SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR SECTION
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended SEPTEMBER 30, 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
September 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 SEPTEMBER 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 - September 30, 1999 and
December 31, 1998 28
Consolidated Statements of Capitalization 30
Consolidated Statements of Cash Flows 31
Consolidated Statements of Common Stock Investment 32
Notes to the Consolidated Financial Statements 33
PART II - OTHER INFORMATION 44
Item 6 - Exhibits and Reports on Form 8-K 45
Signature Page 46
<TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
000's Omitted Except Per Share Amounts
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
1999 1998 1999 1998
-------- -------- --------- ----------
<S> <C> <C> <C> <C>
ELECTRIC OPERATING REVENUES $ 51,452 $ 49,158 $ 148,973 $ 144,859
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OPERATING EXPENSES:
Fuel for generation and purchased power $ 23,183 $ 20,610 $ 60,535 $ 62,014
Other operation and maintenance 7,875 8,433 26,104 25,061
Depreciation and amortization 1,697 2,446 6,563 7,500
Amortization of Seabrook Nuclear Unit 424 424 1,274 1,274
Amortization of contract buyouts
and restructuring 5,200 5,201 15,601 15,242
Taxes -
Property and payroll 1,133 1,289 4,106 4,102
State income 446 363 1,318 775
Federal income 2,163 1,305 5,753 3,388
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$ 42,121 $ 40,071 $ 121,254 $ 119,356
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OPERATING INCOME $ 9,331 $ 9,087 $ 27,719 $ 25,503
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OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction $ (382) $ 131 $ (81) $ 309
Other, net of applicable income taxes 438 113 1,219 582
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$ 56 $ 244 $ 1,138 $ 891
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INCOME BEFORE INTEREST EXPENSE $ 9,387 $ 9,331 $ 28,857 $ 26,394
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INTEREST EXPENSE:
Long-term debt $ 4,120 $ 5,861 $ 14,993 $ 17,122
Other 238 729 1,102 2,158
Allowance for borrowed funds used
during construction (8) (208) 61 (510)
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$ 4,350 $ 6,382 $ 16,156 $ 18,770
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NET INCOME $ 5,037 $ 2,949 $ 12,701 $ 7,624
DIVIDENDS ON PREFERRED STOCK 279 312 836 935
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EARNINGS APPLICABLE TO COMMON STOCK $ 4,758 $ 2,637 $ 11,865 $ 6,689
======== ======== ========= ==========
WEIGHTED AVERAGE NUMBER OF SHARES 7,363 7,363 7,363 7,363
======== ======== ========= ==========
EARNINGS PER COMMON SHARE,
Basic $ .65 $ .36 $ 1.61 $ .91
Diluted .57 .34 1.42 .89
======== ======== ========= ==========
DIVIDENDS DECLARED PER COMMON SHARE $ .15 $ - $ .30 $ -
======== ======== ========= ==========
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 September 30, 1999 resulted in basic earnings per
common share of $.65, as compared to $.36 per common share for the quarter
ended September 30, 1998. The improvement in third quarter earnings is
attributable to an increase in electric sales, a 1.36% increase in rates
related to the Company's alternative rate plan (ARP) effective June 1, 1999
(A discussion of this rate increase is included below under "Important
Current Activities"), a gain on the sale of a subsidiary as part of the
mandatory divestiture of generation assets (A discussion of this sale is
included below under "Important Current Activities"), and one-time income
tax benefits related to the utilization of investment tax credits and
adjustments to the 1998 tax returns filed in September of 1999. The gain on
sale of subsidiary and one-time tax benefits resulted in a $.10 increase in
basic earnings per common share in the 1999 quarter.
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 (PP&L). 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 the New
England Power Pool (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 led to the signing of a
purchase and sale agreement with PP&L 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, and in late August 1999, the Maine Public
Utilities Commission (MPUC) approved the sale to PP&L of Penobscot Hydro
Company, Inc. (Penobscot Hydro), the Company's wholly-owned subsidiary which
held the 50% interest in the West Enfield hydro station. The Company has
utilized a significant portion of the net proceeds of the sale to reduce
outstanding debt and preferred stock.
The Company realized a net gain on the sale related to the PP&L sale
of approximately $23.0 million, and $22.5 million of this amount has been
recorded as a deferred liability at September 30, 1999 on the Consolidated
Balance Sheets. Included in this deferred amount is the accrual of carrying
costs on the deferred gain balance and the net expense associated with the
sale of its generating assets and the simultaneous purchased power buyback
agreement with PP&L (See below for a discussion of the net expense). The
deferred gain will be utilized to reduce electric rates effective March 1,
2000, with the introduction of retail competition. The remaining $.5 million
of the gain relates to the portion of the gain on sale of Penobscot Hydro,
which is allocable to shareholders (recorded as other income in the
Consolidated Statements of Income for the quarter ending September 30, 1999).
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 MPUC approved a portion of
the Company's February 1999 request for rate adjustment under the so-called
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. 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 has
been 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 1999 period in the amount of approximately $1.5 million.
This net expense has been recorded as an addition to the Company's electric
operating revenues and as a reduction of the previously discussed deferred
asset sale gain. Of this amount, the third quarter net expense was
approximately $337,000. The reason for the net expense is due principally to
the Company incurring unusually high purchased power costs during the
extremely hot weather in early June and in July 1999, as a result of the
Company no longer owning certain generation and transmission assets
subsequent to the asset sale to PP&L. Since these high costs would not have
occurred if the Company had not sold these assets, the Company has recorded
the net expense as a reduction of the deferred asset sale gain.
In connection with the Company's current rate proceedings at the
MPUC, the Company's proposed methodology for computing the previously
discussed net expense and the rate used to calculate carrying costs on the
deferred asset sale gain have been challenged by other parties in the rate
proceedings. The Company is uncertain as to which method will ultimately be
approved by the MPUC, and consequently has recorded a reserve of
approximately $1.04 million on the Consolidated Balance Sheets as of
September 30, 1999 to reflect the estimated difference in the computations
between the parties. On the Consolidated Statements of Income, this reserve
is reflected as a $688,000 reduction in electric operating revenues, a
$508,000 reduction in Allowance for Equity Funds Used During Construction and
a $155,000 addition to Allowance for Borrowed Funds Used During Construction.
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. The Company also declared a
cash dividend on its common stock of $.15 per share, payable October 20, 1999
to shareholders of record on September 30, 1999. Prior to suspending the
common dividend in March 1997, the Company had been paying quarterly
dividends on its common stock of $.18 per share.
ELECTRIC UTILITY INDUSTRY RESTRUCTURING - ACCOUNTING ORDER - In September
1999 the Company received an accounting order from the MPUC related to the
Company's request to defer certain incremental costs associated with electric
utility industry restructuring. In connection with the accounting order, the
Company recorded as a deferred asset in September 1999 approximately $314,000
of restructuring costs, which had previously been charged to operation and
maintenance expense in 1999. In connection with the current rate proceeding
with the MPUC, the deferred restructuring costs are expected to start being
recovered on March 1, 2000. Based on the accounting order, the Company will
defer, for future recovery, certain additional incremental restructuring
costs through the advent of retail competition on March 1, 2000.
BANGOR GAS JOINT VENTURE - As reported in the Company's 1998 Form 10-K, the
Company, through a wholly-owned subsidiary, has been participating in a
joint-venture limited liability company, Bangor Gas Company, LLC (Bangor
Gas), to provide natural gas service to the greater Bangor area. Gas
service in the Bangor area has become feasible for the first time because of
development of the Maritimes and Northeast Pipeline Project, extending from
the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the
State of Maine and interconnecting with the Tennessee Gas Pipeline in Dracut,
Massachusetts. The pipeline passes near the Bangor area.
As the restructuring of the electric industry in Maine has developed,
the Company has become increasingly cognizant of the need to focus on its
core electric transmission and distribution business. Consequently the
Company has determined that it no longer intends to participate in the Bangor
Gas joint venture and is exploring options for divesting of its joint venture
interest. The Company's investment in Bangor Gas as of September 30, 1999 is
approximately $307,000 and is recorded as an Other Investment on the
Consolidated Balance Sheets. Management is currently unable to predict the
financial statement impact of this decision.
REGULATORY PROCEEDINGS - As discussed in the 1998 Form 10-K, the principal
provisions of the 1997 Maine Restructuring legislation provide for customers
to have direct retail access to generation services and for deregulation of
competitive electricity providers, commencing March 1, 2000, with
transmission and distribution (T&D) companies continuing to be regulated by
the MPUC. The MPUC is conducting the proceeding that will ultimately
determine the Company's stranded costs and corresponding revenue requirements
and revenue requirements as a T&D utility. The Company expects the MPUC to
issue its order in connection with this proceeding in the near future.
ICE STORM - RECEIPT OF FEDERAL FUNDS - In early October 1999, the Company
received approximately $1.8 million from the federal government in connection
with service restoration costs associated with the major ice storm in January
1998. This amount has been recorded as a reduction of the Company's deferred
ice storm costs and will begin to be returned to customers with the
implementation of new rates effective March 1, 2000.
REVENUES
Electric operating revenue increased by $2.3 million or 4.7% in the
third quarter of 1999 due principally to the impact of the previously
discussed 1.36% rate increase on June 1, 1999, an overall 4.6% increase in
kilowatt hour (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. KWH sales in the third quarter of 1999 were
positively affected by the warm summer weather. The increased revenues were
offset by a reduction in off-system sales in the 1999 quarter and a $504,000
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 increased $2.6
million or 12.5% in the third quarter of 1999 as compared to 1998. Purchased
power expenses increased by about $.9 million in the third quarter of 1999
due to the May 27th sale of the Company's hydroelectric facilities and
subsequent buyback contract with PP&L for the power from the plants. Also as
a result of the sale to PP&L, incremental replacement power costs for other
entitlements in Wyman #4, Hydro-Quebec and MEPCO transmission were $1.8
million greater for the third quarter of 1999 as compared to 1998. 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 approximately two times as great as would
normally occur during July.
Settlement receipts associated with the Company's fuel risk
management program, which are recorded as a reduction of fuel and purchased
power expense, increased by approximately $3 million in the third quarter of
1999 compared to the 1998 quarter. The Company continued its hedge program in
late 1998 and increased its hedge volume by approximately 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 significantly greater in the 1999
quarter, fixed prices that the Company agreed to pay were 13% lower. 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 decreased by $558,000
in the third quarter of 1999 as compared to 1998. Decreasing other O&M
expense in the 1999 quarter was a $314,000 reduction in expenses associated
with the Company's hydroelectric facilities and interest in the Wyman #4
generating plant as a result of the sale to PP&L in May 1999. Also
decreasing other O&M expense in the 1999 quarter was an increase in overhead
expenses allocated to capital projects. This increase was principally a
result of major construction activities being performed by the Company in
connection with the Maine Independence Station, a new 520 megawatt gas fired
generation facility in Veazie, Maine, coming online and connecting to the
regional transmission power grid. The Company is being reimbursed by the
owner of the facility for the construction costs incurred, including
overheads. Other O&M was also reduced by the impact of the previously
discussed deferred restructuring costs accounting order, whereby costs that
were charged to O&M expense in the first two quarters of 1999 were deferred
in the third quarter of 1999. Finally, reducing other O&M expense was a
$142,500 reduction in bad debt expense in the 1999 quarter, resulting from
lower levels of write-offs, and a $147,000 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.
These decreases in other O&M expense in the 1999 quarter were offset
to some extent by a $246,000 increase in postretirement and active medical
costs, principally as a result of increased medical claims costs, and the
Company incurred approximately $247,000 of incremental non-labor expenditures
in the third quarter of 1999 related costs associated with assessment and
testing of systems for year 2000 (Y2K) compliance.
Depreciation and amortization expense decreased $749,000 in the third
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 decrease in property and other taxes in the third quarter of 1999
was due principally to reductions in property taxes as a result of the sale
of the Company's generation assets. This reduction in property taxes was
offset to some extent by increased electric plant additions in 1999.
The increase in income taxes was principally a function of greater
earnings in the third quarter of 1999 as compared to the 1998 quarter. This
increase was offset slightly by the impact of the one-time income tax
benefits related to the utilization of investment tax credits and adjustments
to the 1998 tax returns filed in September of 1999. 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
The increase in other income in the 1999 quarter was due primarily to
the previously discussed gain on sale of Penobscot Hydro and interest income
realized from invested generation asset sale proceeds, reduced by increased
net operating expenses associated with non-core business ventures in the 1999
quarter.
Allowance for funds used during construction (AFDC) decreased
$713,000 in 1999 relative to 1998 due principally to $628,000 in carrying
costs being recorded on the previously discussed deferred asset sale gain,
including the aforementioned reserve, and the deferred gain on sale of Graham
Station property (See the 1998 Form 10-K for a complete discussion of this
property sale). Also decreasing AFDC in the 1999 quarter was a $99,000
reduction in carrying costs recorded on deferred ice storm costs. With the
ARP rate increase on June 1, 1999, the Company ceased accruing carrying costs
on the deferred ice storm costs.
Long-term debt interest expense decreased $1.7 million in the third
quarter of 1999 as compared to 1998 due primarily to principal repayments on
the Company's 12.25% first mortgage bonds (which were fully repaid in August
1999); a $13.1 million principal payment at the end of June 1999 on the
Finance Authority of Maine Revenue Notes; monthly principal payments from
October 1998 through September 1999 amounting to $4.6 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 which were issued on June 29, 1998; the full redemption of $15
million in outstanding 10.25% Series First Mortgage Bonds in early July 1999;
and the redemption of $4.2 million in outstanding variable rate Pollution
Control Revenue Bonds in early September 1999.
Other interest expense decreased due principally to a $21.3 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.
NINE MONTHS OF 1999 AS COMPARED TO THE NINE MONTHS OF 1998
EARNINGS
Basic earnings per common share for the nine months ended September
30, 1999 were $1.61, as compared to $.91 per common share for the 1998
period. The increased earnings were largely the result of the June 1, 1999
rate increase, an increase in KWH sales in the 1999 period, a one-time
benefit of $896,000 ($.07 increase in basic earnings per common share)
related to the settlement of a dispute related to the NEPOOL transmission
rates, a one-time benefit of $802,000 ($.06 increase in basic earnings per
common share) due to the settlement, by NEPOOL, of a contract dispute with
HQ, the February 13, 1998 rate increase authorized by the MPUC designed to
increase annual revenues by approximately $13.2 million (which included the
$5.1 million authorized in a temporary rate increase that became effective on
July 1, 1997), and the previously discussed impact of the gain on sale of
subsidiary and one-time income tax benefits in the third quarter of 1999.
REVENUES
Electric operating revenue increased by $4.1 million, or 2.8% in the
first nine 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
3.5% increase in KWH sales (excluding off-system sales) in the 1999 period,
and $854,000 in additional revenues attributable to the previously discussed
net expense, for the period from June through September 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 during the
summer months of 1999 as compared to 1998. The increased revenues were
offset by a $1 million reduction in off-system sales in the 1999 period and a
$1.7 million reduction in revenue sharing from the Company's largest
industrial customer.
EXPENSES
Fuel for generation and purchased power expense decreased $1.5
million or 2.4% 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 $2.4
million in the 1999 period, as compared to $1.3 million for 1998, related to
savings realized from the restructuring of the PERC purchased power contract
in June 1998. The $1 million reduction in off-system sales in the 1999 period
also impacted the decrease in fuel and purchased power expense.
Purchased power expenses increased by about $1.3 million in the 1999
period due to the May 27th sale of the Company's hydroelectric facilities and
subsequent buyback contract with PP&L for the power from the plants.
Incremental replacement power costs for other entitlements in Wyman #4,
Hydro-Quebec and MEPCO transmission were $3.4 million greater than the
comparable 1998 expense. June 1999 replacement power costs were extremely
high due to very unusual circumstances in NEPOOL, with record-breaking loads
while many generators were still out of service on spring maintenance.
Further, as previously discussed, the NEPOOL new market rules resulted in on-
peak power prices that were two to three times as great as would normally
occur during June.
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 17% lower in the first quarter
and largely unchanged in the second quarter of 1999 as compared to 1998, was
67% higher in the third quarter of 1999 as compared to 1998. For the nine
month period residual oil prices have been 16% higher in 1999 compared to
1998. However, the Company had hedged these purchases through its fuel risk
management program with a fixed price about 13% lower in 1999 compared to
1998 (See the 1998 Form 10-K for a more complete discussion of the Company's
fuel risk management program). 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 million in the 1999 period as
compared to 1998. Increasing other O&M expense in 1999 was a $791,000
increase in postretirement and active medical costs due principally to higher
medical claims costs; the Company incurred approximately $621,000 of
additional incremental non-labor expenditures in the 1999 period as compared
to 1998 related to electric utility industry restructuring activities (net of
the previously discussed deferral in the third quarter of 1999), costs
associated with Y2K compliance, and an upgrade to the Company's customer
information system; the Company has incurred approximately $354,000 in
increased outside legal services expense in 1999 as compared to 1998, with
much of the increase attributable to Federal Energy Regulatory Commission and
NEPOOL issues; and the Company recorded $383,000 of amortization expense
associated with deferred ice storm costs for the period from June 1 through
September 30, 1999.
Offsetting the increases in other O&M expense to some extent were a
$333,000 reduction in bad debt expense, due to reduced write-offs in the 1999
period; hydroelectric and Wyman #4 O&M expenses were $433,000 lower in the
1999 period as a result of the generation asset sale in late May 1999;
amortization of deferred DSM expenses was $342,000 lower in 1999 as compared
to 1998 and overhead expenses allocated to capital projects were higher in
the 1999 period, each for the previously discussed reasons.
Depreciation and amortization expense decreased $937,000 in the 1999
period as compared to 1998, due principally to the reasons discussed for the
third quarter of 1999 as compared to the third quarter of 1998.
The $359,000 increase in amortization of contract buyouts and
restructuring in 1999 was due principally to PERC purchased power contract
restructuring in June 1998. In 1999 the Company recorded $750,000 of
amortization related to deferred PERC contract restructuring costs as
compared to $250,000 of amortization in 1998. 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 $2.1 million in the
1999 period as compared to $2.2 million in 1998.
The increase in income tax expense in the first nine months of 1999
was due principally to the reasons previously discussed for the third quarter
of 1999 as compared to 1998.
OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE
The $637,000 increase in other income in 1999 was due principally to
the previously discussed gain on sale of Penobscot Hydro and interest income
realized from invested generation asset sale proceeds.
The decreases in AFDC, long-term debt and other interest expense in
the first nine months of 1999 as compared to the first nine months of 1998
were principally due to the reasons previously discussed for the quarters
ended September 30, 1999 and 1998. Additionally, affecting the change in
long-term debt interest expense in the two periods was the issuance of $24.8
million and $45 million of medium term notes at the end of March 1998 and the
end of June 1998, respectively, and principal payments of $4 million in March
1998 and the final $30 million in June 1998 on the Company's old medium term
notes.
LIQUIDITY AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events in the first
nine months of 1999 and 1998 as they affect the Company's liquidity. Net
increase in cash from operating activities was $40.4 million in 1999 as
compared to $18.7 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), a $2.6 million reduction in deferred Maine
Yankee incremental costs in the 1999 period as compared to 1998, and the
Company's interest payments were reduced by $1.7 million in the 1999 period
due principally to the previously discussed long-term debt principal payments
and reduction in borrowings on the Company's revolving credit facility in
1999. In addition, in the 1998 period cash flows were reduced by $7.5
million in payments associated with restructuring the PERC purchased power
contract, a $1.6 million reduction due to the effect of a large customer who
prepaid its electric usage for a one-year period in the third quarter of 1997
and $4.0 million in incremental costs incurred in 1998 in connection with the
January 1998 ice storm.
Offsetting the previously discussed cash flow enhancements in 1999 as
compared to 1998 were an $8.4 million increase in state and federal income
tax payments as a result of the gain on sale of generating assets for income
tax purposes. Also in the third quarter of 1999, the Company paid $2.8
million to the holders of the PERC warrants, upon the exercise of the
warrants, (See the 1998 Form 10-K for a discussion of the warrants) in lieu
of issuing shares of common stock.
Construction expenditures were $2.1 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 and an additional $10 million in late July 1999
in connection with the sale of Penobscot Hydro.
As previously discussed, the Company reinstated it common stock
dividend in the second quarter of 1999, resulting in the increase in
dividends on common stock in the 1999 period. 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. The previously discussed
$38.8 million repayment of the remaining outstanding medium term notes, $15
million redemption of the 10.25% First Mortgage Bonds, $2.1 million
redemption of the 12.25% First Mortgage Bonds, and the redemption of $4.2
million of Pollution Control Revenue Bonds were accomplished through the
utilization of the generation asset sale proceeds. Additionally, on October
20, 1999, the Company utilized asset sale proceeds to redeem the remaining $9
million of outstanding 8.76% mandatory redeemable preferred stock.
Cash flows were enhanced in the 1998 period by the previously
discussed issuances of $69.8 million in medium term notes, net of $1.5
million which were required to be deposited in a capital reserve fund.
As previously discussed, the Company has maintained full borrowing
capacity under its revolving credit facility since early in 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 was issued in the fourth quarter of 1998.
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 $950,000 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 nine months of 1999, approximately $1.1 million was expended
in connection with the Y2K, of which $292,000 was capitalized and $779,000
charged to expense. Through September 30, 1999, on a cumulative basis,
approximately $1.5 million has been expended, of which $613,000 has been
capitalized and $867,000 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 has identified realistic
failure scenarios, which for contingency plans have been developed. In
addition, detailed transition and staffing plans have also been developed
allowing efficient and effective problem resolution in the event of an
unanticipated failure.
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)
Sept. 30, Dec. 31,
ASSETS 1999 1998
-------- --------
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original cost $ 290,374 $ 352,975
Less - Accumulated depreciation and amortization 86,911 101,633
-------- --------
$ 203,463 $ 251,342
Construction work in progress 17,775 13,930
-------- --------
$ 221,238 $ 265,272
Investments in corporate joint ventures:
Maine Yankee Atomic Power Company $ 5,385 $ 5,439
Maine Electric Power Company, Inc. 919 439
-------- --------
$ 227,542 $ 271,150
-------- --------
OTHER INVESTMENTS, principally at cost $ 1,702 $ 5,882
-------- --------
FUNDS HELD BY TRUSTEE, at cost $ 23,040 $ 29,868
-------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 18,314 $ 2,946
Accounts receivable, net of reserve 18,936 17,558
Unbilled revenue receivable 10,881 12,086
Inventories, at average cost:
Material and supplies 2,749 2,909
Fuel oil 47 16
Prepaid expenses 222 1,129
-------- --------
Total current assets $ 51,149 $ 36,644
-------- --------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $31,447 in 1999
and $30,173 in 1998 $ 27,395 $ 28,669
Costs to terminate/restructure power contracts,
net of accumulated amortization of $95,660
in 1999 and $80,059 in 1998 123,008 136,979
Maine Yankee decommissioning costs 47,144 50,055
Deferred regulatory assets 24,664 32,996
Demand-side management costs 426 779
Other 8,743 12,666
-------- --------
Total deferred charges $ 231,380 $ 262,144
-------- --------
Total assets $ 534,813 $ 605,688
======== ========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
000's Omitted
(Unaudited)
Sept. 30, Dec. 31,
STOCKHOLDERS' INVESTMENT AND LIABILITIES 1999 1998
-------- --------
CAPITALIZATION:
Common stock investment $ 128,169 $ 118,864
Preferred stock 4,734 4,734
Preferred stock subject to mandatory redemption,
exclusive of current sinking fund requirements 7,650 7,604
Long-term debt, net of current portion 184,725 263,028
-------- --------
Total capitalization $ 325,278 $ 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 $ 20,874 $ 27,109
Accounts payable 14,037 13,896
Dividends payable 1,368 295
Accrued interest 3,837 3,474
Customers' deposits 419 329
Current income taxes (refundable) payable (390) 86
-------- --------
Total other current liabilities $ 40,145 $ 45,189
-------- --------
Total current liabilities $ 40,145 $ 57,189
-------- --------
DEFERRED CREDITS AND RESERVES:
Deferred income taxes - Seabrook $ 14,216 $ 14,880
Other accumulated deferred income taxes 57,049 63,775
Maine Yankee decommissioning liability 47,144 50,055
Deferred regulatory liability 8,930 9,618
Deferred gain on asset sale 27,340 4,510
Unamortized investment tax credits 1,624 1,721
Accrued pension and postretirement benefit costs 9,178 7,770
Other 3,909 1,940
-------- --------
Total deferred credits and reserves $ 169,390 $ 154,269
-------- --------
Total Stockholders' Investment and Liabilities $ 534,813 $ 605,688
======== ========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
000's Omitted
(Unaudited)
Sept. 30, Dec. 31,
1999 1998
--------- ---------
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 1999 and 1998
Amounts paid in excess of par value 58,703 59,054
Retained earnings 32,649 22,993
--------- ---------
Total common stock investment $ 128,169 $ 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 $ 9,244 $ 9,198
Less: Sinking fund requirements 1,594 1,594
--------- ---------
$ 7,650 $ 7,604
--------- ---------
LONG-TERM DEBT
First Mortgage Bonds-
10.25% Series due 2019 $ - 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 - 3,743
--------- ---------
$ 85,000 $ 103,743
Less: Sinking fund requirements - 1,675
--------- ---------
Total first mortgage bonds $ 85,000 $ 102,068
--------- ---------
Variable rate demand pollution control revenue bonds
Series 1983 due 2009 $ - $ 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 18,405 21,900
Medium Term Notes, Variable interest rate- LIBO
Rate plus 2%, due 2000 - 45,000
--------- ---------
$ 119,005 $ 180,600
Less: Current portion of long-term debt 19,280 23,840
--------- ---------
$ 99,725 $ 156,760
--------- ---------
Total long-term debt $ 184,725 $ 263,028
--------- ---------
Total Capitalization $ 325,278 $ 394,230
========= =========
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
000's Omitted
(Unaudited)
Nine Months Ended
Sept. 30, Sept. 30,
1999 1998
--------- ---------
Cash Flows From Operating Activities:
Net income $ 12,701 $ 7,624
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 6,563 7,500
Amortization of Seabrook Nuclear Project 1,274 1,274
Amortization of contract buyouts and
restructuring 15,601 15,242
Other amortizations 1,832 1,469
Allowance for equity funds used during
construction 81 (309)
Deferred income tax provision and amortization
of investment tax credits (2,857) 4,041
Asset sale interim revenue requirement
deficiency (853) -
Gain on sale of subsidiary (523) -
Changes in assets and liabilities:
Release of Graham Station property sale
proceeds by trustee 6,200 -
Payment received related to terminated
purchased power contract 1,750 -
Costs to restructure purchased power
contract (849) (7,448)
Deferred incremental ice storm costs - (4,192)
Deferred incremental Maine Yankee costs 1,699 (869)
Deferred Maine Yankee refueling costs - 286
Exercise of PERC warrants-cash paid in
lieu of issuing shares (2,834) -
Accounts receivable, net and unbilled revenue (179) 689
Accounts payable (1,191) (1,994)
Accrued interest 363 1,043
Current and deferred income taxes (62) 133
Deferred revenue - (1,571)
Other current assets and liabilities, net 412 262
Other, net 1,239 (4,517)
--------- ---------
Net Increase in Cash From Operating Activities: $ 40,367 $ 18,663
--------- ---------
Cash Flows From Investing Activities:
Construction expenditures $ (15,346) $ (13,244)
Allowance for borrowed funds used during construction 61 (510)
Asset sale proceeds 89,588 -
--------- ---------
Net Increase (Decrease) in Cash From Investing
Activities $ 74,303 $ (13,754)
--------- ---------
Cash Flows From Financing Activities:
Dividends on common stock $ (1,104) $ -
Dividends on preferred stock (822) (920)
Payments on long-term debt (84,538) (52,353)
Call premiums on early redemption of securities (838) -
Proceeds from issuances of long-term debt, net of
capital reserve fund requirements - 68,300
Short-term debt, net (12,000) (15,000)
Special deposit associated with securing
letter of credit - (4,592)
--------- ---------
Net Decrease in Cash From Financing Activities $ (99,302) $ (4,565)
--------- ---------
Net Increase in Cash and Cash Equivalents $ 15,368 $ 344
Cash and Cash Equivalents at Beginning of Period 2,946 937
--------- ---------
Cash and Cash Equivalents at End of Period $ 18,314 $ 1,281
========= =========
Cash Paid During the Nine Months For:
Interest (Net of Amount Capitalized) $ 15,066 $ 16,776
Income Taxes 8,800 425
========= =========
See notes to consolidated financial statements.
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 - - 7,624 7,624
Cash dividends declared on-
Preferred stock - - (889) (889)
Other - - (46) (46)
Issuance of warrants - 2,085 - 2,085
---------- ---------- ----------------------
BALANCE SEPTEMBER 30, 1998 $36,817 $59,054 $19,461 $115,332
========== ========== ======================
BALANCE DECEMBER 31, 1998 $36,817 $59,054 $22,993 $118,864
Net income - - 12,701 12,701
Cash dividends declared on-
Preferred stock - - (790) (790)
Common stock - - (2,209) (2,209)
Other - - (46) (46)
Exercise of warrants-cash paid
in lieu of issuing shares - (351) - (351)
---------- ---------- ----------------------
BALANCE SEPTEMBER 30, 1999 $36,817 $58,703 $32,649 $128,169
========== ========== ======================
See notes to the consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 September 30, 1999 and the results of operations and
cash flows for the periods ended September 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:
Nine Months Ended September 30,
-------------------------------
1999 1998
---- ----
Amount % Amount %
------ - ------ -
(Dollars in Thousands)
Federal income tax provision
at statutory rate $7,250 35 $4,279 35
Plus permanent reductions in
tax expense resulting
from statutory exclusions
from taxable income 63 - 33 -
------ --- ----- ---
Federal income tax provision before
effect of temporary differences
and investment tax credits $7,313 35 $4,312 35
(Less) temporary differences that
are flowed through for rate-
making and accounting purposes (462) (3) (421) (4)
(Less) utilization and amortization
of investment tax credits (363) (2) (160) (1)
------ --- ----- ---
Federal income tax provision $6,488 30 $3,731 30
====== === ===== ===
(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 Nine Months Ended
-------------------------------------
Sept 30, Sept 30, Sept 30, Sept 30,
1999 1998 1999 1998
OPERATIONS: -------- -------- -------- --------
As reported by investee-
Operating revenues $ 53,604 $ 92,814 $ 2,072 $ 2,466
========= ========= ======== =========
Earnings applicable to
common stock $ 3,775 $ 6,386 $ 3,225 $ 822
========= ========= ======== =========
Company's reported equity-
Equity in net income $ 264 $ 447 $ 458 $ 117
(Deduct) Add-Effect of
adjusting Company's
estimate to actual (261) 9 33 (34)
--------- -------- ------- ---------
Amounts reported by Co. $ 3 $ 456 $ 491 $ 83
========== ========= ======== =========
MAINE YANKEE MEPCO
------------ -----
(Dollars in Thousands)
(Unaudited)
Financial Position at
----------------------------------
Sept 30, Dec. 31, Sept 30, Dec. 31,
1999 1998 1999 1998
FINANCIAL POSITION: --------- --------- -------- --------
As reported by investee-
Total assets $1,112,163 $1,183,298 $ 9,537 $ 5,515
Less-
Preferred stock 16,200 16,800 - -
Long-term debt 57,000 68,433 70 220
Other liabilities
and deferred credits 962,572 1,018,575 3,099 2,079
--------- ---------- ------- -------
Net assets $ 76,391 $ 79,490 $ 6,368 $ 3,216
=========== ========== ======= =======
Co.'s reported equity-
Equity in net assets $ 5,347 $ 5,564 $ 904 $ 457
Add(Deduct)- Effect
of adjusting Company's
estimate to actual 38 (125) 15 (18)
----------- ---------- ------- -------
Amounts reported by Co. $ 5,385 $ 5,439 $ 919 $ 439
========== ========== ======= =========
In late July 1999, the Company sold its wholly-owned subsidiary
Penobscot Hydro Company, Inc., which held a 50% ownership interest in
BPHA (See Note 5). Consequently, no financial information related to
financial position is presented for BPHA as of September 30, 1999.
BPHA Chester
------------------- ------------------
(Dollars in Thousands)
(Unaudited)
Operations for Nine Months Ended *
-----------------------------------------
July 31, Sept 30, Sept 30, Sept 30,
1999 1998 1999 1998
-------- -------- -------- --------
OPERATIONS:
As reported by investee-
Operating revenues $ 4,426 $ 5,663 $ 3,244 $ 3,347
======= ======= ======= =======
Net Income $ 1,730 $ 2,010 $ - $ -
======= ======= ======= =======
Co.'s reported equity
in net income $ 865 $ 1,005 $ - $ -
======= ======= ======= =======
* Except for BPHA for the 1999 period, which is presented for the seven
months ending July 31, 1999.
Financial Position at
Sept 30, Dec. 31, Sept 30, Dec. 31,
1999 1998 1999 1998
--------- -------- -------- --------
FINANCIAL POSITION:
As reported by investee-
Total assets $ - $38,324 $25,427 $26,478
Less-
Long-term debt - 26,300 23,767 24,654
Other liabilities - 2,517 1,660 1,824
-------- ------- ------- -------
Net assets $ - $ 9,507 $ - $ -
======== ======= ======= =======
Co.'s reported equity
in net assets $ - $ 4,754 $ - $ -
======== ======= ======= =======
At September 30, 1999, and December 31, 1998, the Company's
wholly owned subsidiary, Penobscot Natural Gas Company, had a $307,000
and $77,000 equity investment in Bangor Gas, a start-up entity,
respectively and recorded equity losses in Bangor Gas of approximately
$170,000 and $55,000 for the nine months ended September 30, 1999 and
1998, respectively. At September 30, 1999 and December 31, 1998, Bangor
Gas' total assets, principally construction work in progress,
amounted to $6.8 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 Nine Months
Ended Ended
-------------------- -------------------
Sept 30, Sept 30, Sept 30, Sept 30,
1999 1998 1999 1998
-------- -------- -------- --------
Earnings applicable to
common stock $ 4,758 $ 2,637 $11,865 $ 6,689
-------- -------- ------- -------
Average common
shares outstanding 7,363 7,363 7,363 7,363
Plus: incremental shares
from assumed conversion 1,032 461 989 164
-------- -------- ------- -------
Average common shares
outstanding plus assumed
warrants converted 8,395 7,824 8,352 7,527
-------- -------- ------- -------
Basic earnings
per common share $ .65 $ .36 $ 1.61 $ .91
======== ======= ======= =======
Diluted earnings
per common share $ .57 $ .34 $ 1.42 $ .89
======== ======= ======= =======
(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 transmission
rights to PP&L Global (PP&L). 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 the New England Power Pool (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 led to
the signing of a purchase and sale agreement with PP&L 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, and in late
August 1999, the Maine Public Utilities Commission (MPUC) approved the
sale of Penobscot Hydro Company, Inc. (Penobscot Hydro), the Company's
wholly-owned subsidiary which held the 50% interest in the West Enfield
hydro station, to PP&L. The Company has utilized a significant portion
of the net proceeds of the sale to reduce outstanding debt and preferred
stock.
The Company realized a net gain on the sale related to the PP&L
sale of approximately $23.0 million, and $22.5 million of this amount
has been recorded as a deferred liability at September 30, 1999 on the
Consolidated Balance Sheets. Included in this deferred amount is the
accrual of carrying costs on the deferred gain balance and the net
expense associated with the sale of its generating assets and the
simultaneous purchased power buyback agreement with PP&L (See below for
a discussion of the net expense). The deferred gain will be utilized to
reduce electric rates effective March 1, 2000, with the introduction of
retail competition. The remaining $.5 million of the gain relates to the
portion of the gain on sale of Penobscot Hydro which is allocable to
shareholders (recorded as other income in the Consolidated Statements of
Income for the quarter ending September 30, 1999). 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. 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 has been 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 1999 period in the amount of approximately $1.5 million. This net
expense has been recorded as an addition to the Company's electric
operating revenues and as a reduction of the previously discussed
deferred asset sale gain. Of this amount, the third quarter net expense
was approximately $337,000. The reason for the net expense is due
principally to the Company incurring unusually high purchased power costs
during the extremely hot weather in early June and in July 1999, as a
result of the Company no longer owning certain generation and
transmission assets subsequent to the asset sale to PP&L. Since these
high costs would not have occurred if the Company had not sold these
assets, the Company has recorded the net expense as a reduction of the
deferred asset sale gain.
In connection with the Company's current rate proceedings at the
MPUC, the Company's proposed methodology for computing the previously
discussed net expense and the rate used to calculate carrying costs on
the deferred asset sale gain have been challenged by other parties in the
rate proceedings. The Company is uncertain as to which method will
ultimately be approved by the MPUC, and consequently has recorded a
reserve of approximately $1.04 million on the Consolidated Balance
Sheets as of September 30, 1999 to reflect the estimated difference in
the computations between the parties. On the Consolidated Statements of
Income, this reserve is reflected as a $688,000 reduction in
electric operating revenues, a $508,000 reduction in Allowance for Equity
Funds Used During Construction and a $155,000 addition to Allowance for
Borrowed Funds Used During Construction.
(7) EXERCISE OF WARRANTS:
In the period from late June through August 1999, 299,999 common
stock warrants, which were issued in connection with the Penobscot Energy
Recovery Company (PERC) purchased power contract restructuring, were
exercised at a market prices ranging from $16 1/16 to $16 11/16 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 holders of the warrants instead
of actually issuing shares of common stock. These payments amounted to
approximately $2.8 million. 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 the cash payments option to increase the PERC regulatory asset by
approximately $2.5 million and reduce additional paid-in capital by
approximately $351,000 as of September 30, 1999.
(8) ELECTRIC UTILITY INDUSTRY RESTUCTURING-ACCOUNTING ORDER:
In September 1999 the Company received an accounting order from the
MPUC related to the Company's request to defer certain incremental costs
associated with electric utility industry restructuring. In connection
with the accounting order, the Company recorded as a deferred asset in
September 1999 approximately $314,000 of restructuring costs, which had
previously been charged to operation and maintenance expense in 1999. In
connection with the current rate proceeding with the MPUC, the deferred
restructuring costs are expected to start being recovered on March 1,
2000. Based on the accounting order, the Company will defer, for future
recovery, certain additional incremental restructuring costs through the
advent of retail competition on March 1, 2000
(9) RECLASSFICATIONS:
Certain 1998 amounts have been reclassified to conform with the
presentation used in Form 10-Q for the quarter ended September 30, 1999.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-Q FOR PERIOD ENDING SEPTEMBER 30, 1999
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 SEPTEMBER 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)
/s/ Frederick S. Samp
---------------------
Dated: November 15, 1999
Frederick S. Samp
Vice President - Finance & Law
(Chief Financial Officer)
<TABLE> <S> <C>
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<LEGEND>
This schedule contains summary financial information extracted from Bangor
Hydro-Electric Company's Form 10-Q for the third quarter of 1999 and is
qualified in its entirety by reference to such 10-Q.
</LEGEND>
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<NAME> BANGOR HYDRO-ELECTRIC COMPANY
<MULTIPLIER> 1,000
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