SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR SECTION
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended September 30, 2001 Commission File No. 0-505
----------------- -----
BANGOR HYDRO-ELECTRIC COMPANY
-----------------------------
(Exact Name of Registrant as specified in its Charter)
Maine 01-0024370
----- ----------
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
33 State Street, Bangor, Maine 04401
------------------------------ -----
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, including Area Code 207-945-5621
------------
None
----
Former Name, Former Address and Former Fiscal Year,
if Changed Since Last Report
Outstanding Common Stock, $5 Par Value - 7,363,424 Shares
September 30, 2001
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No ____
----
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2001
PART I - FINANCIAL INFORMATION
PAGE
----
Cover Page 1
Index 2
Consolidated Statements of Income 3
Management's Discussion and Analysis of Results of
Operations and Financial Condition 4
Consolidated Balance Sheets - September 30, 2001 and
December 31, 2000 28
Consolidated Statements of Capitalization 30
Consolidated Statements of Cash Flows 31
Consolidated Statements of Common Stock Investment 32
Notes to the Consolidated Financial Statements 33
PART II - OTHER INFORMATION 40
Item 6 - Exhibits and Reports on Form 8-K 41
Signature Page 42
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
000's Omitted Except Per Share Amounts
(Unaudited)
Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2001 2001 2001 2001
----------- ---------- ---------- ----------
Operating Revenues:
Electric operating revenue $ 33,042 $ 34,522 $ 98,664 $ 111,386
Standard offer service 22,528 24,119 67,113 45,939
------------ ----------- -------------- --------------
$ 55,570 $ 58,641 $ 165,777 $ 157,325
------------ ----------- -------------- --------------
Operating Expenses:
Fuel for generation and purchased power $ 9,169 $ 8,494 $ 25,587 $ 34,299
Standard offer service purchased power 22,220 24,074 65,894 45,666
Other operation and maintenance 8,620 9,956 28,848 28,748
Depreciation and amortization 2,404 2,461 7,827 6,831
Amortization of Seabrook nuclear unit 424 424 1,274 1,274
Amortization of contract buyouts
and restructuring 5,640 5,639 16,918 16,672
Amortization of deferred asset sale gain (2,112) (2,095) (5,971) (4,267)
Taxes -
Local property and other 1,173 1,145 3,773 3,742
State Income 410 454 1,156 954
Federal Income 1,523 1,554 3,576 3,912
------------ ----------- ------------ ------------
$ 49,471 $ 52,106 $ 148,882 $ 137,831
------------ ----------- ------------ ------------
Operating Income $ 6,099 $ 6,535 $ 16,895 $ 19,494
------------ ----------- ------------ ------------
Other Income And (Deductions):
Allowance for equity funds used
during construction $ 146 $ 153 $ 465 $ 60
Other, net of applicable income taxes 216 929 814 1,855
------------ ----------- ------------ ------------
Income Before Interest Expense $ 6,461 $ 7,617 $ 18,174 $ 21,409
------------ ----------- ------------ ------------
Interest Expense:
Long-term debt $ 3,276 $ 3,649 $ 10,429 $ 11,588
Other 252 178 723 675
Allowance for borrowed funds used
during construction (129) (150) (423) (71)
------------ ----------- ------------ ------------
$ 3,399 $ 3,677 $ 10,729 $ 12,192
------------ ----------- ------------ ------------
Net Income $ 3,062 $ 3,940 $ 7,445 $ 9,217
Dividends On Preferred Stock 66 66 199 199
------------ ----------- ------------ ------------
Earnings Applicable To Common Stock $ 2,996 $ 3,874 $ 7,246 $ 9,018
============ =========== ============ ============
Weighted Average Number Of Shares Outstanding 7,363 7,363 7,363 7,363
============ =========== ============ ============
Earnings Per Common Share:
Basic $ .41 $ .53 $ .98 $ 1.22
Diluted .37 .46 .89 1.08
============ ============= ============== ==============
Dividends Declared Per Common Share $ .20 $ .20 $ .60 $ .60
============ ============ ============= ==============
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
Management's Discussion and Analysis of the Results of Operations and
Financial Condition (MD&A) contained in Bangor Hydro-Electric Company's (the
Company) Annual Report on Form 10-K for the year ended December 31, 2000
(2000 Form 10-K) should be read in conjunction with the comments below.
EARNINGS
For the quarters ended September 30, 2001 and 2000 basic earnings per
common share were $.41 and $.53, respectively. The largest single item
negatively impacting earnings in the third quarter of 2001 was the
establishment of a reserve ($.13 per common share after tax reduction in
earnings) in connection with potential loss exposure associated with current
regulatory proceedings in which the Company is a party. Also impacting the
comparative quarterly earnings was the recognition of a gain on the sale of a
Company subsidiary in the third quarter of 2000, which resulted in a $.10 per
common share benefit to earnings after taxes. Other items impacting the
quarterly earnings comparisons were as follows: In the third quarter of 2000
the Company incurred expense associated with Maine Public Utilities
Commission (MPUC) regulatory assessments ($.04 per common share after tax
impact), while in 2001 the assessment was incurred in the second quarter. In
the third quarter of 2001, the Company received an accounting order from the
Federal Energy Regulatory Commission allowing the Company to defer previously
incurred expenses associated with the Company's involvement in the
development of a regional transmission organization (RTO) in New England. For
a more complete discussion of the RTO see the section on Important Current
Activities. In the third quarter of 2001 the Company recorded deferred RTO
related costs that were previously charged to operating expenses in 2001
prior to the third quarter resulting in a $.03 per common share after tax
increase in earnings. Further enhancing earnings in the 2001 quarter as
compared to 2000 was a reduction in the 2001 quarter of ISO New England costs
associated with transmission constraints ($.04 per common share after tax
increase in earnings).
IMPORTANT CURRENT ACTIVITIES
MERGER WITH EMERA - In early October 2001, final regulatory approvals for the
merger between the Company and Emera, Inc. were received. On October 10,
2001, Emera completed the acquisition of all of the outstanding common stock
of the Company for US$26.806 per share in cash. The purchase increases
Emera's customer base by 25% and broadens the Company's presence in the
expanding northeast energy market. Emera also owns Nova Scotia Power, a
fully integrated electric utility that supplies substantially all of the
generation, transmission and distribution of electricity in Nova Scotia; and
has an interest in the Maritimes & Northeast Pipeline, which transports Sable
natural gas through Maine to Boston.
In connection with the closing of the merger, the Company incurred
certain expenses in October 2001, prior to the closing of the merger,
amounting to approximately $3.7 million.
REGIONAL TRANSMISSION ORGANIZATION - On December 20, 1999, FERC issued Order
No. 2000, requiring each FERC regulated transmission utility to file a plan
regarding the transfer of control of its transmission assets to an RTO. The
ostensive purpose of this order is to improve the operation of energy markets
in the United States. Since that time, the Company has been actively
involved in a process with the other transmission owning utilities in New
England, ISO New England and other interested parties to form such an
organization.
On January 16, 2001, the Company participated in a joint filing with ISO
New England and six New England transmission companies proposing the creation
of a two party or "binary" RTO for the New England region. The first party,
ISO New England, would be primarily responsible for wholesale pricing markets
and short term reliability, and the second, a to-be-created Northeast
Independent Transmission Company, would play a lead role in transmission
planning, operation and administration.
Under the proposal, the New England Power Pool, currently composed of
transmitters, power generators, consumer groups and state regulators, would
have a modified role in making rules for the electricity market. Also, under
the proposal, steps would be taken to ensure power flowed freely between New
England and New York and that the market conditions and rules be similar.
On July 12, 2001, the FERC issued an order denying RTO status for the
proposed New England organization. The primary basis for the denial was
insufficient geographic scope. As part of that order, and as part of
simultaneously issued orders with respect to proposals in New York and the
mid-Atlantic states, FERC has required the Company to engage in a mediated
process to form a single regional transmission organization for the entire
northeastern United States. The Company cannot predict what the final
outcome of that process will be or what the potential impacts of a larger
regional transmission organization would be on the Company.
ALTERNATIVE RATE PLAN FILING - On October 12, 2001, the Company filed a
proposal with the MPUC for an alternative rate plan (ARP) that would reduce
the overall costs for electricity service for most customers by approximately
10% (or about $8 per month) for a typical residential customer assuming the
plan is implemented on March 1, 2002. This plan would also provide rate
stability for four years.
The ARP would accomplish this cost reduction by combining the expected
increases in delivery service rates with reductions in the price of the
standard offer service already announced by the MPUC. In addition to delivery
service rates, the Company's ARP proposal includes incentives to improve the
efficiency and the service quality of power delivery services to Bangor
Hydro's customers.
As an alternative to this innovative ARP, the Company has also filed
notice of a traditional delivery service rate increase to be implemented by
October 1, 2002. If pursued by the MPUC, this more conventional approach
would result in higher delivery service rates which, when combined with the
announced standard offer price decrease, would result in a reduction in the
overall cost for most customers of approximately 8% or $7 per month.
Previously the Company had proposed a plan that in addition to delivery
service rates would have included the provision of standard offer service by
the Company for both residential and small and medium business customers -
this would have resulted in an overall cost reduction of approximately 8%.
Though the MPUC order rejected the Company's plan at the time, it also noted
an appreciation of the effort to create an attractive alternative.
Management cannot predict the outcome of the regulatory proceedings
associated with the Company's rate proposals with the MPUC.
REVENUES
With the implementation of competition in the electric utility
industry starting March 1, 2000, and excluding the standard-offer service,
the Company is no longer selling electricity to customers. The Company's
transmission and distribution (T&D) and stranded cost charges to customers,
though, continue to be based on customers' electricity usage measured in
kWh's. Consequently, discussion related to electric operating revenues
continue to have a kWh sales, or hereafter referred to as energy sales
component.
Electric operating revenues, excluding revenues associated with the
standard-offer service decreased by approximately $1.5 million in the third
quarter of 2001. The decrease was principally due to two factors. First, in
the third quarter of 2001 there was a $904,000 decrease in off-system sales,
which are principally sales related to resales of purchased power. Second,
other revenues were reduced in the third quarter of 2001 due to the
establishment of the previously discussed reserve in connection with
potential loss exposure associated with current regulatory proceedings in
which the Company is a party.
Total electric operating revenues, excluding the standard-offer
service, attributable to energy sales were approximately $210,000 higher in
the third quarter of 2001 than in the 2000 quarter. Two large items impacted
the comparability of revenues for the two quarters. Effective July 1, 2001,
the Company entered into a special rate contract with a large industrial
customer to provide fully bundled electric service (both T&D and energy) to
this customer. Formerly, the Company was only providing T&D service to this
customer. The Company has entered into a power purchase contract to procure
the power necessary to serve this customer under this contact. Principally
as a result of the new contract, the Company recognized approximately $1.4
million in greater electric operating revenues associated with this customer
in the third quarter of 2001 as compared to the 2000 quarter. Offsetting
this increase to some extent was the impact of the shutdown of the Company's
formerly largest special contract customer, HoltraChem Manufacturing Company
(HoltraChem) on September 15, 2000. Energy sales and corresponding electric
operating revenues for HoltraChem were 47.3 million kWh's and $548,000 lower,
respectively, in the 2001 quarter as compared to 2000.
Absent the impact of the largest special rate contract customers,
energy sales and corresponding revenues were principally flat in the third
quarter of 2001 as compared to the third quarter of 2000. The Company
experienced warmer weather in the third quarter of 2001 which for the most
part positively impacted sales.
Electric operating revenues associated with the standard-offer
service were approximately $1.6 million, or 7%, lower in the third quarter of
2001 as compared to the third quarter of 2000. As discussed in more detail
in the 2000 Form 10-K, the Company is allowed by the MPUC to defer the
difference between revenues realized from the standard-offer sales and the
costs incurred to provide this service, including carrying costs on the
deferred balance. As a result of this reconciliation mechanism, standard-
offer related revenues and expenses do not have any impact on the Company's
earnings, although they do result in increases in both categories in the
Company's consolidated statements of income. The deferred amount will be
recovered from/returned to customers in the future. The decrease in
standard-offer service revenues is due to a $6 million reduction in revenues
associated with the deferral of the excess of standard-offer service revenues
over standard-offer service expenses, offset by an $4.4 million (54.2%)
increase in revenues attributable to energy sales. The greatest impact on
increased energy sales related revenues in the 2001 quarter was the effect of
various increases in the Company's standard-offer service rates since the
advent of competition in March 2000. These increases were offset to some
extent by a 14.1% reduction in standard-offer related energy sales in the
third quarter of 2001 as compared to the third quarter of 2000, due primarily
to industrial customers no longer taking the standard-offer service.
EXPENSES
Fuel for generation and purchased power expense, excluding the cost
of standard-offer service purchased power, increased by approximately
$675,000 in the third quarter of 2001 as compared to the third quarter of
2000. The single largest item affecting this increase was the previously
discussed new special rate contract with a large industrial customer. In the
third quarter of 2001, the Company incurred $1.1 million of purchased power
expense associated with serving the customer. Further increasing purchased
power expense in the third quarter of 2001 was the establishment of the
previously discussed reserve in connection with potential loss exposure
associated with current regulatory proceedings in which the Company is a
party. Offsetting these increases to some extent was a $560,000 reduction in
the third quarter of 2001 in ISO New England costs associated with
transmission constraints. Also reducing purchased power expense to some
extent in the 2001 quarter was a reduction in costs associated with power
purchases from independent power producers under existing power supply
contracts.
Purchased power expense related to providing the standard-offer service
decreased by approximately $1.9 million in the third quarter of 2001 in
comparison to the 2000 quarter. The decrease was due primarily to the
previously discussed 14% reduction in standard-offer service related energy
sales in the third quarter of 2001.
Other operation and maintenance (O&M) expense decreased by
approximately $1.3 million in the third quarter of 2001 in comparison to the
third quarter of 2000. The decrease is principally a result of two factors.
First, as previously discussed, in the third quarter of 2000 the Company
incurred $525,000 of expense associated with the MPUC regulatory assessments,
while in 2001 the assessment was incurred in the second quarter. Second,
also previously discussed, in the third quarter of 2001, in connection with
an accounting order received from the FERC, the Company recorded deferred RTO
related costs that were previously charged to operating expenses in 2001
prior to the third quarter. This deferral resulted in a $371,000 reduction
in other O&M expense in the third quarter of 2001.
Effective with the March 1, 2000 rate change, the Company began
amortizing the deferred asset sale gain over a 70-month period. The annual
amortization amounts are being recorded in an uneven manner in order to
levelize the Company's revenue requirement over this period. As a result of
an increase in the Company's FERC regulated transmission rates on June 1,
2000, and the desire to not increase rates to its retail customers so close
to the implementation of electric industry restructuring, which occurred on
March 1, 2000, the Company agreed to reduce its MPUC jurisdictional
distribution rates in an amount equal to the increase in its transmission
rates. The reduction in the distribution rates was accomplished by
accelerating the amortization of the deferred asset sale gain through May
2001 by an annualized total of $2.5 million.
Effective April 15, 2001, and through February 28, 2002, in an effort
to mitigate the effects of increased energy prices for the Company's large
customers, the MPUC ordered the Company to reduce its distribution and
stranded cost electric rates to certain large customers by $.008/kWh. To
fund this rate reduction and corresponding decrease in revenues, the MPUC
ordered the Company to accelerate the amortization of the deferred asset sale
gain in an amount necessary to offset the estimated decrease in revenues
caused by the rate reduction. The asset sale gain amortization is expected
to be increased by approximately $2.5 million over the 10 1/2 month period the
reduced rates are in effect. Also, the Company's FERC jurisdictional
transmission rates changed on June 1, 2001. Consistent with 2000, the
Company has proposed to reduce its distribution rates via an adjustment to
the asset sale gain amortization to offset the change in the transmission
rates effective June 1, 2001. The annualized accelerated amortization
associated with the transmission rate change amounts to approximately $1.6
million and ends in May 2002.
The decrease in total federal and state income taxes was principally
a function of lower earnings in the third quarter of 2001 as compared to the
2000 quarter. See Footnote 2 to the Consolidated Financial Statements for a
reconciliation of the Company's effective income tax rate.
OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENS
Allowance for funds used during construction, which includes carrying
costs on certain regulatory assets and liabilities, decreased by $28,000 in
third quarter of 2001 relative to 2000 due principally to reductions in
construction work in progress in the 2001 quarter as compared to 2000. Also
reducing AFDC was the accrual of carrying costs on certain regulatory
liabilities in the third quarter of 2001. Offsetting these increases to some
extent was increased carrying costs being recorded on exercised PERC common
stock warrants.
Other income, net of income taxes, decreased by approximately
$713,000 in the third quarter of 2001. The decreased other income was
primarily a result of the previously discussed $708,000 after-tax gain on the
sale of a wholly-owned subsidiary in the third quarter of 2000.
Long-term debt interest expense decreased $373,000 in the third
quarter of 2001 as compared to 2000 due primarily to a $15.1 million
principal payment on the Company's Finance Authority of Maine (FAME) Revenue
Notes at the end of June 2001 and monthly principal payments on the $24.8
million medium term notes from October 2000 through September 2001 amounting
to approximately $6 million.
Other interest expense increased $74,000 due principally to
borrowings and fees under the Company's revolving credit facility in the
third quarter of 2001. Weighted average borrowings outstanding were
approximately $6.3 million for the quarter ending September 30, 2001. The
Company had no outstanding borrowings in the third quarter of 2000. This was
offset to some extent by a reduction in the amortization of debt issuance
costs in the third quarter of 2001. The amortization decrease was primarily
attributable to the end of the amortization period of certain deferred debt
issuance costs in June 2001.
NINE MONTHS OF 2001 AS COMPARED TO THE NINE MONTHS OF 2000
EARNINGS
For the nine months ended September 30, 2001 and 2000 basic earnings
per common share were $.98 and $1.22, respectively. The earnings comparisons
were impacted by the reasons discussed above for the third quarters of each
year associated with the gain on sale of the subsidiary and the reserve
associated with certain regulatory loss exposure, as well as several other
factors. In 2001 the Company recorded a $615,000 reserve ($.05 reduction in
earnings per common share) associated with adjustments to revenue related to
filings with the New England Power Pool (NEPOOL). Also in 2001, the Company
recorded approximately $318,000 in expense ($.03 reduction in earnings per
common share) related to an increase in a environmental remediation reserve
associated with a waste removal site in which the Company was involved in the
past. For a complete discussion of this site, see the Environmental Matters
section of MD&A.
Offsetting these earnings decreases in 2001 to some extent was an
approximately $1 million (or a $.08 impact on earnings per common share
decrease in incremental merger related costs in 2001 as compared to 2000.
REVENUES
With the implementation of retail competition effective March 1,
2000, comparisons of electric operating revenues for the first nine months of
2001 as compared to the first nine months of 2000 is difficult. Total
electric operating revenues, including standard-offer service, increased by
approximately $8.5 million, or 5.4%, for the first nine months of 2001 as
compared to the 2000 period. Principally as a result of the previously
discussed standard-offer service rate increases in 2000 and 2001, electric
operating revenues attributable to energy sales were approximately $15.6
million higher in the 2001 period. The impact of the increased standard-
offer service rates were offset to some extent by a 9.6% reduction in total
energy sales in 2001, due principally to the previously discussed HoltraChem
shutdown in 2000, and by the approximately 2.9% fully-bundled rate decrease
on March 1, 2000 when electric restructuring was implemented. Energy sales
to the Company's non-large special contract customers increased by 1.1% in
the first nine months of 2001 as compared to the 2000 period.
Other revenues, which decreased by approximately $7.2 million in the
2001 period, were most affected by of a $10.2 million reduction in revenues
associated with the standard-offer service deferral mechanism. In 2001, the
Company's energy sales related to standard-offer revenues were greater than
the associated costs of providing the standard-offer service, and
consequently the Company's recorded reductions in other revenues of
approximately $4.6 million. In the 2000 period, starting March 1, the Company
recorded additional other revenues of approximately $5.7 million as a result
of standard-offer costs exceeding energy sales related standard-offer
revenues. This decrease was offset to some extent by Holtrachem revenue
sharing, which was a $1.1 million reduction in revenues in the 2000 period,
while, as a result of the Holtrachem plant shutdown, there was no revenue
sharing in 2001. Also offsetting the other revenue reductions was an
approximately $850,000 increase in off-system sales. The increase occurred
principally as a result of the fact the Company did not begin to realize
revenues from the Chapter 307 resales of power in 2000 until March 1. A full
nine months of Chapter 307 sales have been recorded in 2001.
EXPENSES
Total fuel for generation and purchased power expense, including the
standard offer, increased approximately $11.5 million in the 2001 period as
compared to 2000. Standard offer purchased power expense for the comparable
periods of March through September of each year were $6.4 million higher in
2001. The increase is due to higher power prices, offset by reductions in
standard offer sales. Also, in connection with the previously discussed new
special rate contract with a large industrial customer, in the third quarter
of 2001, the Company incurred $1.1 million of purchased power expense
associated with serving this customer. Further increasing purchased power
expense in 2001 was the establishment of the previously discussed reserve in
connection with potential regulatory loss exposure. Also increasing
purchased power expense was the recording of a $615,000 reserve associated
with adjustments to revenue related to filings with the NEPOOL.
In the first two months of 2001, purchased power costs were also
higher. The Company purchased significantly more power on the spot power
market as compared to 2000 as a result of the expiration of the power
contracts that had been in place in the 2000 period. Further, the market
prices for power were higher due to higher fuel prices and possibly lack of
sufficient competition in the generation market.
Offsetting these increases to some extent were lower transmission
related costs, including those associated with NEPOOL, in the 2001 period as
compared to 2000. In 2001, the Company realized reduced transmission costs
as a result of the construction of additional qualifying transmission
facilities whose costs are recoverable from the other NEPOOL transmission
owners.
Other O&M expense increased by approximately $100,000 in the first
nine months of 2001 as compared to the first nine months of 2000. The two
items having the largest impact on other O&M expense for the comparable
periods are as follows. In 2000 the Company incurred approximately $1.2
million in costs associated with the Company's proposed merger with Emera.
The Company reclassified these costs to Other Income and (Deductions) in the
fourth quarter of 2000. Incremental merger related costs in 2001 have also
been recorded as a component of Other Income and (Deductions); and the
Company's pension expense was approximately $986,000 greater in 2001 as
compared to 2000 due principally to changes in actuarial assumptions used in
calculating pension expense and the end of the amortization of the transition
pension benefit in 2001.
Depreciation and amortization expense increased by approximately
$996,000 in the 2001 period as compared to 2000 due principally to two
factors, the first being additions to the Company's electric plant in
service. Also increasing depreciation expense was the effect of a
depreciation study conducted in December 1996, which determined that the
Company's reserve for depreciation was overaccumulated by approximately $3.6
million. In connection with the MPUC's rate order in February 1998, the
Company was allowed to amortize this balance over a two-year period, starting
in February 1998. The amortization was increased in June 1999 as a result of
the Company's generation asset sale. See the 2000 Form 10-K for a complete
discussion of this transaction. The amortization recorded as a reduction in
depreciation expense in the first quarter of 2000 amounted to $308,000.
The $246,000 increase in amortization of contract buyouts and
restructuring in the 2001 period was due to changes, effective March 1, 2000
with the implementation of new rates, in the amortization of the deferred
Beaver Wood contract buyout costs and the deferred costs associated with the
June 1998 restructuring of the Penobscot Energy Recovery Company (PERC)
purchased power contract. The Beaver Wood amortization was $141,000 higher in
the first quarter of 2000 and is being amortized at an annual rate of $3.9
million which started March 2000. Prior to the implementation of new rates
in March 2000, the Company was recovering deferred PERC restructuring costs
at an annual rate of $1 million. Effective March 1, 2000, recovery of PERC
restructuring costs was adjusted to include the estimated future value of
warrants to be exercised. The adjusts the annual amortization amount to $1.6
million. For a complete discussion of the Beaver Wood purchased power
contract buyout and the PERC contract restructuring, see the 2000 Form 10-K.
The increase in the amortization of the deferred asset sale gain and
the decrease in the state and federal income tax expense in first nine months
of 2001 as compared to 2000 were each due principally to the same reasons as
discussed previously for the third quarters of 2001 and 2000. Also affecting
state income tax expense for 2001 were the results of an audit by the State
of Maine associated with investment tax credits claimed by the Company in
prior years' income tax returns. The audit resulted in the Company being
assessed for improperly claiming approximately $183,000 of investment tax
credits. The Company is currently involved in litigation with the State of
Maine contesting the audit findings. Management cannot currently predict the
outcome of this litigation.
OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE
Allowance for funds used during construction, which includes carrying
costs on certain regulatory assets and liabilities, increased by $757,000 in
first nine months of 2001 relative to 2000 due mainly to approximately
$467,000 in carrying costs being recorded on the deferred asset sale gain in
2000. The Company also recorded increased carrying costs on exercised PERC
common stock warrants, deferred special rate contract revenues, and deferred
standard-offer service costs in the 2001 period as compared to the 2000
period. Offsetting these increases to some extent was less AFDC associated
with lower levels of construction in the 2001 period.
Other income, net of income taxes decreased by approximately $1
million in the first nine months of 2001 principally as a result of the
previously discussed reason for the third quarters of 2001 and 2000.
Investment income decreased by approximately $358,000 in the 2001 period due
principally to reductions in the Company's available cash balances from the
1999 generation asset sale(see the section on Liquidity and Capital
Resources). Also impacting the decrease in other income in 2001 was
approximately $158,000 of incremental merger related costs being incurred.
LIQUIDITY AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events in the first
nine months of 2001 and 2000 as they affect the Company's liquidity. Net
increase in cash from operating activities was approximately $18 million in
the first nine months of 2001 as compared to $29.8 million in the 2000
period. The largest single item impacting the change in operating cash
flows in the 2001 period was payments made in connection with Company's
common stock warrants. For a more complete discussion of the common stock
warrants, see the 2000 Form 10-K. In 2001, the Company made approximately
$9.2 million in payments to the warrant holders as compared to approximately
$1.8 million in 2000. The decrease in operating cash flows in the first nine
months of 2001 relative to the 2000 period was also negatively affected by
increases in deferred special rate contract revenues. The Company deferred
$2.3 million in 2001 as compared to $1.2 million in 2000 associated with
realizing less revenues from special rate contract customers than the amounts
assumed in the Company's rates which became effective March 1, 2000. Also
cash flows were negatively impacted by the previously discussed $.008/kWh
rate reductions provided to certain large customers. While earnings impacts
of the rate discounts are negated by additional asset sale gain amortization
to offset the rate discounts, cash flows are negatively impacted by providing
the $2.5 million in rate discounts over the 10 1/2 month period the reduced
rates are in effect.
Operating cash flows are also impacted in each period by the
standard-offer service. In 2001, the Company's standard-offer service
revenues exceeded associated costs by approximately $4.6 million, while in
the corresponding 2000 period, the costs exceeded revenues by approximately
$5.7 million. Changes in accounts receivable and accounts payable in the
statement of cash flows are also greatly impacted by the standard-offer
related revenues and purchased power obligations.
Construction expenditures were approximately $536,000 lower in the
2001 period as compared to 2000 due to reductions in the Company's capital
spending program. Positively impacting cash flows from financing activities
in the 2000 period was $1.25 million in proceeds in connection with the
previously discussed sale of a Company subsidiary in July 2000.
The increase in common dividends paid in the first nine months of
2001 was due to an increase in the common dividend from $.15 to $.20 per
share in March 2000.
The increase in payments on long-term debt is due principally to the
higher monthly principal payments on the $24.8 million medium term notes in
the 2001 period relative to 2000, and at the end of June 2001 the Company
made a $15.1 million principal payment on the FAME revenue notes, as compared
to a $14 million principal payment at the end of June 2000.
The Company had maintained full borrowing capacity under its
revolving credit facility, with no new borrowings since early 1999. Without
the cash on hand to fund the required FAME debt payment at the end of June
2001, the Company borrowed $6 million under its short-term credit facilities
at the end of June. The Company's outstanding borrowings under the this
agreement were $6 million at September 30, 2001. On June 29, 2001, the
Company extended the Amended and Restated Revolving Credit Agreement until
October 1, 2001, and on October 1, 2001 the agreement was further extended
until December 31, 2001. As more fully discussed in the 2000 Form 10-K, the
facility provides for a $30 million line of credit. The terms of the
revolver essentially remain the same, however, the zero coupon first mortgage
bonds, which also expired on June 29, 2001 and provided collateral to the
banks involved in the facility, were not extended along with the facility.
In addition, the Company entered into a unsecured working capital line of
credit of $10 million. Borrowings under the $10 million line of credit are
priced in the same manner as the revolver credit line. Under the current
projections of cash needs, the new facilities should provide adequate
borrowing capacity until a longer term financing structure is implemented.
The Company was in compliance with all financial covenants as of September
30, 2001. For additional discussion of liquidity and capital resources, see
the Company's 2000 Form 10-K.
ENVIRONMENTAL MATTERS
The Company is regulated by the United States Environmental
Protection Agency (EPA) as to compliance with the Federal Water Pollution
Control Act, the Clean Air Act, and several federal statutes governing the
treatment and disposal of hazardous wastes. The Company is also regulated by
the Maine Department of Environmental Protection (DEP) under various Maine
environmental statutes. The Company is actively engaged in complying with
these federal and state acts and statutes, and it has not, to date,
encountered material difficulties in connection with such compliance.
In 1992, the Company received notice from the DEP that it was
investigating the cleanup of several sites in Maine that were used in the
past for the disposal of waste oil and other hazardous substances, and that
the Company, as a generator of waste oil that was disposed at those sites,
may be liable for certain cleanup costs. The Company learned in October 1995
that the EPA placed one of those sites on the National Priorities List under
the Comprehensive Environmental Response, Compensation and Liability Act and
would pursue potentially responsible parties. With respect to this site, the
Company is one of a number of waste generators under investigation.
The Company has recorded a liability, based on currently available
information, for what it believes are the estimated future environmental
cleanup costs that the Company expects to incur for this waste disposal site.
At September 30, 2001, the liability recorded by the Company for its
estimated environmental remediation costs amounted to approximately $435,000.
The Company's actual future environmental remediation costs may be different
as additional factors become known.
The Company estimates that during 2001 it will incur approximately
$248,000 in operations expense to comply with environmental standards for
air, water and hazardous materials. This amount may change based on facts
and circumstances that occur in 2001.
DISCLOSURES ABOUT MARKET RISK
The Company's major financial market risk exposure is changing interest
rates. Changes in interest rates will affect interest paid on variable rate
debt and the fair value of fixed rate debt. The Company manages interest
rate risk through a combination of both fixed and variable rate debt
instruments and an interest rate swap, which is associated with the Company's
medium term notes (See Note 14 to the 2000 Form 10-K). As of September 30,
2001, the Company had $7.1 million of medium term notes outstanding which
bear floating, LIBOR-based rates (2.63% LIBO rate at September 30, 2001).
The interest rate swap fixes the interest rate on the medium term notes at
5.72% for the full notional amount of the debt. See Note 4 to the 2000 Form
10-K for a discussion of these medium term notes.
NEW ACCOUNTING PRONOUNCEMENTS
On July 20, 2001 the Financial Accounting Standards Board (FASB) issued
Statement No. 141, "Business Combinations", and Statement No. 142, "Goodwill
and Other Intangible Assets". Use of the pooling-of-interests method is no
longer permitted. Statement 141 requires that the purchase method be used for
business combinations initiated after June 30, 2001. Statement 142 requires
that goodwill no longer be amortized to earnings, but instead be reviewed for
impairment. The amortization of goodwill ceases upon adoption of the
Statement, which for the Company, will be January 1, 2002.
The issuance of these two statements will impact Emera's accounting for
its acquisition of the Company when the merger transaction is completed in
the fourth quarter of 2001. Management is currently examining the impact of
the adoption of this standard on the Company. However, the goodwill recorded
in connection with the merger with Emera will not be amortized.
At the end of June 2001 the FASB issued Statement No. 143, "Accounting
for Asset Retirement Obligations". This standard will require entities to
record the fair value of a liability for an asset retirement obligation in
the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of
the related long-lived asset. Over time, the liability is accreted to its
present value each period, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain
or loss upon settlement.
This standard is effective for fiscal years beginning after June 15,
2002. The Company has not yet determined the potential impact of this
statement.
OTHER
Management's discussion and analysis of results of operations and
financial condition contains items that are "forward-looking" as defined in
the Private Securities Litigation Reform Act of 1995. These statements are
subject to certain risks and uncertainties that could cause actual results to
differ materially from those anticipated in the forward-looking statements.
Readers should not place undue reliance on forward-looking statements, which
reflect management's view only as of the date hereof. The Company undertakes
no obligation to publicly revise these forward-looking statements to reflect
subsequent events or circumstances. Factors that might cause such differences
include, but are not limited to, the Company's proposed merger with Emera,
future economic conditions, relationships with lenders, earnings retention
and dividend payout policies, electric utility restructuring, developments in
the legislative, regulatory and competitive environments in which the Company
operates, environmental issues and other circumstances that could affect
revenues and costs.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
000's Omitted
(Unaudited)
Sept. 30, Dec. 31,
Assets 2001 2000
--------- ---------
Investment In Utility Plant:
Electric plant in service, at original cost $ 322,669 $ 316,167
Less - Accumulated depreciation and amortization 92,287 86,684
---------- ----------
$ 230,382 $ 229,483
Construction work in progress 7,606 5,458
---------- ----------
$ 237,988 $ 234,941
Investments in corporate joint ventures:
Maine Yankee Atomic Power Company $ 5,056 $ 4,950
Maine Electric Power Company, Inc. 861 672
---------- ----------
$ 243,905 $ 240,563
---------- ----------
Other Investments, at cost $ 3,368 $ 3,175
---------- ----------
Funds held by trustee, at cost $ 23,042 $ 22,696
---------- ----------
Current Assets:
Cash and cash equivalents $ 1,448 $ 12,463
Accounts receivable, net of reserve
$961 in 2001 and $761 in 2000 20,932 21,732
Unbilled revenue receivable 15,280 15,779
Inventories, at average cost:
Material and supplies 2,599 2,585
Fuel oil 66 94
Prepaid expenses 334 829
---------- ----------
Total current assets $ 40,659 $ 53,482
---------- ----------
Regulatory Assets and Deferred Charges:
Investment in Seabrook nuclear project, net of
accumulated amortization of $34,845 in 2001
and $33,571 in 2000 $ 23,997 $ 25,271
Costs to terminate/restructure purchased power
contracts, net of accumulated amortization
of $140,090 in 2001 and $123,172 in 2000 88,770 99,312
Maine Yankee decommissioning costs 38,384 43,028
Above-market purchased power contract obligations 74,135 -
Other regulatory assets 35,167 41,025
Other deferred charges 3,976 3,668
---------- ----------
Total regulatory assets and deferred charges $ 264,429 $ 212,304
---------- ----------
Total Assets $ 575,403 $ 532,220
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
000's Omitted
(Unaudited)
Sept. 30, Dec. 31,
Stockholders' Investment and Liabilities 2001 2000
--------- ---------
Capitalization:
Common stock investment $ 136,154 $ 137,420
Preferred stock 4,734 4,734
Long-term debt, net of current portion 140,417 161,960
---------- ----------
Total capitalization $ 281,305 $ 304,114
---------- ----------
Current Liabilities:
Notes payable - banks $ 6,000 $ -
---------- ----------
Other current liabilities -
Current portion of long-term debt $ 23,184 $ 21,340
Accounts payable 22,111 24,785
Dividends payable 1,539 1,539
Accrued interest 3,366 2,529
Customers' deposits 574 502
Current income taxes payable 3,629 306
---------- ----------
Total other current liabilities $ 54,403 $ 51,001
---------- ----------
Total current liabilities $ 60,403 $ 51,001
---------- ----------
Commitments and Contingencies
Regulatory and Other Long-term Liabilities:
Deferred income taxes - Seabrook $ 12,445 $ 13,109
Other accumulated deferred income taxes 52,259 58,314
Maine Yankee decommissioning liability 38,384 43,028
Deferred gain on asset sale 16,674 22,789
Above-market purchased power contract obligations 74,135 12,556
Other regulatory liabilities 11,145 -
Unamortized investment tax credits 1,347 1,452
Accrued pension and postretirement benefit costs 14,307 12,124
Other long-term liabilities 12,999 13,733
---------- ----------
Total regulatory and other long-term liabilities $ 233,695 $ 177,105
---------- ----------
Total Stockholders' Investment and Liabilities $ 575,403 $ 532,220
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
000's Omitted
(Unaudited)
Sept. 30, Dec. 31,
2001 2000
--------- ---------
Common Stock Investment
Common stock, par value $5 per share- $ 36,817 $ 36,817
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares in 2001 and 2000
Amounts paid in excess of par value 54,618 58,643
Accumulated other comprehensive loss (69) -
Retained earnings 44,788 41,960
---------- ---------
Total common stock investment $ 136,154 $ 137,420
---------- ----------
Preferred Stock
Non-participating, cumulative, par value $100 per share,
authorized 600,000 shares, not redeemable or
redeemable solely at the option of the issuer-
7%, Noncallable, 25,000 shares
authorized and outstanding $ 2,500 $ 2,500
4.25%, Callable at $100, 4,840 shares
authorized and outstanding 484 484
4%, Series A, Callable at $110, 17,500 shares
authorized and outstanding 1,750 1,750
---------- ----------
$ 4,734 $ 4,734
---------- ----------
Long-Term Debt
First Mortgage Bonds-
10.25% Series due 2020 $ 30,000 $ 30,000
8.98% Series due 2022 20,000 20,000
7.38% Series due 2002 20,000 20,000
7.30% Series due 2003 15,000 15,000
---------- ----------
$ 85,000 $ 85,000
---------- ----------
Other Long-Term Debt-
Finance Authority of Maine - Taxable Electric Rate
Stabilization Revenue Notes,
7.03% Series 1995A, due 2005 $ 71,500 $ 86,600
Medium Term Notes, Variable interest rate-
LIBO rate plus 1.125%, due 2002 7,080 11,700
Other Miscellaneous Notes Payable, 3.90%, due 2003 21 -
---------- ----------
$ 78,601 $ 98,300
Less: Current portion of long-term debt 23,184 21,340
---------- ----------
$ 55,417 $ 76,960
---------- ----------
Total Long-Term Debt $ 140,417 $ 161,960
---------- ----------
Total Capitalization $ 281,305 $ 304,114
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
000's Omitted
(Unaudited)
Nine Months Ended
Sept. 30, Sept. 30,
2001 2000
--------- ---------
Cash Flows From Operating Activities:
Net income $ 7,445 $ 9,217
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 7,827 6,831
Amortization of Seabrook nuclear project 1,274 1,274
Amortization of contract buyouts and
restructuring 16,918 16,672
Amortization of deferred asset sale gain (5,971) (4,267)
Other amortizations 1,194 1,622
Allowance for equity funds used during
construction (465) (60)
Deferred income tax provision and
amortization of investment tax credits (5,676) (1,922)
Gain on sale of subsidiary - (1,196)
Changes in assets and liabilities:
Costs to restructure purchased power contract (750) (750)
Deferred standard-offer service costs 4,580 (5,664)
Deferred special rate contract revenues (2,276) (1,232)
Deferred incremental Maine Yankee costs - 808
Exercise of PERC warrants-cash paid in
lieu of issuing shares (9,227) (1,758)
Accounts receivable, net and unbilled revenue 1,299 2,890
Accounts payable (2,773) 5,950
Accrued interest 837 1,082
Current and deferred income taxes 3,356 (1,252)
Accrued postretirement benefit costs 1,564 1,364
Other current assets and liabilities, net 581 468
Other, net (1,718) (307)
---------- ----------
Net Increase in Cash From Operating Activities: $ 18,019 $ 29,770
---------- ----------
Cash Flows From Investing Activities:
Construction expenditures $ (10,274) $ (10,810)
Proceeds from sale of subsidiary - 1,250
Allowance for borrowed funds used during
construction (423) (71)
---------- ----------
Net Decrease in Cash From Investing Activities $ (10,697) $ (9,631)
---------- ----------
Cash Flows From Financing Activities:
Dividends on preferred stock $ (199) $ (199)
Dividends on common stock (4,418) (4,050)
Payments on long-term debt (19,720) (18,035)
Short-term debt, net 6,000 -
---------- ----------
Net Decrease in Cash From Financing Activities $ (18,337) $ (22,284)
---------- ----------
Net Decrease in Cash and Cash Equivalents $ (11,015) $ (2,145)
Cash and Cash Equivalents at Beginning of Period 12,463 15,691
---------- ----------
Cash and Cash Equivalents at End of Period $ 1,448 $ 13,546
========== ==========
Cash Paid During the Nine Months for:
Interest (Net of Amount Capitalized) $ 9,058 $ 10,467
Income Taxes 7,772 9,295
========== ==========
See notes to consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
000's Omitted
(Unaudited)
Amounts Accumulated Total
Paid in Other Common
Common Excess of Retained Comprehensive Stock
Stock Par Value Earnings Loss Investment
-------- ---------- ---------- --------------- ----------
Balance December 31, 1999 $ 36,817 $ 58,890 $ 37,015 $ - $ 132,722
Net income - - 9,217 - 9,217
Cash dividends declared on-
Preferred stock - - (199) - (199)
Common stock - - (4,418) - (4,418)
Exercise of warrants-cash paid
in lieu of issuing shares - (210) - - (210)
--------- ---------- ----------- ---------------- ----------
Balance September 30, 2000 $ 36,817 $ 58,680 $ 41,615 $ - $ 137,112
========= ========== ========== ================ ==========
Balance December 31, 2000 $ 36,817 $ 58,643 $ 41,960 $ - $ 137,420
Net income - - 7,445 - 7,445
Other comprehensive loss
net of taxes:
Unrealized loss on interest
rate swap - - - (69) (69)
----------
Total Comprehensive income $ 7,376
Cash dividends declared on- ----------
Preferred stock - - (199) - (199)
Common stock - - (4,418) - (4,418)
Exercise of warrants-cash paid -
in lieu of issuing shares - (4,025) - - (4,025)
-------- ---------- ---------- ---------------- ----------
Balance September 30, 2001 $ 36,817 $ 54,618 $ 44,788 $ (69) $ 136,154
======== ========== ========== ================ ==========
See notes to the consolidated financial statements
BANGOR HYDRO-ELECTRIC COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
-------------
(Unaudited)
(1) BASIS OF PRESENTATION AND ACCOUNTING POLICIES:
Certain information and footnote disclosures, normally included in
financial statements prepared in accordance with generally accepted
accounting principles, have been condensed or omitted in this Form 10-Q
pursuant to the Rules and Regulations of the Securities and Exchange
Commission. However, in the opinion of Bangor Hydro-Electric Company
(the Company), the disclosures contained in this Form 10-Q are adequate
to make the information presented not misleading. The year end
condensed balance sheet data was derived from audited consolidated
financial statements but does not include all disclosures required by
generally accepted accounting principles. These statements should be
read in conjunction with the consolidated financial statements,
footnotes and all other information included in the 2000 Form 10-K.
In the opinion of the Company, the accompanying unaudited
consolidated financial statements reflect all adjustments, including
normal recurring accruals, necessary to present fairly the financial
position as of September 30, 2001 and the results of operations and
cash flows for the periods ended September 30, 2001 and 2000.
The Company's significant accounting policies are described in the
Notes to the Consolidated Financial Statements included in its 2000
Form 10-K filed with the Securities and Exchange Commission. For
interim reporting purposes, the Company follows these same basic
accounting policies but considers each interim period as an integral
part of an annual period. Accordingly, certain expenses are allocated
to interim periods based upon estimates of such expenses for the year.
(2) INCOME TAXES:
The following table reconciles a provision calculated by
multiplying income before federal income taxes by the statutory federal
income tax rate to the federal income tax provision:
Nine Months Ended Sept. 30,
2001 2000
---- ----
Amount % Amount %
(Dollars in Thousands)
Federal income tax provision
at statutory rate $4,541 35.0 $5,325 35.0
Plus (Less) permanent reductions
in tax expense resulting
from statutory exclusions
from taxable income 140 1.1 (113) (.7)
------ ---- ------ ----
Federal income tax provision before
effect of temporary differences
and investment tax credits $4,681 36.1 $5,212 34.3
Less temporary differences that
are flowed through for rate-
making and accounting purposes (378) (2.9) (311) (2.1)
Less utilization and amortization
of investment tax credits (105) (.8) (105) (.7)
------ ---- ------ ----
Federal income tax provision $4,198 32.4 $4,796 31.5
====== ==== ====== ====
(3) INVESTMENT IN JOINTLY OWNED FACILITIES:
Condensed financial information for Maine Yankee Atomic Power
Company (Maine Yankee), Maine Electric Power Company, Inc. (MEPCO), and
Chester SVC Partnership (Chester) is as follows:
MAINE YANKEE MEPCO
------------ -----
(Dollars in Thousands - Unaudited)
Operations for Nine Months Ended
-------------------------------------
Sep. 30, Sep. 30, Sep. 30, Sep. 30,
2001 2000 2001 2000
OPERATIONS: -------- -------- -------- --------
As reported by investee-
Operating revenues $ 47,419 $ 45,075 $ 3,606 $ 2,818
======== ======== ======== ========
Earnings applicable to
common stock $ 3,336 $ 3,500 $ 1,085 $ 975
======== ======== ======== ========
Company's reported equity-
Equity in net income $ 234 $ 245 $ 154 $ 138
Add(Deduct)-Effect of
adjusting Company's
estimate to actual 7 (5) 45 (33)
-------- -------- -------- --------
Amounts reported by Company $ 241 $ 240 $ 199 $ 105
======== ======== ======== ========
MAINE YANKEE MEPCO
------------ -----
(Dollars in Thousands - Unaudited)
Financial Position at
---------------------------------------
Sep. 30, Dec. 31, Sep. 30, Dec. 31,
2001 2000 2001 2000
FINANCIAL POSITION: --------- --------- --------- --------
As reported by investee-
Total assets $ 808,494 $ 915,097 $ 6,380 $ 5,873
Less-
Preferred stock - 15,000 - -
Long-term debt 33,600 40,800 - -
Other liabilities and
deferred credits 712,655 788,703 357 863
---------- --------- -------- --------
Net assets $ 62,239 $ 70,594 $ 6,023 $ 5,010
========== ========== ======== ========
Company's reported equity-
Equity in net assets $ 4,357 $ 4,942 $ 855 $ 711
Add(Deduct)- Effect
of adjusting Company's
estimate to actual 699 8 6 (39)
---------- ---------- -------- --------
Amounts reported by Co. $ 5,056 $ 4,950 $ 861 $ 672
========== ========== ======== ========
Chester
------------------------------------------
(Dollars in Thousands - Unaudited)
Operations for Nine Months Ended
------------------------------------------
Sep. 30, Sep. 30,
2001 2000
--------- ---------
OPERATIONS:
As reported by investee-
Operating revenues $ 2,968 $ 3,198
======= =======
Net Income $ - $ -
======= =======
Company's reported equity
in net income $ - $ -
======= =======
Financial Position at
Sep. 30, Dec. 31,
2001 2000
--------- --------
FINANCIAL POSITION:
As reported by investee-
Total assets $ 23,135 $ 24,082
Less-
Long-term debt 21,401 22,288
Other liabilities 1,734 1,794
-------- --------
Net assets $ - $ -
======== ========
Company's reported equity
in net assets $ - $ -
======== ========
At the end of September 2001, Maine Yankee redeemed 500,000 shares of
common stock, of which the Company's share was 35,000 shares, resulting in
the Company receiving approximately $699,000 of proceeds in October 2001.
The Company has recorded this transaction on its books in October 2001, while
Maine Yankee reflected the transaction in its third quarter 2001 financial
statements. Consequently, this has resulted in the difference above in the
Company's computed net equity in Maine Yankee as compared to the Maine Yankee
investment as reported by the Company on its September 30, 2001 consolidated
balance sheet.
(4) EARNINGS PER SHARE:
The following table reconciles basic and diluted earnings per common
share assuming all stock warrants were converted to common shares.
(Amounts in 000's, except per share data)
For the Three Months For the Nine Months
Ended Ended
--------------------- ---------------------
Sep. 30, Sep. 30, Sep. 30, Sep. 30,
2001 2000 2001 2000
-------- -------- -------- --------
Earnings applicable
to common stock $ 2,996 $ 3,874 $ 7,246 $ 9,018
-------- -------- -------- --------
Average common
shares outstanding 7,363 7,363 7,363 7,363
Plus: incremental
shares from assumed
conversion 704 1,049 792 959
-------- -------- -------- --------
Average common shares
outstanding plus
assumed warrants
converted 8,067 8,412 8,155 8,322
-------- -------- -------- --------
Basic earnings
per common share $ .41 $ .53 $ .98 $ 1.22
======== ======== ======== ========
Diluted earnings
per common share $ .37 $ .46 $ .89 $ 1.08
======== ======== ======== ========
(5) ACCOUNTING FOR DERIVATIVE INSTRUMENTS:
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 138. This new accounting
standard requires that all derivative instruments be recorded on the balance
sheet at fair value and establishes criteria for designation and
effectiveness of hedging relationships. The effect of adopting this standard
was not material to the Company's consolidated financial statements.
The accounting for derivative financial instruments can change based
on guidance received from the Derivatives Implementation Group (DIG). The
DIG identifies practice issues that arise from applying the requirements of
SFAS 133 and advises the Financial Accounting Standards Board on how to
resolve those issues.
In the second quarter of 2001, the DIG reached a conclusion as to the
interpretation of clearly and closely related contracts that qualify for the
normal purchase and sales exception under SFAS 133. The conclusion of the
DIG was that for contracts with prices indexed to the Consumer Price Index
(CPI), these would not qualify for the normal purchase and sale exception
under SFAS 133 and would need to be accounted for as derivatives under this
statement effective July 1, 2001. The Company has two power contracts (one
purchase and one sale) with prices indexed to a broad price measure similar
to the CPI, that were excluded from the scope of SFAS 133 on January 1, 2001,
as a result of the normal purchase and sale exception. Given the DIG's
conclusion, the Company, effective July 1, 2001, began to account for these
power contracts as derivatives in accordance with SFAS 133 and recorded them
at fair value on the Company's consolidated balance sheet in the third
quarter of 2001. The fair value of the above-market portion of these
contracts as of June 30, 2001 represents a liability of approximately $74.1
million. The Company has recorded a regulatory asset to offset this
liability, since the Company is currently recovering the net above-market
cost of these contracts as part of its stranded cost recovery. As a result
of this regulatory accounting, the recording of these contracts on the
Company's consolidated balance sheet does not result in an impact on earnings.
(6) RECLASSIFICATIONS:
Certain 2000 amounts have been reclassified to conform with the
presentation used in Form 10-Q for the quarter ended September 30, 2001.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDING SEPTEMBER 30, 2001
PART II
Item 6. Exhibits and Reports on Form 8-K
Exhibits: None.
Reports on Form 8-K:
One Current Report on Form 8-K was filed October 18, 2001 regarding
Amendment No. 1 to the Agreement and Plan of Merger, dated August 28, 2001,
by and among the Company and Emera and a press release, dated October 10,
2001, announcing the closing of the Merger.
There was no Form 8-K filed in the third quarter.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDED SEPTEMBER 30, 2001
The information furnished in this report reflects all adjustments which
are, in the opinion of management, necessary to a fair statement of the
results for the interim period.
SIGNATURES
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 thereunto duly authorized.
BANGOR HYDRO-ELECTRIC COMPANY
(Registrant)
/s/ Frederick S. Samp
---------------------
Dated: November 13, 2001
Frederick S. Samp
Vice President - Finance & Law
(Chief Financial Officer)