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, 1999 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, 1999
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, 1999
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 - June 30, 1999 and
December 31, 1998 24
Consolidated Statements of Capitalization 26
Consolidated Statements of Cash Flows 27
Consolidated Statements of Common Stock Investment 28
Notes to the Consolidated Financial Statements 29
PART II - OTHER INFORMATION 39
Item 4 - Submission of Matters to a Vote of
Security Holders 40
Item 6 - Exhibits and Reports on Form 8-K 40
Signature Page 41
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
000's Omitted Except Per Share Amounts
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
-------- -------- --------- ----------
<S> <C> <C> <C> <C>
ELECTRIC OPERATING REVENUES $ 47,299 $ 46,601 $ 97,521 $ 95,701
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OPERATING EXPENSES:
Fuel for generation and purchased power $ 18,837 $ 20,045 $ 37,352 $ 41,404
Other operation and maintenance 8,636 8,318 18,229 16,628
Depreciation and amortization 2,346 2,440 4,866 5,054
Amortization of Seabrook Nuclear Unit 425 425 850 850
Amortization of contract buyouts
and restructuring 5,201 4,950 10,401 10,041
Taxes -
Property and payroll 1,340 1,278 2,973 2,813
State income 378 184 872 412
Federal income 1,634 955 3,590 2,083
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$ 38,797 $ 38,595 $ 79,133 $ 79,285
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OPERATING INCOME $ 8,502 $ 8,006 $ 18,388 $ 16,416
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OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction $ 158 $ 109 $ 301 $ 178
Other, net of applicable income taxes 521 272 781 469
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$ 679 $ 381 $ 1,082 $ 647
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INCOME BEFORE INTEREST EXPENSE $ 9,181 $ 8,387 $ 19,470 $ 17,063
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INTEREST EXPENSE:
Long-term debt $ 5,120 $ 5,786 $ 10,873 $ 11,261
Other 336 507 864 1,429
Allowance for borrowed funds used
during construction 273 (173) 69 (302)
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$ 5,729 $ 6,120 $ 11,806 $ 12,388
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NET INCOME $ 3,452 $ 2,267 $ 7,664 $ 4,675
DIVIDENDS ON PREFERRED STOCK 278 311 557 623
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EARNINGS APPLICABLE TO COMMON STOCK $ 3,174 $ 1,956 $ 7,107 $ 4,052
======== ======== ========= ==========
WEIGHTED AVERAGE NUMBER OF SHARES 7,363 7,363 7,363 7,363
======== ======== ========= ==========
EARNINGS PER COMMON SHARE,
Basic $ .43 $ .27 $ .97 $ .55
Diluted .38 .26 .86 .55
======== ======== ========= ==========
DIVIDENDS DECLARED PER COMMON SHARE $ .15 $ - $ .15 $ -
======== ======== ========= ==========
See notes to the consolidated financial statements.
</TABLE>
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 contained in Bangor Hydro-Electric Company's (the
Company) Annual Report on Form 10-K for the year ended December 31, 1998
(1998 Form 10-K) should be read in conjunction with the comments below.
EARNINGS
The quarter ended June 30, 1999 resulted in basic earnings per common
share of $.43, as compared to $.27 per common share for the quarter ended
June 30, 1998. The improvement in second quarter 1999 earnings is
attributable to an increase in KWH sales, a one-time benefit of $896,000
($530,000 after taxes) related to the settlement of a dispute related to the
New England Power Pool (NEPOOL) transmission rates and a 1.36% increase in
rates related to the Company's alternative rate plan effective June 1, 1999
(A discussion of this rate increase is included below under "Important
Current Activities").
IMPORTANT CURRENT ACTIVITIES-
SALE OF COMPANY'S GENERATING ASSETS - On May 27, 1999, the Company completed
most of the transaction for the sale of its electric generating assets and
certain transmission rights to PP&L Global. The purchase price for the assets
transferred was $79 million.
The sale involved all but one of the Company's hydroelectric plants
on the Penobscot, Piscataquis, and Union rivers and Bangor
Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in
Yarmouth, Maine--a total base load capacity of 83 megawatts. The sale also
involved a transfer by the Company of rights to transmit power over the Maine
Electric Power Company (MEPCO) transmission facilities connecting NEPOOL to
New Brunswick Canada; the Company's rights as a participant in the regional
utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and
the Company's rights to develop a second high voltage transmission line that
will connect NEPOOL to New Brunswick, Canada.
As discussed in the 1998 Form 10-K, the Company and other Maine
utilities were required to sell their generation assets as a result of the
comprehensive electric utility industry restructuring law adopted in Maine in
1997. The Company conducted an auction in 1998, which lead to the signing of
a purchase and sale agreement with PP&L Global in late September 1998. The
purchase and sale agreement also included the Company's 50% interest in the
13 megawatt West Enfield hydro station on the Penobscot River. In late July
1999, the Company received $10 million in proceeds from the transfer of the
economic interest in that project.
The Company has utilized a portion of the net proceeds of the sale to
reduce outstanding debt and expects to utilize most of the remaining net
proceeds also for debt and preferred stock reduction.
The Company realized a net gain on the sale related to the
transaction of approximately $19.2 million, and this amount has been recorded
as a deferred liability at June 30, 1999 on the Consolidated Balance Sheets.
The gain will be utilized to reduce electric rates effective March 1, 2000,
with the introduction of retail competition. For a discussion of the
restructuring of the electric utility industry in the State of Maine, please
see the 1998 Form 10-K.
ALTERNATIVE RATE PLAN FILING - In May 1999, the Maine Public Utilities
Commission (MPUC) approved a portion of the Company's February 1999 request
for rate adjustment under the so-called Alternative Rate Plan (ARP).
Pursuant to the MPUC Order, the Company implemented an increase in its
standard tariff of about 1.36% effective June 1, 1999. An alternative rate
plan is a method of utility regulation intended to replace the costly,
controversial periodic rate increase proceedings of the past. Under such a
plan, utilities are permitted to adjust rates annually based on a formula
tied to inflation minus a "productivity factor". Adjustments for certain
specified categories of costs that are unrelated to inflation are also
permitted. The MPUC implemented this plan for the Company in 1998.
The 1999 increase was comprised entirely of the recovery of some of
the specified categories of costs that are unrelated to inflation. This was
made up mostly of the recovery of a portion (about $1.4 million, or about
25%) of the costs incurred to recover from the 1998 ice storm. The inflation
component actually contributed to a reduction of the 1999 adjustment, because
the productivity factor offset of 1.2% exceeded the inflation rate of .9%.
The ARP will not be in effect with the implementation of new rates on March
1, 2000, and the Company is uncertain if any alternative rate plan will be
adopted in the future.
Also in connection with the ARP Order, as a result of the sale of the
Company's generation assets, the Company was required to defer all savings,
for the period from the asset sale through February 29, 2000, associated with
the sale of its generating assets and the simultaneous purchased power
buyback agreement with PP&L Global. Any net savings for this period are to
be flowed-back to customers effective with new rates on March 1, 2000. The
Company filed its plan for measuring the net savings with the MPUC in June
1999, and the determination of the methodology for measuring the savings will
be incorporated into the Company's current rate proceeding with the MPUC. The
Company utilized this methodology to calculate a net expense, as compared to
savings, for the month of June 1999 in the amount of approximately $1.2
million. This net expense has been recorded as an addition to the Company's
electric operating revenues for the second quarter of 1999 and a reduction of
the previously discussed deferred asset sale gain. The reason for the net
expense in June 1999 is due to the Company incurring unusually high purchased
power costs during the extremely hot weather in early June 1999, as a result
of the Company no longer owning certain generation and transmission assets
subsequent to the asset sale to PP&L Global. Since these high costs would
not have occurred if the Company had not sold these assets, the Company has
recorded the net expense for June 1999 as a reduction of the deferred asset
sale gain.
RESUMPTION OF DIVIDEND ON COMMON STOCK - At a regularly scheduled Board of
Directors meeting held on June 16, 1999, the Board of Directors of the
Company declared a cash dividend on its common stock of $.15 per share,
payable July 20, 1999 to shareholders of record on June 30, 1999. This was
the first common stock dividend since the Company suspended common dividend
payments in March 1997 due to financial difficulties triggered by problems at
the Maine Yankee nuclear generating plant. The Company has a 7% ownership
interest in Maine Yankee, which was permanently shut down later in 1997 and
is now in the process of being decommissioned. Prior to suspending the common
dividend in March 1997, The Company had been paying quarterly dividends on
its common stock of $.18 per share.
REVENUES
Electric operating revenue increased by $698,000, or 1.5% in the
second quarter of 1999 due principally to the impact of the previously
discussed 1.36% rate increase on June 1, 1999, an overall 2.35% increase in
KWH sales (excluding off-system sales, which are sales related to power pool
and interconnection agreements and resales of purchased power) in the 1999
quarter, and the previously discussed deferred expense in June 1999
associated with the generation asset sale. KWH sales in the second quarter of
1999 were positively affected by the weather. The increased revenues were
offset by a $735,000 reduction in off-system sales in the 1999 quarter and a
$661,000 reduction in revenue sharing from the Company's largest industrial
customer (See the 1998 Form 10-K for further discussion of this revenue
sharing arrangement).
EXPENSES
Fuel for generation and purchased power expense decreased $1.2
million or 6% in the second quarter of 1999 as compared to 1998. The
decreased expense was a result of several factors. The previously discussed
settlement of the dispute with NEPOOL resulted in a $896,000 reduction in
expense in the second quarter of 1999. The Company recorded a benefit of
$963,000 in the 1999 quarter, as compared to $500,000 for the 1998 quarter,
related to savings realized from the restructuring of the Penobscot Energy
Recovery Company (PERC) purchased power contract in June 1998 (See the 1998
Form 10-K for a complete discussion of this transaction). Fuel and purchased
power expense was also reduced in the 1999 quarter by an approximately
$382,000 increase in equity earnings from the Company's investment in MEPCO,
which was principally the result of a gain on sale of right-of-ways in
connection with a natural gas transmission pipeline currently being
constructed in Maine. The previously discussed $735,000 reduction in off-
system sales also impacted the decrease in fuel and purchased power expense
in the second quarter of 1999.
The costs of purchases from non-utility generators were lower in the
second quarter of 1999 due mostly to lower production at PERC, resulting in
an overall decrease in expense of about $.6 million from 1998. Purchased
power expenses also increased by about $.5 million in the 1999 second quarter
due to the May 27th sale of the Company's hydroelectric facilities and
subsequent buyback contract with PP&L Global for the power from the plants.
Replacement power costs for other entitlements in Wyman #4, Hydro-Quebec and
MEPCO transmission were significant in June of 1999, largely causing a $1.5
million increase in oil-related and NEPOOL purchased power costs for the
period. This was due to very unusual circumstances in NEPOOL, with record-
breaking loads while many generators were still out of service on spring
maintenance. Further, in preparation for utility restructuring, new market
rules were implemented in NEPOOL on May 1, 1999 which sets prices for
replacement purchases from the pool at open market levels related to supply
and demand as opposed to marginal fuel costs, as was the case in the prior
year. The result was on-peak power prices that were two to three times as
great as would normally occur during June.
Settlement payments associated with the Company's fuel risk
management program increased by approximately $.5 million in the second
quarter of 1999 compared to the 1998 quarter. The Company continued its hedge
program in late 1998 and increased its hedge volume by 30% as a result of
replacing a fixed price power contract with a residual oil indexed contract.
Although the spot price of residual oil was largely unchanged in the 1999
quarter, fixed prices that the Company agreed to pay were lower, resulting in
the savings. See the 1998 Form 10-K for a more complete discussion of the
Company's fuel risk management program.
Other operation and maintenance (O&M) expense increased by $318,000
in the second quarter of 1999 as compared to 1998. Increasing other O&M
expense in the 1999 quarter was a $160,000 increase in postretirement and
active medical costs; and the Company incurred approximately $384,000 of
incremental non-labor expenditures in the second quarter of 1999 related to
electric utility industry restructuring activities, costs associated with
assessment and testing of systems for year 2000 (Y2K) compliance, and an
upgrade to the Company's customer information system. These increases were
offset to some extent by a $142,500 reduction in bad debt expense in the 1999
quarter, resulting from lower levels of write-offs, and a $146,000 reduction
in amortization expense associated with deferred demand-side management (DSM)
costs, which resulted from the end of the amortization of a portion of the
deferred DSM costs in 1999.
O&M payroll expense increased by $161,000 due principally to the 2.6%
union wage increase effective January 1, 1999, other various non-union wage
increases, and higher employee levels in 1999. These increases were offset
to some extent by a reduction of 18 employees in connection with the sale of
the Company's hydro generation facilities at the end of May 1999 (See
previous discussion).
Depreciation and amortization expense decreased $94,000 in the second
quarter of 1999 as compared to the 1998 quarter due principally to the sale
of the Company's generation assets in May 1999. This reduction was offset
somewhat by the impact of anticipated 1999 property additions.
The $251,000 increase in amortization of contract buyouts and
restructuring in the 1999 quarter was also due principally to the June 1998
restructuring of the PERC purchased power contract. In the second quarter of
1999 the Company recorded $250,000 of amortization related to deferred PERC
contract restructuring costs. There was no amortization of the PERC contract
restructuring costs in the 1998 quarter.
The increase in property and other taxes in the second quarter of
1999 was due principally to greater property taxes, which were primarily a
result of electric plant additions, and higher payroll taxes, which resulted
from the previously discussed increase in payroll expense in the 1999
quarter.
The increase in income taxes was principally a function of greater
earnings in the second quarter of 1999 as compared to the 1998 quarter. See
Footnote 2 to the Consolidated Financial Statements for a reconciliation of
the Company's effective income tax rate.
The increase in other income in the 1999 quarter was due primarily to
interest income realized from invested generation asset sale proceeds and a
reduction in start-up costs associated with non-core business ventures by the
Company, offset by higher non-operating income taxes.
Allowance for funds used during construction (AFDC) decreased in 1999
relative to 1998 due principally to $483,000 in carrying costs being recorded
on the previously discussed deferred asset sale gain and the deferred gain on
sale of Graham Station property (See the 1998 Form 10-K for a complete
discussion of this property sale). These carrying costs in the 1999 quarter
include $144,000 previously recorded on the deferred gain on sale of Graham
Station property, which were reclassified from long-term debt interest
expense to AFDC in June 1999. The increase in AFDC was also impacted by
higher levels of construction work in progress in the 1999 quarter, offset
somewhat by reductions in carrying costs recorded on deferred incremental
Maine Yankee and ice storm costs in the second quarter of 1999 as compared to
the 1998 quarter. With the ARP rate increase on June 1, 1999, the Company
ceased accruing carrying costs on these deferred costs.
Long-term debt interest expense decreased $666,000 in the second
quarter of 1999 as compared to 1998 due principally to a total of $1.6 in
principal payments on the Company's 12.25% first mortgage bonds in July 1998
and January 1999; a $12.3 million principal payment in June 1998 on the
Finance Authority of Maine Revenue Notes; monthly principal payments from
June 1998 through June 1999 amounting to $5.2 million on the $24.8 million
medium term notes; principal repayments of $6.2 million and $38.8 million in
January and June 1999, respectively, on the $45 million medium term notes;
and a principal payment of $30 million in June, 1998, on the Company's old
medium term notes. The $38.8 million repayment of the remaining outstanding
medium term notes was accomplished through the utilization of the generation
asset sale proceeds. The decrease was also affected by $144,000 of carrying
costs reclassified to AFDC in the 1999 quarter. These increases were offset
to some extent by the issuance of the $45 million term loan in June 1998.
Other interest expense decreased due principally to a $13.4 million
reduction in weighted average short-term borrowings outstanding in the 1999
quarter as compared to 1998. The Company fully repaid the outstanding
balance under its revolving credit line in April 1999, and no new borrowings
have subsequently occurred. These decreases were offset to some extent by a
$91,000 increase in the amortization of debt issuance costs in the second
quarter of 1999, principally as a result of the previously discussed medium
term note issuances in 1998.
SIX MONTHS OF 1999 AS COMPARED TO THE SIX MONTHS OF 1998 EARNINGS
Basic earnings per common share for the six months ended June 30,
1999 were $.97, as compared to $.55 per common share for the 1998 period.
The increased earnings were largely the result of the June 1, 1999 rate
increase, and the one-time benefit related to the settlement of the NEPOOL
dispute, both of which were previously discussed, as well as an increase in
KWH sales in the 1999 period, a one-time benefit of $802,000 ($475,000 after
taxes)due to the settlement, by NEPOOL, of a contract dispute with Hydro-
Quebec (HQ), and the February 13, 1998 rate increase authorized by the MPUC
designed to increase annual revenues by approximately $13.2 million. That
amount included the $5.1 million authorized in a temporary rate increase that
became effective on July 1, 1997.
REVENUES
Electric operating revenue increased by $1.8 million, or 1.9% in the
first six months of 1999 due principally to the impact of the previously
discussed rate increases on February 13, 1998 and on June 1, 1999, an overall
2.87% increase in KWH sales (excluding off-system sales) in the 1999 period,
and the previously discussed deferred expense in June 1999 associated with
the generation asset sale. The increase in KWH sales in 1999 was affected by
service interruptions during the ice storm in January 1998, slightly colder
weather in the winter and spring of 1999, and warmer weather in June 1999 as
compared to June 1998. The increased revenues were offset by a $820,000
reduction in off-system sales in the 1999 period and a $1.2 million reduction
in revenue sharing from the Company's largest industrial customer.
EXPENSES
Fuel for generation and purchased power expense decreased $4.1
million or 9.8% in the 1999 period as compared to 1998. The decreased expense
was a result of several factors. The previously discussed settlements of the
disputes with HQ and NEPOOL resulted in $747,000 and $896,000 reductions in
expense, respectively in 1999. The Company recorded a benefit of $1.5
million in the 1999 period, as compared to $500,000 for 1998, related to
savings realized from the restructuring of the PERC purchased power contract.
Fuel and purchased power expense was also reduced in 1999 by a $390,000
increase in equity earnings from the Company's previously discussed MEPCO
investment. The $820,000 reduction in off-system sales in the 1999 period
also impacted the decrease in fuel and purchased power expense.
Excluding the impact of the unusually high replacement power costs
incurred in June 1999, which are discussed above, there was a reduction in
oil-related and other purchased power costs in the 1999 period as compared to
1998. A significant portion of the Company's power contracts are directly
tied to the price of residual oil, which, while it was largely unchanged in
the second quarter of 1999 as compared to 1998, was 17% lower in the first
quarter of 1999 as compared to 1998. Also, prior to the generation asset sale
at the end of May 1999, purchased power expenses were reduced by an increase
in power generation by the Company's hydroelectric facilities.
Other O&M expense increased by $1.6 million in the 1999 period as
compared to 1998. Increasing other O&M expense in 1999 was a $523,000
increase in postretirement and active medical costs; advertising expenses
with the Company's third party advertising agency increased by $238,000 in
the first six months of 1999 as compared to 1998; and the Company incurred
approximately $626,000 of incremental non-labor expenditures in the 1999
period related to electric utility industry restructuring activities, costs
associated with Y2K compliance, and an upgrade to the Company's customer
information system.
Depreciation and amortization expense decreased $188,000 in the 1999
period as compared to 1998. The decrease was affected by the previously
discussed generation asset sale, and effective February 13, 1998, in
connection with the Company's last rate order, the Company began amortizing
its $3.6 million overaccumulated depreciation reserve over a 24 month period
($946,000 amortization in 1999 as compared to $675,000 in 1998), thus causing
a reduction in depreciation expense. This decrease was offset somewhat by
the impact of anticipated 1999 property additions.
The $359,000 increase in amortization of contract buyouts and
restructuring in 1999 was due principally to previously discussed PERC
purchased power contract restructuring. This was offset to some extent by the
February 1998 rate order, whereby the MPUC required the Company to reduce the
amortization of the deferred regulatory asset associated with the 1993 buyout
of one of its high-priced non-utility generator contracts by an annualized
amount of approximately $1.1 million, effective February 13, 1998. The
amortization of this regulatory asset amounted to $1.38 million in the 1999
period as compared to $1.52 million in 1998.
The $160,000 increase in property and other taxes in the 1999 period
was due principally to greater property taxes, which were primarily a result
of electric plant additions.
The increase in income tax expense in the first six months of 1999
was due principally to the reasons previously discussed for the second
quarter of 1999 as compared to 1998.
The $311,000 increase in other income in 1999 was due principally to
the previously discussed reasons for the second quarter of 1999 as compared
to 1998, as well as $54,000 in interest income received attributable to the
previously discussed HQ settlement.
The decreases in AFDC, long-term debt and other interest expense in
the first six months of 1999 as compared to the first six months of 1998 were
principally due to the reasons previously discussed for the quarters ended
June 30, 1999 and 1998.
LIQUIDITY AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events in the first
six months of 1999 and 1998 as they affect the Company's liquidity. Net
increase in cash from operating activities was $31.7 million in 1999 as
compared to $13.4 million in 1998. Positively impacting cash flows from
operating activities in the 1999 period as compared to 1998 were the
beneficial impacts of the 5.83% and 1.36% rate increases effective February
13, 1998 and June 1, 1999, respectively, a $1.75 million payment received in
the first quarter of 1999 quarter related to a terminated purchased power
contract (See 1998 Form 10-K), and $4.0 million in incremental costs incurred
in 1998 in connection with the January 1998 ice storm. In addition, in the
1998 period cash flows were reduced by $1.4 million due to the effect of a
large customer who prepaid its electric usage for a one-year period in the
third quarter of 1997.
Construction expenditures were $1.0 million greater in the 1999
period due principally to increased construction activity on the transmission
and distribution system in 1999. As previously discussed, the Company
received approximately $79.6 million in proceeds related to its generation
asset sale in late May 1999.
The reduction in preferred dividends paid resulted principally from a
$1.5 million sinking fund payment made on the Company's 8.76% mandatory
redeemable preferred stock in December 1998.
The increase in payments on long-term debt is due principally to the
previously discussed principal payment activity. The Company utilized $6.2
million in proceeds, from the September 1998 property sale to Casco Bay
Energy, released by the trustee in January 1999, to repay principal in
connection with the $45 million medium term notes. Upon receipt of the
generation asset sale proceeds in late May 1999 the Company immediately
deposited $45.5 million with the First Mortgage Bond Trustee. The Company
then utilized $38.8 million of this amount to repay the remaining outstanding
principal on the medium term notes in early June 1999.
As previously discussed, the Company has maintained full borrowing
capacity under its revolving credit facility for most of the second quarter
of 1999. This elimination of short-term borrowings in the 1999 period is
principally a result of the previously discussed enhancements in operating
cash flows as well as the current availability of generation asset sale
proceeds which have not yet been utilized to repay outstanding long-term
debt.
In June 1998, in connection with entering into an Amended and
Restated Revolving Credit and Term Loan Agreement, the Company deposited $4.6
million of proceeds from the financing with a third party trustee to secure
the existing letter of credit related to the Pollution Control Revenue Bonds,
until a new letter of credit could be issued.
For additional discussion of liquidity and capital resources, see the
Company's 1998 Form 10-K.
Y2K UPDATE
The Company has established a structured approach in connection with
its Y2K compliance activities, which inventories and prioritizes its
hardware, software and embedded technology systems including electrical
transmission & distribution system, computer network, software applications,
personal computers, telecommunications equipment and facilities. The Company
has attained its goal of inventorying and prioritizing and has completed
testing of the systems and devices that support its mission critical
operations as of June 30, 1999.
The Company has also identified and contacted the third parties with
which it has a material relationship in order to establish their Y2K status
in a timely fashion, and is continuing to do so. In addition, the Company is
coordinating its efforts with the NEPOOL/ISO New England Year 2000 Joint
Oversight Committee which has been given responsibility for operational
reliability of the NEPOOL Control Area and has complied with North American
Electric Reliability Council (NERC) Y2K guidelines and reporting
requirements. In its June 30th NERC filing, the Company reported that all of
its mission critical systems were "Y2K Ready". "Mission critical" systems are
defined as those that are used to produce and deliver sustained and reliable
electricity to customers. For the Company these systems include:
- - The entire electrical transmission & distribution system,
- - Telecommunications systems (phone and radio),
- - Computer networks including division offices,
- - Customer Information System (outage processing),
- - Geographical Information System, and
- - Key facilities devices (generators and uninterrupted power supply
systems).
With mission critical Y2K work complete, the Company will continue to
assess and test various business systems and will be refining and practicing
contingency plans. In addition, we will track and test, where necessary,
changes to our systems to ensure no Y2K related problems are introduced.
The Company has also prepared comprehensive contingency plans for its
own operations and continues to monitor the integrated contingency planning
efforts of NERC and the Northeast Power Coordinating Council.
The estimated cost to conduct testing, develop or modify contingency
plans, and replace non-compliant technologies is approximately $2 million,
which includes both internal and external costs. Approximately $850,000 of
these estimated costs are expected to be capitalized, instead of being
charged to expense, since the costs relate principally to investments in new
equipment and technologies and not the modification of existing systems.
During the first six months of 1999, approximately $700,000 was expended in
connection with the Y2K, of which $200,000 was capitalized and $500,000
charged to expense. Through June 30, 1999, on a cumulative basis,
approximately $1.1 million has been expended, of which $520,000 has been
capitalized and $580,000 charged to expense. Time and cost estimates are
based on currently available information and could be affected by the ability
to correct all relevant computer codes and equipment, and the Y2K readiness
of the Company's business partners, among other factors.
There is no certainty as to whether the Company will be able to solve
its potential Y2K issues. Consequently, the Company is in the process of
identifying and verifying realistic failure scenarios, which will require
contingency plans. While its analysis has not been completed, the Company
anticipates establishing a prioritized list of potential failures with a
formal contingency plan for each one deemed critical to its ongoing
operations during 1999.
Based on our testing to date, the Company believes its plans of
action are adequate for Y2K compliance of its critical systems and to reduce
the risk of external impacts to its operations. Nevertheless, achieving Y2K
compliance is subject to the risks and uncertainties described above and
adverse effects, should they occur, could be material despite the Company's
efforts to prevent or mitigate them.
NEW ACCOUNTING PRONOUNCEMENTS
In May 1999, the Financial Accounting Standards Board voted to delay
for one year the effective date of Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (FASB 133). The new effective date for implementing this
pronouncement is for fiscal years beginning after June 15, 2000. The effects
of the adoption on the Company's financial statements are currently not
known. The Company believes its interest rate swap agreements will qualify
for hedge accounting treatment under FASB 133.
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, 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, the Y2K issue, 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 1999 1998
-------- --------
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original cost $ 288,575 $ 352,975
Less - Accumulated depreciation and
amortization 84,981 101,633
-------- --------
$ 203,594 $ 251,342
Construction work in progress 14,045 13,930
-------- --------
$ 217,639 $ 265,272
Investments in corporate joint ventures:
Maine Yankee Atomic Power Company $ 5,451 $ 5,439
Maine Electric Power Company, Inc. 860 439
-------- --------
$ 223,950 $ 271,150
-------- --------
OTHER INVESTMENTS, principally at cost $ 6,359 $ 5,882
-------- --------
FUNDS HELD BY TRUSTEE, at cost $ 30,301 $ 29,868
-------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 30,638 $ 2,946
Accounts receivable, net of reserve 19,441 17,558
Unbilled revenue receivable 9,730 12,086
Inventories, at average cost:
Material and supplies 2,664 2,909
Fuel oil 65 16
Prepaid expenses 180 1,129
-------- --------
Total current assets $ 62,718 $ 36,644
-------- --------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net
of accumulated amortization of $31,023 in
1999 and $30,173 in 1998 $ 27,819 $ 28,669
Costs to terminate/restructure power contracts,
net of accumulated amortization of
$90,460 in 1999 and $80,059 in 1998 125,994 136,979
Maine Yankee decommissioning costs 47,764 50,055
Deferred regulatory assets 28,843 32,996
Demand-side management costs 511 779
Other 8,557 12,666
-------- --------
Total deferred charges $ 239,488 $ 262,144
-------- --------
Total assets $ 562,816 $ 605,688
======== ========
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 1999 1998
-------- --------
CAPITALIZATION:
Common stock investment $ 124,782 $ 118,864
Preferred stock 4,734 4,734
Preferred stock subject to mandatory
redemption, exclusive of current sinking
fund requirements 7,635 7,604
Long-term debt, net of current portion 206,487 263,028
-------- --------
Total capitalization $ 343,638 $ 394,230
-------- --------
CURRENT LIABILITIES:
Notes payable - banks $ - $ 12,000
-------- --------
Other current liabilities -
Current portion of long-term debt and sinking
fund requirements on preferred stock $ 22,442 $ 27,109
Accounts payable 16,029 13,896
Dividends payable 1,368 295
Accrued interest 3,163 3,474
Customers' deposits 369 329
Current income taxes payable 1,213 86
-------- --------
Total other current liabilities $ 44,584 $ 45,189
-------- --------
Total current liabilities $ 44,584 $ 57,189
-------- --------
DEFERRED CREDITS AND RESERVES:
Deferred income taxes - Seabrook $ 14,437 $ 14,880
Other accumulated deferred income taxes 65,852 63,775
Maine Yankee decommissioning liability 47,765 50,055
Deferred regulatory liability 9,131 9,618
Deferred gain on asset sale 23,896 4,510
Unamortized investment tax credits 928 1,721
Accrued pension and postretirement
benefit costs 8,932 7,770
Other 3,653 1,940
-------- --------
Total deferred credits and reserves $ 174,594 $ 154,269
-------- --------
Total Stockholders' Investment
and Liabilities $ 562,816 $ 605,688
========= =========
See notes to the consolidated financial statements.
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
000's Omitted
(Unaudited)
<CAPTION>
June 30, Dec. 31,
1999 1998
--------- ---------
<S>
COMMON STOCK INVESTMENT <C> <C>
Common stock, par value $5 per share- $ 36,817 $ 36,817
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares in 1999 and 1998
Amounts paid in excess of par value 58,970 59,054
Retained earnings 28,995 22,993
--------- ---------
Total common stock investment $ 124,782 $ 118,864
--------- ---------
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
--------- ---------
8.76%, Subject to mandatory redemption requirements-
Callable at 103.13% if called on or prior to December 27, 1999,
150,000 shares authorized and 90,000 shares outstanding
in 1999 and 1998 $ 9,229 $ 9,198
Less: Sinking fund requirements 1,594 1,594
--------- ---------
$ 7,635 $ 7,604
--------- ---------
LONG-TERM DEBT
First Mortgage Bonds-
10.25% Series due 2019 $ 15,000 15,000
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
12.25% Series due 2001 2,930 3,743
--------- ---------
$ 102,930 $ 103,743
Less: Sinking fund requirements 1,778 1,675
--------- ---------
Total first mortgage bonds $ 101,152 $ 102,068
--------- ---------
Variable rate demand pollution control revenue bonds
Series 1983 due 2009 $ 4,200 $ 4,200
--------- ---------
Other Long-Term Debt-
Finance Authority of Maine - Taxable Electric Rate
Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 100,600 $ 113,700
Medium Term Notes, Variable interest rate- LIBO Rate plus 1.125%,
due 2002 19,605 21,900
Medium Term Notes, Variable interest rate- LIBO Rate plus 2%,
due 2000 - 45,000
--------- ---------
$ 120,205 $ 180,600
Less: Current portion of long-term debt 19,070 23,840
--------- ---------
$ 101,135 $ 156,760
--------- ---------
Total long-term debt $ 206,487 $ 263,028
--------- ---------
Total Capitalization $ 343,638 $ 394,230
========= =========
See notes to the consolidated financial statements.
</TABLE>
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
000's Omitted
(Unaudited)
<CAPTION>
Six Months Ended
June 30, June 30,
1999 1998
--------- ---------
<S> <C> <C>
Cash Flows From Operating Activities:
Net income $ 7,664 $ 4,675
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 4,866 5,054
Amortization of Seabrook Nuclear Project 850 850
Amortization of contract buyouts and restructuring 10,401 10,041
Other amortizations 1,112 885
Allowance for equity funds used during construction (301) (178)
Deferred income tax provision and investment tax credits 4,335 2,829
Asset sale interim revenue requirement deficiency (1,083) -
Changes in assets and liabilities:
Payment received related to terminated purchased power contract 1,750 -
Costs to restructure purchased power contract (599) (7,448)
Deferred incremental ice storm costs - (4,042)
Deferred incremental Maine Yankee costs - (1,240)
Deferred Maine Yankee refueling costs - 286
Deferred income tax impacts associated with asset sale (2,280) -
Accounts receivable, net and unbilled revenue 467 1,467
Accounts payable 1,557 (1,235)
Accrued interest (311) (495)
Current and deferred income taxes 1,962 (145)
Accrued postretirement benefit costs 396 323
Deferred revenue - (1,378)
Other current assets and liabilities, net 1,319 32
Other, net (404) 3,072
--------- ---------
Net Increase in Cash From Operating Activities: $ 31,701 $ 13,353
--------- ---------
Cash Flows From Investing Activities:
Construction expenditures $ (9,899) $ (8,832)
Allowance for borrowed funds used during construction 69 (302)
Asset sale proceeds 79,588 -
--------- ---------
Net Increase (Decrease) in Cash From Investing Activities $ 69,758 $ (9,134)
--------- ---------
Cash Flows From Financing Activities:
Dividends on preferred stock $ (559) $ (624)
Payments on long-term debt (61,208) (50,188)
Proceeds from issuances of long-term debt, net of
capital reserve fund requirements - 68,300
Short-term debt, net (12,000) (12,000)
Special deposit associated with securing letter of credit - (4,592)
--------- ---------
Net (Decrease) Increase in Cash From Financing Activities $ (73,767) $ 896
--------- ---------
Net Increase in Cash and Cash Equivalents $ 27,692 $ 5,115
Cash and Cash Equivalents at Beginning of Period 2,946 937
--------- ---------
Cash and Cash Equivalents at End of Period $ 30,638 $ 6,052
========= =========
Cash Paid During the Six Months For:
Interest (Net of Amount Capitalized) $ 11,233 $ 12,352
Income Taxes 179 141
========= =========
See notes to consolidated financial statements.
</TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
000's Omitted
(Unaudited)
Amounts Total
Paid in Common
Common Excess of Retained Stock
Stock Par Value Earnings Investment
BALANCE DECEMBER 31, 1997 $36,817 $56,969 $12,772 $106,558
Net income - - 4,675 4,675
Cash dividends declared on-
Preferred stock - - (592) (592)
Other - - (31) (31)
Issuance of warrants - 2,036 - 2,036
---------- ---------- ----------------------
BALANCE JUNE 30, 1998 $36,817 $59,005 $16,824 $112,646
========== ========== ======================
BALANCE DECEMBER 31, 1998 $36,817 $59,054 $22,993 $118,864
Net income - - 7,664 7,664
Cash dividends declared on-
Preferred stock - - (527) (527)
Common stock - - (1,105) (1,105)
Other - - (30) (30)
Exercise of warrants-cash paid
in lieu of issuing shares - (84) - (84)
---------- ---------- ----------------------
BALANCE JUNE 30, 1999 $36,817 $58,970 $28,995 $124,782
========== ========== ======================
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
-------------
(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 1998 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, 1999 and the results of operations and cash
flows for the periods ended June 30, 1999 and 1998.
The Company's significant accounting policies are described in the
Notes to the Consolidated Financial Statements included in its 1998
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,
1999 1998
Amount % Amount %
(Dollars in Thousands)
Federal income tax provision
at statutory rate $4,427 35 $2,552 35
(Less) Plus permanent reductions
in tax expense resulting
from statutory exclusions
from taxable income (86) (1) 33 -
------ --- ----- ---
Federal income tax provision before
effect of temporary differences
and investment tax credits $4,341 34 $2,585 35
(Less) temporary differences that
are flowed through for rate-
making and accounting purposes (248) (2) (133) (2)
(Less) utilization and amortization
of investment tax credits (95) (1) (107) (2)
------ --- ----- ---
Federal income tax provision $3,998 31 $2,345 31
====== === ===== ===
(3) INVESTMENT IN JOINTLY OWNED FACILITIES:
Condensed financial information for Maine Yankee Atomic Power
Company (Maine Yankee), Maine Electric Power Company, Inc. (MEPCO),
Bangor-Pacific Hydro Associates (BPHA), Chester SVC Partnership
(Chester) and Bangor Gas Company, LLC (Bangor Gas) is as follows:
MAINE YANKEE MEPCO
(Dollars in Thousands)
(Unaudited)
Operations for Six Months Ended
-------------------------------------
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
OPERATIONS: -------- -------- -------- --------
As reported by investee-
Operating revenues $ 34,553 $ 66,538 $ 1,409 $ 1,610
========= ========= ======== =========
Earnings applicable to
common stock $ 2,520 $ 4,209 $ 3,195 $ 526
========= ========= ======== =========
Company's reported equity-
Equity in net income $ 176 $ 295 $ 454 $ 75
(Deduct) Add-Effect of
adjusting Company's
estimate to actual (260) 4 (23) (34)
--------- -------- ------- ---------
Amounts reported by Co. $ (84) $ 299 $ 431 $ 41
========== ========= ======== =========
MAINE YANKEE MEPCO
(Dollars in Thousands)
(Unaudited)
Financial Position at
-------------------------------------
June 30, Dec. 31, June 30, Dec. 31,
1999 1998 1999 1998
FINANCIAL POSITION: --------- --------- -------- --------
As reported by investee-
Total assets $1,152,052 $1,183,298 $ 9,561 $ 5,515
Less-
Preferred stock 16,200 16,800 - -
Long-term debt 56,000 68,433 120 220
Other liabilities
and deferred credits 1,002,217 1,018,575 3,055 2,079
----------- ---------- ------- -------
Net assets $ 77,635 $ 79,490 $ 6,386 $ 3,216
=========== ========== ======= =======
Co.'s reported equity-
Equity in net assets $ 5,434 $ 5,564 $ 907 $ 457
Add(Deduct)- Effect
of adjusting Company's
estimate to actual 17 (125) (47) (18)
----------- ---------- ------- -------
Amounts reported by Co. $ 5,451 $ 5,439 $ 860 $ 439
=========== ========== ======= =======
BPHA Chester
------------------- ------------------
(Dollars in Thousands)
(Unaudited)
Operations for Six Months Ended
-----------------------------------------
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
-------- -------- -------- --------
OPERATIONS:
As reported by investee-
Operating revenues $ 3,956 $ 3,951 $ 2,137 $ 2,194
======= ======= ======= =======
Net Income $ 1,646 $ 1,542 $ - $ -
======= ======= ======= =======
Co.'s reported equity
in net income $ 823 $ 771 $ - $ -
======= ======= ======= =======
Financial Position at
June 30, Dec. 31, June 30, Dec. 31,
1999 1998 1999 1998
--------- -------- -------- --------
FINANCIAL POSITION:
As reported by investee-
Total assets $ 37,648 $38,324 $25,759 $26,478
Less-
Long-term debt 25,200 26,300 24,063 24,654
Other liabilities 2,495 2,517 1,696 1,824
-------- ------- ------- -------
Net assets $ 9,953 $ 9,507 $ - $ -
======== ======= ======= =======
Co.'s reported equity
in net assets $ 4,977 $ 4,754 $ - $ -
======== ======= ======= =======
At June 30, 1999, and December 31, 1998, the Company's wholly owned
subsidiary, Penobscot Natural Gas Company, had a $215,000 and $77,000
equity investment in Bangor Gas, respectively and recorded equity losses
in Bangor Gas of approximately $112,000 and $47,000 for the six months
ended June 30, 1999 and 1998, respectively. At June 30, 1999 and
December 31, 1998, Bangor Gas' total assets, principally
construction work in progress, amounted to $2.7 million and $2.6
million, respectively.
(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 Quarters For the Six Months
Ended Ended
-------------------- -------------------
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
-------- -------- -------- --------
Earnings
applicable to
common stock $ 3,174 $ 1,956 $ 7,107 $ 4,052
-------- -------- ------- -------
Average common
shares outstanding 7,363 7,363 7,363 7,363
Plus: incremental
shares from assumed
conversion 949 24 944 12
-------- -------- ------- -------
Average common shares
outstanding plus
assumed warrants
converted 8,312 7,387 8,307 7,375
-------- -------- ------- -------
Basic earnings
per common share $ .43 $ .27 $ .97 $ .55
======== ======= ======= =======
Diluted earnings
per common share $ .38 $ .26 $ .86 $ .55
======== ======= ======= =======
(5) GENERATION ASSET SALE:
On May 27, 1999, the Company completed most of the transaction for
the sale of its electric generating assets and certain trans-
mission rights to PP&L Global. The purchase price for the assets
transferred was $79 million.
The sale involved all but one of the Company's hydroelectric plants
on the Penobscot, Piscataquis, and Union rivers and Bangor
Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in
Yarmouth, Maine--a total base load capacity of 83 megawatts. The sale
also involved a transfer by the Company of rights to transmit power over
the Maine Electric Power Company (MEPCO) transmission facilities
connecting NEPOOL to New Brunswick Canada; the Company's rights as a
participant in the regional utilities' agreement with Hydro-Quebec
pursuant to an agency agreement; and the Company's rights to develop a
second high voltage transmission line that will connect NEPOOL to New
Brunswick, Canada.
As discussed in the 1998 Form 10-K, the Company and other Maine
utilities were required to sell their generation assets as a result of
the comprehensive electric utility industry restructuring law adopted in
Maine in 1997. The Company conducted an auction in 1998, which lead to
the signing of a purchase and sale agreement with PP&L Global in late
September 1998. The purchase and sale agreement also includes the
Company's 50% interest in the 13 megawatt West Enfield hydro station on
the Penobscot River. In late July 1999, the Company received $10 million
in proceeds from the transfer of the economic interest in that project.
The Company has utilized a portion of the net proceeds of
the sale to reduce outstanding debt and expects to utilize most of
the remaining net proceeds also for debt and preferred stock reduction.
The Company realized a net gain on sale related to the transaction
of approximately $19.2 million, which includes $2.3 of income tax
expense impacts associated with the excess of the tax over the book gain
on sale. The $19.2 million net gain has been recorded as an other
liability at June 30, 1999 on the Consolidated Balance Sheets. The gain
will be utilized to reduce electric rates effective March 1, 2000, with
the introduction of retail competition. For a discussion of the
restructuring of the electric utility industry in the State of Maine,
please see the 1998 Form 10-K.
(6) ALTERNTIVE RATE PLAN FILING:
In May 1999, the MPUC approved a portion of the Company's February
1999 request for rate adjustment under the so-called Alternative Rate
Plan (ARP). Pursuant to the MPUC Order, the Company implemented an
increase in its standard tariff of about 1.36% effective June 1, 1999.
An alternative rate plan is a method of utility regulation intended to
replace the costly, controversial periodic rate increase proceedings of
the past. Under such a plan, utilities adjust rates annually based on a
formula tied to inflation minus a "productivity factor". Adjustments
for certain specified categories of costs that are unrelated to
inflation are also permitted. The MPUC implemented this plan for the
Company in 1998.
The 1999 increase was comprised entirely of the recovery of some
of the specified categories of costs that are unrelated to inflation.
This was made up mostly of the recovery of a portion (about $1.4
million, or about 25%) of the costs incurred to recover from the 1998
ice storm. The inflation component actually contributed to a reduction
of the 1999 adjustment, because the productivity factor offset of 1.2%
exceeded the inflation rate of .9%. The ARP will not be in effect with
the implementation of new rates on March 1, 2000, and the Company is
uncertain if any alternative rate plan will be adopted in the future.
Also in connection with the ARP Order, as a result of the sale of
the Company's generation assets, the Company was required to defer all
savings, for the period from the asset sale through February 29, 2000,
associated with the sale of its generating assets and the simultaneous
purchased power buyback agreement with PP&L Global. Any net savings for
this period are to be flowed-back to customers effective with new rates
on March 1, 2000. The Company filed its plan for measuring the net
savings with the MPUC in June 1999, and the determination of the
methodology for measuring the savings will be incorporated into the
Company's current rate proceeding with the MPUC. The Company utilized
this methodology to calculate a net expense, as compared to savings, for
the month of June 1999 in the amount of approximately $1.2 million.
This net expense has been recorded as an addition to the Company's
electric operating revenues for the second quarter of 1999 and a
reduction of the previously discussed deferred asset sale gain. The
reason for the net expense in June 1999 is due to the Company incurring
unusually high purchased power costs during the extremely
hot weather in early June 1999, as a result of the Company no longer
owning certain generation and transmission assets subsequent to the asset
sale to PP&L Global. Since these high costs would not have occurred if the
Company had not sold these assets, the Company has recorded the net expense
for June 1999 as a reduction of the deferred asset sale gain.
(7) EXERCISE OF WARRANTS:
In late June 1999, 71,785 common stock warrants, which were issued
in connection with the Penobscot Energy Recovery Company (PERC) purchased
power contract restructuring, were exercised at a market price of $16
1/16 per share. For a complete discussion of the PERC contract
restructuring and the issuance of warrants, please see the 1998 Form 10-
K. The Company exercised its option to pay cash to the holder of the
warrants instead of actually issuing shares of common stock. This
payment, which was made in July 1999 and amounted to approximately
$650,000, has been accrued for at June 30, 1999 on the
Consolidated Balance Sheets. Since the common shares were not issued,
and the Company had recorded the estimated fair value of the warrants
when issued in June 1998 as an addition to the PERC regulatory asset and
additional paid-in capital, an adjustment has been made in connection
with this cash payment option to increase the PERC regulatory asset by
approximately $566,000 and reduce additional paid-in capital by
approximately $84,000 as of June 30, 1999.
Additionally, 50,000 warrants were exercised in July and August
1999, at market prices of $16 11/16 and $16 5/8 per common share,
respectively. In each case the Company exercised its option to pay cash
instead of issuing shares of common stock. The cash payments made
amounted to approximately $484,000 in July and $481,000 in August. The
exercise of these warrants were accounted for consistent with the those
exercised in June 1999.
(8) NEW ACCOUNTING PRONOUNCEMENTS:
In May 1999, the Financial Accounting Standards Board voted to delay
for one year the effective date of Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (FASB 133). The new effective date for implementing this
pronouncement is for fiscal years beginning after June 15, 2000. The
effects of the adoption on the Company's financial statements are
currently not known. The Company believes its interest rate swap
agreements will qualify for hedge accounting treatment under FASB 133.
(9) RECLASSFICATIONS:
Certain 1998 amounts have been reclassified to conform with the
presentation used in Form 10-Q for the quarter ended June 30, 1999.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDING JUNE 30, 1999
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company held its annual meeting of stockholders on May 19, 1999.
The only matter submitted to a vote was the election of three Class I
Directors for terms ending in 2002). The following persons were elected to
fill those positions pursuant to the corresponding tabulations of votes:
Total Vote For Total Vote Against
Marion M. Kane 539,230 13,138
Norman A. Ledwin 539,227 13,141
James E. Rier, Jr. 539,276 13,092
The terms of the following Directors, members of Class II and Class III,
continued after the annual meeting:
Robert S. Briggs
William C. Bullock, Jr.
Jane J. Bush
David M. Carlisle
Joseph H. Cyr
Carroll R. Lee
Item 6. Exhibits and Reports on Form 8-K
Exhibits: None.
Reports on Form 8-K
Two Current Reports on Form 8-K, dated June 4, 1999 and June 17, 1999,
were filed in the second quarter of 1999 regarding sale of generating assets
and transmission rights to PP&L Global (8-K dated June 4, 1999) and
resumption of dividend on common stock (8-K dated June 17, 1999).
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDED JUNE 30, 1999
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)
Dated: August 13, 1999 /s/ Frederick S. Samp
-----------------------
Frederick S. Samp
Vice President - Finance & Law
(Chief Financial Officer)
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from Bangor
Hydro-Electric Company's second quarter Form 10-Q dated 06-30-99 and is
qualified in its entirety by reference to such 10Q.
</LEGEND>
<CIK> 0000009548
<NAME> BANGOR HYDRO-ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 203,594
<OTHER-PROPERTY-AND-INVEST> 57,016
<TOTAL-CURRENT-ASSETS> 62,718
<TOTAL-DEFERRED-CHARGES> 239,488
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 562,816
<COMMON> 36,817
<CAPITAL-SURPLUS-PAID-IN> 58,970
<RETAINED-EARNINGS> 28,995
<TOTAL-COMMON-STOCKHOLDERS-EQ> 124,782
7,635
4,734
<LONG-TERM-DEBT-NET> 206,487
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 20,848
1,594
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 196,736
<TOT-CAPITALIZATION-AND-LIAB> 562,816
<GROSS-OPERATING-REVENUE> 97,521
<INCOME-TAX-EXPENSE> 4,462
<OTHER-OPERATING-EXPENSES> 74,671
<TOTAL-OPERATING-EXPENSES> 79,133
<OPERATING-INCOME-LOSS> 18,388
<OTHER-INCOME-NET> 1,082
<INCOME-BEFORE-INTEREST-EXPEN> 19,470
<TOTAL-INTEREST-EXPENSE> 11,806
<NET-INCOME> 7,664
557
<EARNINGS-AVAILABLE-FOR-COMM> 7,107
<COMMON-STOCK-DIVIDENDS> 1,105
<TOTAL-INTEREST-ON-BONDS> 18,917
<CASH-FLOW-OPERATIONS> 31,701
<EPS-BASIC> $.97
<EPS-DILUTED> $.86
</TABLE>
