amounts of
construction work in progress. The construction work in progress amounts
have increased due to a large capital construction program as well as
expenses incurred in connection with the relicensing of several of the
Company's hydroelectric stations. Carrying costs are also being accrued on
expenditures related to DSM activities ($2.9 million at December 31,
1993). AFDC as a percent of common stock earnings amounted to 142.6% in
1993, 27.5% in 1992 and 28.7% in 1991.
OTHER INCOME AND DEDUCTIONS In 1993, this item was impacted by the
previously described establishment of a $5.6 million after-tax reserve for
the Basin Mills and Veazie projects. In addition, the Company recorded, as
other income, $513,000 in 1993, $206,000 in 1992 and $1.8 million in 1991,
pursuant to a "revenue sharing rate" negotiated with LCP. The revenue
sharing rate is a supplemental rate which began in 1988. Under this rate,
LCP was charged or credited based on increases or decreases in the
customer's per unit product price and electricity costs. A new fixed rate
for this customer began in June of 1992, and at that time all revenue from
this customr was classified as Operating Revenue. Commencing in July 1993,
LCP returned back to the revenue sharing rate. The Company has negotiated
a new rate that is expected to become effective in 1994.
CONTINGENCIES
The Company has received a notice of potential liability under the
Comprehensive Environmental Response, Compensation, and Liability Act as a
generator of hazardous substances that the United States Environmental
Protection Agency alleges may have been disposed of at a waste disposal
facility in Connecticut. The Company is only one of several hundreds of
potentially responsible parties at the site.
The Company has received a notice from the Maine Department of
Environmental Protection under similar Maine legislation relating to
several facilities in Maine. The Company is not yet aware of the extent of
potential clean-up necessary or the number of potentially responsible
parties involved.
In management's opinion, the resolution of these matters is not expected
to have a material adverse impact on the Company's financial condition.
NEW ACCOUNTING STANDARDS
As of January 1, 1993, the Company adopted Financial Accounting Standards
Board Statement No. 106 "Employer's Accounting for Postretirement Benefits
Other Than Pensions" (FAS 106), which requires the accrual of
postretirement benefits, including medical and life insurance coverage,
during the years an employee provides service to the Company. Prior to
1993, the cost of the medical benefits were recorded on a pay-as-you-go
basis. As of January 1, 1993, the Company's transitional liability for the
medical benefits, which have been earned by active employees and retirees,
was $10 million. The annual expense under FAS 106 for 1993 has been
actuarially determined to be $1.5 million, which includes a 20-year
amortization of the transitional liability, compared with $535,000 of such
expense for 1993 calculated on the pay-as-you-go basis.
The MPUC issued a final accounting rule in connection with FAS 106 which
adopted FAS 106 for ratemaking purposes and provided the Company with the
accounting and regulatory framework required to defer the excess
($604,529, which is net of capitalized amounts at December 31, 1993) of
the net periodic postretirement benefit cost recognized under FAS 106 over
the pay-as-you-go amount in 1993 and to record such excess as a regulatory
asset pending inclusion in future rates, subject to the same level of
review for prudence and reasonableness as are all other utility expenses.
The Company, in accordance with the ruling and FAS 106, is amortizing the
unrecognized transition obligation of $10.0 million over a 20-year period.
The Company included these costs in its current base rate filing on which a
final decision was reached in February 1994. The MPUC approved the
inclusion in base rates of FAS 106 costs of $1.5 million annually. In
addition, the Company has been allowed to amortize the actuarially
determined FAS 106 costs over pay-as-you-go that have been deferred from
January 1, 1993 through February 28, 1994 over a ten-year period. This
amortization amounts to approximately $70,000 annually.
The Company also adopted FAS 109 "Accounting for Income Taxes" effective
January 1, 1993. FAS 109 required a change in the accounting for income
taxes from the deferred method to an asset and liability approach, which
requires the recognition of deferred tax liabilities and assets for the
future tax effects of temporary differences between the tax basis and
carrying amounts of assets and liabilities. In accordance with FAS 109,
the Company recorded net additional deferred income taxes of approximately
$23.1 million as of December 31, 1993. These additional deferred income
taxes have resulted from the accrual of deferred taxes on temporary
differences on which deferred taxes had not been previously accrued ($32.5
million), offset by the effect of the 1987 change to lower income tax
rates (reduced by the 1% increase in the federal income tax rate in 1993)
that will be refunded to customers over time ($8.1 million) and the
establishment of deferred tax assets on unamortized investment tax credits
($1.3 million). These latter amounts have been recorded as a deferred
regulatory liability at December 31, 1993. The accrual of these amounts
has been offset by the establishment of a regulatory asset which
represents the customers' future payment of these income taxes when the
taxes are, in fact, expensed. As a result of this accounting, the
Statement of Income for the year ended December 31, 1993 is not affected
by the implementation of FAS 109.
In November 1992, the FASB issued Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment Benefits"
("FAS 112"). The Company is required to adopt this standard no later than
January 1, 1994. FAS 112 applies to postemployment benefits provided to
former or inactive employees, their beneficiaries, and covered dependents
after employment but before retirement. FAS 112 will change the current
methods of accounting for postemployment benefits from recognizing costs
as benefits are paid, to accruing the expected costs of providing these
benefits if certain conditions are met. Management is currently evaluating
the financial impact of this accounting standard. The effect of FAS 112 on
the Company's results of operations and financial position is not expected
to be significant.
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholders and Directors of Bangor Hydro-Electric Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Bangor Hydro-Electric Company and subsidiaries (the
"Company") as of December 31, 1993 and 1992, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements are
the responsibility of the Company s management. Our responsiblity 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
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that 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 the Company as
of December 31, 1993 and 1992, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December
31, 1993, in conformity with generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, in 1993 the
Company changed its method of accounting for income taxes.
Coopers & Lybrand
Portland, Maine
February 17, 1994<PAGE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
ELECTRIC OPERATING REVENUES (Note 1):
Base rate revenue $ 75,008,082 $ 74,009,543 $ 61,971,955
Fuel charge revenue 102,963,688 102,779,462 100,271,242
----------- ------------ ------------
$177,971,770 $176,789,005 $ 162,243,197
----------- ------------ -----------
OPERATING EXPENSES:
Fuel for generation (Note 1) $102,670,217 $101,465,555 $ 93,686,895
Purchased power capacity (Notes 1 and 7) 13,716,436 13,477,717 13,387,523
Other operation and maintenance (Notes 1, 6 and 10) 29,474,327 27,041,625 25,252,525
Depreciation and amortization (Note 1) 4,747,491 4,122,446 3,787,636
Amortization of Seabrook Nuclear Project (Note 8) 1,699,050 2,667,086 2,827,218
Taxes -
Local property and other 4,102,097 3,897,290 4,005,571
Income (Note 2) 4,762,945 5,601,772 2,850,364
----------- ------------ -----------
$161,172,563 $158,273,491 $ 145,797,732
----------- ------------ -----------
OPERATING INCOME $ 16,799,207 $ 18,515,514 $ 16,445,465
OTHER INCOME AND (DEDUCTIONS):
Provision for Basin Mills (Note 7) (8,695,539) - -
Income tax benefits related to
provision for Basin Mills (Note 7) 3,137,895 - -
Allowance for equity funds used during
construction (Note 1) 2,464,934 1,294,958 998,813
Other, net of applicable income taxes (Notes 1 and 2) 435,316 396,329 1,368,402
----------- ------------ -----------
INCOME BEFORE INTEREST EXPENSE $ 14,141,813 $ 20,206,801 $18,812,680
----------- ------------ -----------
INTEREST EXPENSE:
Long-term debt (Note 4) $ 10,438,828 $ 9,617,574 $ 9,692,354
Other (Note 5) 1,164,795 1,418,618 1,812,815
Allowance for borrowed funds used during
construction (Note 1) (2,798,241) (1,084,173) (891,127)
----------- ------------ -----------
$ 8,805,382 $ 9,952,019 $10,614,042
----------- ------------ -----------
NET INCOME $ 5,336,431 $ 10,254,782 8,198,638
DIVIDENDS ON PREFERRED STOCK (Note 3) 1,645,663 1,613,415 1,613,415
----------- ------------ -----------
EARNINGS APPLICABLE TO COMMON STOCK $ 3,690,768 $ 8,641,367 $ 6,585,223
============ ============= ============
EARNINGS PER COMMON SHARE, based on the weighted
average number of shares outstanding of
5,862,411 in 1993, 5,393,306 in 1992 and
4,947,232 in 1991 $ 0.63 $ 1.60 $ 1.33
============ ============= ============
DIVIDENDS DECLARED PER COMMON SHARE $ 1.32 $ 1.32 $ 1.29
============ ============= ============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
<CAPTION>
1993 1992
ASSETS
<S> <C> <C>
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original
cost (Note 7) $250,122,521 $227,604,856
Less - Accumulated depreciation and
amortization (Notes 1 and 7) 71,183,586 67,644,554
------------- -------------
$178,938,935 $159,960,302
Construction in progress (Note 1) 26,601,995 23,135,871
------------- -------------
$205,540,930 $183,096,173
Investments in corporate joint ventures (Notes 1 and 7) -
Maine Yankee Atomic Power Company $ 4,755,848 $ 4,735,848
Maine Electric Power Company, Inc. 124,900 124,900
------------- -------------
$210,421,678 $187,956,921
------------- -------------
OTHER INVESTMENTS, principally at cost $ 4,474,167 $ 3,315,400
------------- -------------
CURRENT ASSETS:
Cash and cash equivalents (Note 1) $ 2,387,156 $ 1,488,038
Accounts receivable, net of reserve ($1,450,000 in 1993
and 1992) 18,763,183 21,549,295
Unbilled revenue receivable (Note 1) 7,161,747 7,399,246
Inventories, at average cost:
Material and supplies 3,220,482 3,106,309
Fuel oil 635,072 853,297
Prepaid expenses 1,573,707 1,613,093
Deferred fuel and interest costs (Note 1) 2,568,539 10,822,244
Deferred purchased power costs (Note 1) 1,795,544 1,107,060
Current deferred income taxes (Note 2) - 265,070
------------- -------------
Total current assets $ 38,105,430 $ 48,203,652
------------- -------------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $21,677,946 in 1993
and $19,978,896 1992 (Note 8) $ 37,164,129 $ 38,863,179
Deferred fuel and interest costs (Note 1) - 1,474,188
Costs to terminate purchased power contract (Note 7) 40,301,603 -
Deferred regulatory assets (Notes 2 and 6) 33,068,241 -
Prepaid pension costs (Note 6) 2,398,498 2,386,498
Demand-side management costs 3,691,248 2,786,292
Other 3,896,178 3,880,863
------------- -------------
Total deferred charges $120,519,897 $ 49,391,020
------------- -------------
Total Assets $373,521,172 $288,866,993
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
December 31,
<CAPTION>
1993 1992
STOCKHOLDERS' INVESTMENT AND LIABILITIES
<S> <C> <C>
CAPITALIZATION (see accompanying statement):
Common stock investment (Note 3) $ 93,944,148 $ 82,230,093
Preferred stock (Note 3) 4,734,000 4,734,000
Preferred stock subject to mandatory redemption (Notes 3 and 11) 15,167,629 15,101,536
Long-term debt, exclusive of sinking fund requirements and
a current maturity in 1992 (Notes 4 and 11) 119,125,856 100,685,000
------------- -------------
Total capitalization $232,971,633 $202,750,629
------------- -------------
CURRENT LIABILITIES:
Notes payable - banks (Note 5) $ 36,000,000 $ 15,000,000
------------- -------------
Other current liabilities -
Sinking fund requirements and a current maturity in 1992
of long-term debt (Notes 4 and 11) $ 1,297,448 $ 5,570,000
Accounts payable 15,960,900 17,042,405
Dividends payable 2,449,309 2,183,844
Accrued interest 3,705,527 2,596,094
Customers' deposits (Note 9) 498,332 502,715
Current income taxes payable - 5,214,381
------------- -------------
Total other current liabilities $ 23,911,516 $ 33,109,439
------------- -------------
Total current liabilities $ 59,911,516 $ 48,109,439
------------- -------------
COMMITMENTS AND CONTINGENCIES (Notes 7 and 9)
DEFERRED CREDITS AND RESERVES (Note 2):
Deferred income taxes - Seabrook $ 19,176,232 $ 9,541,371
Other accumulated deferred income taxes 47,000,779 24,149,032
Deferred regulatory liability 9,347,049 -
Unamortized investment tax credits 2,271,550 2,449,726
Other (Note 6) 2,842,413 1,866,796
------------- -------------
Total deferred credits and reserves $ 80,638,023 $ 38,006,925
------------- -------------
Total Stockholders' Investment and Liabilities $373,521,172 $288,866,993
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
December 31, 1993 1992
<S> <C> <C>
COMMON STOCK INVESTMENT (Note 3):
Common stock, par value $5 per share -
Authorized - 7,500,000 shares
Outstanding - 6,225,394 in 1993 and 5,420,955 in 1992 $31,126,970 $ 27,104,775
Amounts paid in excess of par value 45,430,734 33,485,949
Retained earnings (Note 1) 17,386,444 21,639,369
------------ -------------
Total Common Stock $93,944,148 $ 82,230,093
------------ -------------
PREFERRED STOCK, non-participating, cumulative, par value
$100 per share, authorized 400,000 shares (Note 3):
Not redeemable or redeemable solely at the option of the issuer -
7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000
4 1/4% Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000
4%, Series A, Callable at $110, 17,500 shares authorized and
outstanding 1,750,000 1,750,000
------------ -------------
$ 4,734,000 $ 4,734,000
Subject to mandatory redemption requirements - ------------ -------------
8.76%, Not redeemable prior to December 27, 1994, then callable
at 105.63% if called on or prior to December 27, 1995, 150,000
shares authorized and outstanding (Note 11) $15,167,629 $ 15,101,536
------------ -------------
LONG-TERM DEBT:
First Mortgage Bonds (Notes 4 and 11) -
4% Series due 1993 $ - $ 3,500,000
6 3/4% Series due 1998 2,500,000 2,500,000
8 1/4% Series due 1999 - 3,500,000
9 1/4% Series due 2001 - 2,280,000
8 3/5% Series due 2003 - 1,375,000
12 1/2% Series due 1998 - 3,900,000
10 1/4% Series due 2019 15,000,000 15,000,000
10 1/4% Series due 2020 30,000,000 30,000,000
8.98% Series due 2022 20,000,000 20,000,000
7.38% Series due 2002 20,000,000 20,000,000
7.30% Series due 2003 15,000,000 -
12.1/4% Series due 2001 13,723,304 -
------------ -------------
$116,223,304 $102,055,000
Less - Sinking fund requirements and a current maturity in 1992 1,297,448 5,570,000
------------ -------------
$114,925,856 $ 96,485,000
Variable rate demand pollution control revenue bonds
Series 1983 due 2009 4,200,000 4,200,000
------------ -------------
Total long-term debt $119,125,856 $100,685,000
------------ -------------
Total Capitalization $232,971,633 $202,750,629
============ =============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
CASH FLOWS FROM OPERATIONS:
Net Income $ 5,336,431 $ 10,254,782 $ 8,198,638
Adjustments to reconcile net income to net cash
provided by (used in) operations:
Depreciation and amortization (Note 1) 4,747,491 4,122,446 3,787,636
Amortization of Seabrook Nuclear Project (Note 8) 1,699,050 2,667,086 2,827,218
Allowance for equity funds used during
construction (Note 1) (2,464,934) (1,294,958) (998,813)
Deferred income tax provision (Note 2) 2,673,409 (3,003,698) 2,881,805
Deferred income taxes on Seabrook Nuclear
Project (Note 2) (414,647) (792,396) (855,333)
Deferred investment tax credits (Note 2) (178,176) 672,798 214,345
Provision for Basin Mills Project (Note 7) 8,695,539 - -
Changes in assets and liabilities:
Deferred fuel, purchased power and interest
costs (Note 1) 9,039,409 10,826,632 7,251,476
Receivables, net and unbilled revenue 3,023,611 (3,166,120) (2,369,572)
Accounts payable (1,081,505) 2,518,005 (4,351,840)
Accrued interest 1,109,433 241,976 (155,671)
Current and deferred income taxes 2,566,443 5,214,381 -
Other current assets and current liabilities, net 139,055 (212,929) 903,938
Other, net (1,513,238) (2,441,478) (1,460,770)
------------- ------------- -------------
Net Cash Provided By Operations $ 33,377,371 $ 25,606,527 $ 15,873,057
------------- ------------- -------------
CASH FLOWS FROM INVESTING:
Construction expenditures $(33,611,031) $(24,270,884) $(21,769,242)
Cost to terminate purchased power contract (Notes 7)* (23,711,733) - -
Allowance for borrowed funds used during
construction (Note 1) (2,798,241) (1,084,173) (891,127)
------------- ------------- -------------
Net Cash Used in Investing $(60,121,005) $(25,355,057) $(22,660,369)
------------- ------------- -------------
CASH FLOWS FROM FINANCING:
Dividends on preferred stock $ (1,579,570) $ (1,579,570) $ (1,579,570)
Dividends on common stock (7,678,229) (7,105,895) (6,285,675)
Redemptions, maturities and sinking fund payments of
long-term debt (15,148,118) (19,860,000) (8,550,000)
Issuances:
Common stock (Note 3)
Public offering (745,000 in 1993 and 920,000
shares in 1991) 14,803,150 - 13,110,000
Dividend reinvestment plan (59,439 shares in 1993
and 50,271 shares in 1992) 1,245,519 914,477 -
Long-term debt (Note 4)* 15,000,000 40,000,000 -
Short-term debt, net (Note 5) 21,000,000 (13,500,000) 5,500,000
------------- ------------- -------------
Net Cash Provided By (Used in) Financing $ 27,642,752 $ (1,130,988) $ 2,194,755
------------- ------------- -------------
NET CHANGE IN CASH AND CASH EQUIVALENTS $ 899,118 $ (879,518) $ (4,592,557)
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR 1,488,038 2,367,556 6,960,113
------------- ------------- -------------
CASH AND CASH EQUIVALENTS - END OF YEAR $ 2,387,156 $ 1,488,038 $ 2,367,556
============= ============= =============
SUPPLEMENTAL CASH FLOW INFORMATION:
CASH PAID DURING THE YEAR FOR:
Interest (Net of Amount Capitalized) $ 4,549,462 $ 8,757,236 $ 10,769,713
Income Taxes - 4,850,574 1,550,340
============= ============= =============
* Significant Non-Cash Investing and Financing Activity - In connection with the termination of the
purchased power agreement in 1993 with the Beaver Wood Joint Venture, the Company issued $14.3 of
12 1/4 First Mortgage Bonds in substitution for Beaver Wood's previously outstanding secured notes
which is not reflected on this Statement.
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $21,639,369 $20,120,486 $20,618,746
ADD - Net income 5,336,431 10,254,782 8,198,638
------------ ------------ ------------
$26,975,800 $30,375,268 $28,817,384
------------ ------------ ------------
DEDUCT:
Cash dividends declared on -
Preferred stock $ 1,579,570 $ 1,579,570 $ 1,579,570
Common stock - $1.32 per share in 1993 and
1992, and $1.29 per share in 1991. 7,943,693 7,122,484 6,633,782
Other (Note 3) 66,093 33,845 483,546
------------ ------------ ------------
$ 9,589,356 $ 8,735,899 $ 8,696,898
------------ ------------ ------------
BALANCE AT END OF YEAR $17,386,444 $21,639,369 $20,120,486
============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION The Consolidated Financial Statements of Bangor
Hydro-Electric Company (the "Company") include its wholly owned subsidiaries,
Penobscot Hydro Co., Inc. ("PHC"), and Bangor Var Co., Inc. ("BVC"). The
operations of PHC consist solely of a 50% interest in Bangor-Pacific Hydro
Associates ("BPHA"), the owner and operator of the redeveloped West Enfield
hydroelectric station. PHC accounts for its investment in BPHA under the
equity method. BVC was incorporated in 1990 to own the Company's 50% interest
in a partnership which owns certain facilities used in the Hydro-Quebec Phase
II transmission project in which the Company is a participant. BVC accounts
for its investment in the partnership under the equity method. All
significant intercompany balances and transactions have been eliminated. The
accounts of the Company are maintained in accordance with the Uniform System
of Accounts prescribed by the regulatory bodies having jurisdiction.
EQUITY METHOD OF ACCOUNTING The Company accounts for its investments in the
common stock of Maine Yankee Atomic Power Company ("Maine Yankee") and Maine
Electric Power Company, Inc. ("MEPCO") under the equity method of accounting,
and records its proportionate share of the net earnings of these companies
(substantially all of these earnings are paid out in dividends) as a
reduction of purchased power capacity costs. See Note 7 for additional
information with respect to these investments.
ELECTRIC OPERATING REVENUE Electric Operating Revenue consists primarily of
amounts charged for electricity delivered to customers during the period. The
Company records unbilled revenue, based on estimates of electric service
rendered and not billed at the end of an accounting period, in order to match
revenue with related costs. The Federal Energy Regulatory Commission ("FERC")
requires utilities to reclassify to operating revenue sales transactions
related to power pool and interconnection agreements and resales of purchased
power previously netted within fuel and purchased power expense. The
reclassification increased total operating fuel revenue by $15.3 million in
1993, $13.8 million in 1992 and $15.7 million in 1991, while increasing fuel
and purchased power expense by the same amounts.
DEFERRED FUEL AND PURCHASED POWER CAPACITY ACCOUNTING The Company utilizes
deferred fuel accounting. Under this accounting method, retail fuel costs are
expensed when recovered through rates and recognized as revenue. Retail fuel
costs not yet expensed are classified on the Consolidated Balance Sheets
("Balance Sheets") as deferred fuel costs. The fuel cost adjustment rate in-
cludes a factor calculated to reimburse the Company or its customers, as
appropriate, for the carrying cost of funds used to finance under- or
over-collected fuel costs, respectively.
Under the Maine Public Utilities Commission ("MPUC") fuel cost adjustment
regulations effective through December 31, 1993, the Company is allowed to
recover its fuel costs on a current basis. The fuel charge is based on the
Company's projected cost of fuel for a twelve-month period. Under- or
over-collections resulting from differences between estimated and actual fuel
costs for a period are included in the computation of the estimated fuel
costs of the succeeding fuel adjustment period. Commencing January 1, 1988,
in accordance with an agreement approved by the MPUC, the Company began to
phase-in increased fuel costs (primarily the cost of power purchased from
small power producers see Note 7). The fuel rates are being designed so that
all fuel costs incurred during that period will be billed in 1994.
Prior to 1992, the MPUC allowed the Company to defer for future collection
from, or payback to, customers the difference between actual purchased power
costs incurred and those costs billed. As with fuel, the deferred purchased
power capacity amounts were, for these years, considered when setting the
fuel cost adjustment rate for the forthcoming year. The portion of purchased
power capacity costs which is included in fuel revenue is classified as
purchased power capacity expense in the Statements of Income. Effective
November 15, 1992, the collection of the remaining balance of deferred
purchased power costs is being recorded on the Statements of Income as fuel
expense. The base rates, which became effective on January 1, 1992, excluded
all purchased power capacity costs from this deferral process.
DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY Depreciation of
electric plant is provided using the straight-line method at rates designed
to allocate the original cost of the properties over their estimated service
lives. The composite depreciation rate, expressed as a percentage of average
depreciable plant in service, and considering the amortization of the
over-accrued depreciation which is discussed below, was approximately 2.1% in
1993, 1992 and 1991.
A study conducted in 1989 by an independent firm determined that, as a group,
the actual lives of the Company's property, plant and equipment are longer
than the lives represented by the depreciation rates that the Company had
been using to compute its depreciation expense for accounting purposes. In
addition, the study also determined that the reserve for depreciation was
over-accumulated. The agreement on base rates which became effective on
October 1, 1990, contained a provision to amortize the remaining balance of
the over-accumulated reserve for depreciation account ($11.4 million at
October 1) over a six-year period and adopted the longer depreciable lives as
determined by the aforementioned study.
The Company follows the practice of charging to maintenance the cost of
repairs, replacements and renewals of minor items considered to be less than
a unit of property. Costs of additions, replacements and renewals of items
considered to be units of property are charged to the utility plant accounts,
and any items retired are removed from such accounts. The original costs of
units of property retired and removal costs, less salvage, are charged to the
reserve for depreciation.
Depreciation, local property taxes and other taxes not based on income, which
were charged to operating expenses, are stated separately in the Statements
of Income. Rents and advertising costs are not significant. No royalty or
research and development expenses were incurred.
Maintenance expense was $6.5 million in 1993, $5.6 million in 1992 and $6.4
million in 1991.
EQUITY RESERVE FOR LICENSED HYDRO PROJECTS The FERC requires that a reserve
be maintained equal to one-half of the earnings in excess of a prescribed
rate of return on the Company's investment in licensed hydro property,
beginning with the twenty-first year of the project operation under license.
The required reserve for licensed hydro projects is classified in retained
earnings and has a balance of $584,942 at December 31, 1993.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION ("AFDC") In accordance with
regulatory requirements of the MPUC, the Company capitalizes as AFDC
financing costs related to portions of its construction work in progress at a
rate equal to its weighted cost of capital and is capitalized into utility
plant with offsetting credits to other income and interest. This cost is not
an item of current cash income, but is recovered over the service life of
plant in the form of increased revenue collected as a result of higher
depreciation expense. In addition, carrying costs on certain regulatory
assets are also capitalized and included in AFDC in the Statements of Income.
The average AFDC (and carrying cost) rates computed by the Company were 10.0%
in 1993, 10.6% for 1991 and 11.1% 1991.
CASH AND CASH EQUIVALENTS The Company considers all highly liquid debt
instruments purchased with an original maturity of three months or less to be
temporary cash investments.
RECLASSIFICATIONS Prior year amounts have been reclassified to conform with
the presentation used in the 1993 Consolidated Financial Statements.
SIGNIFICANT CUSTOMER The Company has one industrial customer, LCP Chemicals
("LCP"), that accounted for 4.8%, 4.9% and 5.4% of total revenue (excluding
AR 14 reclassifications) in 1993, 1992 and 1991, respectively. In 1988, with
approval of the MPUC, the Company entered into an agreement with this
customer by which its base rates for services were reduced and a
"revenue-sharing" plan was instituted. Under the revenue-sharing plan, the
amounts billed to this customer were adjusted up or down to reflect changes
in the customer's per unit product price and electricity costs. The
revenue-sharing rate continued for part of 1992 when it was replaced by a new
rate that had a higher contribution to base revenue. In June 1993, LCP
returned to the revenue-sharing rate. The Company recorded, as other income,
approximately $513,000 in 1993, 206,000 in 1992, and $1.8 million in 1991
pursuant to the revenue-sharing rate.
NOTE 2. INCOME TAXES
The Company adopted Financial Accounting Standard Board Statement No. 109
"Accounting for Income Taxes" ("FAS 109") effective January 1, 1993. FAS 109
required a change in the accounting for income taxes from the deferred method
to an asset and liability approach, which requires the recognition of
deferred tax liabilities and assets for the future tax effects of temporary
differences between the tax basis and carrying amounts of assets and
liabilites. In accordance with FAS 109, the Company recorded net additional
deferred income tax liabilities of approximately $23.1 million as of December
31, 1993. These additional deferred income tax liabilities have resulted from
the accrual of deferred taxes on temporary differences on which deferred
taxes had not been previously accrued ($32.5 million), offset by the effect
of the 1987 change to lower income tax rates (reduced by the 1% increase in
the federal income tax rate in 1993) that will be refunded to customers over
time ($8.1 million) and the establishment of deferred tax assets on
unamortized investment tax credits ($1.3 million). These latter amounts have
been recorded as deferred regulatory liabilities at December 31, 1993. The
accrual of the additional amount of deferred tax liabilities has been offset
by a regulatory asset which represents the customers' future payment of these
income taxes when the taxes are, in fact, expensed. As a result of this
accounting, the consolidated statement of income for the year ended December
31, 1993 is not affected by the implementation of FAS 109.
The rate-making practices followed by the MPUC permit the Company to recover
federal and state income taxes payable currently, and to recover some, but
not all, deferred taxes that would otherwise be recorded in accordance with
FAS 109 in the absence of regulatory accounting.
The individual components of other accumulated deferred income taxes are as
follows at December 31, 1993:
Deferred income tax liabilities:
Excess book over tax basis of electric
plant in service $43,023,222
Costs to terminate purchased power contract 4,553,166
Deferred FERC licensing costs 3,431,075
Deferred fuel, purchased power and interest costs 1,616,491
Deferred demand-side management program costs 1,055,030
Prepaid pension costs 1,028,179
Investment in jointly-owned companies 790,881
Other 2,434,532
-----------
$57,932,576
-----------
Deferred income tax assets:
Deferred taxes provided on alternative
minimum tax ($3,175,718)
Provision for Basin Mills investment (3,137,895)
Deferred state income tax benefit (1,561,137)
Unamortized investment tax credit (1,286,156)
Reserve for bad debts (797,696)
Other (973,195)
-------------
($10,931,797)
-------------
Total other accumulated deferred income taxes $ 47,000,779
=============
The individual components of federal and state income taxes reflected in the
Consolidated Statements of Income for 1993, 1992 and 1991 are as stated in
the table at the top of page 34.
Year Ended December 31,
----------------------------------------
1993 1992 1991
----------------------------------------
Current:
Federal $ - $6,274,554 $1,064,754
State - 2,739,089 485,586
-----------------------------------------
$ - $9,013,643 $1,550,340
-----------------------------------------
Deferred - Short-Term:
Federal $ 114,674 $4,330,124 (1,803,480)
State 68,216 213,745 (93,018)
------------------------------------------
$ 182,890 $4,543,869 (1,896,498)
------------------------------------------
Deferred - Long-Term:
Federal - Other $ 2,512,026 $(5,741,329) $4,360,251
State - Other (21,507) (1,806,238) 418,052
Federal - Seabrook (341,917) (653,060) (705,036)
State - Seabrook (72,730) (139,336) (150,297)
-----------------------------------------
$2,075,872 $(8,339,963) $3,922,970
-----------------------------------------
Investment Tax Credits, Net $ (178,176) $ 672,798 $ 214,345
-----------------------------------------
Total Provision $2,080,586 $ 5,890,347 $3,791,157
Allocated to Other Income 2,682,359 (288,575) (940,793)
-----------------------------------------
Charged to Operating Expense $4,762,945 $ 5,601,772 $2,850,364
=========================================
The table below reconciles an income tax provision, calculated by multiplying
income before federal income taxes (as reported on the Statements of Income)
by the statutory federal income tax rate to the federal income tax expense
reported on the Statements of Income. The difference is represented by the
temporary differences for which deferred taxes are not provided.
1993 1992 1991
---- ---- ----
Amount % Amount % Amount %
-------------------------------------------
(Dollars in Thousands)
Federal income tax provisions
at statutory rate $2,522 34% $5,489 34% $4,077 34%
Less (Plus) temporary reductions in
tax expense resulting from statutory
exclusions from taxable income:
Dividend received deduction
related to earnings of
associated companies 133 2 142 1 179 2
Equity component of AFDC 496 6 306 2 277 2
Amortization of equity component
of AFDC on recoverable Seabrook
investment (155) (2) (187) (2) (191) (2)
Other (24) - 4 - (34) -
------ ---- ------ ---- ------ ----
Federal income tax provision before
effect of temporary differences $2,072 28% $5,224 33% $3,846 32%
Less (Plus) timing differences that
are flowed through for ratemaking
and accounting purposes:
Amortization of debt component of
AFDC and capitalized overheads
on recoverable Seabrook investment (146) (2)% (193) (2)% (196) (2)%
Book depreciation greater than tax
depreciation on assets acquired
before 1971 (292) (4) (293) (2) - -
State income tax liability
deducted for federal income
tax purposes 116 2 467 4 351 3
Reversal of excess deferred
income taxes 34 - 221 2 284 3
Life insurance flow-through
in prior years - - - - 178 2
Other 253 4 139 1 98 1
------- ---- ------ ---- ------ ---
Federal income tax provision $2,107 28% $4,883 30% $3,131 25%
======= ==== ====== ==== ====== ===
The differences between the federal and state income tax expense reported on
the Consolidated Statements of Income, and the federal and state income tax
liability as reflected on the Company's tax returns, are caused by temporary
differences on which deferred taxes are provided and recovered through rates.
The table below shows the components of deferred tax expense as reported in
the Statements of Income.
1993 1992 1991
----------- ----------- ------------
Costs to terminate purchased
power contract $4,553,166 $ - $ -
Provision for Basin Mills (3,137,895) - -
Seabrook Nuclear Project (414,647) (792,396) (855,333)
Tax depreciation in excess of
book depreciation 852,187 3,787,047 5,958,182
Deferred fuel and purchased
power costs 163,665 (8,443,906) (2,843,764)
State taxes provided for rate-
making purposes but not paid (124,217) 146,702 (932,197)
Deferred taxes provided on the AMT - 268,254 (551,503)
Deferred interest costs 59,214 (209,149) (52,476)
Costs of removal 84,203 227,649 204,179
Deferred demand-side management costs 97,672 284,297 198,677
FERC licensing costs 277,574 835,487 912,903
Other (152,160) 99,921 (12,196)
----------- ------------ -----------
Total deferred income tax
expense (benefit) $2,258,762 $(3,796,094) $2,026,472
=========== ============ ===========
Under the federal income tax laws, the Company received investment tax credits
on qualified property additions through 1986. Investment tax credits utilized
were deferred and are being amortized over the life of the related property.
Investment tax credits available of about $4.8 million ($2.5 million of which
is attributable to PHC and $900,000 to BVC) have not been utilized or
recorded and, subject to review by the Internal Revenue Service ("IRS"), may
be used prior to their expiration, which occurs between 1996 and 2005.
At December 31, 1993, the Company had, for income tax purposes, alternative
minimum tax credits ("AMT") of approximately $3.2 million for the reduction
of future tax liabilities. At December 31, 1993, the Company had, for income
tax reporting purposes, approximately $21 million of net operating loss
carryforwards that expire in 2008.
NOTE 3. COMMON AND PREFERRED STOCK
COMMON STOCK In June of 1993 the Company issued and sold for cash 745,000
common shares (for proceeds of $14.8 million). The proceeds were utilized to
finance construction expenditures, reduce short-term debt, and fund a portion
of the buyout of the power purchase agreement with the Beaver Wood Joint
Venture, which is more fully described in Note 7. The Company issued and sold
for cash 920,000 common shares (for proceeds of approximately $13.1 million)
in June of 1991. The proceeds were used to reduce outstanding short-term
debt. Prior to 1992, stockholders had been able to invest their dividends and
optional cash payments in common stock of the Company acquired by an
independent agent in the open market through the Company's Dividend
Reinvestment and Common Stock Purchase Plan ("the Plan"). In 1992 the Company
amended the Plan to enable it to issue original shares in return for the
reinvested dividends and optional cash payments. The common stock has general
voting rights of one vote per twelve shares owned.
PREFERRED STOCK Authorized preferred stock consists of 400,000 shares, par
value $100 per share, of which there are 197,340 shares outstanding. The
remaining 202,660 authorized but unissued shares (plus additional shares
equal in number to such presently outstanding shares as may be retired) may
be issued with such preferences, restrictions or qualifications as the Board
of Directors may determine. Any new shares so issued will be required to be
issued with per share voting rights no greater than that of the common stock.
The callable preferred stock may be called in whole or in part upon any
dividend date by appropriate resolution of the Board of Directors. Except for
the holders of the 8.76% issue, which does not carry general voting rights,
the currently outstanding preferred stock has general voting rights of one
vote per share. With regard to payment of dividends or assets available in
the event of liquidation, preferred stock ranks prior to common stock.
REDEEMABLE PREFERRED SHARES Call premiums on preferred stock redeemed in
1986 and 1987 were deferred and were being amortized to earnings over a
ten-year period. In compliance with an audit by FERC, the remaining balance
of these deferred call premiums ($449,700 at December 31, 1990) were charged
directly to retained earnings in 1991.
On December 27, 1989, the Company issued to an institutional investor $15
million of non-voting preferred stock carrying a dividend rate of 8.76%.
These shares have a maturity of fifteen years with a mandatory sinking fund
of $1.5 million per year starting in 1995. The agreement to issue this series
of preferred stock contains a provision whereby, if the Copany pays a
dividend that is considered a return of capital for federal income tax
purposes, the Company is required to make a payment to the stockholder in
order to restore the stockholder's after-tax yield to the level it would have
been had the dividend not been considered a return of capital. Since 100% of
the dividends paid in 1990 and 1993, pending any review by the IRS, are to be
considered a return of capital, the Company has become obligated to pay this
stockholder approximately $969,000 at the time the stock is either sold or
redeemed. This obligation is being recognized over the remaining life of the
issue through a direct charge to retained earnings of $72,862 per year.
NOTE 4. LONG-TERM DEBT
Under the provisions of the first mortgage bond indenture, substantially all
of the Company's plant and property has been mortgaged to secure the
Company's first mortgage bonds. Sinking fund requirements and current
maturities of the first mortgage bonds for the five years subsequent to
December 31, 1993 aggregate $10,536,507 as follows:
Sinking Fund Current
Requirements Maturities Total
1994 $1,297,448 $ - $ 1,297,448
1995 1,461,253 - 1,461,253
1996 1,645,737 - 1,645,737
1997 1,853,515 - 1,853,515
1998 1,778,554 2,500,000 4,278,554
----------- ----------- -----------
$8,036,507 $2,500,000 $10,536,507
=========== =========== ===========
In 1993 the Company issued $15 million of 7.3% first mortgage bonds to an
institutional investor for a period of 10 years. Also in 1993, in connection
with the termination of the purchased power contract (which is discussed in
Note 7), the Company issued $14.3 million of 12.25% mortgage bonds to the
holders of Beaver Wood's debt in substitution for the Beaver Wood's pre-
viously outstanding 12.25% secured notes. In September 1993 the Company
redeemed the 8.25%, 8.6%, and 9.25% series of first mortgage bonds.
The redemptions of these issues resulted in call premiums of $29,563, and
$31,011, respectively.
The Company completed two first mortgage bond financings during 1992. The
first was issued in April for $20 million at an interest rate of 8.98% for a
period of 20 years. The second was issued in October for $20 million at an
interest rate of 7.38% for a period of 10 years. In 1992, the Company
redeemed the 10.5%, 10.25% and the 17.35% series of first mortgage bonds. The
redemption of these issues resulted in call premiums of $88,200, $170,765 and
$88,000, respectively.
The call premiums in 1993 and 1992 were deferred and have been included in
the Company's current base rate filing on which a final decision was reached
in February 1994. The Company is allowed to amortize these costs over a
ten-year period with the unamortized balance included in the rate base.
NOTE 5. SHORT-TERM BORROWINGS
The Company has an unsecured revolving credit agreement ("Credit Agreement")
with a group of four banks providing for loans of up to $25 million. The
Credit Agreement expires on May 26, 1994 but may be extended through May 26,
1995 with unanimous consent of the participating banks. The Credit Agreement
has a term loan arrangement whereby the loan balance at the date of
termination can be paid in equal quarterly installments over a two-year
period. The Company may borrow at rates, as defined within the Credit
Agreement, based on certificate of deposit loan rates, Eurodollar loan rates
or the agent bank's reference rate.
A commitment fee of 1/4 of 1% per annum is required on the amount not
borrowed under any of these borrowing options. A fourth borrowing option
under the Credit Agreement is in the form of "bid loans" whereby the Company
can borrow at "money market" rates independently set by each of the four
banks participating in the Credit Agreement. This form of borrowing does not
reduce the commitment fee but does reduce the credit available under the
Credit Agreement. The Credit Agreement allows the Company to incur an
additional $30 million in unsecured debt outside of the agreement. The
Company maintains lines of credit with banks which it utilizes when the
borrowing costs under the lines of credit are more favorable than those under
the Credit Agreement. Certain of these lines of credit have commitment fees
ranging from 1/8 of 1% to 1/4 of 1% of the line while others have no
commitment fees.
Certain information related to total short-term borrowings under the Credit
Agreement and the lines of credit is as follows:
1993 1992 1991
Total credit available at end
of period $55,000,000 $55,000,000 $42,000,000
Unused credit at end of period $19,000,000 $40,000,000 $13,500,000
Borrowings outstanding at end
of period $36,000,000 $15,000,000 $28,500,000
Effective interest rate (exclusive
of fees) on borrowings out-
standing at end of period 3.7% 4.4% 5.4%
Average daily outstanding bor-
rowings for the period $22,754,205 $22,448,087 $23,297,260
Weighted daily average annual
interest rate 3.7% 4.5% 6.6%
Highest level of borrowings
outstanding at any month-
end during the period $36,000,000 $31,000,000 $28,500,000
The average daily borrowings outstanding for the period represent the sum of
daily borrowings outstanding, divided by the number of days in the period.
The weighted daily average annual interest rate is determined by dividing the
annual interest expense by the average daily borrowings outstanding for the
period. Commitment and agent fees for the revolving credit agreement of
$40,000, $68,000 and $27,000 were paid in 1993, 1992 and 1991, respectively,
and are excluded from the calculation of the weighted daily average annual
interest rate.
NOTE 6. PENSION AND OTHER POST-EMPLOYMENT BENEFITS
The Company has noncontributory pension plans covering substantially all of
its employees. On July 17, 1987, the Company created separate union and
nonunion plans from an original plan. Benefits under the plans are generally
based on the employee's years of service and compensation during the years
preceding retirement. The Company's general policy is to contribute to the
funds the amounts deductible for federal income tax purposes.
The Company recorded pension income of $12,000, $348,214 and $263,700 for
1993, 1992 and 1991, respectively. The tables below and on the following page
detail the components of pension income for 1993, 1992 and 1991, the funded
status of the plans, the amounts recognized in the Company's Financial
Statements and the major assumptions used to determine these amounts.
The plan's assets are composed of fixed income securities, equity securities
and cash equivalents.
Total pension income included the following components:
1993 1992 1991
Service cost - benefits earned
during the period $ 1,085,419 $ 1,037,419 $ 982,180
Interest cost on projected
benefit obligation 2,244,706 1,996,491 1,605,246
Actual return on plan assets (4,633,435) (2,366,341) (6,595,692)
Total of amortized obligations and
the net gain (loss) deferred $ 1,291,310 $(1,015,783) $ 3,744,566
------------ ------------ ------------
Total pension (income) $ (12,000) $ (348,214) $ (263,700)
============ ============ ============
Significant assumptions used were -
Discount rate 7.0% 8.0% 8.0%
Rate of increase in future
compensation levels 5.0% 6.0% 6.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 8.0%
The following table sets forth the plans' funded status and amounts
recognized in the Balance Sheets at December 31, 1993 and 1992:
1993 1992
------------- ------------
Actuarial present value of accumulated
benefit obligation
Vested $ 22,730,655 $ 16,294,432
Non-vested 2,669,955 1,686,977
------------- ------------
Total $ 25,400,610 $ 17,981,409
------------- ------------
Projected benefit obligation $(32,484,893) $(28,182,601)
Plan assets at fair value 37,810,748 35,081,512
------------- ------------
Excess of plan assets over projected benefit
obligation $ 5,325,855 $ 6,898,911
Items not yet recognized in earnings -
Net (asset) at transition (6,916,450) (7,848,775)
Prior service cost 4,597,483 4,206,141
Unrecognized net gain from past experience
and changes in assumptions (608,390) (869,779)
------------- ------------
Net pension asset recognized $ 2,398,498 2,386,498
============= ============
In addition to pension benefits, the Company provides certain health care and
life insurance benefits to its retired employees. Substantially all of the
Company's employees may become eligible for retiree benefits if they reach
normal retirement age while working for the Company.
The Company has adopted Financial Accounting Standards Board Statement No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
("FAS 106") as of January 1, 1993. This standard requires the accrual of
postretirement benefits, including medical and life insurance coverage,
during the years an employee provides services to the Company. Prior to 1993,
the cost of health care benefits were expensed as benefits were paid.
The MPUC issued a final accounting rule in connection with FAS 106 which
adopted this pronouncement for ratemaking purposes and provides the Company
with the accounting and regulatory framework required to defer the excess
($604,529, which is net of capitalized amounts at December 31, 1993) of the
net periodic postretirement benefit cost recognized under FAS 106 over the
pay-as-you-go amount in 1993 and to record such excess as a regulatory asset
pending inclusion in future rates, subject to the same level of review for
prudence and reasonableness as are all other utility expenses. The Company,
in accordance with the ruling and FAS 106, is amortizing the unrecognized
transition obligation of $10,023,200 over a 20-year period. The Company will
begin recovering the deferred FAS 106 costs with the implementation of new
base rates on March 1, 1994 and amortize the deferred balance over a ten-year
period.
In accordance with the provisions of FAS 106, the actuarially determined net
periodic postretirement benefit cost for 1993 and the major assumptions used
to determine these amounts are shown below.
Net periodic postretirement benefit cost for 1993 includes the following
components:
Service cost of benefits earned $ 359,600
Interest cost on accumulated post-
retirement benefit obligation 683,200
Amortization of unrecognized transition
obligation over 20 years 501,200
----------
Net periodic postretirement benefit cost $1,544,000
Expense on a pay-as-you-go basis (534,900)
Amounts capitalized into construction
work in progress (404,571)
----------
Regulatory asset recorded at December 31, 1993 $ 604,529
==========
The following table sets forth the benefit plan's unfunded status and amounts
recognized in the Company's Balance Sheet at December 31, 1993:
Accumulated postretirement benefit obligation:
Retirees $ 5,640,000
Fully eligible active plan participants 773,000
Other active participants 4,196,000
------------
$10,609,000
Unrecognized net transition obligation (9,522,000)
Unrecognized net loss 457,000
------------
Accrued postretirement benefit cost 1,544,000
Less: Expense recognized on a pay-as-you-go basis 534,900
------------
Net liability recorded at December 31, 1993
(included in Other Reserves) $ 1,009,100
===========
For measuring the expected postretirement benefit obligation, a 12.4% annual
rate of increase in the per capita claims cost ("trend rate") for
participants who have not reached the age of 65 was assumed for 1992. This
rate was assumed to decrease annually to 6% in 2050 and remain at that level
thereafter. For those participants who are 65 or older, the trend rate was
assumed to be 8.3% in 1992, 9.7% in 1993 and then decrease until 2050 when it
is assumed to be 5.8%.
If the health care cost trend rate was increased one percent, the accumulated
postretirement benefit obligation as of January 1, 1993 would have increased
by 11%. The effect of such change on the aggregate of service and interest
cost for 1993 would be an increase of 12%.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7% at December 31, 1993.
In November 1992, the FASB issued Statement of Financial Accounting Standards
No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS 112"). The
Company is required to adopt this standard no later than January 1, 1994. FAS
112 applies to postemployment benefits provided to former or inactive
employees, their beneficiaries, and covered dependents after employment but
before retirement. FAS 112 will change the current methods of accounting for
postemployment benefits from recognizing costs as benefits are paid, to
accruing the expected costs of providing these benefits if certain conditions
are met. Management is currently evaluating the financial impact of this
accounting standard. However, the effect of FAS 112 on the Company's results
of operations and financial position is not expected to be significant.
NOTE 7. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS
MAINE YANKEE The Company owns 7% of the common stock of Maine Yankee which
owns and operates a nuclear power plant in Wiscasset, Maine. Under purchased
power arrangements, the Company is entitled to purchase an amount
approximately equal to its ownership share of the output of Maine Yankee, an
entitlement of approximately 62 MW. The Company is obligated to pay its pro
rata share of Maine Yankee's operating expenses, fuel costs, capital costs
and decommissioning costs.
MEPCO The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and
operates electric transmission facilities from Wiscasset, Maine to the
Maine-New Brunswick border. Several New England utilities, including the
Company and MEPCO's other stockholders (two other Maine utiities), are
parties to a transmission support agreement pursuant to which such utilities
have agreed to pay MEPCO's costs, based on their relative system peaks, if
MEPCO's revenues from transmission services are not sufficient to meet its
expenses.
Information relating to the operations and financial position of Maine Yankee
and MEPCO appears at the bottom of page 40.
WYMAN 4 The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman No. 4
unit. The Company's proportionate share of the direct expenses of this unit
is included in the corresponding operating expenses in the Statements of
Income. Included in the Company's utility plant are the following amounts
with respect to this unit:
1993 1992 1991
----------- ----------- -----------
Electric plant in service $16,767,909 $16,760,816 $16,642,989
Accumulated depreciation (7,539,591) (7,025,278) (6,512,562)
----------- ----------- -----------
$ 9,228,318 $ 9,735,538 $10,130,427
=========== =========== ===========
NEPOOL/HYDRO-QUEBEC PROJECT The Company is a 1.6% participant in the
NEPOOL/Hydro-Quebec Phase 1 project ("Phase 1"), a 690 MW DC intertie between
the New England utilities and Hydro-Quebec constructed by a subsidiary of
another New England utility at a cost of about $140 million. The participants
receive their respective share of savings from energy transactions with
Hydro-Quebec, and are obliged to pay for their respective shares of the costs
of ownership and operation whether or not any savings are realized.
The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2
project ("Phase 2"), which involves an increase to the capacity of the Phase
1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a
share of the anticipated energy cost savings derived from purchases from
Hydro-Quebec and capacity benefits provided by the intertie and is required
to pay its share of the costs of ownership and operation whether or not any
savings are obtained.
MAINE YANKEE
(Dollars in Thousands)
--------------------------------------------------------
1993 1992 1991
---- ---- ----
OPERATIONS:
As reported by investee -
Operating Revenue $193,102 $187,259 $166,471
----------------------------
Depreciation $ 25,458 $ 24,462 $ 23,729
Interest and Preferred Dividends 14,407 14,092 16,015
Other expenses, net 145,861 140,311 118,358
----------------------------
Operating expenses $185,726 $178,865 $158,102
----------------------------
Earnings Applicable
to Common Stock $ 7,376 $ 8,394 $ 8,369
============================
Amounts Reported by the Company -
Purchased power costs $ 11,265 $10,830 $ 9,416
Equity in net income (542) (592) (581)
---------------------------
Net purchased power expense $ 10,723 $10,238 $ 8,835
============================
FINANCIAL POSITION:
As reported by investee -
Plant in service $396,133 $384,664 $368,952
Accumulated depreciation (175,996) (163,887) (149,625)
Other assets 314,680 300,416 267,554
-----------------------------
Total assets $534,817 $521,193 $486,881
Less -
Preferred stock 19,800 21,000 6,600
Long-term debt 115,333 110,390 124,633
Other liabilities and
deferred credits 332,030 322,900 287,734
----------------------------
Net assets $ 67,654 $ 67,503 $ 67,914
============================
Company's reported equity -
Equity in net assets $ 4,736 $ 4,725 $ 4,754
Adjust Company's
estimate to actual 20 11 (16)
----------------------------
Equity in net assets as reported $ 4,756 $ 4,736 $ 4,738
============================
MEPCO
(Dollars in Thousands)
--------------------------------------------------------
1993 1992 1991
---- ---- ----
OPERATIONS:
As reported by investee -
Operating Revenue $ 12,809 $ 11,608 $ 14,918
----------------------------
Depreciation $ 1,395 1,250 1,231
Interest and Preferred Dividends 124 186 336
Other expenses, net 11,185 10,067 13,246
----------------------------
Operating expenses $ 12,704 $ 11,503 $ 14,813
----------------------------
Earnings Applicable to Common Stock $ 105 $ 105 $ 105
=============================
Amounts Reported by the Company -
Purchased power costs $ - $ - $ -
Equity in net income (15) (15) (15)
----------------------------
Net purchased power expense $ (15) (15) (15)
=============================
FINANCIAL POSITION:
As reported by investee -
Plant in service $ 23,123 $ 22,915 $ 22,775
Accumulated depreciation (19,174) (17,891) (16,841)
Other assets 2,414 1,815 4,281
-----------------------------
Total assets $ 6,363 6,839 10,215
Less -
Preferred stock - - -
Long-term debt 2,590 3,450 4,310
Other liabilities and
deferred credits 2,895 2,511 5,026
-----------------------------
Net assets $ 878 $ 878 $ 879
=============================
Company's reported equity -
Equity in net assets $ 125 $ 125 $ 125
Adjust Company's
estimate to actual - - -
-----------------------------
Equity in net assets $ 125 $ 125 $ 125
as reported =============================
In 1990, the Company formed Bangor Var Co., Inc. whose sole function is to be
a 50% general partner in the Chester SVC Partnership ("Chester"), a
partnership which owns the static var compensator ("SVC"), which is
electrical equipment that supports the Phase 2 transmission line. A
wholly-owned subsidiary of Central Maine Power Company owns the other 50%
interest in Chester. Chester has financed the acquisition and construction of
the SVC through the issuance of $33 million in principal amount of 10.48%
senior notes due 2020, and up to $3.25 million principal amount of additional
notes due 2020 (collectively, the "SVC Notes"). The holders of the SVC Notes
are without recourse against the partners or their parent companies and may
only look to Chester and to the collateral for payment.
The New England utilities which participate in Phase 2 have agreed under a
FERC-approved contract to bear the cost of Chester, on a cost of service
basis, which includes a return on and of all capital costs.
SMALL POWER PRODUCTION FACILITIES As of the beginning of 1993, the Company
had contracts with ten independent, non-utility power producers known as
"small power production facilities." The West Enfield Project, described
below, is one such facility. There are five other relatively small
hydroelectic facilities. The remainder are larger (15-25 MW) facilities,
three fueled by biomass (primarily wood chips) and one by municipal solid
waste. The cost of power from the small power production facilities is more
than the Company would incur if it were not obligated under these contracts,
and, in the case of the biomass and solid waste plants, substantially more.
The prices were negotiated at a time when oil prices were much higher than at
present, and when forecasts for the costs of the Company's long-term power
supply were higher than current forecasts. In the Company's 1987 rate
proceeding, the MPUC investigated the events surrounding the contract
negotiations but reached no conclusion about the Company's prudence in
entering into these contracts. The fuel cost adjustment approved by the MPUC
effective November 1, 1993 includes projected costs for small power
production facilities.
In order to lower the overall cost of power to its customers, the Company
negotiated an agreement to cancel its long-term purchased power agreement
with one of the biomass plants, the Beaver Wood Joint Venture ("Beaver
Wood"), in June 1993. In connection with the cancellation the Company paid
Beaver Wood $24 million in cash and issued a new series of 12.25% First
Mortgage Bonds due July 15, 2001 to the holders of Beaver Wood's debt in the
amount of $14.3 million in substitution for Beaver Wood's previously
outstanding 12.25% Secured Notes. Also, in connection with the cancellation
agreement, a reconstituted Beaver Wood partnership paid the Company $1
million at the time of settling the transaction and has agreed to pay the
Company $1 million annually for the next six years in return for retaining
the ownership and the option of operating the plant. The payments are secured
by a mortgage on the property of the Beaver Wood facility. The Company
believes this contract buyout transaction will result in significant savings
to its customers compared to the continuation of payments under the purchased
power contract.
In May 1993 the Company received an accounting order from the MPUC related to
the purchased power contract buyout. The order stipulated that the Company
may seek recovery of the costs associated with the buyout in a future base
rate case, and could also record carrying costs on the deferred balance.
Consequently, a regulatory asset of $40.3 million has been recorded as of
December 31, 1993. Effective with the implementation of new base rates on
March 1, 1994, the Company will begin recovering over a nine-year period the
deferred balance, net of the $6 million anticipated from Beaver Wood.
The agreements with the other two biomass plants, located in the Company's
service territory in West Enfield and Jonesboro, are also long-term (30-year)
contracts. The West Enfield and Jonesboro facilities, plants of 24.5 MW each
constructed by the same developer, commenced operation in November 1987. The
Company has contracted to resell a portion of the capacity from these two
projects to another utility. The cost to the Company of these contracts (net
of revenues from the foregoing resale) is approximately $26 million annually.
The Company also has a 30-year contract with the municipal solid waste
facility, a 20 MW waste-to-energy plant in the Company's service territory in
Orrington, completed in 1988. The Company has also contracted to resell a
portion of the capacity for fifteen years from this facility to the other
utility referred to earlier. The cost to the Company of the power delivered
by this facility (net of revenues from the foregoing resale) is projected to
be $14 million annally.
WEST ENFIELD PROJECT In 1986, the Company entered into a joint venture with
a development subsidiary of Pacific Lighting Corporation for the purpose of
financing and constructing the redevelopment of an old 3.8 MW hydroelectric
plant which the Company owned on the Penobscot River in Enfield and Howland,
Maine, into a 13 MW facility (the "West Enfield Project") for the purpose of
operating the facility once it was completed. Commercial operation of the
redeveloped project began in April 1988. A wholly-owned corporate subsidiary,
Penobscot Hydro Co., Inc. ("PHC") was formed to own the Company's 50%
interest in the joint venture, Bangor-Pacific Hydro Associates ("Bangor
Pacific").
Bangor-Pacific financed the $45 million estimated cost of the redevelopment
through the issuance in a privately placed transaction of $40 million of
fixed rate term notes and a commitment for up to $5 million of floating rate
notes. The notes are secured by a mortgage on the project and a security
interest in a 50-year purchased power contract, and the revenues expected
thereunder, between the Company and Bangor-Pacific. Except as described
below, the holders of the notes issued by Bangor-Pacific are without recourse
to the joint venture partners or their parent companies.
In the event Bangor-Pacific fails to pay when due amounts payable pursuant to
the loan agreement, each partner has agreed to make capital contributions to
Bangor-Pacific in an amount equal to 50% of such amounts due and payable, but
not exceeding an amount equal to distributions from Bangor-Pacific received
by such partner in the preceding twelve-month period. The Company is obliged
to provide funds necessary to support the foregoing limited financial
commitment to the project undertaken by PHC as the partner.
Under the purchased power contract, if the project operates as anticipated,
payments by the Company to Bangor-Pacific are estimated to be about $7.5
million annually (without consideration of any distributions by the joint
venture to the partners). It is possible that the Company would be required
to make payments under the contract regardless of whether any power is
delivered, in an amount of approximately $4 million per year. However, the
Company has the right to terminate the contract if the failure to deliver
power continues for a period of 12 consecutive months.
The fuel cost adjustment approved by the MPUC effective November 1, 1993,
includes projected costs for power delivered to the Company by Bangor
Pacific.
BASIN MILLS AND VEAZIE PROJECTS As a result of increased uncertainty
(discussed below) about the recoverability of amounts invested through 1993
in licensing activities for proposed additional hydroelectric facilities, the
Company established a reserve against those investments in the amount of $8.7
million as of December 31, 1993. Further, the Company plans to expense all
future amounts related to these licensing activities. The projects for which
the reserve has been established are a proposed 38 megawatt generating
facility located at the so-called Basin Mills site on the Penobscot River at
Orono and Bradley, Maine and an 8 megawatt addition to the Company's existing
dam and power station on the Penobscot River in Veazie and Eddington, Maine.
The projects would require a total investment of $140 million. The Company
has been pursuing the permitting of these facilities since the early 1980's.
In November 1993 the Maine Board of Environmental Protection ("BEP") approved
the projects under State environmental laws and issued the water quality
certificate required by the Federal Clean Water Act. The BEP's order is
subject to a number of conditions, some of which could prove to be costly if
the projects are developed. The BEP's decision is being appealed by the
projects' opponents, and the Company cannot predict the outcome of these
proceedings.
If the projects continue, further significant licensing activities can be
expected at the FERC, the U.S. Army Corps of Engineers, the MPUC, the BEP and
possibly other agencies. The Company cannot predict the outcome of the
licensing and permitting activities that are required in order for these
projects to be constructed.
In addition to the Company's inability to predict the outcome of the
requisite licensing activities, other uncertainties have arisen as a result
of changes that have developed and are continuing to develop in the electric
utility industry. In general, these changes are occurring as a result of the
infusion of competition into the industry. As a consequence, even if these
projects continue to be the least-cost alternatives for power supply, the
increasing concern about the impact of competition raises uncertainty about
the timely recovery of the investment required to construct the projects.
Accordingly, although the projects are not being abandoned and licensing
activities are continuing, there is now less certainty that they will be
constructed or that the costs for the completed projects could be recovered.
The Company also believes that the recoverability of the costs incurred to
date is subject to increasing uncertainty. Under Maine law and regulation,
the MPUC can authorize the recovery of prudently incurred utility investment
in abandoned or cancelled projects. However, under current MPUC policy,
recovery of plant investment cannot begin until either it becomes operational
or it is abandoned or cancelled. Since neither of these events has occurred
and since the Company cannot predict when either of them might occur, it is
impossible to forecast when a final regulatory decision on the recoverability
of these costs might be made. Moreover, given the concerns about
competitiveness described above, at the time when recovery of those costs
might be requested, the Company would likely take into consideration the
impact of the inclusion of those costs in its rates, and could conclude that
it would not be in the Company's best interests to pursue cost recovery.
NOTE 8. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST
The Company was a participant in he Seabrook nuclear project in Seabrook, New
Hampshire. On December 31, 1984, the Company had almost $87 million invested
in Seabrook, but because the uncertainties arising out of the Seabrook
Project were having an adverse impact on the Company's financial condition,
an agreement for the sale of Seabrook was reached in mid-1985 and was finally
consummated in November 1986.
During 1985, a comprehensive agreement was negotiated among the Company, the
MPUC staff, and the Maine Public Advocate addressing the recovery through
rates of the Company's investment in Seabrook (the "Seabrook Stipulation").
This negotiated agreement was approved by the MPUC in late 1985. Although the
implementation of the Seabrook Stipulation significantly improved the
Company's financial condition, substantial write-offs were required as a
result of the determination that a portion of the Company's investment in
Seabrook would not be recovered. In addition to the disallowance of certain
Seabrook costs, the Seabrook Stipulation also provided for the recovery
through customer rates of 70% of the Company's year-end 1984 investment in
Seabrook Unit 1 over 30 years, and 60% of the Company's investment in Unit 2
over seven years, with base rate treatment of the unamortized balances. As of
December 31, 1992, the Company's investment in Seabrook Unit 2 was fully
amortized.
NOTE 9. CONTINGENCIES
BANKRUPTCY OF LARGEST CUSTOMER LCP filed for protection under Chapter 11 of
the bankruptcy law in July 1991. At the time of the bankruptcy filing, LCP
owed $719,642 for electric service, for which the Company has a general,
unsecured claim. In addition, LCP is seeking to recover from the Company
certain payments for electric service made prior to the filing as preference
payments under the bankruptcy law. Since the filing, pursuant to arrangements
approved by the Bankruptcy Court, LCP must pay for service weekly in arrears
and the Company may curtail deliveries of power three days after the
presentation of a weekly bill. Furthermore, the Company has been permitted to
collect a deposit to secure the value of approximately one week of service.
As a result, the LCP account for service rendered after the date for
bankruptcy filing is current.
ENVIRONMENTAL MATTERS The Company has received a notice of potential
liability under the Comprehensive Environmental Response, Compensation, and
Liability Act as a generator of hazardous substances that the United States
Environmental Protection Agency alleges may have been disposed of at a waste
disposal facility in Connecticut. The Company is only one of several hundreds
of potentially responsible parties at the site.
The Company has received a notice from the Maine Department of Environmental
Protection under similar Maine legislation relating to several facilities in
Maine. The Company is not yet aware of the extent of potential clean-up
necessary or the number of potentially responsible parties involved.
In management's opinion, the resolution of these matters are not expected to
have a material adverse impact on the Company's financial condition.
NOTE 10. UNAUDITED QUARTERLY FINANCIAL DATA
Unaudited quarterly financial data pertaining to the results of operations
are shown below:
Quarter Ended
--------- --------- --------- --------
March 31 June 30 Sept. 30 Dec.31
--------- --------- --------- -------
(Dollars in thousands except per share amounts)
1993
----
Electric Operating Revenue $46,679 $40,548 $43,476 $ 44,269
Operating Income 4,779 4,486 4,396 3,138
Net Income (Loss) 2,908 2,766 3,244 (3,582)*
Earnings (Loss) Per Share of
Common Stock $ .46 $ .42 $ .46 $(.64)*
======= ======== ======== ========
1992
----
Electric Operating Revenue $48,013 $39,722 $41,877 $ 47,177
Operating Income 4,472 4,370 5,050 4,624
Net Income 2,555 2,224 2,885 2,591
Earnings Per Share of Common Stock $ .40 $ .34 $ .46 $ .40
======== ======== ======== =========
1991
----
Electric Operating Revenue $44,142 $35,256 $37,966 $44,879
Operating Income 4,526 3,500 4,119 4,300
Net Income 2,275 1,462 2,068 2,394
Earnings Per Share of Common Stock $ .42 $ .23 $ .31 $ .37
========= ======== ======== ========
* Includes the provision for Basin Mills of $5.7 million after-tax or $.95
per common share.
NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at
December 31, 1993 of each class of financial instruments for which it is
practical to estimate the value:
Cash and cash equivalents:
The carrying amount of $2,387,156 approximates fair value.
The fair values of mandatory redeemable cumulative preferred stock, first
mortgage bonds and pollution control revenue bonds at December 31, 1993 based
upon similar issues of comparable companies are as follows:
In Thousands
-------------------
Carrying Fair
Amount Value
-------------------
Mandatory redeemable cumulative preferred stock $ 15,168 $ 16,022
First Mortgage Bonds 116,223 137,735
Pollution Control Revenue Bonds 4,200 4,200
===================
REPORT OF INDEPENDENT ACCOUNTANTS
In connection with our audits of the consolidated financial statements of
Bangor Hydro-Electric Company and subsidiaries as of December 31, 1993 and
1992, and for each of the three years in the period ended December 31, 1993,
which financial statements are included in Item 5 of this Current Report on
Form 8-K, we have also audited the financial statement schedules listed in
Item 5 herein.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to include
therein.
COOPERS & LYBRAND
Portland, Maine
February 17, 1994
<TABLE>
Property, Plant and Equipment SCHEDULE V
and Construction in Progress
_____________________________________
<CAPTION>
Retirements
Balance Charged to
Beginning Additions Reserve for Balance
1993 of Year at Cost Depreciation Transfers End of Year
---- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Plant in Service
Intangibles -
Organization $ 30,570 $ - $ - $ - $ 30,570
Franchises and Consents 156,240 - - 18,197 174,437
Miscellaneous Intangible Plant - - - 54,701 54,701
Other 24,489 - - - 24,489
Production Plant -
Steam 26,550,454 - - 481,202 27,031,656
Hydro-Electric 20,643,892 - 16,045 6,869,037 27,496,884
Internal Combustion 3,161,957 - 1,307 61,333 3,221,983
Transmission Property 32,628,715 - 260,928 2,303,920 34,671,707
Distribution Property 125,116,852 - 782,749 10,608,078 134,942,181
General Property 19,291,687 - 555,211 3,737,437 22,473,913
------------ ------------ ------------- ------------
Total Plant in Service $227,604,856 $ - $ 1,616,240 $ 24,133,905 $250,122,521
------------ ------------ ------------- ------------ ----------
Construction in Progress 23,135,871 27,600,029 - (24,133,905) 26,601,995
------------ ------------ ------------- ------------ ----------
$250,740,727 $ 27,600,029 $ 1,616,240 $ - $276,724,516
============ ============ ============= ============ ==========
1992
----
Plant in Service
Intangibles -
Organization $ 30,570 $ - $ - $ - $ 30,570
Franchises and Consents 96,691 - - 59,549 156,240
Miscellaneous Intangible Plant - - - - -
Other 24,489 - - - 24,489
Production Plant -
Steam 28,034,321 - 1,561,806 77,939 26,550,454
Hydro-Electric 20,131,657 - 40,280 552,515 20,643,892
Internal Combustion 3,171,499 - 50 (9,492) 3,161,957
Transmission Property 25,975,090 - 135,716 6,789,341 32,628,715
Distribution Property 112,814,182 - 581,192 12,883,862 125,116,852
General Property 17,101,612 - 674,443 2,864,518 19,291,687
------------ ------------ ------------ ------------ ----------
Total Plant in Service $207,380,111 $ - $ 2,993,487 $ 23,218,232 $227,604,856
Construction in Progress 19,836,348 26,517,755 - (23,218,232) 23,135,871
------------ ------------ ------------ ------------ ----------
$227,216,459 $ 26,517,755 $ 2,993,487 $ - $250,740,727
============ ============ ============ ============ ==========
1991
----
Plant in Service
Intangibles -
Organization $ 30,570 $ - $ - $ - $ 30,570
Franchises and Consents 96,691 - - - 96,691
Miscellaneous Intangible Plant - - - - -
Other 24,489 - - - 24,489
Production Plant -
Steam 27,789,172 - 115,159 360,308 28,034,321
Hydro-Electric 19,054,235 - 15,515 1,092,937 20,131,657
Internal Combustion 2,982,826 - 36,845 225,518 3,171,499
Transmission Property 23,492,607 - 93,127 2,575,610 25,975,090
Distribution Property 99,413,512 - 616,702 14,017,372 112,814,182
General Property 15,997,392 - 407,637 1,511,857 17,101,612
------------ ------------ ------------ ------------ ----------
Total Plant in Service $188,881,494 $ - $ 1,284,985 $ 19,783,602 $207,380,111
Construction in Progress 16,008,191 23,611,759 - (19,783,602) 19,836,348
------------ ------------ ------------ ------------ ----------
$204,889,685 $ 23,611,759 $ 1,284,985 $ - $227,216,459
============ ============ ============ ============ ==========
</TABLE>
SCHEDULE VI
Accumulated Depreciation and Amortization
of Property, Plant and Equipment
-----------------------------------------
1993 1992 1991
------- ------- -------
Balance Beginning of Period $ 67,644,554 $ 66,110,526 $ 63,330,104
Additions:
Provisions Charged to Income $ 4,747,491 $ 4,122,446 $ 3,787,636
Salvage 402,182 321,180 273,756
Other 325,237 480,381 307,234
------------ ------------ -----------
$ 73,119,464 $ 71,034,533 $67,698,730
Deductions:
Property Retirements $ 1,616,240 $ 2,993,487 $ 1,284,985
Removal Costs 319,638 396,492 303,219
------------ ------------ -----------
Balance at End of Period $ 71,183,586 $ 67,644,554 $66,110,526
============ ============ ===========
<TABLE>
SCHEDULE VIII
RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
--------------------------------------------
<CAPTION>
Additions
------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
--------- --------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
1993
Reserve for Doubtful Accounts $1,450,000 $ 590,813 $ 142,097 $ 732,910 $1,450,000
--------- --------- -------- --------- ---------
Reserve for Retirees' Life Insurance $ 612,000 $ 92,000 $ - $ 4,000 $ 700,000
--------- --------- -------- --------- ---------
1992
Reserve for Doubtful Accounts $ 950,000 $1,214,568 $ 128,187 $ 842,755 $1,450,000
--------- --------- -------- --------- ---------
Reserve for Retirees' Life Insurance $ 532,000 $ 112,000 $ - $ 32,000 $ 612,000
-------- --------- -------- --------- ---------
1991
Reserve for Doubtful Accounts $ 950,000 $ 640,344 $ 151,585 $ 791,929 $ 950,000
--------- --------- --------- --------- ---------
Reserve for Retirees' Life Insurance $ 524,000 $ 28,000 $ - $ 20,000 $ 532,000
-------- --------- --------- --------- ---------
</TABLE>
