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 September 30, 1994
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 Identification No.)
incorporation or organization)
25 Green Mountain Drive
South Burlington, VT 05402
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 September 30, 1994
$3.33 1/3 Par Value 4,624,815
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1
- - ------
A.1
<CAPTION>
September 30 December 31
----------------------------------- ----------------
1994 1993 1993
---------------- ---------------- ----------------
(In thousands) (In thousands)
ASSETS
ELECTRIC UTILITY
<S> <C> <C> <C>
Utility Plant
Utility plant, at original cost.................... $223,992 $207,765 $214,977
Less accumulated depreciation...................... 69,282 63,530 64,226
---------------- ---------------- ----------------
Net utility plant................................ 154,710 144,235 150,751
Property under capital lease....................... 11,029 11,950 11,029
Construction work in progress...................... 8,807 12,914 9,631
---------------- ---------------- ----------------
Total utility plant, net......................... 174,546 169,099 171,411
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity (Note 2)........... 16,700 17,074 16,886
Nonutility property................................ 3,957 3,417 3,521
Other investments.................................. -- 2,107 2,121
---------------- ---------------- ----------------
Total other investments.......................... 20,657 22,598 22,528
---------------- ---------------- ----------------
Current Assets
Cash............................................... 70 108 50
Temporary investments.............................. -- 1,600 --
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 10,875 12,836 14,814
Accrued utility revenues (Note 1).................. 4,640 4,542 6,138
Fuel, materials and supplies, at average cost...... 3,286 2,667 2,841
Prepayments........................................ 1,811 1,105 1,984
Current revenue due to income taxes................ 214 243 729
Other.............................................. 1,014 1,068 388
---------------- ---------------- ----------------
Total current assets............................. 21,910 24,169 26,944
---------------- ---------------- ----------------
Deferred Charges
Future revenue due to income taxes................. 4,179 4,908 4,179
Unfunded future federal income taxes............... 4,432 4,666 4,590
Demand side management programs................... 15,009 9,680 12,809
Environmental proceedings costs.................... 7,637 4,120 5,356
Purchased power costs.............................. 903 3,024 4,134
Other.............................................. 11,211 9,958 11,277
---------------- ---------------- ----------------
Total deferred charges........................... 43,371 36,356 42,345
---------------- ---------------- ----------------
NON-UTILITY
Cash and cash equivalents.......................... 703 305 177
Other current assets............................... 4,705 2,554 3,479
Property and equipment............................. 11,090 11,207 11,331
Intangible assets.................................. 3,141 3,622 3,484
Other assets....................................... 12,978 7,154 10,155
---------------- ---------------- ----------------
Total non-utility assets......................... 32,617 24,842 28,626
---------------- ---------------- ----------------
Total Assets........................................... $293,101 $277,064 $291,854
================ ================ ================
CAPITALIZATION AND LIABILITIES
ELECTRIC UTILITY
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
4,640,671, 4,501,078, and 4,536,042).......... $15,469 $15,003 $15,120
Additional paid-in capital....................... 59,575 56,193 57,178
Retained earnings................................ 25,306 24,498 25,229
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 99,972 95,316 97,149
Redeemable cumulative preferred stock.............. 9,385 9,575 9,385
Long-term debt, less current maturities............ 78,000 64,950 79,800
---------------- ---------------- ----------------
Total capitalization........................... 187,357 169,841 186,334
---------------- ---------------- ----------------
Capital Lease Obligation............................... 11,029 11,950 11,029
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,800 1,900 1,800
Short-term debt.................................... 12,815 23,215 19,015
Accounts payable, trade, and accrued liabilities... 4,691 5,784 8,373
Accounts payable to associated companies........... 4,012 6,283 4,302
Dividends declared................................. 199 203 199
Customer deposits.................................. 1,112 1,092 1,197
Taxes accrued...................................... 3,248 239 397
Interest accrued................................... 1,818 1,446 2,070
Current revenue reduction due to income taxes...... 66 75 225
Unfunded future federal income taxes............... 214 243 729
Other.............................................. 491 501 572
---------------- ---------------- ----------------
Total current liabilities...................... 30,466 40,981 38,879
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 19,367 18,362 20,683
Unamortized investment tax credits................. 5,473 5,766 5,672
Future revenue reduction due to income taxes....... 4,366 4,590 4,366
Unfunded future federal income taxes............... 4,179 4,908 4,179
Other.............................................. 22,374 13,131 13,541
---------------- ---------------- ----------------
Total deferred credits......................... 55,759 46,757 48,441
---------------- ---------------- ----------------
NON-UTILITY
Current liabilities................................ 648 372 666
Other liabilities.................................. 7,842 7,163 6,505
---------------- ---------------- ----------------
Total non-utility liabilities.................. 8,490 7,535 7,171
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $293,101 $277,064 $291,854
================ ================ ================
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Income Statements
(Unaudited)
Part 1
- - ------
A.2
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
------------------------------- -------------------------------
1994 1993 1994 1993
------------ ------------ ------------ ------------
(In thousands, except amounts per share)
<S> <C> <C> <C> <C>
Operating Revenues (Note 1)................................... $36,684 $35,647 $110,898 $109,824
------------ ------------ ------------ ------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................. 7,419 7,681 21,861 22,675
Company-owned generation................................. 782 1,000 2,619 2,473
Purchases from others.................................... 11,340 10,817 35,210 34,120
Other operating............................................. 4,250 4,374 13,699 13,353
Transmission................................................ 2,683 2,751 7,884 8,193
Maintenance................................................. 963 1,101 3,475 3,256
Depreciation and amortization............................... 3,070 2,143 7,619 6,429
Taxes other than income..................................... 1,542 1,490 4,789 4,592
Income taxes................................................ 1,392 1,215 3,734 4,405
------------ ------------ ------------ ------------
Total operating expenses................................. 33,441 32,572 100,890 99,496
------------ ------------ ------------ ------------
Operating Income....................................... 3,243 3,075 10,008 10,328
------------ ------------ ------------ ------------
Other Income
Equity in earnings of affiliates and non-utility operations. 1,054 562 2,745 1,787
Allowance for equity funds used during construction......... 47 37 258 205
Other income and deductions, net............................ 92 40 282 32
------------ ------------ ------------ ------------
Total other income........................................ 1,193 639 3,285 2,024
------------ ------------ ------------ ------------
Income before interest charges.......................... 4,436 3,714 13,293 12,352
------------ ------------ ------------ ------------
Interest Charges
Long-term debt.............................................. 1,694 1,576 5,174 4,847
Other....................................................... 188 193 581 433
Allowance for borrowed funds used during construction....... (99) (106) (392) (246)
------------ ------------ ------------ ------------
Total interest charges.................................... 1,783 1,663 5,363 5,034
------------ ------------ ------------ ------------
Net Income.................................................... 2,653 2,051 7,930 7,318
Dividends on preferred stock.................................. 199 203 597 609
------------ ------------ ------------ ------------
Net Income Applicable to Common Stock......................... $2,454 $1,848 $7,333 $6,709
============ ============ ============ ============
Common Stock Data
Earnings per share.......................................... $0.54 $0.41 $1.61 $1.51
Cash dividends declared per share........................... $0.53 $0.53 $1.59 $1.58
Weighted average shares outstanding......................... 4,605 4,470 4,569 4,442
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................. $25,289 $25,017 $25,229 $24,801
Net Income.................................................... 2,653 2,051 7,930 7,318
------------ ------------ ------------ ------------
27,942 27,068 33,159 32,119
------------ ------------ ------------ ------------
Cash Dividends - redeemable cumulative preferred stock........ 199 203 597 609
- common stock................................. 2,437 2,367 7,256 7,012
------------ ------------ ------------ ------------
2,636 2,570 7,853 7,621
------------ ------------ ------------ ------------
Balance - end of period....................................... $25,306 $24,498 $25,306 $24,498
============ ============ ============ ============
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Part 1
- - ------
A.3
<CAPTION>
Nine Months Ended
September 30
---------------------------------------
1994 1993
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income........................................................... $7,930 $7,318
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 7,619 6,429
Dividends from associated companies less equity income........... 186 65
Allowance for funds used during construction..................... (651) (451)
Amortization of purchased power costs............................ 3,311 2,970
Deferred income taxes............................................ (1,316) 2,858
Amortization of gain on sale of property......................... (40) (40)
Deferred purchased power costs................................... (80) (4,550)
Amortization of investment tax credits........................... (200) (189)
Environmental proceedings costs, net............................. 7,438 (1,214)
Changes in:
Temporary investments.......................................... -- (1,600)
Accounts receivable............................................ 3,939 4,362
Accrued utility revenues....................................... 798 1,058
Fuel, materials, and supplies.................................. (445) 227
Prepayments and other current assets........................... (979) 2,066
Accounts payable............................................... (3,973) (1,713)
Taxes accrued.................................................. 2,851 (577)
Interest accrued............................................... (252) 279
Other current liabilities...................................... (183) (2,675)
Other............................................................ 53 (190)
----------------- -----------------
Net cash provided by operating activities.......................... 26,006 14,433
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (9,075) (10,675)
Conservation expenditures.......................................... (3,465) (4,028)
Investment in non-utility property................................. 188 (2,883)
Special fund for postretirement benefits........................... -- (587)
----------------- -----------------
Net cash used in investing activities............................ (12,352) (18,173)
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 2,746 2,975
Short-term debt, net............................................... (6,201) 11,600
Cash dividends..................................................... (7,853) (7,622)
Reduction in long-term debt........................................ (1,800) (3,280)
----------------- -----------------
Net cash provided by (used in) financing activities.............. (13,108) 3,673
----------------- -----------------
Net increase (decrease) in cash and cash equivalents............... 546 (67)
Cash and cash equivalents at beginning of period................... 227 480
----------------- -----------------
Cash and Cash Equivalents at End of Period............................. $773 $413
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date for:
Interest (net of amounts capitalized)........................... $5,904 $4,926
Income taxes.................................................... 2,240 1,831
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1994
Part 1
- - ------
A.4
1. SIGNIFICANT ACCOUNTING POLICIES
Pursuant to an order of the Vermont Public Service Board (VPSB), the
Company's rate structure is seasonally differentiated, with higher rates
billed during the four winter months and lower rates billed during the
remaining eight months of the year. In order to match revenues with
related costs more accurately on an interim basis, the Company
recognizes revenue in a manner that seeks to eliminate the impact of
such seasonally differentiated rates. At both September 30, 1994 and
1993, the Company had recorded deferred revenues of $2.2 million, in
accordance with this policy. This deferred asset is recognized as an
expense in subsequent interim periods.
Included in equity in earnings of affiliates and non-utility operations
in the Other Income section of the Consolidated Comparative Income
Statements are the results of operations of the Company's rental water
heater program, which is not regulated by the VPSB, and four of the
Company's wholly-owned subsidiaries, Green Mountain Propane Gas Company,
Mountain Energy, Inc., GMP Real Estate Corporation, and Lease-Elec, Inc.
(also unregulated). Summarized financial information for the rental
water heater program and such wholly-owned subsidiaries is as follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------ -----------------
1994 1993 1994 1993
---- ---- ---- ----
(In Thousands) (In Thousands)
Revenue . . . . . . . . . . $2,695 $1,985 $9,315 $8,222
Expenses . . . . . . . . . . 2,155 2,048 8,112 8,313
------ ------- ------ -------
Net Income . . . . . . . . . $ 540 $ (63) $1,203 $ (91)
====== ======= ====== =======
2. INVESTMENT IN ASSOCIATED COMPANIES
The Company accounts for its investment in the companies listed below
using the equity method. Summarized financial information is as
follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------ -----------------
1994 1993 1994 1993
---- ---- ---- ----
(In Thousands)
Vermont Yankee Nuclear Power Corporation
Gross Revenue . . . . $39,176 $57,064 $115,438 $137,632
Net Income Applicable
to Common Stock . . 1,642 2,077 4,920 6,362
Company's Equity in
Net Income . . . . . . 297 368 884 1,133
Vermont Electric Power Company, Inc.
Gross Revenue . . . $12,837 $13,877 $ 35,883 $37,440
Net Income
Before Dividends . . . . 301 361 985 1,079
Company's Equity in
Net Income (Includes
preferred equity) . . . . 95 111 294 317
3. ENVIRONMENTAL MATTERS
In 1982, the United States Environmental Protection Agency (EPA)
notified the Company that the EPA, pursuant to the Comprehensive
Environmental Response, Compensation and Liability Act of 1980 (CERCLA),
was considering spending public funds to investigate and take corrective
action involving claimed releases of allegedly hazardous substances at a
site identified as the Pine Street Marsh in Burlington, Vermont. On
part of this site was located a manufactured-gas facility owned and
operated by a number of separate enterprises, including the Company,
from the late 19th century to 1967. In its notice, the EPA stated that
the Company may be a "potentially responsible party" (PRP) under CERCLA
from which reimbursement of costs of investigation and of corrective
action may be sought. On February 23, 1988, the Company received a
Special Notice letter from the EPA stating that the letter constituted a
formal demand for reimbursement of costs, including interest thereon,
that were incurred and were expected to be incurred in response to the
environmental problems at the site.
On December 5, 1988, the EPA brought suit against the Company, New
England Electric System, and Vermont Gas Systems, Inc. in the United
States District Court for the District of Vermont seeking reimbursement
for costs it incurred in conducting activities in 1985 to remove
allegedly hazardous substances from the site, and requested a
declaratory judgment that the Company and the other defendants are
liable for all costs that have been incurred since the removal and that
continue to be incurred in responding to claims of releases or
threatened releases from the Maltex Pond Area -- the portion of the site
where the removal action occurred. The complaint specifically alleged
that the EPA expended at least $741,000 during the 1985 removal action
and sought interest on this amount from the date the funds were expended
and costs of litigation, including attorneys' fees. The Company entered
a cross-claim against New England Electric System and third-party claims
against UGI Corporation, Southern Union Corporation, the State of
Vermont, and an individual property owner at the site for recovery of
its response costs and for contribution. Fourth-party defendants
subsequently were joined.
In July 1990, the Company and other parties signed a proposed Consent
Decree settling the removal action litigation. All 14 settling
defendants contributed to the aggregate settlement amount of $945,000.
Individual contributions were treated as confidential under the proposed
Consent Decree.
On December 26, 1990, upon the unopposed motion of the United States,
the Consent Decree was entered by the Court.
During the summer and fall of 1989, the EPA conducted the initial phase
of the Remedial Investigation (RI) and commenced the Feasibility Study
(FS) relating to the site. In the fall of 1990 and in 1991, the EPA
conducted a second phase of RI work and studied the treatability of
soils and groundwater at the site. In the fall of 1991, the EPA
responded favorably to a request from the Company and other PRPs to
participate in informal discussions on the EPA's ongoing investigation
and evaluation of the site, and invited the Company and other interested
parties to share technical information and resources with the EPA that
might assist it in evaluating remedial options. Thereafter, the Company
and other PRPs held several meetings with the EPA to discuss technical
issues and received copies of the EPA's Supplemental Remedial
Investigation Final Report, and its Baseline Risk Assessment Final
Report.
On November 6, 1992, the EPA released its final RI/FS and announced a
proposed remedy with an estimated total cost of approximately
$49.5 million, including 30 years' operation and maintenance costs, with
a net present value of approximately $26.4 million. The EPA's preferred
remedy called for construction of a Containment/Disposal Facility (CDF)
over a portion of the site. The CDF would have consisted of subsurface
vertical barriers and a low permeability cap, with collection trenches
and hydraulic control system to capture groundwater and prevent its
migration outside of the CDF. Collected groundwater would have been
treated and discharged or stored and disposed of off-site. The proposed
remedy also would have required construction of new wetlands to replace
those that would be destroyed by construction of the CDF and a long-term
monitoring program.
On May 15, 1993, the PRP group in which the Company participated
submitted extensive comments to the EPA opposing the proposed remedy.
In response to an earlier request from the EPA, the PRP group also
submitted a detailed analysis of an alternative remedy anticipated to
cost approximately $20 million. In early June 1993, in response to
overwhelming negative comment, the EPA withdrew its proposed remedy and
announced that it would work with all interested parties in developing a
new proposal. Since then, the EPA has established a coordinating
council, with representatives of PRPs, environmental groups, and
government agencies, and presided over by a neutral mediator. The
Company is represented on the council, which is charged with determining
what additional studies may be appropriate for the site and may also
eventually address additional response activities.
In July 1994, the Company, New England Electric System (NEES), and
Vermont Gas Systems, Inc. (VGS) entered into an Administrative Order by
Consent, with the EPA, pursuant to which these PRPs are conducting
certain additional studies that have been agreed to by the coordinating
council. These studies constitute the first phase of action the council
has decided on to fill data gaps at the site. A second phase is
expected to begin next year unless the coordinating council finds that
the first phase provided sufficient data to decide on a remedy. The EPA
did not require reimbursement for its past RI/FS study costs as a
condition to allowing the PRPs to conduct these additional studies. The
EPA has previously advised the Company that ultimately it will seek to
hold the Company and the PRPs liable for such costs.
In August 1994, the Company, NEES and VGS completed negotiations with
the State, the City of Burlington and nearly all other landowner PRPs of
an agreement under which the liability of those landowner PRPs for
future Superfund response costs would be limited and specified. The
agreement will become effective if the Company, NEES and VGS can reach
an appropriate separate agreement for allocation of the responsibilities
they would assume under the agreement with the landowners by December 1,
1994. Negotiations among the Company, NEES and VGS are continuing.
In December 1991, the Company brought suit against several previous
insurers seeking recovery of unrecovered past costs and indemnity
against future liabilities associated with environmental problems at the
site. Discovery in the case is largely complete, with the exception of
expert discovery which was stayed by the magistrate pending the
resolution of Summary Judgment Motions filed by the Company. In August
1994, the Magistrate granted the Company's Motion for Summary Judgment
with respect to defense costs against one defendant and denied it
against another defendant. The United States District Judge affirmed
those orders on September 30, 1994. The Company now intends to request
the court to permit the resumption of expert discovery.
The Company has reached confidential settlements with two of the
defendants in its insurance litigation. One of these defendants
provided the Company with comprehensive general liability insurance
between 1976 and 1982, and with environmental impairment liability
insurance from 1981 to 1984. These policies were in place in 1982 when
the EPA first notified the Company that it might be a potentially
responsible party at the Pine Street Marsh site. The other defendant
provided the Company with second layer excess liability coverage for a
seven-month period in 1976.
The Company has deferred amounts received from third parties pending
further resolution of the Company's ultimate liability with respect to
the site and rate recognition of that liability. The Company is unable
to predict at this time the magnitude of any liability resulting from
potential claims for the costs of the RI/FS or the performance of any
remedial action, or the likely disposition or magnitude of claims the
Company may have against others, including its insurers, except to the
extent described above.
Through rate cases filed in 1991 and 1993, the Company has sought and
received recovery for ongoing expenses associated with the Pine Street
Marsh site. Specifically, the Company proposed rate recognition of its
unrecovered expenditures between January 1991 and July 31, 1993 (in the
total of approximately $4.6 million) for technical consultants and legal
assistance in connection with the EPA's enforcement actions at the site
and insurance litigation. While reserving the right to argue in the
future about the appropriateness of rate recovery for Pine Street Marsh
related costs, the Company and the Vermont Department of Public Service
(Department) reached agreements in both cases that the full amount of
Pine Street Marsh costs reflected in those rate cases should be
recovered in rates. The Company's rates approved by the Vermont Public
Service Board (VPSB) on April 2, 1992, and on May 13, 1994, reflected
the Pine Street Marsh related expenditures referred to above.
As of September 30, 1994, the Company had reserved approximately
$680,000 for costs attributable to the site, other than those costs that
are the subject of the agreements between the Department and the Company
mentioned above. Management expects to seek and receive ratemaking
treatment for other costs incurred beyond the amounts that have been
reserved. As of September 30, 1994, such other costs are approximately
$7,249,000, which include the costs referred to above that were approved
by the VPSB.
4. 1994 RETAIL RATE CASE
On September 26, 1994, the Company filed a request with the VPSB to
increase retail rates by 13.9 percent. The increase is needed primarily
to cover the rising cost of existing power sources, the cost of new
power sources the Company has secured to replace power supply that will
be lost in the near future, and the cost of energy efficiency programs
the Company has implemented for its customers.
5. 1993 RETAIL RATE CASE
On October 1, 1993, the Company filed a request with the VPSB to
increase retail rates by 8.6 percent. The increase was needed primarily
to cover the cost of buying power from independent power producers, the
cost of energy conservation programs, the cost of plant additions made
in the past two years, and costs incurred in 1992 and 1993 associated
with the Company's response to the EPA's RI/FS and proposed remedy at
the Pine Street Marsh site and with the Company's litigation against its
previous insurers seeking recovery of past costs incurred and indemnity
against future liabilities in connection with the site. On January 28,
1994, the Company and the other parties in the proceeding reached a
settlement agreement providing for a 2.9 percent retail rate increase
effective June 15, 1994, and a target return on equity for utility
operations of 10.5 percent. The settlement agreement also provided for
the Company's recovery in rates of $4.2 million in costs associated with
the Pine Street Marsh site, as described herein above. The agreement
was approved by the VPSB on May 13, 1994.
6. 1991 RETAIL RATE CASE
On July 19, 1991, the Company filed a request with the VPSB to increase
retail rates by 9.96 percent to cover power supply cost increases
expected in 1992, the costs of upgrading and maintaining the Company's
generation, transmission and distribution facilities; expenditures
associated with the Company's conservation programs; and higher employee
pension and health care costs. In orders dated April 2, 1992 and May
21, 1992, the VPSB approved an increase of 5.6 percent, or approximately
$6.6 million, effective April 2, 1992.
The Department appealed the VPSB orders challenging, among other
rulings, the VPSB's acceptance of the Company's method of treating
accumulated depreciation and certain Vermont Yankee-related power costs.
The Company filed a cross-appeal contending, among other things, that
the VPSB had erred in reducing ratebase relating to certain demand-side
management (DSM) program cost projections that had been made in the
Company's prior rate case.
On April 22, 1994, the Vermont Supreme Court affirmed in part and
reversed in part the VPSB orders. The Court overturned the VPSB's
decision disallowing certain DSM costs. The impact of this portion of
the Court's ruling resulted in the Company's other income since April
1992 being increased by $162,000. On the other hand, the Court
overturned the VPSB decision in the Company's favor on an issue
involving the method of treating accumulated depreciation, and on the
inclusion of one item of Vermont Yankee's capital projections in power
costs. The overall impact of the Court's ruling resulted in a reduction
of $840,000 in the Company's revenues.
The Consolidated Financial Statements are unaudited
and, in the opinion of the Company, 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.
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SEPTEMBER 30, 1994
Part 1
- - ------
A.5
RESULTS OF OPERATIONS
EARNINGS SUMMARY
Earnings per share of common stock in the third quarter of 1994 were
$0.54 compared to $0.41 in the third quarter of 1993. The increase in
earnings was primarily due to a $520,000 increase in earnings of
Mountain Energy, Inc., a wholly-owned subsidiary that makes investments
in energy-related development projects. For the third quarter of 1994,
the Company's unregulated operations contributed a total of 12 cents to
the per-share earnings, compared to a loss of 1 cent per share in the
third quarter of 1993. (See Note 1 of Notes to Consolidated Financial
Statements.)
For the nine months ended September 30, 1994 and 1993, earnings per
share were $1.61 and $1.51, respectively. The increase in earnings was
primarily due to a $815,000 increase in earnings of Mountain Energy,
Inc., and a $555,000 increase in earnings of Green Mountain Propane Gas
Company, the Company's wholly-owned propane subsidiary.
OPERATING REVENUES AND MWH SALES
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------ -------------------
1994 1993 1994 1993
---- ---- ---- ----
Operating Revenues
(In thousands)
Retail* . . . . . . . $ 31,771 $ 31,039 $ 97,903 $ 96,702
Sales for Resale . . 4,234 4,011 10,504 11,154
Other . . . . . . . . 679 597 2,491 1,968
-------- -------- ---------- ----------
Total Operating
Revenues . . . . . $ 36,684 $ 35,647 $ 110,898 $ 109,824
======== ======== ========== ==========
MWh Sales
Retail* . . . . . . . 402,725 406,217 1,268,776 1,253,337
Sales for Resale . . 129,601 99,973 295,699 268,004
------- ------- --------- ---------
Total MWh Sales . . 532,326 506,190 1,564,475 1,521,341
======= ======= ========= =========
Average Number of Customers
Residential . . . . . 68,851 68,032 68,683 67,893
Commercial &
Industrial . . . . . 11,645 11,502 11,630 11,450
Other . . . . . . . . 79 78 75 75
------ ------ ------ ------
Total Customers . . 80,575 79,612 80,388 79,418
====== ====== ====== ======
*Includes lease transmissions.
Total operating revenues in the third quarter of 1994 increased
2.9 percent over the third quarter of 1993. Commercial and industrial
revenues increased 2.4 percent in the third quarter of 1994 over the
same period in 1993 primarily due to a rate increase of 2.9 percent that
took effect in June 1994. Residential revenues increased 7.3 percent in
the third quarter of 1994 over the same period in 1993 primarily due to
the 2.9 percent rate increase and warmer than normal summer weather in
1994. Wholesale revenues increased 5.6 percent in the third quarter of
1994 over the same period in 1993 primarily because of a substantial
increase in electricity sales to other utilities in New England.
For the nine months ended September 30, 1994, total operating revenues
increased 1.0 percent over the same period in 1993. Retail revenues
increased 1.2 percent primarily due to a 3.2 percent increase in sales
to residential customers attributable to colder than normal winter
weather and warmer than normal summer weather in 1994. Other operating
revenue increased 26.5 percent primarily due to regulatory recognition
of higher levels of expenditures on energy conservation programs. This
increase was partially offset by a Vermont Supreme Court decision that
caused a reduction in revenues of approximately $840,000. (See Note 6
of Notes to Consolidated Financial Statements.) Wholesale revenues
decreased 5.8 percent primarily due to the greater availability of low-
cost energy in New England, which drove down wholesale prices.
OPERATING EXPENSES
Power supply expenses were essentially unchanged in the third quarter of
1994 as compared to the same period in 1993. Power supply expenses
increased nearly 1 percent for the nine months ended September 30, 1994
over the same period in 1993 primarily due to a 13.5 percent increase in
purchases from independent power producers mandated by federal
legislation. This increase was partially offset by a decrease in costs
associated with Vermont Yankee Nuclear Power Corporation due to the
absence of a refueling outage in 1994.
Transmission expenses decreased 2.5 percent in the third quarter of 1994
compared to the same period in 1993 primarily due to the restructuring
of a series of transmission contracts. Transmission expenses decreased
3.8 percent for the nine months ended September 30, 1994 compared to the
same period in 1993 for the same reason.
Other operating expenses decreased 2.9 percent in the third quarter of
1994 compared to the same period in 1993 primarily due to cost
containment measures implemented during the latter part of the second
quarter of 1994. Other operating expenses increased 2.6 percent for the
nine months ended September 30, 1994 over the same period in 1993
primarily due to a settlement with a former insurance carrier that
resulted in a one-time offset of $359,000 to such expenses in 1993.
Maintenance expenses decreased 12.6 percent in the third quarter of 1994
compared to the same period in 1993 primarily due to a scheduled
decrease in plant maintenance. Maintenance expenses increased
6.7 percent for the nine months ended September 30, 1994 primarily due
to a scheduled increase in plant maintenance.
Depreciation and amortization expenses increased 43.3 percent in the
third quarter of 1994 over the same period in 1993 primarily due to the
amortization of expenditures related to energy conservation programs and
to the Pine Street Marsh environmental matter and insurance litigation.
(See Note 3 of Notes to Consolidated Financial Statements.)
Depreciation and amortization expenses increased 18.5 percent for the
nine months ended September 30, 1994 for the same reason.
Taxes other than income taxes increased 3.5 percent in the third quarter
of 1994 over the same period in 1993 primarily due to an increase in
property taxes. Taxes other than income taxes increased 4.3 percent for
the nine months ended September 30, 1994 for the same reason.
INCOME TAXES
Income taxes were higher in the third quarter of 1994 compared to the
same period in 1993 primarily due to greater taxable income. Income
taxes were lower for the nine months ended September 30, 1994, compared
to the same period in 1993, primarily due to lower taxable income
resulting from the Vermont Supreme Court decision reducing income in the
first quarter of 1994.
OTHER INCOME
Other income increased 86.7 percent in the third quarter of 1994, over
the same period in 1993, primarily due to a $520,000 increase in
earnings generated by Mountain Energy, Inc. Other income increased
62.3 percent for the nine months ended September 30, 1994 primarily due
to increases in earnings generated by Mountain Energy, Inc. and Green
Mountain Propane Gas Company of $815,000 and $555,000, respectively.
INTEREST CHARGES
Interest charges increased 7.2 percent in the third quarter of 1994,
over the same period in 1993, primarily due to interest charges related
to the sale of $20 million of the Company's first mortgage bonds in
November 1993. Interest charges increased 6.5 percent for the nine
months ended September 30, 1994 for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
For the nine months ended September 30, 1994, construction and
conservation expenditures totaled $12.5 million. Such expenditures in
1994 are expected to be approximately $20.0 million, principally for
expansion and improvements of the Company's transmission and
distribution plant and for conservation measures.
The Company anticipates issuing additional shares of its common stock in
1995. The Company has not determined the date or the amount of the
stock issuance.
The rating of the Company's first mortgage bonds was lowered by Standard
and Poor's from "A-" to "BBB+", reflecting Standard and Poor's
assessment that the electric utility industry is becoming increasingly
more competitive. Standard and Poor's changed its "outlook" of the
Company from "negative" to "stable", reflecting Standard and Poor's
recognition of the Company's competitive rates, solid operations and
management, and diverse fuel mix.
GREEN MOUNTAIN POWER CORPORATION
September 30, 1994
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Notes 3, 4, 5 and 6 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
Form 8-K was not required to be filed
during the current quarter
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: November 10, 1994 /s/ E. M. Norse
E. M. Norse, Vice President, Chief
Financial Officer and Treasurer
Date: November 10, 1994 /s/ G. J. Purcell
G. J. Purcell, Controller
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