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 March 31, 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 incorporation (I.R.S. Employer
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 March 31, 1999
$3.33 1/3 Par Value 5,326,525
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
Part 1 - Item 1
March 31 December 31
----------------------------------- ----------------
1999 1998 1998
---------------- ---------------- ----------------
(Unaudited) (In thousands)
(In thousands)
ASSETS
<S> <C> <C> <C>
Utility Plant
Utility plant, at original cost.................... $276,614 $265,137 $276,853
Less accumulated depreciation...................... 96,804 90,287 94,604
---------------- ---------------- ----------------
Net utility plant................................ 179,810 174,850 182,249
Property under capital lease....................... 7,696 8,342 7,696
Construction work in progress...................... 7,699 12,607 5,611
---------------- ---------------- ----------------
Total utility plant, net......................... 195,205 195,799 195,556
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity ................... 15,057 15,497 15,048
Other investments.................................. 5,763 5,838 5,630
---------------- ---------------- ----------------
Total other investments.......................... 20,820 21,335 20,678
---------------- ---------------- ----------------
Current Assets
Cash and cash equivalents.......................... 11,574 15,371 439
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $471, $404 and $449........................... 18,457 16,019 18,977
Accrued utility revenues .......................... 6,223 6,075 6,611
Fuel, materials and supplies, at average cost...... 3,140 3,487 3,139
Prepayments........................................ 1,893 9,723 6,091
Other.............................................. 213 312 443
---------------- ---------------- ----------------
Total current assets............................. 41,500 50,987 35,700
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 9,493 12,632 10,590
Purchased power costs.............................. 4,062 4,278 5,708
Other.............................................. 13,689 12,962 14,278
---------------- ---------------- ----------------
Total deferred charges........................... 27,244 29,872 30,576
---------------- ---------------- ----------------
Non-Utility
Cash and cash equivalents.......................... 149 93 151
Other current assets............................... 2,682 3,871 3,409
Property and equipment............................. 431 1,222 1,213
Intangible assets.................................. 1,585 21 1,658
Equity investment in energy related businesses..... 11,804 12,316 12,357
Other assets....................................... 9,664 9,239 8,526
---------------- ---------------- ----------------
Total non-utility assets......................... 26,315 26,762 27,314
---------------- ---------------- ----------------
Total Assets........................................... $311,084 $324,755 $309,824
================ ================ ================
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,342,381, 5,223,018 and 5,313,296)........... $17,799 $17,544 $17,711
Additional paid-in capital....................... 72,123 70,995 71,914
Retained earnings................................ 19,425 21,884 17,508
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 108,969 110,045 106,755
Redeemable cumulative preferred stock.............. 16,085 17,735 16,085
Long-term debt, less current maturities............ 88,500 90,200 88,500
---------------- ---------------- ----------------
Total capitalization........................... 213,554 217,980 211,340
---------------- ---------------- ----------------
Capital lease obligation............................... 7,696 8,342 7,696
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,700 4,700 1,700
Short-term debt.................................... -- 8,016 7,000
Accounts payable, trade, and accrued liabilities... 4,826 7,203 5,453
Accounts payable to associated companies........... 5,664 8,020 7,143
Dividends declared................................. 364 352 362
Customer deposits.................................. 361 733 336
Taxes accrued...................................... 2,472 813 370
Interest accrued................................... 1,888 2,073 1,203
Deferred revenues ................................. 6,146 5,773 --
Other.............................................. 3,803 4,763 5,258
---------------- ---------------- ----------------
Total current liabilities...................... 27,224 42,446 28,825
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 23,780 24,119 23,389
Unamortized investment tax credits................. 4,189 4,472 4,260
Pine Street Barge Canal site cleanup............... 5,000 -- 5,000
Other.............................................. 21,734 17,759 22,240
---------------- ---------------- ----------------
Total deferred credits......................... 54,703 46,350 54,889
---------------- ---------------- ----------------
Non-Utility
Current liabilities................................ 525 1,543 720
Other liabilities.................................. 7,382 8,094 6,354
---------------- ---------------- ----------------
Total non-utility liabilities.................. 7,907 9,637 7,074
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $311,084 $324,755 $309,824
================ ================ ================
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Income Statements
(Unaudited)
Part 1 - Item 1
Three Months Ended
March 31
-----------------------------------------
1999 1998
----------------- -----------------
(In thousands, except amounts per share)
<S> <C> <C>
Operating Revenues ............................................. $59,018 $46,932
----------------- -----------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation .................. 8,359 7,980
Company-owned generation................................... 1,025 2,835
Purchases from others...................................... 28,891 23,042
Other operating............................................... 5,292 4,416
Transmission.................................................. 2,310 2,261
Maintenance................................................... 1,570 1,202
Depreciation and amortization................................. 4,240 4,424
Taxes other than income....................................... 1,814 1,957
Income taxes.................................................. 1,611 (1,501)
----------------- -----------------
Total operating expenses................................... 55,112 46,616
----------------- -----------------
Operating income......................................... 3,906 316
----------------- -----------------
Other Income (Expense)
Equity (loss) in earnings of affiliates and non-utility
operations.................................................. 813 (573)
Allowance for equity funds used during construction........... 20 53
Other income and deductions, net.............................. 53 (919)
----------------- -----------------
Total other income (expense)................................ 886 (1,439)
----------------- -----------------
Income (loss) before interest charges..................... 4,792 (1,123)
----------------- -----------------
Interest Charges
Long-term debt................................................ 1,703 1,799
Other......................................................... 150 217
Allowance for borrowed funds used during construction........ (14) (74)
----------------- -----------------
Total interest charges...................................... 1,839 1,942
----------------- -----------------
Net Income (Loss)............................................... 2,953 (3,065)
Dividends on preferred stock.................................... 305 340
----------------- -----------------
Net Income (Loss) Applicable to Common Stock.................... $2,648 ($3,405)
================= =================
Common Stock Data
Basic and diluted earnings per share.......................... $0.50 ($0.66)
Cash dividends declared per share............................. $0.1375 $0.275
Weighted average shares outstanding........................... 5,318 5,196
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................... $17,508 $26,717
Net Income (Loss)............................................... 2,953 (3,065)
----------------- -----------------
20,461 23,652
----------------- -----------------
Cash Dividends - redeemable cumulative preferred stock.......... 305 340
- common stock................................... 731 1,428
----------------- -----------------
1,036 1,768
----------------- -----------------
Balance - end of period......................................... $19,425 $21,884
================= =================
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Part 1 - Item 1
Three Months Ended
March 31
---------------------------------------
1999 1998
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income (Loss).................................................... $2,953 ($3,158)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 4,240 4,424
Dividends from associated companies less equity income........... (10) 362
Allowance for funds used during construction..................... (34) (142)
Deferred purchased power costs................................... (243) (1,981)
Amortization of purchased power costs............................ 1,889 1,089
Deferred income taxes............................................ 391 746
Deferred revenues ............................................... 6,146 5,773
Amortization of investment tax credits........................... (71) (71)
Environmental proceedings costs.................................. (243) (595)
Conservation expenditures........................................ (311) (382)
Changes in:
Accounts receivable............................................ 519 1,347
Accrued utility revenues....................................... 388 430
Fuel, materials, and supplies.................................. (1) (226)
Prepayments and other current assets........................... 5,156 (4,922)
Accounts payable............................................... (2,106) 734
Taxes accrued.................................................. 2,102 (2,029)
Interest accrued............................................... 685 762
Other current liabilities...................................... (1,624) 4,038
Other............................................................ 650 (2,027)
----------------- -----------------
Net cash provided by operating activities.......................... 20,476 4,172
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (1,539) (3,048)
Investment in nonutility property.................................. 19 420
Proceeds from sale of propane subsidiary........................... -- 11,500
----------------- -----------------
Net cash provided by (used in) investing activities.............. (1,520) 8,872
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 297 500
Short-term debt, net............................................... (7,000) 5,400
Reduction in long-term debt........................................ (84) (1,983)
Cash dividends..................................................... (1,036) (1,768)
----------------- -----------------
Net cash provided by (used in) financing activities.............. (7,823) 2,149
----------------- -----------------
Net increase in cash and cash equivalents.......................... 11,133 15,193
Cash and cash equivalents at beginning of period................... 590 271
----------------- -----------------
Cash and cash equivalents at end of period............................. $11,723 $15,464
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date for:
Interest (net of amounts capitalized)........................... $1,103 $1,190
Income taxes.................................................... -- 6
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 1999
Part 1 -- 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 as
specifically noted in the Consolidated Financial Statements, are of a
normal, recurring nature.
The rates we charge our customers for their electricity are set by
the Vermont Public Service Board (VPSB), which is the regulatory
commission in Vermont. 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 March 31, 1999, there was a deferred credit balance of
$6.1 compared to $5.8 million for the same period in 1998 consistent
with the temporary retail rate increase of 5.7 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 suspension of the 1998 rate case.
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) We also have a rental water heater program that is not regulated
by the VPSB. The results of the operations of these subsidiaries 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:
Three Months Ended
March 31
1999 1998
---- ----
(In thousands)
Revenue . . . . . . . . . . . . . . . . $ 1,054 $2,406
Expense . . . . . . . . . . . . . . . 742 3,465
------- --------
Net Income (Loss) . . . . . . . . . . . $ 312 ($1,059)
======= ========
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%
Three Months Ended
March 31
1999 1998
---- ----
(In Thousands)
Gross Revenue . . . . . $43,777 $51,170
Net Income Applicable
to Common Stock . . 1,656 1,702
Company's Equity in
Net Income . . . . . 294 298
Vermont Electric Power Company, Inc.
Percent Ownership: 29.5% common
30.0% preferred
Three Months Ended
March 31
1999 1998
---- ----
(In Thousands)
Gross Revenue . . . . . . $ 6,934 $11,820
Net Income . . . . . . . 292 286
Company's Equity in
Net Income . . . . . . 86 67
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 its 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.
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 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.
The EPA estimates that the present value cost of the remedy will be
$4.4 million, although actual costs may be higher.
As of March 31, 1999, our total expenditures related to the Pine
Street Barge Canal site since 1982 were approximately $17.2 million.
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 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, 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 negotiation soon of a final settlement with
the United States and the State 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 $5 to $9 million.
In 1998, we recorded a liability of $5 million to recognize the low end
of this range of costs. 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
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-Quebec power contract costs. The amount charged to first
quarter income of $4.6 million (pre-tax) was less than the full
disallowance because we expected 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, delays 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
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 March 31, 1999 balance sheet, if we were required to
discontinue the application of SFAS 71, we would be required to take an
after-tax charge to earnings of approximately $21.3 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.
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-Quebec 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 deprives 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 5.7 percent temporary retail rate
increase, to produce $9.19 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 and will remain in effect until the VPSB issues a
final order in the rate case docket, expected by December 15, 1999.
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.
6. Corporate Headquarters Lease
As part of our efforts to reduce operating costs, we negotiated the
purchase of our operating lease for our corporate headquarters and two
of our district offices. On April 29, 1999, we sold the corporate
headquarters, but retained ownership of the two district offices. A loss
of approximately $1.9 million (pre-tax) was recorded in 1998 to reflect
the loss associated with completing this transaction.
7. 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.
Segment information for the three months ended March 31,
1999 includes the following:
Electric
Utility MEI
-------- ---
(In thousands)
Revenues-external $59,018 $777
Segment profit (loss) 3,170 (522)
Segment information for the three months ended March 31,
1998 includes the following:
Electric
Utility MEI
-------- ---
(In thousands)
Revenues-external $46,932 $215
Segment loss (2,648) (757)
Net Income (Loss) of Mountain Energy, Inc., is included
in the Equity (Loss)in Earnings of Affiliates and Non-
Utility Operations line of the Consolidated Statements of
Income. The following table is a reconciliation of MEI's
loss to the equity (loss) in
Earnings of affiliates and non-utility
operations:
For the three months ended
March 31,
1999 1998
---- ----
(In thousands)
MEI loss ($522) ($757)
Electric utility
equity in earnings
of affiliates and
non-utility
Operations 1,335 184
----- ------
Total equity (loss)
in earnings of
affiliates and
non-utility
operations $813 ($573)
==== =======
8. 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 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.
9. Reclassification
Certain line items on the prior year's financial statements have
been reclassified for consistent presentation with the current year.
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
March 31, 1999
Part 1 -- 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.
RESULTS OF OPERATIONS
Earnings Summary- Overview
In this section, we discuss our earnings and the factors affecting
them. We separately discuss earnings for the utility business and for
our subsidiaries.
Total earnings (loss) per share of Common Stock
Three months ended
March 31,
1999 1998
---- ----
Utility business $0.44 ($0.46)
Unregulated businesses $0.06 ($0.20)
----- -------
Basic and diluted earnings
(loss) per share $0.50 ($0.66)
===== =======
Three months ended March 31, 1999
Utility business
Earnings from our utility business in the first quarter of 1999
improved from the loss for the same period of 1998. We recorded a loss
of $0.46 in the first quarter of 1998 that reflected a charge of $0.69
per share for an accrual of $4.6 million (pretax) in losses related to
our long-term Hydro-Quebec power contract and a $1.3 million (pretax)
write off of our investment in the Searsburg wind facility under a rate
order issued by the VPSB on March 2, 1998.
Unregulated businesses
Earnings from our subsidiaries in the first quarter of 1999 were
greater than the same period of 1998 due to:
- -- A $600,000 (after-tax) gain on the sale of our remaining
interest in Green Mountain Energy Resources, or $.11 per share
of common stock;
- -- The sale in March 1998 of the assets of Green Mountain Propane
Gas (GMPG), which lost $290,000 (after tax) in the first quarter
of 1998, or $.05 per share of common stock; and
- -- A $235,000 (after tax) decrease in losses by Mountain Energy,
Inc. (MEI), or $.04 per share of common stock.
MEI, our wholly owned subsidiary that invests in energy generation
and energy and wastewater efficiency projects, experienced a loss of
$522,000 in the first quarter of 1999 as compared to a loss of $757,000
for the same period in 1998, primarily due to the continued start-up
operating losses incurred by 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 months ended March 31, 1999 and 1998
are summarized below:
Three Months Ended
March 31
1999 1998
---- ----
Operating Revenues
(In thousands)
Retail . . . . . . . $46,771 $ 41,852
Sales for Resale . . 11,596 4,378
Other . . . . . . . 651 702
------- --------
Total Operating
Revenues . . . . $59,018 $ 46,932
======= ========
MWh Sales
Retail . . . . . . . . 486,473 475,702
Sales for Resale . . . 427,792 109,186
------- -------
Total MWh Sales . . . 914,265 584,888
======= =======
Average Number of Customers
Residential . . . . . 71,423 71,134
Commercial &
Industrial . . . . . 12,366 12,112
Other . . . . . . . . 68 71
------ ------
Total Customers . . 83,857 83,317
====== ======
Revenues - three months ended March 31, 1999
Our operating revenue results from the retail and wholesale sales
of electricity.
Revenues from operations in the first quarter of 1999 increased
25.8 percent compared to the same period in 1998.
Our retail revenues in the first quarter of 1999 were 11.8 percent
higher than for the same period in 1998 for the following reasons:
- -- A 5.7 percent temporary retail rate increase that became
effective in December 1998 and the 3.61 percent rate increase
granted by the VPSB in its Order dated February 27, 1998;
- -- Colder, but more normal, weather in 1999 as compared to the
same period in 1998; and
- -- a 2.9 percent increase in sales to small commercial and
industrial customers primarily caused by a 2.0 percent
increase in the number of these customers.
We sell wholesale electricity to otherss for resale. Our revenue
from wholesale sales of electricity increased $7.2 million in the first
quarter of 1999 compared to the same period in 1998. The increase is
primarily due to a new power purchase and supply agreement between the
Company and Morgan Stanley Capital Group, Inc. (MS), entered into on
February ll, 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.
OPERATING EXPENSES
Power supply expenses--three months ended March 31, 1999
Our power supply expenses increased 13.1 percent in the first
quarter of 1999 over the same period in 1998.
Costs associated with scheduled outages at Vermont Yankee are
amortized over an 18-month refueling cycle. As a result of amortization
due to a scheduled outage in 1998, our power expense from Vermont
Yankee, a nuclear plant in which we have a 17.9 percent equity interest
and from which we purchase power, increased 4.7 percent in the first
quarter of 1999 over the same period in 1998.
Company-owned generation expenses decreased 63.9 percent in the
first quarter of 1999 compared with the same period in 1998 primarly due
to the ice storm in 1998, which necessitated use of high-cost generating
facilities to replace power that was unavailable from Hydro-Quebec.
The cost of power that we purchased from other companies increased
25.4 percent in the first quarter of 1999 over the same period in 1998.
This was primarily due to the following:
- -- An $8.5 million increase in power purchased under the power
purchase and sale contract, discussed above, with Morgan Stanley
Capital Group whereby we buy power from Morgan Stanley at a
predefined price that is sufficient to serve pre-established
load requirements;
- -- An increase in the capacity costs in 1999 associated with our
long-term Hydro-Quebec power contract; and
- -- The cost to replace less expensive power we had purchased from
Merrimack 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 Vermont Public
Service Board 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-three months ended March 31, 1999
Other operating expenses increased 19.8 percent or $875,000 in the
first quarter of 1999 compared to the same period in 1998 primarily due
to charges associated with our reorganization.
Transmission expenses-three months ended March 31, 1999
Transmission expenses were virtually unchanged for the three months
ended March 31, 1999 as compared to the same period in 1998.
Maintenance expenses-three months ended March 31, 1999
Our maintenance expenses increased 30.6 percent or $368,000 in the
first quarter of 1999 compared to the same period in 1998 due to the
amortization of tree trimming and storm costs incurred during prior
periods.
Depreciation and amortization expenses-three months ended March 31, 1999
Our depreciation and amortization expenses decreased 4.2 percent in
the first quarter of 1999 as compared to the same period in 1998
primarily due to a decrease in the amortization of expenditures related
to the Pine Street Barge Canal site. These amortization charges were
suspended by the VPSB in an Order released March 2, 1998.
Taxes other than income taxes-three months ended March 31, 1999
Other taxes decreased 7.3 percent in the first quarter of 1999 over
the same period in 1998 primarily because of a decrease in municipal
property taxes as a result of reappraisals in some municipalities.
Income taxes-three months ended March 31, 1999
Income taxes increased in the first quarter of 1999 compared to the
same period in 1998 due to an increase in pretax book income.
Other income-three months ended March 31, 1999
Other income increased in the first quarter of 1999 over the same
period in 1998 for the following reasons:
- -- A write-off in the first quarter of 1998 of $1.3 million of
construction costs for the Searsburg wind generating plant
resulting from a VPSB order on our 1997 rate case;
- -- A $600,000 (after-tax) gain on the sale of our remaining
interest in Green Mountain Energy Resources;
- -- A $290,000 (after tax) operating loss incurred by GMPG in 1998; and
- -- A $235,000 (after tax) reduction in losses incurred by MEI.
Interest Charges
Our interest charges decreased 5.3 percent or $102,000 in the first
quarter of 1999 over the same period in 1998 primarily due to ?a
reduction in long-term and short-term debt outstanding.
LIQUIDITY AND CAPITAL RESOURCES
In the three months ended March 31, 1999, we spent $2.9 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 $18.4 million during the remainder of 1999.
We have a revolving credit agreement in the amount of $45 million
with three banks, with no borrowings outstanding on March 31, 1999. The
agreement expires as of June 30, 1999.
We expect that certain of the banks will enter into a new agreement
with the Company at a reduced amount for a period of 364 days. 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-Quebec is unwilling to make new arrangements regarding the
cost of our long-term contract with it.
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- -- BB+
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 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 have nearly completed
installing new customer service and financial management systems. These
systems have greatly reduced our exposure to date-related problems. We
will implement and test further upgrades to these systems during 1999 to
ensure that they are Year 2000 compliant. 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 is 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 management, contingency
planning and legal issues. In addition to these internal efforts, we
are 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.
We have also developed contingency plans for major outages and are
adapting 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.
The following table summarizes the status at March 31, 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 . . . . . . . 85% 100%
Renovation . . . . . . . 50% 95%
Testing . . . . . . . . . 30% 95%
Implementation . . . . . 30% 95%
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 independent system
operator (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 remediating or upgrading software that would not
otherwise be replaced in accordance with our business plans is
approximately $376,000. Approximately $110,000 has been expended as of
March 31, 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 utilizing 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 begun the process of developing 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 include 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 will be 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.
Based on our current schedule for completion of Year 2000 tasks, we
believe that our planning is adequate to secure Year 2000 readiness of
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. In April 1999, approximately
60 employees out of a population of 280 have elected to leave through
early retirement or voluntary separation programs. The unaccrued
liability for pension costs related to the 60 employees is estimated to
exeeed $5.2 million. We anticipate further workforce reductions and
associated costs which could be material. We will defer the majority of
these costs and believe that it is probable that we will receive future
revenues to recover these costs.
GREEN MOUNTAIN POWER CORPORATION
March 31, 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
NONE.
ITEM 5. Other Information
NONE
ITEM 6. (a) EXHIBITS
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K
NONE
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: May 14, 1999 /s/ Nancy Rowden Brock
Nancy Rowden Brock, Vice President,
Chief Financial Officer and
Treasurer
Date: May 14, 1999 /s/ R. J. Griffin
R. J. Griffin, Controller
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