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, 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 March 31, 1994
$3.33 1/3 Par Value 4,551,012
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1
- - ------
A.1
<CAPTION>
March 31 December 31
----------------------------------- ----------------
1994 1993 1993
---------------- ---------------- ----------------
(In thousands) (In thousands)
ASSETS
ELECTRIC UTILITY
<S> <C> <C> <C>
Utility Plant
Utility plant, at original cost.................... $216,417 $201,600 $214,977
Less accumulated depreciation...................... 66,130 60,435 64,226
---------------- ---------------- ----------------
Net utility plant................................ 150,287 141,165 150,751
Property under capital lease....................... 11,029 11,950 11,029
Construction work in progress...................... 10,157 11,847 9,631
---------------- ---------------- ----------------
Total utility plant, net......................... 171,473 164,962 171,411
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity (Note 2)........... 16,859 17,322 16,886
Non-utility property............................... 3,719 3,307 3,521
Other investments.................................. -- 2,079 2,121
---------------- ---------------- ----------------
Total other investments.......................... 20,578 22,708 22,528
---------------- ---------------- ----------------
Current Assets
Cash............................................... 61 1,246 50
Temporary investments.............................. 900 -- --
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 15,454 18,504 14,814
Accrued utility revenues (Note 1).................. 5,619 5,290 6,138
Fuel, materials and supplies, at average cost...... 2,756 2,724 2,841
Prepayments........................................ 1,593 1,363 1,984
Current revenue due to income taxes................ 428 454 729
Other.............................................. 232 342 388
---------------- ---------------- ----------------
Total current assets............................. 27,043 29,923 26,944
---------------- ---------------- ----------------
Deferred Charges
Future revenue due to income taxes................. 4,179 4,908 4,179
Unfunded future federal income taxes............... 4,498 4,731 4,590
Demand side management programs................... 13,407 7,058 12,809
Environmental proceedings costs.................... 6,152 2,710 5,356
Purchased power costs.............................. 3,027 407 4,134
Other.............................................. 12,406 9,022 11,277
---------------- ---------------- ----------------
Total deferred charges........................... 43,669 28,836 42,345
---------------- ---------------- ----------------
NON-UTILITY
Cash and cash equivalents.......................... 123 136 177
Other current assets............................... 3,616 5,132 3,479
Property and equipment............................. 11,198 10,919 11,331
Intangible assets.................................. 3,365 3,895 3,484
Other assets....................................... 9,551 5,460 10,155
---------------- ---------------- ----------------
Total non-utility assets......................... 27,853 25,542 28,626
---------------- ---------------- ----------------
Total Assets........................................... $290,616 $271,971 $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
4,566,868, 4,443,410, and 4,536,042).......... $15,222 $14,811 $15,120
Additional paid-in capital....................... 57,974 54,409 57,178
Retained earnings................................ 26,668 26,585 25,229
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 99,486 95,427 97,149
Redeemable cumulative preferred stock.............. 9,385 9,575 9,385
Long-term debt, less current maturities............ 79,800 67,644 79,800
---------------- ---------------- ----------------
Total capitalization........................... 188,671 172,646 186,334
---------------- ---------------- ----------------
Capital lease obligation............................... 11,029 11,950 11,029
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,800 2,486 1,800
Short-term debt.................................... 13,215 6,213 19,015
Accounts payable, trade, and accrued liabilities... 5,361 5,522 8,373
Accounts payable to associated companies........... 3,792 4,679 4,302
Dividends declared................................. 199 203 199
Customer deposits.................................. 1,215 1,124 1,197
Taxes accrued...................................... 1,697 3,470 397
Interest accrued................................... 1,819 1,562 2,070
Deferred revenues (Note 1)......................... 8,177 8,123 --
Current revenue reduction due to income taxes...... 132 140 225
Unfunded future federal income taxes............... 428 454 729
Other.............................................. 625 564 572
---------------- ---------------- ----------------
Total current liabilities...................... 38,460 34,540 38,879
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 20,844 16,056 20,683
Unamortized investment tax credits................. 5,570 5,848 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.............................................. 11,384 11,994 13,541
---------------- ---------------- ----------------
Total deferred credits......................... 46,343 43,396 48,441
---------------- ---------------- ----------------
NON-UTILITY
Current liabilities................................ 391 615 666
Other liabilities.................................. 5,722 8,824 6,505
---------------- ---------------- ----------------
Total non-utility liabilities.................. 6,113 9,439 7,171
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $290,616 $271,971 $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
March 31
-----------------------------------------
1994 1993
----------------- -----------------
(In thousands, except amounts per share)
<S> <C> <C>
Operating Revenues (Note 1)..................................... $40,611 $40,751
----------------- -----------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation (Note 2).......... 7,379 7,472
Company-owned generation................................... 1,179 749
Purchases from others...................................... 12,773 12,468
Other operating............................................... 4,769 4,503
Transmission.................................................. 2,579 2,816
Maintenance................................................... 1,245 1,016
Depreciation and amortization................................. 2,305 2,143
Taxes other than income....................................... 1,726 1,636
Income taxes.................................................. 1,764 2,788
----------------- -----------------
Total operating expenses................................... 35,719 35,591
----------------- -----------------
Operating income......................................... 4,892 5,160
----------------- -----------------
Other Income
Equity in earnings of affiliates and non-utility operations... 748 860
Allowance for equity funds used during construction........... 89 52
Other income and deductions, net.............................. 145 (42)
----------------- -----------------
Total other income.......................................... 982 870
----------------- -----------------
Income before interest charges............................ 5,874 6,030
----------------- -----------------
Interest Charges
Long-term debt................................................ 1,742 1,628
Other......................................................... 230 149
Allowance for borrowed funds used during construction........ (138) (49)
----------------- -----------------
Total interest charges...................................... 1,834 1,728
----------------- -----------------
Net Income...................................................... 4,040 4,302
Dividends on preferred stock.................................... 199 203
----------------- -----------------
Net Income Applicable to Common Stock........................... $3,841 $4,099
================= =================
Common Stock Data
Earnings per share............................................ $0.85 $0.93
Cash dividends declared per share............................. $0.53 $0.525
Weighted average shares outstanding........................... 4,537 4,415
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................... $25,229 $24,801
Net Income...................................................... 4,040 4,302
----------------- -----------------
29,269 29,103
----------------- -----------------
Cash Dividends - redeemable cumulative preferred stock.......... 199 203
- common stock................................... 2,402 2,315
----------------- -----------------
2,601 2,518
----------------- -----------------
Balance - end of period......................................... $26,668 $26,585
================= =================
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>
Three Months Ended
March 31
---------------------------------------
1994 1993
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income........................................................... $4,040 $4,302
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 2,305 2,143
Dividends from associated companies less equity income........... 26 (183)
Allowance for funds used during construction..................... (227) (101)
Amortization of purchased power costs............................ 1,161 1,073
Deferred income taxes............................................ 161 553
Deferred revenues (Note 1)....................................... 8,177 8,122
Amortization of gain on sale of property......................... (13) (13)
Deferred purchased power costs................................... (54) (36)
Amortization of investment tax credits........................... (102) (108)
Environmental proceedings costs.................................. (825) 238
Changes in:
Temporary investments.......................................... (900) --
Accounts receivable............................................ (641) (1,306)
Accrued utility revenues....................................... 519 310
Fuel, materials, and supplies.................................. 85 170
Prepayments and other current assets........................... 411 2,188
Accounts payable............................................... (3,524) (4,076)
Taxes accrued.................................................. 1,299 2,655
Interest accrued............................................... (251) 394
Other current liabilities...................................... (202) (2,873)
Other............................................................ (1,197) (1,801)
----------------- -----------------
Net cash provided by operating activities.......................... 10,248 11,651
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (2,024) (2,492)
Conservation expenditures.......................................... (857) (888)
Investment in nonutility property.................................. 93 108
Special fund for postretirement benefits........................... -- (559)
----------------- -----------------
Net cash used in investing activities............................ (2,788) (3,831)
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 898 999
Short-term debt, net............................................... (5,801) (5,401)
Cash dividends..................................................... (2,601) (2,516)
----------------- -----------------
Net cash used in financing activities............................ (7,504) (6,918)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents............... (44) 902
Cash and Cash equivalents at beginning of period................... 227 480
----------------- -----------------
Cash and Cash Equivalents at End of Period............................. $183 $1,382
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid during the quarter for:
Interest (net of amounts capitalized)........................... $2,193 $1,350
Income taxes.................................................... -- 282
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 March 31, 1994 and 1993, the
Company had recorded deferred revenues of $6.6 million and $6.9 million,
respectively, in accordance with this policy. These deferred revenues
are recognized 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 is as
follows:
Three Months Ended
March 31
------------------
1994 1993
---- ----
(In Thousands)
Revenue . . . . . . . . . . . . . $3,823 $4,192
Expenses. . . . . . . . . . . . . 3,588 3,967
----- -----
Net Income. . . . . . . . . . . . $ 235 $ 225
===== =====
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
March 31
------------------
(In thousands)
1994 1993
---- ----
Vermont Yankee Nuclear Power Corporation
Gross Revenue. . . . . . . . . . . . . . $39,169 $39,649
Net Income Applicable to Common Stock. . 1,683 2,137
Company's Equity in Net Income . . . . . 307 379
Vermont Electric Power Company, Inc.
Gross Revenue. . . . . . . . . . . . . . $12,264 $12,280
Net Income Before Dividends. . . . . . . 314 353
Company's Equity in Net Income
(Includes preferred equity). . . . . . 85 101
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, 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
council is charged with determining what additional studies may be
appropriate for the site and may also eventually address additional
response activities. The Company is represented on the council.
In early 1994, the Company and other PRPs met with the EPA to
commence negotiations on an Administration Order by Consent pursuant to
which the PRPs would conduct additional studies agreed to by the
coordinating council. Although negotiations are not yet complete, it is
likely that the EPA will consent to allowing the PRPs to conduct
additional studies at the site and that the EPA will 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 September 1993, the Company, New England Electric System and
Vermont Gas Systems, Inc. entered into confidential negotiations with
most other PRPs concerning allocation of unresolved liabilities
concerning the site. Those negotiations 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. The parties to this action are engaged in discovery and motions
practice.
The Company has reached a confidential settlement with one of the
defendants that provided the Company with second layer excess liability
coverage for a seven month period in 1976. The Company has also reached
a confidential agreement in principle with another insurance company
defendant that 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 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.
In its 1991 rate case, the Company, for the first time, sought
recovery for expenses associated with the Pine Street Marsh site.
Specifically, the Company proposed rate recognition of its estimated,
unrecovered 1991 expenditures (approximately $400,000) 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 agreement that
the full amount of Pine Street Marsh costs reflected in the Company's
1991 rate case should be recovered in rates. The Company's rates
approved by the Vermont Public Service Board (VPSB) on April 2, 1992,
reflected the 1991 Pine Street Marsh related expenditures referred to
above.
In its rate increase request filed on October 1, 1993, the Company
proposed rate recognition for its expenditures between January 1, 1992
and July 31, 1993 (approximately $4.2 million) for technical consultants
and legal assistance in connection with the EPA's enforcement actions at
the site and insurance litigation. The Department and the Company have
reached the same agreement regarding recovery of these costs in rates
that they reached with respect to the Company's 1991 Pine Street Marsh
related expenditures. A comprehensive settlement of the Company's 1993
rate case, including the agreement regarding Pine Street Marsh costs, is
currently pending before the VPSB.
As of March 31, 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 March 31, 1994, such other costs are approximately
$5,736,000, which includes the $4.2 million in costs that are the
subject of the rate case settlement agreement referred to above.
4. 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 is 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
must be reviewed and approved by the VPSB before it can take effect.
5. 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 impact of this portion of the Court's ruling resulted in the
Company's revenues since April 1992 being reduced by $990,000.
The Company filed a motion for re-argument with the Vermont Supreme
Court on May 6, 1994, contending that the Court had erred in overturning
the VPSB's decision with respect to accumulated depreciation.
- - ---------------------------------------------------
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
MARCH 31, 1994
Part 1
- - ------
A.5
RESULTS OF OPERATIONS
Earnings Summary
Earnings per share of common stock in the first quarter of 1994
were $0.85, compared to $0.93 per share in the first quarter of 1993.
The decreased earnings in 1994 resulted primarily from an April 1994
ruling by the Vermont Supreme Court, which reversed a portion of the
VPSB's April 1992 order raising the Company's rates by 5.6 percent. The
Supreme Court ruling caused a reduction of approximately $990,000 in
revenues collected from customers during the past two years. (See Note
5 of Notes to Consolidated Financial Statements.)
Operating Revenues and MWh Sales
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended
March 31
-------------------
1994 1993
---- ----
Operating Revenues (In thousands)
Retail*. . . . . . . . . . . . $35,892 $36,267
Sales for Resale . . . . . . . 3,609 3,804
Other. . . . . . . . . . . . . 1,110 680
-------- --------
Total Operating Revenues . . $ 40,611 $ 40,751
======== ========
MWh Sales
Retail*. . . . . . . . . . . . 477,169 466,890
Sales for Resale . . . . . . . 99,561 83,074
------- -------
Total MWh Sales. . . . . . . 576,730 549,964
======= =======
Average Number of Customers
Residential. . . . . . . . . . 68,579 67,791
Commercial & Industrial. . . . 11,617 11,413
Other. . . . . . . . . . . . . 73 73
------ ------
Total Customers. . . . . . 80,269 79,277
====== ======
*Includes lease transmissions.
Total operating revenues in the first quarter of 1994 were
essentially unchanged compared to the same period in 1993. Retail
revenues decreased 1.0 percent in the first quarter of 1994 compared to
the same period in 1993 primarily due to the Vermont Supreme Court
decision discussed above, resulting in a reduction in revenues of
approximately $990,000. This decrease in retail revenues was partially
offset by a 3.8 percent increase in sales to small commercial and
industrial customers (reflecting increased economic activity in this
sector in 1994) and a 3.9 percent increase in sales to residential
customers (reflecting colder than normal winter weather in 1994).
Wholesale revenues decreased 5.1 percent in the first quarter of 1994
primarily due to the greater availability of low-cost energy in New
England, which drove down wholesale electricity prices.
Operating Expenses
Power supply expenses increased 3.1 percent in the first quarter of
1994 over the same period in 1993, primarily due to a 19.8 percent
increase in purchases from independent power producers mandated by
federal legislation. During the first quarter of 1994, two of such
independent power producers that went into service in 1993 experienced a
full period of operations.
Transmission expenses decreased 8.4 percent in the first quarter of
1994 compared to the same period in 1993, primarily due to the
restructuring of a series of transmission contracts.
Maintenance expenses increased 22.7 percent in the first quarter of
1994 compared to the same period in 1993, due primarily to a scheduled
increase in plant maintenance.
Depreciation and amortization expenses increased 7.5 percent in the
first quarter of 1994 compared to the same period in 1993, due to an
increase in utility plant additions.
Income Taxes
Income taxes decreased 36.7 percent in the first quarter of 1994
compared to the same period in 1993, due primarily to a reduction in
book pre-tax income and a reversal of the tax reserve established to
cover potential audit assessments (reflecting the Company's judgment
that the likelihood of adverse tax audits had diminished).
Interest Charges
Interest charges increased 6.1 percent in the first 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.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 1994, construction and
conservation expenditures totaled $2.9 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 common stock
in late 1994. The Company has not determined the date or the amount of
the stock issuance.
GREEN MOUNTAIN POWER CORPORATION
March 31, 1994
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
NONE
(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: May 13, 1994 /s/ E. M. Norse
E. M. Norse, Vice President, Chief
Financial Officer and Treasurer
Date: May 13, 1994 /s/ G. J. Purcell
G. J. Purcell, Controller
