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 JUNE 30, 2001 Commission File No. 0-505
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact Name of Registrant as specified in its Charter)
MAINE 01-0024370
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification 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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NONE
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Former Name, Former Address and Former Fiscal Year,
if Changed Since Last Report
Outstanding Common Stock, $5 Par Value - 7,363,424 Shares
June 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
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FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2001
PART I - FINANCIAL INFORMATION
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PAGE
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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 - June 30, 2001 and
December 31, 2000 29
Consolidated Statements of Capitalization 31
Consolidated Statements of Cash Flows 32
Consolidated Statements of Common Stock Investment 33
Notes to the Consolidated Financial Statements 34
PART II - OTHER INFORMATION 41
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Item 6 - Exhibits and Reports on Form 8-K 42
Signature Page 43
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
000's Omitted Except Per Share Amounts
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
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Operating Revenues:
Electric operating revenue $ 31,435 $ 31,075 $ 65,622 $ 76,864
Standard offer service 22,568 17,488 44,585 21,820
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$ 54,003 $ 48,563 $ 110,207 $ 98,684
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Operating Expenses:
Fuel for generation and purchased power $ 9,357 $ 8,181 $ 16,418 $ 25,805
Standard offer service purchased power 22,138 17,333 43,674 21,592
Other operation and maintenance 11,403 9,921 20,228 18,792
Depreciation and amortization 2,725 2,399 5,423 4,370
Amortization of Seabrook nuclear unit 425 425 850 850
Amortization of contract buyouts
and restructuring 5,639 5,639 11,278 11,033
Amortization of deferred asset sale gain (2,155) (1,681) (3,859) (2,172)
Taxes -
Local property and other 1,262 1,210 2,600 2,597
State Income 152 135 746 500
Federal Income (112) 349 2,053 2,358
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$ 50,834 $ 43,911 $ 99,411 $ 85,725
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Operating Income $ 3,169 $ 4,652 $ 10,796 $ 12,959
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Other Income And (Deductions):
Allowance for equity funds used
during construction $ 153 $ 127 $ 319 $ (93)
Other, net of applicable income taxes 205 656 598 926
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Income Before Interest Expense $ 3,527 $ 5,435 $ 11,713 $ 13,792
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Interest Expense:
Long-term debt $ 3,566 $ 3,960 $ 7,153 $ 7,939
Other 301 260 471 497
Allowance for borrowed funds used
during construction (139) (124) (294) 79
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$ 3,728 $ 4,096 $ 7,330 $ 8,515
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Net Income (Loss) $ (201) $ 1,339 $ 4,383 $ 5,277
Dividends On Preferred Stock 67 67 133 133
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Earnings (Loss) Applicable To Common Stock $ (268) $ 1,272 $ 4,250 $ 5,144
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Weighted Average Number Of Shares Outstanding 7,363 7,363 7,363 7,363
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Earnings (Loss) Per Common Share:
Basic $ (.04) $ .17 $ .58 $ .70
Diluted (.03) .15 .52 .62
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Dividends Declared Per Common Share $ .20 $ .20 $ .40 $ .40
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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 quarter ended June 30, 2001 basic loss per common share was
$.04 as compared to basic earnings per common share of $.17 for the quarter
ended June 30, 2000. Earnings were negatively affected in the second quarter
of 2001 by several items, principally one-time events. The New England
independent system operator (ISO New England) costs associated with
transmission constraints were approximately $643,000 greater ($.05 reduction
in earnings per common share) in the 2001 quarter as compared to the 2000
quarter. In the second quarter of 2001 the Company recorded a $585,000
reserve ($.05 reduction in earnings per common share) associated with
adjustments to revenue related to filings with the New England Power Pool
(NEPOOL). Also in the 2001 quarter, 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. In
the second quarter of 2001, the Company increased its reserve for bad debts
by $200,000 due principally to a Chapter 11 bankruptcy filing by one of the
Company's large industrial customers, while in the second quarter of 2000,
the Company reduced its bad debt reserve by $264,000 as a result of the
electric utility industry restructuring. The $464,000 change in expense
between the two quarters represents $.04 reduction in earnings per common
share for the second quarter of 2001 as compared to the 2000 quarter.
Finally negatively impacting earnings in the second quarter of 2001 was
approximately $262,000 of incremental costs ($.02 reduction in earnings per
common share) incurred in connection 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. The Company has filed for an accounting order with the
Federal Energy Regulatory Commission (FERC) to defer the incremental costs
associated with the RTO for future recovery from the RTO. With the recent
FERC actions concerning the RTO, discussed below, the Company cannot predict
when an accounting order may be approved by the FERC.
Offsetting these earnings decreases in the 2001 quarter to some
extent was an approximately $984,000 decrease in incremental merger related
costs in the second quarter of 2001 as compared to the second quarter of
2000.
IMPORTANT CURRENT ACTIVITIES
STATUS OF PENDING MERGER WITH EMERA - Regulatory approvals for the pending
merger between the Company and Emera, Inc. continue to be nearing completion.
Under an agreement reached in June 2000, Emera will acquire all of the
outstanding common stock of the Company for US$26.50 per share as adjusted in
accordance with the agreement. All necessary regulatory approvals required
for the merger have been received except for approval from the U.S.
Securities and Exchange Commission pursuant to the Public Utility Holding
Company Act of 1935. That approval is expected in the near future, at which
time the Company and Emera plan to complete the merger.
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 July 31, 2001, the Company filed a proposal
with the Maine Public Utilities Commission (MPUC) for an alternative rate
plan (ARP) that would reduce overall electricity prices for most customers
served by the Company by approximately 8%. The plan includes stable standard-
offer service prices for a four-year period beginning March 1, 2002. The
filing of this proposal was required pursuant to an order issued by the MPUC
on January 5, 2001, approving the merger between Emera and the Company.
Since the beginning of restructuring, overall electricity costs for
residential customers have increased by 18% solely due to increases in the
price of standard-offer service. Standard-offer service is administered by
the MPUC and had been expected to be provided pursuant to competitive bids.
However, for the first two years since the commencement of restructuring, the
MPUC has rejected such bids and ordered the Company to obtain power supply
arrangements satisfactory to the MPUC in order to provide the service.
Unfortunately, the price for standard-offer service has been high, reflecting
high power supply costs. Now, the Company has developed a plan that proposes
to reduce and stabilize this price for a four-year period beginning March 1,
2002. At the end of that time, the Company expects reductions in charges for
delivery service will also be possible, since a significant portion of the
costs related to pre-restructuring commitments will be paid off. Management
cannot be certain, though, that these reductions in charges for delivery
service will occur.
Under the most innovative part of the Company's ARP proposal, the
Company will agree to arrange for power supply resources in order to serve
small and medium standard-offer customers, i.e., those customers who do not
choose to purchase their generation service from competitive energy
suppliers. Since restructuring of the electricity industry began on March 1,
2000, the MPUC has ordered the Company to arrange for such standard-offer
service, rather than accept bids from potential suppliers. In its ARP
proposal, the Company is committing to continue this service and set the
price for standard-offer service at 5.5 cents per kilowatt-hour (kWh),
subsequent to revision prior to MPUC approval of the plan, a 25% reduction
from prices currently being charged for this portion of electricity charges.
The overall electricity price, including delivery charges of the Company,
will decline by approximately 8% under the Company's proposed ARP plan.
In addition to agreeing to reduce and stabilize electricity prices, the
Company's ARP proposal includes incentives to improve the efficiency and the
service quality of power delivery services to customers.
Currently, as previously discussed, the standard-offer service is fully
reconciling, and ratepayers fund the over or under-collection associated with
the difference between standard offer revenues and costs. Under the
Company's proposal, this reconciliation mechanism would end, and the
Company's shareholders would assume the financial risks and rewards
associated with the standard-offer service. Management cannot predict the
outcome of the regulatory proceedings associated with approving the Company's
ARP proposal.
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 increased by approximately $360,000 in the second
quarter of 2001. The increase was due to several factors. Increase in
revenues in the second quarter of 2001 were positively impacted by an
$924,000 increase in off-system sales, which are sales related to power pool
and inter-connection agreements and resales of purchased power. The off-
system sales increase is due principally to the Company's requirement,
starting March 1, 2000, to resell the capacity and energy from its six
purchased power contracts pursuant to Chapter 307 of Maine's 1997 law
restructuring the State's electric utility industry (See the 2000 Form 10-K
for a more complete discussion). Also, in the second quarter of 2001 the
Company recorded $1.3 million in deferred costs as compared to deferrals of
$550,000 in the second quarter of 2000, associated with a deficiency in
actual revenues realized from customers under special rate contracts as
compared to the estimated revenues for these customers utilized in setting
the Company's electric rates starting March 1, 2000. The Company was granted
a deferral mechanism for the differences in these revenues in its February
2000 rate order from the MPUC.
Total electric operating revenues, excluding the standard-offer
service, attributable to energy sales were $1.8 million, or 7.4%, lower in
the second quarter of 2001 than in the 2000 quarter. The largest item
impacting the decreased revenue was a 47.6% or 52.5 million kWh energy sales
reduction to the Company's largest special contract customers in the second
quarter of 2001 as compared to the 2000 quarter, largely attributable to the
September 15, 2000 shutdown of the Company's formerly largest special
contract customer, HoltraChem Manufacturing Company (HoltraChem). As a
result of the shutdown, energy sales and corresponding electric operating
revenues for HoltraChem were 52 million kWh's and $754,000 lower,
respectively, in the 2001 quarter as compared to 2000. For a discussion of
the HoltraChem shutdown, see the 2000 Form 10-K. Also revenues associated
with one of the Company's other large special contract customers were
approximately $784,000 lower in the second quarter of 2001. The reduction in
non-standard-offer revenue is due to the fact that the customer pays a fully
bundled electric rate, and when standard-offer prices increase, the T&D rate
decreases. With the increases in the standard-offer rates (discussed below),
this customer's contributions to the Company's T&D revenues have decreased.
Also as a result of this revenue reduction, the Company's previously
discussed revenue deferral associated with special rate contract customers
has increased.
Absent the impact of the largest special rate contract customers,
energy sales and corresponding revenues were flat in the second quarter of
2001 as compared to the second quarter of 2000. The Company experienced
warmer weather in the spring of 2001 which for the most part negatively
impacted sales, although the warmer weather in June 2001 did serve to benefit
energy sales.
Electric operating revenues associated with the standard-offer
service were approximately $5.1 million, or 29%, higher in the second quarter
of 2001 as compared to the second 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 increase in
standard-offer service revenues is due to an $8.5 million (54.2%) increase in
revenues attributable to energy sales, offset by a $3.4 million reduction in
revenues associated with the deferral of the excess of standard-offer service
revenues over standard-offer service expenses. 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. The current standard-offer service
rates for residential/small commercial and large industrial customers are
approximately 62% and 58% higher, respectively than the initial standard-
offer service rates that were in effect starting March 1, 2000. These
increases were offset to some extent by a 2.7% reduction in standard-offer
related energy sales in the second quarter of 2001 as compared to the second
quarter of 2000.
EXPENSES
Fuel for generation and purchased power expense, excluding the cost
of standard-offer service purchased power, increased by approximately $1.2
million in the second quarter of 2001 as compared to the second quarter of
2000. As previously discussed, ISO New England costs associated with
transmission constraints were approximately $643,000 greater in the 2001
quarter as compared to the 2000 quarter, and transmission costs were $585,000
higher in the 2001 quarter as a result of the previously discussed reserve
associated with adjustments to revenue related to filings with the NEPOOL.
Purchased power expense related to providing the standard-offer
service increased by approximately $4.8 million in the second quarter of 2001
in comparison to the 2000 quarter. The increase was due principally to an
increase in the price of power purchased from suppliers. The prices that the
Company contracted for power almost doubled between early 2000 when the prior
year contracts were entered into and early 2001 when the current year's
contracts were signed
Other operation and maintenance (O&M) expense increased by
approximately $1.5 million in the second quarter of 2001 compared to the
second quarter of 2000. The increase is due to several factors. The
Company's bad debt expense in the second quarter of 2001 was approximately
$648,000 greater than in the 2000 quarter, including the effects of the
previously discussed changes in the bad debt reserve in the second quarters
of each year. Also, other O&M increased in the 2001 quarter by approximately
$318,000 and $262,000, respectively, related to the previously discussed
increase in the environmental remediation reserve and incremental costs
associated with the Company's involvement in the RTO. Also, in the second
quarter of 2001 the Company recorded approximately $564,000 of expense
associated with regulatory assessments from the MPUC and the Office of the
Public Advocate (OPA), while in the second quarter of 2000 the Company only
incurred approximately $117,000 of expense associated with the assessment
from the OPA. The MPUC assessment in 2000 was recorded in the third quarter.
The Company's pension expense was approximately $304,000 greater in the
second quarter of 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. Finally increasing
other O&M in the second quarter of 2001 was a $476,000 increase in payroll
expense, which was due principally to an extra week of payroll included in
the second quarter 2001 expense (timing) and the impact of the 3.75% wage
rate increase for bargaining unit employees effective January 1, 2001 and
various individual wage rate increases for non-bargaining unit employees.
Decreasing other O&M expense in the second quarter of 2001 was
approximately $1.1 million in costs associated with the Company's proposed
merger with Emera recorded in June 2000. 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).
Depreciation and amortization expense increased $326,000 in the
second quarter of 2001 as compared to the 2000 due principally to additions
to the Company's electric plant in service.
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 10.5 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 second quarter of 2001 as compared to the
2000 quarter. This was offset to some extent by the impact 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. 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, increased by $41,000 in
second quarter of 2001 relative to 2000 due principally to increased carrying
costs being recorded on deferred standard-offer service and deferred special
rate contract revenue regulatory assets and on exercised PERC common stock
warrants. These increases were offset to some extent by reduced AFDC as a
result of decreased construction activity in 2001 as compared to 2000.
Other income, net of income taxes, decreased by approximately
$451,000 in the second quarter of 2001. Investment income decreased by
approximately $288,000 in the 2001 quarter due principally to reductions in
the Company's available cash balances (see the section on Liquidity and
Capital Resources). Also impacting the decrease in other income in the
second quarter of 2001 was approximately $114,000 of incremental merger
related costs being incurred.
Long-term debt interest expense decreased $394,000 in the second
quarter of 2001 as compared to 2000 due primarily to a $14 million principal
payment on the Company's Finance Authority of Maine (FAME) Revenue Notes at
the end of June 2000 and monthly principal payments on the $24.8 million
medium term notes from July 2000 through June 2001 amounting to $5.85
million.
Other interest expense increased $41,000 due principally to
approximately $95,000 of interest charged by the State of Maine associated
with the previously discussed audit adjustment related to disallowed
investment tax credits. This was offset to some extent by a reduction in the
amortization of debt issuance costs in the second quarter of 2001. The
amortization decrease was primarily attributable to the end of the
amortization period of certain deferred debt issuance costs in June 2000.
SIX MONTHS OF 2001 AS COMPARED TO THE SIX MONTHS OF 2000
EARNINGS
For the six months ended June 30, 2001 and 2000 basic earnings per
common share were $.58 and $.70, respectively. The six-month earning numbers
declined for the same reasons as mentioned above offset by the positive
impact of higher energy sales in the first quarter of 2001 due principally to
colder weather in the 2001 quarter as compared to 2000.
REVENUES
With the implementation of retail competition effective March 1,
2000, comparisons of electric operating revenues for the first six months of
2001 as compared to the first six months of 2000 is difficult. Total
electric operating revenues, including standard-offer service, increased by
approximately $11.5 million, or 11.7%, for the first six 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 $11
million higher in the 2001 period. The impact of the increased standard-
offer service rates were offset to some extent by a 10% 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 1.2% in the
first six months of 2001 as compared to the 2000 period.
Other revenues, which increased by approximately $560,000 in the
first six months of 2001, were positively impacted by an approximately $1.8
million increase in off-system sales. The increase occurred principally for
the same reasons discussed for the second quarters of 2001 as compared to
2000 and also due to the fact the Company's revenues realized from the
Chapter 307 sales did not begin in 2000 until March 1. Also enhancing other
revenues in 2001 was a $1.2 million increase in revenues associated with the
previously discussed deferral of special rate contract revenues. The
increase was due to the previously discussed reasons for the second quarters
of 2001 as compared to 2000 and also due to the fact the Company did not begin
the deferral of these revenues in 2000 until March 1. These increases were
offset by the impact of a $4 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 $3.5 million. In the
2000 period, starting March 1, the Company recorded additional other revenues
of approximately $541,000 as a result of standard-offer costs exceeding
energy sales related standard-offer revenues.
EXPENSES
Total fuel for generation and purchased power expense, including the
standard offer, increased approximately $12.7 million in the 2001 period as
compared to 2000. The increase was due to the reasons discussed above for
the second quarters of 2001 and 2000 as well as several factors in the first
quarters of each year. ISO New England costs associated with transmission
constraints were approximately $448,000 greater in the first six months of
2001 as compared to the 2000 period. Total power purchases in the first
quarter of 2001 were fairly consistent with those in the 2000 quarter due to
the Company continuing to fulfill its existing power purchase contract
obligations subsequent to the implementation of the electric industry
restructuring on March 1, 2000 and procuring power to serve the standard-
offer load. In the first two months of 2001, though, 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 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 $1.4 million in the first six months
of 2001 as compared to the first six months of 2000. The reasons for the
increases and offsetting decreases for this period are consistent with those
presented for the second quarters of each year.
Depreciation and amortization expense increased by approximately $1.1
million 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 $245,000 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 adjusted annual amortization amounts 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 six months
of 2001 as compared to 2000 were each due principally to the same reasons as
discussed previously for the second quarters of 2001 and 2000.
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 $785,000 in
first six months of 2001 relative to 2000 due mainly to approximately
$463,000 in carrying costs being recorded on the deferred asset sale gain in
2000. The Company also recorded increased carrying costs on deferred
standard-offer service costs, deferred special rate contract revenues, and on
exercised PERC common stock warrants in the 2001 period as compared to the
2000 period.
Other income, net of income taxes decreased by approximately $328,000
in the first six months of 2001 principally as a result of the previously
discussed reasons for the second quarters of 2001 and 2000. These decreases
were offset to some extent by a higher level of start-up costs associated
with non-core activities in the 2000 period.
LIQUIDITY AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events in the first
six months of 2001 and 2000 as they affect the Company's liquidity. Net
increase in cash from operating activities was approximately $10.8 million in
the first six months of 2001 as compared to $26.2 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 $8.8 million in
payments to the warrant holders as compared to approximately $1.4 million in
2000. The decrease in operating cash flows in the first six months of 2001
relative to the 2000 period was also affected by the impact of deferred
special rate contract revenues. The Company deferred $1.7 million in 2001 as
compared to $520,000 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. In the 2001 period the Company
made approximately $1.5 million more in state and federal income tax payments
principally as a result of an audit by the Internal Revenue Service of the
Company's 1998 and 1999 corporate income tax returns.
These increases in operating cash flows were offset to some extent by
an increase in cash inflows associated with the standard-offer service. In
2001, the Company's standard-offer service revenues exceeded associated costs
by approximately $3.5 million, while in the corresponding 2000 period, the
costs exceeded revenues by approximately $541,000.
Construction expenditures were approximately $176,000 lower in the
2001 period as compared to 2000 due to reductions in the Company's capital
budget.
The increase in common dividends paid in the first six 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. On June 29, 2001, the Company extended the Amended and
Restated Revolving Credit Agreement until October 1, 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
associated with the two credit agreements as of June 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 June 30, 2001, the liability recorded by the Company for its estimated
environmental remediation costs amounted to $457,000. 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 June 30, 2001,
the Company had $8.7 million of medium term notes outstanding which bear
floating, LIBOR-based rates (3.8625% LIBO rate at June 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". Statement 141 improves the transparency of the
accounting and reporting for business combinations by requiring that all
business combinations be accounted for under a single method-the purchase
method. 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. This change provides investors with greater transparency
regarding the economic value of goodwill and its impact on earnings. 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.
Management is currently examining the impact of the adoption of this standard
on the Company.
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)
June 30, Dec. 31,
Assets 2001 2000
--------- ---------
Investment In Utility Plant:
Electric plant in service, at original cost $ 319,676 $ 316,167
Less - Accumulated depreciation and amortization 90,431 86,684
---------- ----------
$ 229,245 $ 229,483
Construction work in progress 7,261 5,458
---------- ----------
$ 236,506 $ 234,941
Investments in corporate joint ventures:
Maine Yankee Atomic Power Company $ 4,841 $ 4,950
Maine Electric Power Company, Inc. 850 672
---------- ----------
$ 242,197 $ 240,563
---------- ----------
Other Investments, at cost $ 3,352 $ 3,175
---------- ----------
Funds held by trustee, at cost $ 22,697 $ 22,696
---------- ----------
Current Assets:
Cash and cash equivalents $ 1,351 $ 12,463
Accounts receivable, net of reserve
$961 in 2001 and $761 in 2000 20,368 21,732
Unbilled revenue receivable 14,788 15,779
Inventories, at average cost:
Material and supplies 2,597 2,585
Fuel oil 70 94
Prepaid expenses 462 829
---------- ----------
Total current assets $ 39,636 $ 53,482
---------- ----------
Regulatory Assets and Deferred Charges:
Investment in Seabrook nuclear project, net of
accumulated amortization of $34,421 in 2001
and $33,571 in 2000 $ 24,421 $ 25,271
Costs to terminate/restructure purchased power
contracts, net of accumulated amortization
of $134,450 in 2001 and $123,172 in 2000 93,805 99,312
Maine Yankee decommissioning costs 39,453 43,028
Other regulatory assets 41,033 41,025
Other deferred charges 3,047 3,668
---------- ----------
Total regulatory assets and deferred charges $ 201,759 $ 212,304
---------- ----------
Total Assets $ 509,641 $ 532,220
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
000's Omitted
(Unaudited)
June 30, Dec. 31,
Stockholders' Investment and Liabilities 2001 2000
--------- ---------
Capitalization:
Common stock investment $ 134,820 $ 137,420
Preferred stock 4,734 4,734
Long-term debt, net of current portion 141,885 161,960
---------- ----------
Total capitalization $ 281,439 $ 304,114
---------- ----------
Current Liabilities:
Notes payable - banks $ 6,000 $ -
---------- ----------
Other current liabilities -
Current portion of long-term debt $ 23,300 $ 21,340
Accounts payable 23,909 24,785
Dividends payable 1,539 1,539
Accrued interest 2,509 2,529
Customers' deposits 536 502
Current income taxes payable 1,793 306
---------- ----------
Total other current liabilities $ 53,586 $ 51,001
---------- ----------
Total current liabilities $ 59,586 $ 51,001
---------- ----------
Commitments and Contingencies
Regulatory and Other Long-term Liabilities:
Deferred income taxes - Seabrook $ 12,666 $ 13,109
Other accumulated deferred income taxes 58,996 58,314
Maine Yankee decommissioning liability 39,453 43,028
Deferred gain on asset sale 18,787 22,789
Other regulatory liabilities 10,061 12,556
Unamortized investment tax credits 1,382 1,452
Accrued pension and postretirement benefit costs 13,523 12,124
Other long-term liabilities 13,748 13,733
---------- ----------
Total regulatory and other long-term liabilities $ 168,616 $ 177,105
---------- ----------
Total Stockholders' Investment and Liabilities $ 509,641 $ 532,220
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
000's Omitted
(Unaudited)
June 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 54,800 58,643
Accumulated other comprehensive loss (62) -
Retained earnings 43,265 41,960
---------- ----------
Total common stock investment $ 134,820 $ 137,420
---------- ----------
Preferred Stock
Non-participating, cumulative, par value $100 per share,
authorized 600,000 shares, not redemable 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 8,685 11,700
---------- ----------
$ 80,185 $ 98,300
Less: Current portion of long-term debt 23,300 21,340
---------- ----------
$ 56,885 $ 76,960
---------- ----------
Total Long-Term Debt $ 141,885 $ 161,960
---------- ----------
Total Capitalization $ 281,439 $ 304,114
========== ==========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
000's Omitted
(Unaudited)
Six Months Ended
June 30, June 30,
2001 2000
--------- ---------
Cash Flows From Operating Activities:
Net income $ 4,383 $ 5,277
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 5,423 4,370
Amortization of Seabrook nuclear project 850 850
Amortization of contract buyouts and
restructuring 11,278 11,033
Amortization of deferred asset sale gain (3,859) (2,172)
Other amortizations 819 1,212
Allowance for equity funds used
during construction (319) 93
Deferred income tax provision and
amortization of investment tax credits (3,989) (4,615)
Changes in assets and liabilities:
Costs to restructure purchased power contract (500) (500)
Deferred standard-offer service costs 3,503 (541)
Deferred special rate contract revenues (1,726) (520)
Deferred incremental Maine Yankee costs - 808
Exercise of PERC warrants-cash paid
in lieu of issuing shares (8,845) (1,365)
Accounts receivable, net and unbilled revenue 2,355 5,946
Accounts payable (876) 1,399
Accrued interest (20) (78)
Current and deferred income taxes 1,489 3,884
Accrued postretirement benefit costs 1,025 943
Other current assets and liabilities, net 413 436
Other, net (606) (308)
---------- ----------
Net Increase in Cash From Operating Activities: $ 10,798 $ 26,152
---------- ----------
Cash Flows From Investing Activities:
Construction expenditures $ (6,423) $ (6,599)
Allowance for borrowed funds used during
construction (294) 79
---------- ----------
Net Decrease in Cash From Investing Activities $ (6,717) $ (6,520)
---------- ----------
Cash Flows From Financing Activities:
Dividends on preferred stock $ (133) $ (133)
Dividends on common stock (2,945) (2,578)
Payments on long-term debt (18,115) (16,625)
Short-term debt, net 6,000 -
---------- ----------
Net Decrease in Cash From Financing Activities $ (15,193) $ (19,336)
---------- ----------
Net (Decrease) Increase in Cash and Cash Equivalents $ (11,112) $ 296
Cash and Cash Equivalents at Beginning of Period 12,463 15,691
---------- ----------
Cash and Cash Equivalents at End of Period $ 1,351 $ 15,987
========== ==========
Cash Paid During the Six Months for:
Interest (Net of Amount Capitalized) $ 6,762 $ 8,239
Income Taxes 5,866 4,215
========== ==========
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 - - 5,277 - 5,277
Cash dividends declared on-
Preferred stock - - (133) - (133)
Common stock - - (2,946) - (2,946)
Exercise of warrants-cash paid
in lieu of issuing shares - (169) - - (169)
-------- ---------- ---------- ------------------------
Balance June 30, 2000 $36,817 $58,721 $39,213 $ - $134,751
======== ========== ========== ========================
Balance December 31, 2000 $36,817 $58,643 $41,960 $ - $137,420
Net income - - 4,383 - 4,383
Other comprehensive loss
net of taxes:
Unrealized loss on interest
rate swap - - - (62) (62)
----------
Total Comprehensive income $ 4,321
Cash dividends declared on- ----------
Preferred stock - - (133) - (133)
Common stock - - (2,945) - (2,945)
Exercise of warrants-cash paid -
in lieu of issuing shares - (3,843) - - (3,843)
-------- ---------- ---------- ------------------------
Balance June 30, 2001 $36,817 $54,800 $43,265 $ (62) $134,820
======== ========== ========== ========================
See notes to the consolidated financial statements
BANGOR HYDRO-ELECTRIC COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 June 30, 2001 and the results of operations and cash
flows for the periods ended June 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:
Six Months Ended June 30,
2001 2000
------------- ---------------
Amount % Amount %
(Dollars in Thousands)
------------------------------
Federal income tax provision
at statutory rate $2,737 35.0 $3,033 35.0
Plus (Less) permanent reductions
in tax expense resulting
from statutory exclusions
from taxable income 103 1.3 (49) (.6)
------ ---- ------ ----
Federal income tax provision before
effect of temporary differences
and investment tax credits $2,840 36.3 $2,984 34.4
Less temporary differences that
are flowed through for rate-
making and accounting purposes (219) (2.8) (142) (1.6)
Less utilization and amortization
of investment tax credits (70) (.9) (70) (.8)
------ ---- ------ ----
Federal income tax provision $2,551 32.6 $2,772 32.0
====== ==== ====== ====
(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 Six Months Ended
---------------------------------------
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
OPERATIONS: -------- -------- -------- --------
As reported by investee-
Operating revenues $ 31,877 $ 29,121 $ 2,682 $ 1,773
======== ======== ======== ========
Earnings applicable to
common stock $ 2,253 $ 2,337 $ 978 $ 570
======== ======== ======== ========
Company's reported equity-
Equity in net income $ 158 $ 164 $ 139 $ 81
Add(Deduct)-Effect of
adjusting Company's
estimate to actual 12 (5) 45 21
-------- -------- -------- --------
Amounts reported by Company $ 166 $ 159 $ 184 $ 102
======== ======== ======== ========
MAINE YANKEE MEPCO
---------------------------------------
(Dollars in Thousands - Unaudited)
Financial Position at
---------------------------------------
June 30, Dec. 31, June 30, Dec. 31,
2001 2000 2001 2000
FINANCIAL POSITION: --------- --------- --------- --------
As reported by investee-
Total assets $ 832,369 $ 915,097 $ 6,406 $ 5,873
Less-
Preferred stock - 15,000 - -
Long-term debt 36,000 40,800 - -
Other liabilities and
deferred credits 725,222 788,703 467 863
---------- --------- -------- --------
Net assets $ 71,147 $ 70,594 $ 5,939 $ 5,010
========== ========== ======== ========
Company's reported equity-
Equity in net assets $ 4,980 $ 4,942 $ 843 $ 711
Add(Deduct)- Effect
of adjusting Company's
estimate to actual 139 8 7 (39)
---------- ---------- -------- --------
Amounts reported by Co. $ 4,841 $ 4,950 $ 850 $ 672
========== ========== ======== ========
Chester
------------------------------------------
(Dollars in Thousands - Unaudited)
Operations for Six Months Ended
------------------------------------------
June 30, June 30,
2001 2000
--------- ---------
OPERATIONS:
As reported by investee-
Operating revenues $ 2,021 $ 2,115
======= =======
Net Income $ - $ -
======= =======
Company's reported equity
in net income $ - $ -
======= =======
Financial Position at
June 30, Dec. 31,
2001 2000
--------- --------
FINANCIAL POSITION:
As reported by investee-
Total assets $ 23,345 $ 24,082
Less-
Long-term debt 21,697 22,288
Other liabilities 1,648 1,794
-------- --------
Net assets $ - $ -
======== ========
Company's reported equity
in net assets $ - $ -
======== ========
(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 Six Months
Ended Ended
--------------------- ---------------------
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
-------- -------- -------- --------
Earnings (Loss) applicable
to common stock $ (268) $ 1,272 $ 4,250 $ 5,144
-------- -------- -------- --------
Average common
shares outstanding 7,363 7,363 7,363 7,363
Plus: incremental
shares from assumed
conversion 750 857 836 873
-------- -------- -------- --------
Average common shares
outstanding plus
assumed warrants
converted 8,114 8,220 8,199 8,236
-------- -------- -------- --------
Basic earnings (loss)
per common share $ (.04) $ .17 $ .58 $ .70
======== ======== ======== ========
Diluted earnings (loss)
per common share $ (.03) $ .15 $ .52 $ .62
======== ======== ======== ========
(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 will be required to account for these power
contracts as derivatives in accordance with SFAS 133 and record 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. The Company
will record 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 will 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 June 30, 2001.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDING JUNE 30, 2001
PART II
Item 6. Exhibits and Reports on Form 8-K
- ------- --------------------------------
Exhibits: None.
--------
Reports on Form 8-K: None.
-------------------
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDED JUNE 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: August 14, 2001 _____________________________
Frederick S. Samp
Vice President - Finance & Law
(Chief Financial Officer)