SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________________
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
-------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO ___________
COMMISSION FILE NUMBER 1-8291
------
GREEN MOUNTAIN POWER CORPORATION
-----------------------------------
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
VERMONT 03-0127430
------------------------------ --------------------
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
163 ACORN LANE
COLCHESTER, VT 05446
-------------------------------------- --------------------
ADDRESS OF PRINCIPAL EXECUTIVE OFFICES (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (802) 864-5731
--------------------
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
--- ---
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE ISSUER'S CLASSES
OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
CLASS - COMMON STOCK OUTSTANDING JUNE 30, 1999
--------------------------- -------------------------------
$3.33 1/3 PAR VALUE 5,329,064
<PAGE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE BALANCE SHEETS
(UNAUDITED)
JUNE 30 JUNE 30 DECEMBER 31
-------- -------- ------------
1999 1998 1998
-------- -------- ------------
(In thousands)
ASSETS
UTILITY PLANT
<S> <C> <C> <C>
Utility plant, at original cost $277,018 $269,649 $ 276,853
Less accumulated depreciation 98,716 92,330 94,604
-------- -------- ------------
Net utility plant 178,302 177,319 182,249
Property under capital lease 7,696 8,342 7,696
Construction work in progress 8,956 11,469 5,611
-------- -------- ------------
Total utility plant, net 194,954 197,130 195,556
-------- -------- ------------
OTHER INVESTMENTS
Associated companies, at equity 15,016 15,321 15,048
Other investments 5,895 5,382 5,630
-------- -------- ------------
Total other investments 20,911 20,703 20,678
-------- -------- ------------
CURRENT ASSETS
Cash and cash equivalents 7,293 208 439
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $424, $379 and $449 16,747 14,277 18,977
Accrued utility revenues 5,773 5,459 6,611
Fuel, materials and supplies, at average cost 2,822 3,501 3,139
Prepayments 1,672 10,901 6,091
Other 261 264 443
-------- -------- ------------
Total current assets 34,568 34,610 35,700
-------- -------- ------------
DEFERRED CHARGES
Demand side management programs 8,518 11,734 10,590
Purchased power costs 2,841 9,437 5,708
Other 19,019 12,656 14,278
-------- -------- ------------
Total deferred charges 30,378 33,827 30,576
-------- -------- ------------
NON-UTILITY
Cash and cash equivalents 18 1233 151
Other current assets 63 8,893 3,409
Property and equipment 253 1,220 1,213
Intangible assets - 20 1,658
Equity investment in energy related businesses - 12,146 12,357
Business segment held for disposal 16,433 - -
Other assets 1,350 5,188 8,526
-------- -------- ------------
Total non-utility assets 18,117 28,700 27,314
-------- -------- ------------
TOTAL ASSETS $298,928 $314,970 $ 309,824
======== ======== ============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
1
<PAGE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE BALANCE SHEETS
(UNAUDITED)
JUNE 30 JUNE 30 DECEMBER 31
--------- --------- -------------
1999 1998 1998
--------- --------- -------------
(In thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
<S> <C> <C> <C>
Common Stock Equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,344,920, 5,233,582 and 5,313,296) $ 17,892 $ 17,634 $ 17,711
Additional paid-in capital 72,331 71,326 71,914
Retained earnings 18,197 21,379 17,508
Treasury stock, at cost (15,856 shares) (378) (378) (378)
--------- --------- -------------
Total common stock equity 108,042 109,961 106,755
Redeemable cumulative preferred stock 16,085 17,735 16,085
Long-term debt, less current maturities 86,800 88,500 88,500
--------- --------- -------------
Total capitalization 210,927 216,196 211,340
--------- --------- -------------
CAPITAL LEASE OBLIGATION 7,696 8,342 7,696
--------- --------- -------------
CURRENT LIABILITIES
Current maturities of long-term debt 1,700 4,700 1,700
Short-term debt - 3,516 7,000
Accounts payable, trade and accrued liabilities 6,941 5,857 5,453
Accounts payable to associated companies 6,994 6,313 7,143
Dividends declared 320 355 362
Customer deposits 226 537 336
Taxes accrued - - 370
Interest accrued 1,165 1,312 1,203
Deferred revenues 3,124 2,436 -
Other 2,287 3,300 5,258
--------- --------- -------------
Total current liabilities 22,757 28,326 28,825
--------- --------- -------------
DEFERRED CREDITS
Accumulated deferred income taxes 24,311 28,264 23,389
Unamortized investment tax credits 4,119 4,401 4,260
Pine Street Barge Canal site cleanup 8,700 - 5,000
Other 20,349 22,023 22,240
--------- --------- -------------
Total deferred credits 57,479 54,688 54,889
--------- --------- -------------
NON-UTILITY
Current liabilities - 868 720
Other liabilities 69 6,550 6,354
--------- --------- -------------
Total non-utility liabilities 69 7,418 7,074
--------- --------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $298,928 $314,970 $ 309,824
========= ========= =============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
2
<PAGE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
(UNAUDITED)
Part 1 - Item 1
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
------------------ --------------------
1999 1998 1999 1998
-------- -------- --------- ---------
(In thousands, except amounts per share)
PERATING REVENUES $59,535 $43,733 $118,553 $90,665
-------- -------- --------- ---------
OPERATING EXPENSES
<S> <C> <C> <C> <C>
Power Supply
Vermont Yankee Nuclear Power Corporation 8,944 8,025 17,302 16,146
Company-owned generation 1,926 1,194 2,950 4,029
Purchases from others 33,834 16,599 62,725 39,500
Other operating 4,166 4,840 9,458 9,256
Transmission 2,149 2,407 4,459 4,668
Maintenance 1,893 1,262 3,464 2,464
Depreciation and amortization 4,238 3,879 8,478 8,304
Taxes other than income 1,684 1,810 3,499 3,766
Income taxes (276) 906 1,335 (595)
-------- -------- --------- ---------
Total operating expenses 58,558 40,922 113,670 87,538
-------- -------- --------- ---------
OPERATING INCOME 977 2,811 4,883 3,127
-------- -------- --------- ---------
OTHER INCOME
Equity (loss) in earnings of affiliates and non-utility operations 563 617 1,899 801
Allowance for equity funds used during construction 30 45 49 98
Other income (deductions), net 107 32 159 (887)
-------- -------- --------- ---------
Total other income (deductions) 700 694 2,107 12
-------- -------- --------- ---------
INCOME (LOSS) BEFORE INTEREST CHARGES 1,677 3,505 6,990 3,139
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt 1,690 1,784 3,393 3,583
Other 110 127 260 344
Allowance for borrowed funds used during construction (16) (32) (30) (106)
-------- -------- --------- ---------
Total interest charges 1,784 1,879 3,623 3,821
-------- -------- --------- ---------
NET INCOME (LOSS) BEFORE PREFERRED DIVIDENDS
AND DISCONTINUED SEGMENT (107) 1,626 3,367 (682)
Dividends on preferred stock 305 340 610 681
-------- -------- --------- ---------
NET INCOME FROM CONTINUING OPERATIONS (412) 1,286 2,757 (1,363)
Net income(loss) from operations of
discontinued segment, net of income taxes (81) (355) (603) (1,112)
-------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK ($493) $ 931 $ 2,154 ($2,475)
======== ======== ========= =========
COMMON STOCK DATA
Basic and diluted earnings (loss) per share
from continuing operations ($0.08) $ 0.25 $ 0.51 ($0.27)
Basic and diluted earnings (loss) per share ($0.10) $ 0.18 $ 0.40 ($0.48)
Cash dividends declared per share $ 0.14 $ 0.28 $ 0.28 $ 0.55
Weighted average shares outstanding 5,344 5,222 5,331 5,209
CONSOLIDATED COMPARATIVE STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Balance - beginning of period $19,425 $21,884 $ 17,508 $ 26,717
Net Income (Loss) (188) 1,271 2,764 (1,794)
-------- -------- --------- ---------
19,237 23,155 20,272 24,923
-------- -------- --------- ---------
Cash Dividends-redeemable cumulative preferred stock 305 340 610 681
Cash Dividends-common stock 735 1,436 1,465 2,863
-------- -------- --------- ---------
1,040 1,776 2,075 3,544
-------- -------- --------- ---------
Balance - end of period $18,197 $21,379 $ 18,197 $ 21,379
======== ======== ========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
3
<PAGE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Part 1 - Item 1 SIX MONTHS ENDED
JUNE 30 JUNE 30
--------- ---------
1999 1998
--------- ---------
(In thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income (Loss) $ 2,764 ($1,794)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 8,478 8,304
Dividends from associated companies less equity income (38) 538
Allowance for funds used during construction (80) (204)
Amortization of purchased power costs 3,795 2,571
Deferred income taxes 922 4,890
Deferred revenues 3,124 2,437
Deferred purchased power costs (378) (7,725)
Amortization of investment tax credits (141) (141)
Environmental proceedings costs (1,117) (891)
Conservation expenditures (744) (649)
Changes in:
Accounts receivable 2,229 3,089
Accrued utility revenues 838 1,047
Fuel, materials and supplies 317 (240)
Prepayments and other current assets 4,788 (4,501)
Accounts payable 1,340 (2,319)
Taxes accrued (370) (5,024)
Interest accrued (38) 1
Other current liabilities (3,051) 1,611
Other (691) 898
--------- ---------
Net cash provided by continuing operations 21,947 1,898
Net cash provided (used) by discontinued segment 362 (777)
--------- ---------
Net cash provided by operating activities 22,309 1,121
INVESTING ACTIVITIES:
Construction expenditures (5,313) (6,541)
Investment in nonutility property (97) 495
Proceeds from sale of propane subsidiary - 11,500
--------- ---------
Net cash provided by (used in) investing activities (5,410) 5,454
--------- ---------
FINANCING ACTIVITIES:
Issuance of common stock 598 921
Short-term debt, net (7,000) 900
Cash dividends (2,076) (3,543)
Reduction in long-term debt (1,700) (3,683)
--------- ---------
Net cash provided by (used in) financing activities (10,178) (5,405)
--------- ---------
Net increase in cash and cash equivalents 6,721 1,170
Cash and cash equivalents at beginning of period 590 271
--------- ---------
Cash and cash equivalents at end of period $ 7,311 $ 1,441
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) $ 3,692 $ 3,796
Income taxes 997 938
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
4
<PAGE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
PART I -- ITEM 1
1. SIGNIFICANT ACCOUNTING POLICIES
It is our opinion that the financial information contained in this report
reflects all normal, recurring adjustments necessary to present a fair statement
of results for the period reported, but such results are not necessarily
indicative of results to be expected for the year due to the seasonal nature of
our business. 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, the
disclosures herein, when read with the annual report for 1998 filed on Form
10-K, are adequate to make the information presented not misleading.
The Consolidated Financial Statements are unaudited and, in our opinion,
reflect the adjustments necessary to a fair statement of the results of the
interim periods. All such adjustments, except for the deferral of early
retirement and separation costs, environmental costs related to Pine Street, and
arbitration costs related to Hydro-Quebec, each of which is discussed separately
in this form 10-Q, are of a normal, recurring nature.
The Vermont Public Service Board ("VPSB"), the regulatory commission in Vermont,
sets the rates we charge our customers for their electricity. We charge our
customers higher rates for billing cycles in December through March and lower
rates for the remaining months. These are called "seasonally differentiated
rates". In order to eliminate the impact of the seasonally differentiated
rates, we defer some of the revenues from those four months and account for them
in later periods in which we have lower revenues or higher costs. By deferring
certain revenues we are able to better match our revenues to our costs. On June
30, 1999, there was a deferred credit balance of $3.1 million compared to $2.4
million for the same period in 1998, consistent with the temporary retail rate
increase of 5.5 percent effective with service rendered December 15, 1998 and
the 3.61 percent rate increase granted by the VPSB in its order dated February
27, 1998.
In our pending rate case, we asked the VPSB to approve a new rate design
that would eliminate the seasonal rate differential, since our analysis
indicates that our customers' electricity usage is leveling out over the course
of a year. Action on this matter is suspended as a result of the temporary stay
of the 1998 rate case.
5
<PAGE>
FINANCIAL SUMMARY OF UNREGULATED OPERATIONS
We have five unregulated, wholly-owned subsidiaries: Mountain Energy, Inc.
("MEI"), Green Mountain Propane Gas Limited ("GMPG"), GMP Real Estate
Corporation, Lease-Elec, Inc. and Green Mountain Resources, Inc. ("GMRI"). As
of June 30, 1999 we decided to sell the assets of MEI, and report its results as
net income(loss) from operations of a discontinued segment. We also have a
rental water heater program that is not regulated by the VPSB. The results of
the operations of these subsidiaries(excluding MEI) and the rental water heater
program are included in earnings of affiliates and non-utility operations in the
Other Income section of the Consolidated Comparative Income Statements. A
financial summary for these businesses follows:
<TABLE>
<CAPTION>
Three months Six months
ended ended
June 30 June 30
In thousands 1999 1998 1999 1998
----- ----- ------ -------
<S> <C> <C> <C> <C>
Revenue $ 268 $ 107 $ 545 $2,298
Expense 247 13 (309) 2,480
----- ----- ------ -------
Net Income(Loss) $ 21 $ 94 $ 854 $ (182)
===== ===== ====== =======
</TABLE>
2. INVESTMENT IN ASSOCIATED COMPANIES
We recognize net income in our affiliates (companies in which we have
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION
Percent ownership: 17.9%
<TABLE>
<CAPTION>
Three months Six months
ended ended
June 30 June 30
1999 1998 1999 1998
------- ------- ------- --------
<S> <C> <C> <C> <C>
Gross Revenue $46,376 $57,913 $90,153 $109,083
Net Income Applicable 1,638 1,806 3,294 3,508
to Common Stock
Equity in Net Income 299 315 593 613
</TABLE>
6
<PAGE>
VERMONT ELECTRIC POWER COMPANY, INC.
Percent Ownership: 29.5% common
30.0% preferred
<TABLE>
<CAPTION>
Three months Six months
ended ended
June 30 June 30
1999 1998 1999 1998
------ ------ ------- -------
<S> <C> <C> <C> <C>
Gross Revenue $7,271 $8,861 $14,205 $20,681
Net Income 329 298 621 584
Equity in Net Income 122 96 208 163
</TABLE>
3. ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air
and aesthetic requirements as administered by local, state and federal
regulatory agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about the
Company's compliance with present environmental protection regulations, except
for developments related to the Pine Street Barge Canal site.
PINE STREET BARGE CANAL SITE
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. We have been
notified by the Environmental Protection Agency ("EPA") that we are one of
several potentially responsible parties ("PRPs") for cleanup of the Pine Street
Barge Canal site in Burlington, Vermont, where coal tar and other industrial
materials were deposited. We remain a PRP for other past, ongoing and future
response costs. In November 1992, the EPA proposed a cleanup plan estimated by
the EPA to cost $47 million. In June 1993, the EPA withdrew this cleanup plan
in response to public concern about the plan and its cost. In 1994, the EPA
established a coordinating council, with representatives of the PRPs,
environmental and community groups, the City of Burlington and the State of
Vermont, presided over by a neutral facilitator.
7
<PAGE>
In June 1998, the Coordinating Council reached a consensus agreement on a
recommended plan for remediation of the Pine Street Barge Canal site. As part
of the Council's process of reaching a consensus recommendation, the Company and
certain other parties conditionally agreed to fund environmentally beneficial
projects in the greater Burlington area, the cost of which may reach $3.0
million. In June 1998, the EPA formally proposed the Council's recommended plan
and received public comments.
On September 29, 1998, the EPA issued its final Record of Decision,
announcing selection of the proposed remedy. The proposed remedy includes:
* Construction of an underwater cover over canal sediments that present the
highest risk to the environment;
* Placement of a soil cap over certain contaminated wetland areas and
restoration of those areas;
* Improvements that will better distribute storm water entering the site;
and
* Monitoring of the site to ensure that the cap is effective over the long
term and that harmful contamination does not migrate offsite.
As of June 30, 1999, our total expenditures related to the Pine Street
Barge Canal site since 1982 were approximately $17.2 million, including $815,000
to begin funding the environmentally beneficial projects agreed upon. This
includes those amounts not recovered in rates, amounts recovered in rates, and
amounts for which rate recovery has been sought but which are presently awaiting
further VPSB action. The bulk of these expenditures consisted of transaction
costs. Transaction costs include legal and consulting costs associated with our
opposition to the EPA's earlier proposals for the site, as well as litigation
and related costs necessary to obtain settlements with insurers and other PRPs
to provide amounts required to fund the clean up (remediation costs) and to
address liability claims at the site. A smaller amount of past expenditures was
for site-related response costs, including costs incurred pursuant to the EPA
and State orders that resulted in funding response activities at the site, and
to reimbursing the EPA and the State for oversight and related response costs.
The EPA and the State have asserted and affirmed that all costs related to these
orders are appropriate costs of response under CERCLA for which the Company and
other PRPs were legally responsible.
The EPA has made claims against the Company for additional past response
costs associated with the Pine Street Barge Canal site in an amount exceeding
$11 million. The EPA also has advised us that we may be responsible for
implementation of further response activities at the site. In early 1998, the
8
<PAGE>
United States and the State of Vermont asked us to begin "fast-track"
negotiation of tentative terms of settlement of all cost reimbursement and
natural resource damages claims of the United States and the State. Those
negotiations began immediately, involved other PRPs as well, and included
discussion of our potential contribution claims against the United States. In
May 1998, a confidential tentative agreement was reached on issues under
discussion.
We expect to complete soon negotiation of a final settlement with the
United States, the State, and other parties over terms of a Consent Decree that
will cover claims addressed in the earlier negotiations and implementation of
the selected remedy. The Consent Decree must be submitted to a federal court
for approval and adoption as its order. We have entered into various
confidential settlement agreements with other PRPs that provide for sharing of
past response costs, future cleanup costs and related future federal and state
monetary claims.
We estimate that we have recovered or secured, or will recover, through
past settlements of litigation claims against insurers and other parties,
amounts that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We have estimated that
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, to resolve monetary claims of the EPA and the
State and to remediate the site, are likely to be in the range of $8.7 to $12.5
million. In 1998, we recorded a liability of $5 million to recognize the low
end of our previous estimated range of costs. In the second quarter of 1999, we
recorded the additional liability of $3.7 million that reflects increased
estimates of site monitoring costs to be incurred over the next 33 years. The
estimated liability is not discounted, and it is possible that our estimate of
future costs could change by a material amount. We also have recorded an
offsetting regulatory asset since we believe it is probable that we will receive
future revenues to recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and
received recovery for ongoing expenses associated with the Pine Street Barge
Canal site. Specifically, we proposed rate recognition of our non-recovered
expenditures incurred between January 1, 1991 and June 30, 1995 (in the total of
approximately $8.7 million) for technical consultants and legal assistance in
connection with the EPA's enforcement action at the site and insurance
litigation. While reserving the right to argue in the future about the
appropriateness of full rate recovery of the Pine Street Barge Canal costs, the
Vermont Department of Public Service (the Department), and as applicable, other
9
<PAGE>
intervenors, reached agreements with the Company in these cases that the full
amount of the Pine Street Barge Canal costs reflected in those rate cases should
be recovered in rates. Our rates, as approved by the VPSB in those proceedings,
reflected the Pine Street Barge Canal related expenditures referred to above.
We proposed in our rate filing made on June 16, 1997, recovery of an
additional $3.0 million in such expenditures. In an order in that case released
March 2, 1998, the VPSB suspended the amortization of expenditures associated
with the Pine Street Barge Canal site pending further proceedings. Although it
did not eliminate the rate base deferral of these expenditures, or make any
specific order in this regard, the VPSB indicated that it was inclined to agree
with other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRPs, should be "shared" between customers and shareholders of the
Company. In response to the Company's Motion for Reconsideration, the VPSB on
June 8, 1998 stated "our intent, and we believe the fair reading of our Order,
was to reserve for a future docket issues pertaining to the sharing of
remediation-related costs between the Company and its customers."
4. 1997 RETAIL RATE CASE
On June 16, 1997, we filed a request with the VPSB to increase our retail
rates by 16.7 percent ($26 million in additional annual revenues) and to
increase the target return on common equity from 11.25 percent to 13 percent.
In our final submissions to the VPSB we asked for an increase of 14.4 percent
($22 million in additional annual revenues) to cover increased cost of service.
On March 2, 1998, the VPSB released its Order dated February 27, 1998 in the
then pending rate case. The VPSB authorized us to increase our rates by 3.61
percent, which gave us increased annual revenues of $5.6 million.
The VPSB, in its Order dated February 27, 1998, denied us the right to
charge customers $5.48 million of the costs for power purchased under our
contract with Hydro-Quebec. The VPSB denied recovery of these costs for the
following reasons:
* The VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Quebec in August 1991 (the imprudence disallowance),
and
* To the extent that the costs of power to be purchased from Hydro-Quebec
are now higher than current estimates of market prices for power during
the contract term, after accounting for the imprudence disallowance,
the contract power is not "used and useful".
As a result of the rate order, we recorded in the first quarter of 1998 the
losses resulting from the disallowed recovery of a portion of the 1998 Hydro-Que
bec power supply contract costs. The amount charged to first quarter income of
$4.6 million (pre-tax) was less than the full disallowance because we expected
10
<PAGE>
that new rates would become effective in January 1999 as the result of our May
8, 1998 rate filing. The agreement to suspend our 1998 rate case, as described
below, delayed the date of a final decision on the 1998 rate case to December
15, 1999. Accordingly, we recognized an additional loss of $5.25 million in the
last quarter of 1998 representing the effect of the continued disallowance of
$5.48 million of annual Hydro-Quebec power costs through December 15, 1999.
In its February 27, 1998 Order, the VPSB described its policies that do not
allow a utility to recover imprudent expenditures and the costs of power supply
contract purchases that the VPSB decides are not used and useful. The VPSB also
stated in its Order that the methods and measures used in this rate case were
provisional and applied to this rate case only. If the VPSB were to apply the
same, or similar, methods and measures that it used in the 1997 rate case Order
to future power contract costs in our 1998 retail rate case, we would likely be
required to take a charge to income of approximately $163 million pre-tax.
This $163 million estimate represents primarily the 20 percent disallowance for
Hydro-Quebec power costs that the VPSB considered imprudent in its Order. We are
not able to estimate the loss to be recorded for power purchased after December
15, 1999, if any, until the pending 1998 rate case is completed.
If the VPSB does not modify in future regulatory proceedings its ruling
that the costs of power purchased from Hydro-Quebec are above estimated market
rates and are not used and useful and, therefore, a portion of such costs is not
recoverable, we would likely conclude that the VPSB has changed its approach to
setting rates from cost-based rate making to another form of regulation. We
would then be required to discontinue application of Statement of Financial
Accounting Standards("SFAS") No. 71("SFAS 71"), Accounting for the Effects of
Certain Types of Regulation, and eliminate all regulatory assets and liabilities
that arose from prior actions of the VPSB. The write-off of these regulatory
assets and liabilities, net of any tax effects, would be charged to income as an
extraordinary item for the financial reporting period in which the
discontinuation of SFAS 71 occurs.
Based on the June 30, 1999 balance sheet, if we were required to
discontinue the application of SFAS 71, we would be required to record as an
extraordinary item an after-tax charge to earnings of approximately $25.2
million attributable to net regulatory assets.
In June 1998, we appealed the VPSB's February 27, 1998 Order and its June
8, 1998 Reconsideration Order to the Vermont Supreme Court. The briefing of the
case by all parties was completed in January 1999. Oral argument before the
Vermont Supreme Court was held on March 16, 1999.
11
<PAGE>
We believe that the decisions in the VPSB's Order and Reconsideration Order
are factually inaccurate and legally incorrect. Specifically, we are appealing
the VPSB's determination that we were imprudent in committing to the Hydro-Que
bec contract in August 1991, and its ruling that because the contract power is
priced over-market under current forecasts of market prices, it is therefore
considered "not used and useful". The Company asserts, among other arguments,
that the VPSB's orders deprive the Company's shareholders of their property in
an unconstitutional manner. The VPSB's decisions, if not changed, could have a
significant negative impact on our reported financial condition, and could
impact our credit ratings, dividend policy and financial viability.
5. 1998 RETAIL RATE CASE
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent. We requested the retail rate increase because of the
following:
* The higher cost of power;
* The cost of the January 1998 ice storm; and
* Investments in new plant and equipment.
On November 18, 1998, by Memorandum of Understanding ("MOU"), the Company,
the Department and IBM, our largest customer and an intervenor in the case,
agreed to stay, effective November 16, 1998, rate proceedings in the 1998 rate
case until or after September 1, 1999, or such earlier date as the parties may
later agree to or the VPSB may order. The MOU provides for a 5.5 percent
temporary retail rate increase, to produce $8.92 million in annualized
additional revenue, effective with service rendered December 15, 1998. An
additional surcharge will be permitted, without further VPSB order, in order to
produce additional revenues necessary to provide the Company with the capacity
to finance estimated 1999 Pine Street Barge Canal site expenditures of $5.84
million. The MOU was approved by the VPSB on December 11, 1998.
On August 12, 1999, by amendment to the MOU, the Company, the Department of
Public Service and IBM requested that the VPSB extend the stay of the 1998 rate
case through December 15, 1999. If the VPSB approves the extension, a final
rate order would be issued by March 31, 2000, and the Company would record a
$1.6 million loss resulting from the continued disallowance of Hydro-Quebec
power supply costs occurring during the extension period.
Notwithstanding the interim rate settlement, we are unable to predict
whether the MOU or other future events, singularly or in combination, could
cause our lending banks to refuse to allow further borrowings under our
revolving loan agreement, to seek to enter into a new credit agreement with us
and/or to immediately call in all outstanding loans. If we are unable to borrow
on a short-term basis, we will evaluate all potential alternatives available at
the time, including, but not limited to, the filing of a petition for
reorganization under the United States Bankruptcy Code.
12
<PAGE>
6. SEGMENTS AND RELATED INFORMATION
In 1998, the Company adopted SFAS NO. 131, Disclosures About Segments of an
Enterprise and Related Information.
The Company has two reportable segments, the electric utility and Mountain
Energy, Inc. ("MEI"). The electric utility is engaged in the distribution and
sale of electrical energy in the State of Vermont and also reports the results
of its wholly-owned unregulated subsidiaries (GMPG, GMRI, GMP Real Estate,
Lease-Elec, Inc., and the rental water heater program) as a separate line item
in the Other Income Section in the Consolidated Statement of Income.
MEI is an unregulated business that invests in energy generation, energy
efficiency and wastewater treatment projects. As of June 30, 1999, we classified
our investment in MEI as "Business Segment held for sale", reflecting the
Company's intent to sell some or all of MEI's assets within the next twelve
months. Results of operations for MEI are reported under "Net income(loss) from
operations of discontinued segment, net of applicable income taxes". Segment
information for the three and six months ended June 30, 1999 includes the
following:
In thousands except per share data
<TABLE>
<CAPTION>
Three months ended Six months ended
June 30 June 30
1999 1998 1999 1998
-------- -------- --------- --------
Electric utility
<S> <C> <C> <C> <C>
Revenues-external $59,535 $43,733 $118,553 $90,665
Income(loss) (412) 1,286 2,757 (1,363)
MEI segment
Revenues 1,583 240 2,360 2,646
Loss (81) (355) (603) (1,112)
Income tax benefit 36 371 356 794
Income(loss) per share $(0.02) $(0.07) $(0.11) $(0.21)
</TABLE>
There has been no income or loss recognized since the classification of MEI as
discontinued operations.
7. SFAS 133
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative
Instruments and Hedging Activities. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
13
<PAGE>
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS 133 is effective for
fiscal years beginning after June 15, 1999. SFAS 133 must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded in hybrid
contracts that were issued, acquired, or substantively modified after December
31, 1997 (and, at the Company's election, before January 1, 1998).
The Company has not yet quantified the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of or method of its
adoption of SFAS 133. However, SFAS 133 could increase volatility in earnings
and other comprehensive income.
8. RECLASSIFICATION
Certain line items on the prior year's financial statements have been
reclassified for consistent presentation with the current year.
14
<PAGE>
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
JUNE 30, 1999
PART I -- ITEM 2
In this section, we explain the general financial condition and the results
of operations for Green Mountain Power Corporation (the Company) and its
subsidiaries. This includes:
* Factors that affect our business;
* Our earnings and costs in the periods presented and why they changed
between periods;
* The source of our earnings;
* Our expenditures for capital projects year-to-date and what we expect they
will be in the future;
* Where we expect to get cash for future capital expenditures; and
* How all of the above affects our overall financial condition.
As you read this section it may be helpful to refer to the consolidated
financial statements and notes in Part I-Item 1.
There are statements in this section that contain projections or estimates
and are considered to be "forward-looking" as defined by the Securities and
Exchange Commission. In these statements, you may find words such as
"believes," "expects," "plans," or similar words. These statements are not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be different from those projected.
Some of the reasons the results may be different are listed below and are
discussed under "Competition and Restructuring" and "Year 2000 Computer
Compliance" in this section:
* Regulatory decisions or legislation;
* Weather;
* Energy supply and demand and pricing;
* Availability, terms, and use of capital;
* General economic and business risk;
* Nuclear and environmental issues;
* Changes in technology; and
* Industry restructuring and cost recovery (including stranded costs).
These forward-looking statements represent only our estimates and
assumptions as of the date of this report.
15
<PAGE>
RESULTS OF OPERATIONS
EARNINGS SUMMARY- OVERVIEW
In this section, we discuss our earnings and the principal factors
affecting them. We separately discuss earnings for the utility business and for
our unregulated businesses.
<TABLE>
<CAPTION>
Three months ended Six months ended
June 30 June 30
1999 1998 1999 1998
------- -------- -------- -------
<S> <C> <C> <C> <C>
Utility business ($0.08) $ 0.22 $ 0.35 ($0.23)
Unregulated businesses - $ 0.03 $ 0.16 ($0.04)
------- -------- -------- -------
Earnings(loss) from ($0.08) $ 0.25 $ 0.51 ($0.27)
Continuing operations
Discontinued segment ($0.02) ($0.07) ($0.11) ($0.21)
------- -------- -------- -------
Basic and diluted earnings
(loss) per share ($0.10) $ 0.18 $ 0.40 ($0.48)
======= ======== ======== =======
</TABLE>
UTILITY BUSINESS
The Company recorded a loss from utility operations of $0.09 in the quarter
ended June 30, 1999, compared to earnings of $0.22 in the second quarter of
1998. Higher costs of purchased power that followed the deregulation of energy
markets in New England during the second quarter of 1999, and the increase in
capacity costs under our power supply contract with Hydro Quebec adversely
impacted results. The higher power supply costs were offset in part by higher
retail revenues due to a 5.5 percent temporary retail rate increase granted by
the VPSB in December 1998.
Earnings from utility operations for the six months ended June 30, 1999 were
$0.35 per common share, compared to a loss of $0.23 in the first half of 1998.
The 1998 loss reflected a charge of $0.65 per share for an accrual of $4.6
million (pretax) in losses related to our long-term Hydro-Quebec power supply
contract and a $900,000 (pretax) write-off of our investment in the Searsburg
wind facility under orders issued by the VPSB.
UNREGULATED BUSINESSES
Earnings from our unregulated businesses included in results from
continuing operations in the second quarter of 1999 were less than the same
period of 1998 due to a gain recognized on the sale of GMPG assets in 1998, and
lower lease revenues in the second quarter of 1999 as a result of the sale of
one of our facilities during the first quarter of 1999.
16
<PAGE>
Earnings from unregulated businesses included in results from
continuing operations for the six months ended June 30, 1999 were greater than
the same period in 1998 due to:
* The sale in March 1998 of the assets of GMPG, which lost $127,000 in the
first half of 1998.
* GMRI had losses of $290,000 in 1998 compared to six month earnings of
$595,000 in 1999, reflecting the absence of pilot operations that ended in
1998 and a $600,000 (after tax) gain on the 1999 sale of our remaining
interest in Green Mountain Energy Resources, LLC.
DISCONTINUED SEGMENT OPERATIONS
MEI, a wholly owned subsidiary that invests in energy generation, energy
and wastewater efficiency projects is the business segment being discontinued.
Its results are reported separately after net income(loss) from continuing
operations. MEI's loss for the three months ended June 30, 1999 was $274,000
less than the same period a year ago. MEI also reported a loss of $603,000 in
the first half of 1999 compared to a loss of $1,111,000 for the same period in
1998. The improvement in both the three and six month periods ended June 30,
1999 as compared to the same periods in 1998 reflects primarily a reduction of
losses from its subsidiary Micronair, LLC. Micronair owns patent rights in 35
states to a wastewater treatment process that addresses sludge disposal
problems.
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour (MWh) sales and average number
of customers for the three and six months ended June 30, 1999 and 1998 are
summarized below:
<TABLE>
<CAPTION>
Three months ended Six months ended
(dollars in thousands) June 30 June 30
Operating revenues 1999 1998 1999 1998
-------- -------- ---------- ----------
<S> <C> <C> <C> <C>
Retail $ 41,689 $ 39,314 $ 88,460 $ 81,166
Sales for Resale 17,154 3,771 28,750 8,149
Other 692 648 1,343 1,350
-------- -------- ---------- ----------
Total Operating Revenues $ 59,535 $ 43,733 $ 118,553 $ 90,665
======== ======== ========== ==========
17
<PAGE>
MWH sales-Retail 438,852 435,228 925,325 910,930
MWH sales for Resale 556,632 115,693 984,424 224,879
-------- -------- ---------- ----------
Total MWH Sales 995,484 550,921 1,909,749 1,135,809
======== ======== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Three months ended Six months ended
June 30 June 30
Average Number of Customers 1999 1998 1999 1998
------ ------ ------ ------
<S> <C> <C> <C> <C>
Residential 71,144 71,221 71,329 71,178
Commercial and Industrial 12,395 12,170 12,371 12,141
Other 65 69 67 70
------ ------ ------ ------
Total Number of Customers 83,604 83,460 83,767 83,389
====== ====== ====== ======
</TABLE>
REVENUES
Revenues from operations in the second quarter of 1999 increased 36.1
percent compared to the same period in 1998. Our operating revenue results from
the retail and wholesale sales of electricity.
Our retail revenues in the second quarter of 1999 were $2.4 million or 6.0
percent higher than for the same period in 1998 due primarily to the 5.5 percent
temporary retail rate increase that became effective in December 1998.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $13.4 million in the second quarter of
1999 compared to the same period in 1998. The 355 percent increase was
primarily due to a new power purchase and supply agreement between the Company
and Morgan Stanley Capital Group, Inc.("MS"), entered into in February 1999.
Under the agreement, we sell power to MS at predefined operating and pricing
parameters. MS then sells to us, at a predefined price, power sufficient to
serve pre-established load requirements.
18
<PAGE>
Revenues from the retail and wholesale sales of electricity increased 30.8
percent for the six months ended June 30, 1999 compared to the same period in
1998.
Year to date retail revenues increased 9.0 percent or $7.3 million over the same
period in 1998, due primarily to the 5.5 percent temporary retail rate increase
discussed above and a 3.61 percent rate increase granted by the VPSB in its
Order dated February 27, 1998. Wholesale revenues for the first half of 1999
increased approximately $20.6 million over the same period of 1998 primarily due
to the new power purchase and supply agreement with MS.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED JUNE 30, 1999
Our power supply expenses increased 73.2 percent or $18.9 million in the
second quarter of 1999 over the same period in 1998.
As a result of a 1998 scheduled outage at Vermont Yankee ("VY"), a nuclear
plant in which we have a 17.9 percent equity interest, we purchased more energy
in 1999 from VY, causing power supply expense to increase by 11.4 percent in the
second quarter of 1999 over the same period in 1998. Costs associated with
scheduled outages at VY are amortized over an 18-month refueling cycle.
Company-owned generation expenses increased 61.4 percent in the second
quarter of 1999 compared with the same period in 1998 primarily due to the
unavailability of several nuclear generation facilities in New England and
higher demand caused by warmer than normal June temperatures that necessitated
the use of our high-cost generating facilities.
The cost of power that we purchased from other companies increased 103.8
percent or $17.2 million in the second quarter of 1999 over the same period in
1998. This was primarily due to the following:
* A $14.7 million increase in power purchased, reflecting the MS power
purchase and sale contract discussed above, whereby we buy power from MS
that is sufficient to serve pre-established load requirements at a
predefined price;
* An increase in the capacity costs in 1999 associated with our
long-term Hydro-Quebec power supply contract; and
* An increase in the costs of short-term power following the
deregulation of energy markets in New England.
19
<PAGE>
An Independent System Operator ("ISO") replaced the New England Power Pool
effective May 1, 1999. The ISO works as a clearinghouse for purchasers and
sellers of electricity in the new deregulated markets. Sellers place bids for
the sale of their generation or purchased power resources and if demand is high
enough the output from those resources is sold.
We must purchase electricity to meet customer demand during periods of high
usage and to replace energy repurchased by Hydro Quebec under an arrangement
negotiated in 1997. Our costs to serve demand during periods of warmer than
normal temperatures in the month of June 1999, and to replace such energy
repurchases by Hydro Quebec rose substantially after the ISO replaced Nepool as
the governing power supply during the second quarter of 1999. During the second
quarter of 1999, costs per MWH were as high as $1,000, contrasted with
historical costs of approximately $100 per MWH during peak periods of demand.
The Company has mitigated some future price risk by purchasing future supplies
on a contractual basis with third parties. The cost of securing future power
supplies has also risen substantially in tandem with higher summer supply costs.
The Company cannot predict the duration or the extent to which future prices
will continue to trade above historical levels of cost. If the new markets
continue to experience the volatility evident in the second quarter of 1999, our
earnings and cash flow could be adversely impacted by a material amount.
POWER SUPPLY EXPENSES - SIX MONTHS ENDED JUNE 30, 1999
For the six months ended June 30, 1999, power supply expenses increased
39.1 percent or $23.3 million over the same period in 1998.
As a result of a 1998 scheduled outage at VY, a nuclear plant in which we
have a 17.9 percent equity interest, we purchased more energy in 1999 from VY
causing power supply expense for the plant to increase by 7.1 percent over the
same period in 1998. Higher amortization of the costs deferred during the 1998
scheduled outage also caused 1999 VY expenses to increase during 1999. Costs
associated with scheduled outages at VY are amortized over an 18-month refueling
cycle.
Company-owned generation expenses decreased 26.8 percent or $1.1 million
for the first six months of 1999 compared to the same period in 1998 primarily
due to the ice storm in 1998, which necessitated use of high-cost generating
facilities to replace power that was unavailable from Hydro-Quebec. This
decrease more than offset the increase occurring in the second quarter of 1999
due to the unavailability of nuclear generation plants.
20
<PAGE>
The cost of power that we purchased from other companies during the first
six months of 1999 increased 58.8 percent or $23.2 million over the same period
in 1998. This was primarily due to the following:
* A $23.3 million increase in power purchased, reflecting the
MS power purchase and sale contract discussed above, whereby we buy power
from MS that is sufficient to serve pre-established load requirements
at a predefined price;
* An increase in the capacity costs in 1999 associated with our long-term
Hydro-Quebec power supply contract;
* An increase in the costs of power following the deregulation of energy
markets in New England, described above; and
* The incremental cost to replace less expensive power we had purchased
from Merrimack Unit #2 under a contract that expired in April 1998.
These increases were partially offset by:
* The absence in the first quarter of 1999 of a $4.6 million loss accrued
in the first quarter of 1998 related to our long-term Hydro-Quebec
power contract as a result of the VPSB order in our 1997 rate case; and
* A $1.4 million reversal in the first quarter of 1999 of a $5.25 million
loss accrued in the fourth quarter of 1998 resulting from the
continued disallowance of Hydro-Quebec power costs during 1999.
OTHER OPERATING EXPENSES
Other operating expenses decreased 13.93 percent or $674,000 in the second
quarter of 1999 compared to the same period in 1998 primarily due to the
elimination of $1.2 million in deferred credits relating to the lease and sale
of our former corporate headquarters. As part of our efforts to reduce operating
costs, we negotiated the purchase of our operating lease for our corporate
headquarters and sold the facility on April 29, 1999. Other operating expense
increased $202,000 for the first six months of 1999. The 2.2 percent increase
over the same 1998 fiscal period reflects costs associated with the Company's
reorganization, partially offset by the reduction in expense caused by the
elimination of the $1.2 million in deferred credits.
We deferred $550,000 in arbitration costs related to our pursuit of claims
against Hydro-Quebec arising from its suspension of deliveries during and after
the 1998 ice storm. The Company has received an accounting order from the VPSB
providing for the deferral of these charges, subject to final determination in a
future rate proceeding. We believe it is probable that the arbitration costs
will ultimately be recovered in rates.
21
<PAGE>
TRANSMISSION EXPENSES
Transmission expenses decreased 10.7% for the three months ended June 30,
1999 as compared to the same period in 1998. The decrease is primarily due to
classification differences between transmission and power supply costs arising
in conjunction with the deregulation of energy markets in New England. For the
six months ended June 30, 1999, transmission expenses decreased 4.5% for the
same reason.
MAINTENANCE EXPENSES
Our maintenance expenses increased 50.0 percent or $631,000 in the second
quarter of 1999 compared to the same period in 1998 due to the amortization of
tree trimming and storm costs incurred during prior periods. For the six months
ended June 30, 1999, maintenance expenses increased 40.6 percent or $1.0 million
compared to the same period in 1998 for the same reason. The increase reflects
the provisions of the MOU under which our 1998 retail rate case was suspended in
November, 1998, including a seven year amortization of costs incurred during a
severe ice storm that swept through the northeast in January 1998, an increase
of $1 million in rights of way maintenance and pole treatment programs and
increased amortization of previuosly deferred tree trimming and storm costs.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses increased 9.3 percent or $359,000 in
the second quarter of 1999 as compared to the same period in 1998 primarily due
to an increase in the amortization of expenditures related to our investments in
technology and the amortization of pension and separation costs deferred during
1998. For the first six months of 1999, depreciation and amortization expense
increased $174,000 or 2.1 percent from the first half of 1998 to $8.5 million.
These amounts reflect the suspension of amortization charges related to the Pine
Street Barge Canal site as discussed under Part I, Item 1,"Environmental
matters".
TAXES OTHER THAN INCOME TAXES
Other taxes decreased 6.9 percent or $125,000 in the second quarter of 1999
over the same period in 1998. A decrease in municipal property taxes resulted
from reappraisals in some municipalities. Other taxes decreased $267,000 or 7.1
percent in the six month period ended June 30, 1999 compared to 1998 for the
same reason.
INCOME TAXES
Income taxes decreased $1.2 million in the second quarter of 1999 compared
to the same period in 1998 due to a decrease in pretax book income. Income
taxes increased from a $595,000 benefit to an expense of $1,335,000 for the six
months ended June 30, 1999 over 1998, respectively, due to an increase in pretax
book income.
22
<PAGE>
OTHER INCOME
Other income for the three months ended June 30, 1999 increased
approximately $280,000 or 82.4 percent over the same 1998 period due primarily
to increases in earnings from subsidiaries as discussed under Part I, Item 2,
"Unregulated Businesses". These same reasons are reflected in the $2.6 million
increase in other income for the six months ended June 30, 1999 compared to the
first half of 1998.
INTEREST CHARGES
Interest charges decreased 5.1 percent or $95,000 in the second quarter of
1999 over the same period in 1998 primarily due to a reduction in long-term and
short-term debt outstanding.
Interest charges decreased $198,000 or 5.2 percent in the first half of 1999
compared to the first half of 1998 for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the six months ended June 30, 1999, we spent $6.9 million principally
for expansion and improvements of our transmission and distribution plant, for
programs to help our customers conserve electricity (conservation), for
expenditures related to the Pine Street Barge Canal site, and for computer
information systems. We expect to spend an additional $14.4 million during the
remainder of 1999.
On June 23, 1999, we renewed a revolving credit agreement with Fleet
National Bank and State Street Bank and Trust Company. The commitment of $15
million represents a reduction from the previous commitment of $45 million. The
agreement is for a period of 364 days and will expire on June 21, 2000. We
believe the amounts available under the new agreement will be sufficient to meet
our forecasted borrowing requirements during the 364 day period. We had no
borrowings outstanding on June 30, 1999.
There are a number of future events that, singularly or in combination,
could lead the banks to refuse to allow further borrowings under the existing
credit agreement, to seek to enter into a new credit agreement with the Company
that has terms that are less advantageous to the Company, and/or to immediately
call in all outstanding loans. Some of those events are:
* the VPSB issues an order in 1999 in our currently suspended 1998 rate
case that triggers a "material adverse change" for the Company; or
* Hydro-Qu bec is unwilling to make new arrangements regarding the cost
of our long-term contract with it.
23
<PAGE>
The credit ratings of the Company's securities are:
Duff & Phelps Moody's Standard & Poor's
--------------- ------- -------------------
First mortgage bonds BBB Baa3 BBB
Unsecured medium term debt BBB- Baa3 BBB-
Preferred stock BB+ ba1 BB+
Duff & Phelps' and Standard & Poor's credit ratings for the Company
remain on Rating Watch-Down and Credit Watch Negative, respectively, due to the
high level of regulatory and public policy uncertainty in Vermont and certain
positions argued by the Department in our rate cases. Moody's has also placed
all of our ratings on review for possible further downgrade.
COMPETITION AND RESTRUCTURING
The electric utility business is experiencing rapid and substantial
changes. These changes are the result of the following trends:
* Surplus generating capacity;
* Disparity in electric rates among and within various regions of the
country;
* Improvements in generation efficiency;
* Alternative energy sources;
* Increasing demand for customer choice; and
* New regulations and legislation intended to foster competition, also
known as "restructuring".
YEAR 2000 COMPUTER COMPLIANCE
We use computer software, hardware, and other equipment in our business
that could be affected by the date transition to the next century. Our primary
Year 2000 concern is the possibility of interruptions in delivery of electricity
to our customers. We are not able to predict the impact of any interruption on
our operations or earnings, but the impact could be material.
In the past several years, we purchased and installed new customer service
and financial management systems. These systems have greatly reduced our
exposure to date-related problems. We have also replaced equipment that would
have been affected by the date change.
Management has established a project team to address Year 2000 issues. The
team has focused on three elements that are integral to the project: business
continuity; project management; and risk management. Business continuity
involves the continuation of reliable electric supply and service in a safe and
cost-effective manner. Project management involves defining and meeting the
project scope schedule and budget. Risk management involves customer
24
<PAGE>
management, contingency planning and legal issues. In addition to these
internal efforts, we have been working with various industry groups to
coordinate electric utility industry Year 2000 efforts.
The approach to identifying and addressing non-compliant software
applications and embedded systems consists of the following stages: inventory
and awareness; assessment; renovation; testing; and implementation. The first
stage is to inventory all applications and systems. The assessment stage
involves determining whether software applications and embedded systems are Year
2000 compliant and prioritizing remediation needs based on risk management. The
renovation stage involves remediating or upgrading applications and systems to
make them Year 2000 ready. The testing stage determines whether the renovated
applications and systems are Year 2000 ready. The implementation stage occurs
when the tested applications and systems are deployed.
The following table summarizes the status at June 30, 1999 of our progress
toward achieving Year 2000 readiness. The figures set forth in the table
represent the estimated extent to which each phase of the Year 2000 project for
software applications and embedded systems have been completed.
Software Embedded
Applications Systems
------------ -------
Inventory 100% 100%
Assessment 90% 100%
Renovation 90% 100%
Testing 80% 100%
Implementation 80% 100%
We have also developed contingency plans for major outages and have adapted
these to the special problems posed by the date change to the next century. If
an unexpected outage does occur we can operate equipment manually and will have
personnel at important locations on New Years Eve 1999 and into 2000.
Our Year 2000 project focuses on those facets of our business that are
required to deliver reliable electric service. The project encompasses the
computer systems that support our core business functions such as customer
information and billing, finance, procurement, supply and personnel as well as
the components of metering, transmission, distribution and generation support.
The project also focuses on embedded systems, instrumentation and control
systems in facilities.
25
<PAGE>
Our current schedule is subject to change, depending on developments that
may arise through unforeseen business circumstances, and through remediation and
testing phases of our compliance effort. Our ability to deliver electricity to
our customers could also be impacted if one of our major power suppliers or
vendors of telecommunication service experienced a date-related system failure.
An interruption in power supplied by other delivery systems, such as the ISO for
New England, could also cause power delivery problems for us. We are
participating in the efforts of the ISO's New England Joint Oversight Committee
to ensure that the systems and delivery of electricity in New England are in
compliance. We have asked these companies to send written reports on their
status in eliminating Year 2000 issues that could negatively affect their
ability to serve us. All other major vendors or businesses that we depend on
for services or supplies have also been asked to report on their status.
The total cost of upgrading software that would not otherwise be replaced
in accordance with our business plans is approximately $376,000. Approximately
$165,000 has been expended as of June 30, 1999, for external labor, hardware and
software costs, and for the costs of employees who are dedicated to the Year
2000 project. The foregoing amounts do not include the cost of new software
applications installed as a result of strategic replacement projects described
earlier. Such replacement projects have not been accelerated because of Year
2000 issues.
The cost of the project and the dates on which we plan to complete our Year
2000 modifications are based on management's best estimates, which were derived
using numerous assumptions of future events, including the continued
availability of certain resources, third parties' Year 2000 readiness and other
factors. Further, we expect to incur additional costs after 1999 to remediate
and replace less critical software applications and embedded systems.
We have also developed contingency plans to address the most reasonably
likely worst case scenarios that could occur in the event that various Year 2000
issues are not resolved in a timely manner. Contingency planning is an ongoing
process and will continue through the fourth quarter of 1999.
The phases of our contingency planning process included business impact
analysis, contingency planning and testing. Business impact analysis requires
business unit personnel to evaluate the impact of mission-critical systems
failure on our core business operations, focusing on specific failure scenarios
and how they can be mitigated. The necessary conditions for enacting the plans
are documented along with the appropriate personnel responsible in each of the
business units should a Year 2000 failure occur. Additionally we have
participated in system readiness drills to simulate major outages and restart
capability and will continue to participate in scheduled drills in 1999.
26
<PAGE>
We believe that we have adequately tested our Year 2000 readiness for our
critical systems. Nevertheless, achieving Year 2000 readiness is subject to
various risks and uncertainties, many of which are described above. We are not
able to predict all the factors that could cause actual results to differ
materially from our current expectations as to our Year 2000 readiness.
However, if we, or third parties with whom we have significant business
relationships, fail to achieve Year 2000 readiness with respect to critical
systems, there could be a material adverse effect on our results of operations,
financial position and cash flows.
WORKFORCE REDUCTIONS
Through GMPworks, our internal efficiency effort, we are examining
critically all work done at the Company. Through the second quarter of 1999,
approximately 80 employees out of a population of 290 have elected to leave
through early retirement or separation programs. During the second quarter, we
recorded a liability of $6.0 million representing our estimate of pension and
separation costs related to the programs. We also recorded a regulatory asset of
$6.0 million consistent with past rate treatment, and believe that it is
probable that we will receive future revenues to recover these costs.
POSSIBLE SALE OF VERMONT YANKEE
Vermont Yankee,a nuclear plant in which the Company has a 17.9 percent
equity interest, has received two proposals for the purchase of the power
station and related assets, one from Amergen Energy Company(Amergen) and one
from Entergy Nuclear, Inc.(Entergy). Amergen is a joint venture of PECO Energy
of Philadelphia and British Energy of Edinburgh, Scotland, companies that
together operate other nuclear power facilities in the United States and Great
Britain. Entergy owns and operates several nuclear power plants in the southern
United States and recently completed the purchase of the Pilgrim Nuclear Station
in Massachusetts. Discussions between Vermont Yankee, Amergen, and Entergy are
ongoing. Each of the parties has expressed a desire to close a sale by the end
of the year 2000. Regulatory approval by the Nuclear Regulatory Commission, the
VPSB, and other government bodies would be required before any transaction could
be completed.
27
<PAGE>
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
JUNE 30, 1999
-------------
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
At the Annual Shareholders Meeting held May 20, 1999, Shareholders elected
the nominees listed below as Directors of this company. The voting results are
set forth below. There were no other items brought before the meeting.
ELECTION OF DIRECTORS
-----------------------
Shareholders elected the nominees for Director as follows:
<TABLE>
<CAPTION>
BROKER
TOTAL VOTES TOTAL VOTES NON-VOTES
NOMINEE FOR AGAINST ABSENTIONS
--------------------------- ---------------------- ---------------------
<S> <C> <C> <C>
Class I (term expires 2002)
William H. Bruett 4,071,585 144,704 1,098,922
David R. Coates 4,074,831 141,458 1,098,922
Martin L. Johnson 4,062,481 153,808 1,098,922
Thomas P. Salmon 4,062,200 154,089 1,098,922
DIRECTORS CONTINUING IN OFFICE
- ---------------------------------
Class II (term expires 2000)
Merrill O. Burns
Christopher L. Dutton
Ruth W. Page
Class III (term expires 2001)
Nordahl L. Brue
Lorraine E. Chickering
John V. Cleary
Euclid A. Irving
</TABLE>
ITEM 5. Other Information
NONE
ITEM 6. (A) EXHIBITS
--------
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
----------------------
A report on Form 8-K was filed on June 2, 1999 disclosing a new revolving credit
agreement.
28
<PAGE>
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
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.
GREEN MOUNTAIN POWER CORPORATION
-----------------------------------
(Registrant)
Date: August 14, 1999 /s/ Nancy Rowden Brock
-----------------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer and
Treasurer
Date: August 14, 1999 /s/ R. J. Griffin
-----------------------------------
R. J. Griffin, Controller
29
<PAGE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of June 30, 1999 and the related Consolidated
Statements of Income and Cash Flows for the six months ended June 30, 1999, and
is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1000
<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> 194954
<OTHER-PROPERTY-AND-INVEST> 20911
<TOTAL-CURRENT-ASSETS> 33806
<TOTAL-DEFERRED-CHARGES> 30377
<OTHER-ASSETS> 1684
<BUSINESS SEGMENT HELD FOR SALE> 16433
<TOTAL-ASSETS> 298166
<COMMON> 17892
<CAPITAL-SURPLUS-PAID-IN> 72331
<RETAINED-EARNINGS> 18197
<TOTAL-COMMON-STOCKHOLDERS-EQ> 108041
3440
12645
<LONG-TERM-DEBT-NET> 86800
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1700
0
<CAPITAL-LEASE-OBLIGATIONS> 7696
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 79543
<TOT-CAPITALIZATION-AND-LIAB> 298166
<GROSS-OPERATING-REVENUE> 118553
<INCOME-TAX-EXPENSE> 1335
<OTHER-OPERATING-EXPENSES> 9458
<TOTAL-OPERATING-EXPENSES> 113671
<OPERATING-INCOME-LOSS> 4883
<OTHER-INCOME-NET> 1505
<INCOME-BEFORE-INTEREST-EXPEN> 6388
<TOTAL-INTEREST-EXPENSE> 3624
<NET-INCOME> 2764
610
<EARNINGS-AVAILABLE-FOR-COMM> 2154
<COMMON-STOCK-DIVIDENDS> 1465
<TOTAL-INTEREST-ON-BONDS> 3394
<CASH-FLOW-OPERATIONS> 21947
<EPS-BASIC> (0.10)
<EPS-DILUTED> (0.10)
</TABLE>
