SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
X Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 1996
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 05403
Address of principal executive offices (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class - Common Stock Outstanding June 30, 1996
$3.33 1/3 Par Value 4,935,313
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1 - Item 1
<CAPTION>
June 30 December 31
----------------------------------- ----------------
1996 1995 1995
---------------- ---------------- ----------------
(In thousands) (In thousands)
ASSETS
ELECTRIC UTILITY
<S> <C> <C> <C>
Utility Plant
Utility plant, at original cost.................... $245,536 $232,919 $239,291
Less accumulated depreciation...................... 79,817 72,897 75,797
---------------- ---------------- ----------------
Net utility plant................................ 165,719 160,022 163,494
Property under capital lease....................... 9,778 10,278 9,778
Construction work in progress...................... 9,186 7,100 8,727
---------------- ---------------- ----------------
Total utility plant, net......................... 184,683 177,400 181,999
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity (Note 2)........... 16,011 16,408 16,024
Other investments.................................. 4,640 4,146 4,224
---------------- ---------------- ----------------
Total other investments.......................... 20,651 20,554 20,248
---------------- ---------------- ----------------
Current Assets
Cash............................................... 69 187 84
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 14,537 12,772 18,081
Accrued utility revenues (Note 1).................. 5,248 4,920 6,523
Fuel, materials and supplies, at average cost...... 3,381 3,493 3,312
Prepayments........................................ 536 181 1,890
Other.............................................. 286 207 326
---------------- ---------------- ----------------
Total current assets............................. 24,057 21,760 30,216
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 17,448 16,128 18,367
Environmental proceedings costs.................... 8,056 7,735 7,893
Purchased power costs.............................. 5,747 3,495 8,433
Other.............................................. 8,310 11,945 8,258
---------------- ---------------- ----------------
Total deferred charges........................... 39,561 39,303 42,951
---------------- ---------------- ----------------
NON-UTILITY
Cash and cash equivalents.......................... 263 900 76
Other current assets............................... 2,481 6,208 4,055
Property and equipment............................. 11,348 11,469 11,478
Intangible assets.................................. 2,402 2,837 2,580
Equity investment in energy related businesses..... 14,578 10,167 10,999
Other assets....................................... 8,110 5,208 8,680
---------------- ---------------- ----------------
Total non-utility assets......................... 39,182 36,789 37,868
---------------- ---------------- ----------------
Total Assets........................................... $308,134 $295,806 $313,282
================ ================ ================
CAPITALIZATION AND LIABILITIES
ELECTRIC UTILITY
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
4,951,169, 4,762,308 and 4,850,496)........... $16,503 $15,874 $16,168
Additional paid-in capital....................... 66,496 62,226 64,206
Retained earnings................................ 25,950 25,584 26,412
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 108,571 103,306 106,408
Redeemable cumulative preferred stock.............. 8,930 9,135 8,930
Long-term debt, less current maturities............ 82,234 71,467 91,134
---------------- ---------------- ----------------
Total capitalization........................... 199,735 183,908 206,472
---------------- ---------------- ----------------
Capital lease obligation............................... 9,778 10,278 9,778
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,700 3,500 7,833
Short-term debt.................................... 18,615 23,715 8,416
Accounts payable, trade, and accrued liabilities... 3,333 4,039 5,529
Accounts payable to associated companies........... 5,993 4,777 7,011
Dividends declared................................. 190 194 194
Customer deposits.................................. 581 739 816
Taxes accrued...................................... 1,644 320 571
Interest accrued................................... 1,341 1,824 1,847
Deferred revenues (Note 1)......................... 2,566 2,157 --
Other.............................................. 230 579 412
---------------- ---------------- ----------------
Total current liabilities...................... 36,193 41,844 32,629
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 23,943 23,626 25,292
Unamortized investment tax credits................. 4,995 5,267 5,107
Other.............................................. 22,132 21,421 21,642
---------------- ---------------- ----------------
Total deferred credits......................... 51,070 50,314 52,041
---------------- ---------------- ----------------
NON-UTILITY
Current liabilities................................ 712 606 1,124
Other liabilities.................................. 10,646 8,856 11,238
---------------- ---------------- ----------------
Total non-utility liabilities.................. 11,358 9,462 12,362
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $308,134 $295,806 $313,282
================ ================ ================
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 - Item 1
<CAPTION>
Three Months Ended Six Months Ended
June 30 June 30
------------------------------- -------------------------------
1996 1995 1996 1995
------------ ------------ ------------ ------------
(In thousands, except amounts per share)
<S> <C> <C> <C> <C>
Operating Revenues (Note 1)................................... $40,467 $37,127 $88,881 $77,150
------------ ------------ ------------ ------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation ................ 8,093 7,229 15,504 14,802
Company-owned generation................................. 726 1,216 1,572 2,031
Purchases from others.................................... 15,210 11,912 33,878 24,302
Other operating............................................. 4,740 4,709 9,647 9,273
Transmission................................................ 2,523 2,563 5,214 4,912
Maintenance................................................. 1,264 912 2,386 2,084
Depreciation and amortization............................... 4,048 3,206 7,923 6,409
Taxes other than income..................................... 1,610 1,565 3,387 3,235
Income taxes................................................ 394 1,045 2,439 2,850
------------ ------------ ------------ ------------
Total operating expenses................................. 38,608 34,357 81,950 69,898
------------ ------------ ------------ ------------
Operating Income....................................... 1,859 2,770 6,931 7,252
------------ ------------ ------------ ------------
Other Income
Equity in earnings of affiliates and non-utility operations. 923 944 1,780 1,540
Allowance for equity funds used during construction......... 49 27 89 27
Other income and deductions, net............................ 15 68 30 55
------------ ------------ ------------ ------------
Total other income........................................ 987 1,039 1,899 1,622
------------ ------------ ------------ ------------
Income before interest charges.......................... 2,846 3,809 8,830 8,874
------------ ------------ ------------ ------------
Interest Charges
Long-term debt.............................................. 1,696 1,657 3,511 3,343
Other....................................................... 224 333 452 650
Allowance for borrowed funds used during construction...... (98) (173) (221) (338)
------------ ------------ ------------ ------------
Total interest charges.................................... 1,822 1,817 3,742 3,655
------------ ------------ ------------ ------------
Net Income.................................................... 1,024 1,992 5,088 5,219
Dividends on preferred stock.................................. 190 194 379 388
------------ ------------ ------------ ------------
Net Income Applicable to Common Stock......................... $834 $1,798 $4,709 $4,831
============ ============ ============ ============
Common Stock Data
Earnings per share.......................................... $0.17 $0.38 $0.96 $1.03
Cash dividends declared per share........................... $0.53 $0.53 $1.06 $1.06
Weighted average shares outstanding......................... 4,911 4,721 4,885 4,701
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................. $27,716 $26,283 $26,412 $25,727
Net Income.................................................... 1,024 1,992 5,088 5,219
------------ ------------ ------------ ------------
28,740 28,275 31,500 30,946
------------ ------------ ------------ ------------
Cash Dividends - redeemable cumulative preferred stock........ 190 194 379 388
- common stock................................. 2,600 2,497 5,171 4,974
------------ ------------ ------------ ------------
2,790 2,691 5,550 5,362
------------ ------------ ------------ ------------
Balance - end of period....................................... $25,950 $25,584 $25,950 $25,584
============ ============ ============ ============
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 - Item 1
<CAPTION>
Six Months Ended
June 30
---------------------------------------
1996 1995
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income........................................................... $5,088 $5,219
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 7,923 6,409
Dividends from associated companies less equity income........... 13 276
Allowance for funds used during construction..................... (311) (365)
Amortization of purchased power costs............................ 3,174 2,531
Deferred income taxes............................................ (1,149) 1,764
Deferred revenues (Note 1)....................................... 2,566 2,158
Amortization of gain on sale of property......................... (26) (26)
Deferred purchased power costs................................... (1,518) (5,538)
Amortization of investment tax credits........................... (112) (123)
Environmental proceedings costs, net............................. (917) (456)
Changes in:
Accounts receivable............................................ 3,544 2,468
Accrued utility revenues....................................... 1,275 1,092
Fuel, materials and supplies................................... (69) (180)
Prepayments and other current assets........................... 2,970 1,237
Accounts payable............................................... (3,214) (1,533)
Taxes accrued.................................................. 1,073 (1,122)
Interest accrued............................................... (505) (129)
Other current liabilities...................................... (834) (450)
Other............................................................ 368 (2,471)
----------------- -----------------
Net cash provided by operating activities.......................... 19,339 10,761
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (7,187) (5,950)
Conservation expenditures.......................................... (1,507) (1,923)
Investment in non-utility property................................. (2,716) 72
----------------- -----------------
Net cash used in investing activities............................ (11,410) (7,801)
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 2,626 2,130
Short-term debt, net............................................... 10,200 3,500
Cash dividends..................................................... (5,550) (5,362)
Reduction in long-term debt........................................ (15,033) (4,833)
----------------- -----------------
Net cash used in financing activities............................ (7,757) (4,565)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents............... 172 (1,605)
Cash and cash equivalents at beginning of period................... 160 2,692
----------------- -----------------
Cash and Cash Equivalents at End of Period............................. $332 $1,087
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date:
Interest (net of amounts capitalized)........................... $4,351 $4,053
Income taxes.................................................... 2,436 2,040
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
Part 1 -- ITEM 1
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 June 30, 1996 and 1995, the
Company had recorded deferred revenues of $2.6 million and $2.1 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 five of the
Company's wholly-owned subsidiaries, Green Mountain Propane Gas Company,
Mountain Energy, Inc., GMP Real Estate Corporation, Green Mountain
Resources, Inc. and Lease-Elec, Inc., all of which are unregulated.
Summarized financial information for the rental water heater program and
such wholly-owned subsidiaries is as follows:
Three Months Ended Six Months Ended
June 30 June 30
--------------------- ------------------
1996 1995 1996 1995
---- ---- ---- ----
(In Thousands) (In Thousands)
Revenue . . . . . . . . . $2,792 $2,621 $6,717 $5,625
Expenses . . . . . . . . . 2,417 2,201 5,975 5,084
------ ------ ------ ------
Net Income . . . . . . . . $ 375 $ 420 $ 742 $ 541
====== ====== ====== ======
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 Six Months Ended
June 30 June 30
------------------- ------------------
1996 1995 1996 1995
---- ---- ---- ----
(In Thousands)
Vermont Yankee Nuclear Power Corporation
Gross Revenue . . . . . $43,282 $47,043 $83,038 $98,418
Net Income Applicable
to Common Stock . . . 1,702 1,716 3,300 3,474
Company's Equity in
Net Income . . . . . 305 307 585 588
Three Months Ended Six Months Ended
June 30 June 30
------------------- -------------------
1996 1995 1996 1995
---- ---- ---- ----
(In Thousands)
Vermont Electric Power Company, Inc.
Gross Revenue . . . . . $12,123 $12,171 $24,412 $24,832
Net Income
Before Dividends . . 353 315 651 648
Company's Equity in
Net Income (Includes
preferred equity) . . 127 93 209 192
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 in response to claimed
releases of allegedly hazardous substances at what since has become
known as the Pine Street Barge Canal Site (Site) in Burlington, Vermont.
A manufactured-gas facility was owned and operated on part of the Site
by several separate enterprises, including the Company, from the late
19th century to 1967. The EPA's notice 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 response costs, including interest thereon,
incurred and to be incurred at the Site.
On December 5, 1988, the EPA brought suit against the Company, New
England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS) 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 a portion of the Site, and
seeking a declaratory judgment concerning liability of the defendants
for all subsequent response costs associated with that area, known as
the Maltex Pond Area. The complaint alleged that the removal costs were
at least $741,000. The EPA also sought interest on this amount from the
date the funds were expended and costs of litigation, including
attorneys' fees. The Company entered certain cross-claims and third-
party claims. Fourth-party defendants also were joined. In July 1990,
without admission of liability, the Company and 13 other settling
defendants signed a proposed Consent Decree settling the removal action
litigation, paying collectively $945,000. Individual contributions were
confidential. On December 26, 1990, upon the unopposed motion of the
United States, the Consent Decree was entered by the Court.
During 1989, the EPA began a Remedial Investigation (RI) and Feasibility
Study (FS) relating to the Site. In late 1990 and in 1991, the EPA
conducted a second phase of RI work and studied the treatability of
soils and groundwater at the Site.
On November 6, 1992, the EPA released its final RI/FS reports and
announced a proposed remedy with an estimated total present value of
$47.0 million. This amount included 30 years' estimated operation and
maintenance costs, with a net present value of $26.4 million. The EPA's
proposed remedy called for construction of a large above-grade
Containment/Disposal Facility (CDF) that also would have consisted of
subsurface vertical barriers and a low permeability cap, with collection
trenches and a hydraulic control system to capture groundwater for
eventual treatment. The proposed remedy also included a long-term
monitoring program and construction of new wetlands.
The Company and other PRPs submitted extensive comments to the EPA
opposing the proposed remedy and in response to an earlier request from
the EPA, a detailed analysis of an alternative remedy anticipated to
cost approximately $20 million. In 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. The EPA then established a coordinating council, with
representatives of PRPs, environmental groups, and government agencies,
and presided over by a neutral facilitator. The council has reached
consensus on additional studies appropriate for the Site and is
beginning to address remedy selection.
In July 1994, the Company, NEES, and VGS entered into an Administrative
Order by Consent with the EPA, pursuant to which these PRPs conducted
certain additional studies agreed to by the coordinating council. A
second phase, including tasks carried over from the first phase,
additional field studies and preparation of an addendum feasibility
study, will be completed in early 1997 by the Company and NEES under a
second Order. 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 announced that ultimately it
will seek to hold the Company and other PRPs liable for such costs,
which have been estimated to be at least $4.5 million. The Company has
sufficient reserves on its balance sheet to cover such costs.
On December 1, 1994, (i) the Company, NEES and VGS entered into a
confidential agreement with the State, the City of Burlington and nearly
all other landowner PRPs under which the liability of those landowner
PRPs for future Superfund response costs would be limited and specified
and (ii) the Company entered into a confidential agreement with VGS
compromising contribution and cost recovery claims of each party and
contractual indemnity claims of the Company arising from the 1964 sale
of the manufactured gas plant to VGS. In March 1996, the Company and
NEES entered into a confidential agreement compromising contribution and
cost recovery claims of each party concerning the Site.
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. Further discovery has been stayed by the court until
the revised RI/FS reports are finalized, the Company's liability is
finally determined or January 1, 1997, which ever comes first. In 1994,
the United States District Judge granted the Company's Motion for
Summary Judgment with respect to defense costs against one defendant and
denied it against another defendant. The Company has reached
confidential settlements with two of the other defendant insurers. One
settling defendant provided the Company with comprehensive general
liability insurance between 1976 and 1982 and with environmental
impairment liability insurance from 1981 to 1984. The other 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
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 concerning the Site, 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, 1993 and 1994, the Company has sought
and received recovery for ongoing expenses associated with the Site.
Specifically, the Company proposed rate recognition of its unrecovered
expenditures between January 1991 and June 30, 1994 (totaling
approximately $7.3 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 all Site-related
costs, the Company and the Vermont Department of Public Service (the
Department) and, in some instances, other parties in the rate
proceedings, reached agreements in these cases that the full amount of
Site costs reflected in those rate cases should be recovered in rates.
The Company's rates approved by the VPSB on April 2, 1992, on May 13,
1994 and on June 5, 1995 reflected the Site related expenditures
referred to above.
In a rate case filed on September 15, 1995, the Company sought recovery
in rates of approximately $1.3 million in expenses associated with the
Site. This amount represented the Company's unrecovered expenditures
between July 1994 and June 1995 for technical consultants and legal
assistance in connection with EPA's enforcement action at the Site and
insurance litigation. While reserving the right to argue in the future
about the appropriateness of rate recovery for all Site-related costs
(and whether recovery or non-recovery of past costs and any insurance
proceeds or proceeds from PRP's is relevant to such issue), the parties
to the case reached agreement that the full amount of Site costs
reflected in the Company's 1995 rate case should be recovered in rates.
This agreement was approved by the VPSB on May 23, 1996.
Management expects to seek and (assuming treatment consistent with the
previous regulatory treatment set forth above) receive ratemaking
treatment for unreimbursed costs incurred beyond the amounts for which
ratemaking treatment has been received.
4. 1995 Retail Rate Case
In September 1995, the Company filed a 12.7 percent retail rate increase
to cover higher power supply costs, to support additional investment in
plant and equipment, to fund expenses associated with the Pine Street
site, and to cover higher costs of capital. Early in 1996, the Company
settled this rate case with the Department and other parties, enabling
the Company to conduct its business and achieve satisfactory financial
results without the drain on human resources and the additional costs
that rate increase litigation imposes.
The settlement became possible when the Company negotiated a new
arrangement with Hydro-Quebec that will reduce the Company's net power-
supply costs below the amounts anticipated in the rate increase request.
The settlement provides: projected additional annual revenues of
$7.6 million; an overall increase in retail rates of 5.25 percent;
target return on equity for electric operations of 11.25 percent; and
recovery of $1.3 million of costs associated with the Pine Street site,
amortized over five years. The VPSB approved the settlement in an order
dated May 23, 1996.
5. 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 was 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. The Company,
the Department and the other parties in the proceeding reached a
settlement agreement providing for a 9.25 percent retail rate increase
effective June 15, 1995, and a target return on equity for utility
operations of 11.25 percent. The agreement was approved by the VPSB on
June 9, 1995.
6. SFAS 121
Statement of Financial Accounting Standards (SFAS) 121, Accounting for
the Impairment of Long Lived Assets, which was implemented by the
Company on January 1, 1996, requires that any assets, including
regulatory assets, which are no longer probable of recovery through
future revenues, be revalued based upon future cash flows. SFAS 121
requires that a rate-regulated enterprise recognize an impairment loss
for the amount of costs excluded from recovery. As of June 30, 1996,
based upon the regulatory environment within which the Company currently
operates, SFAS 121 did not have an impact on the Company's financial
position or results of operations.
7. RECLASSIFICATION
Certain line items on the prior year's financial statements have been
reclassified for consistent presentation with the current year.
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
JUNE 30, 1996
Part 1 -- ITEM 2
RESULTS OF OPERATIONS
EARNINGS SUMMARY
Earnings per share of common stock in the second quarter of 1996 were
$0.17 compared to $0.38 in the second quarter of 1995. The decrease in
earnings was primarily due to an increase in power supply expense
resulting from higher costs for power purchased from Hydro-Quebec and
independent power producers and to increased operations and maintenance
expenses at the Vermont Yankee nuclear plant.
For the six months ended June 30, 1996 and 1995, earnings per share of
common stock were $0.96 and $1.03, respectively.
OPERATING REVENUES AND MWH SALES
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended Six Months Ended
June 30 June 30
------------------- ------------------
1996 1995 1996 1995
---- ---- ---- ----
Operating Revenues
(In thousands)
Retail . . . . . . $ 35,026 $ 31,729 $ 76,128 $ 67,294
Sales for Resale . 4,768 4,654 11,238 8,018
Other . . . . . . 672 744 1,515 1,838
--------- --------- --------- ---------
Total Operating
Revenues . . . . $ 40,466 $ 37,127 $ 88,881 $ 77,150
========= ========= ========= =========
MWh Sales
Retail . . . . . . 403,046 398,606 888,137 858,943
Sales for Resale . 164,545 162,383 403,832 253,766
------- ------- --------- ---------
Total MWh Sales . 567,591 560,989 1,291,969 1,112,709
======= ======= ========= =========
Average Number of Customers
Residential . . . 70,062 69,540 70,087 69,503
Commercial &
Industrial . . . 11,834 11,722 11,817 11,696
Other . . . . . . . 78 78 76 77
------ ------ ------ ------
Total Customers . . 81,974 81,340 81,980 81,276
====== ====== ====== ======
Total operating revenues in the second quarter of 1996 increased 9.0
percent over the same period in 1995. Retail revenues increased 10.4
percent in the second quarter of 1996 over the same period in 1995
primarily due to a 9.25 percent retail rate increase that went into
effect in June 1995, and cooler, but normal, weather conditions that
prevailed in 1996. Wholesale revenues increased 2.4 percent in the
second quarter of 1996 over the same period in 1995 primarily due to
regional market conditions that allowed the Company to buy electricity
and resell it to other utilities at prices slightly higher than the
purchase price.
For the six months ended June 30, 1996, total operating revenues
increased 15.2 percent over the same period in 1995. Retail revenues
increased 13.1 percent over the same period in 1995 primarily due to a
9.25 percent retail rate increase that went into effect in June 1995 and
a 5.4 percent increase in electricity sales in the first quarter of 1996
resulting from an increase in sales of electricity caused by colder (but
normal) winter weather and modest growth in the business sector.
Wholesale revenues increased 40.2 percent over the same period in 1995
primarily due to regional market conditions that allowed the Company to
buy electricity and resell it to other utilities at prices slightly
higher than the purchase price.
Early in 1996, the Company settled a rate case that it had filed in
September 1995 with the Department and other parties. The settlement
provides: projected additional annual revenues of $7.6 million; an
overall increase in retail rates of 5.25 percent; target return on
equity for electric operations of 11.25 percent; and recovery of
$1.3 million of costs associated with the Pine Street site, amortized
over five years. The VPSB approved the settlement in an order dated May
23, 1996. The rate increase, which was intended in part to cover higher
power supply costs, particularly those relating to purchases from Hydro-
Quebec, was implemented on a June 1, 1996 service-rendered basis. (See
Note 4 of the Notes to Consolidated Financial Statements.)
OPERATING EXPENSES
Power supply expenses increased 18.0 percent in the second quarter of
1996 over the same period in 1995 primarily due to higher costs for
power purchased from Hydro-Quebec and independent power producers and to
increased operations and maintenance expenses experienced by the Vermont
Yankee nuclear plant. Power supply expenses increased 23.9 percent for
the six months ended June 30, 1996 over the same period in 1995 for the
same reasons. In July 1996, Vermont Yankee informed the Company that
the Vermont Yankee nuclear power plant is considering accelerating
certain operations projects into 1996. Vermont Yankee is unable to
predict at this time the extent to which its operations expenses for
1996 will exceed the level of such expenses incurred during 1995. The
projects related to these additional costs will not affect the scheduled
maintenance and refueling outage anticipated in the fall of 1996.
Other operating expenses were virtually unchanged in the second quarter
of 1996 compared to the same period in 1995. Other operating expenses
increased 4.0 percent for the six months ended June 30, 1996 over the
same period in 1995 primarily due to costs associated with the Company's
customer research and market analysis efforts.
Transmission expenses were virtually unchanged in the second quarter of
1996 compared to the same period in 1995. Transmission expenses
increased 6.2 percent for the six months ended June 30, 1996 over the
same period in 1995 primarily due to the need for additional
transmission services related to the increased wholesale transactions
mentioned above.
Maintenance expenses increased 38.6 percent in the second quarter of
1996 over the same period in 1995 primarily due to an increase in
maintenance activities associated with increased usage of certain
generating facilities. Maintenance expenses increased 14.5 percent for
the six months ended June 30, 1996 over the same period in 1995 for the
same reason.
Depreciation and amortization expenses increased 26.3 percent in the
second quarter of 1996 over the same period in 1995 primarily due to the
amortization of expenditures related to energy conservation programs and
the Pine Street Barge Canal Site. (See Note 3 of the Notes to
Consolidated Financial Statements.) Depreciation and amortization
expenses increased 23.6 percent for the six months ended June 30, 1996
over the same period in 1995 for the same reasons.
Taxes other than income taxes increased 2.9 percent in the second
quarter of 1996 over the same period in 1995 primarily due to increases
in municipal property and gross revenue taxes. Taxes other than income
taxes increased 4.7 percent for the six months ended June 30, 1996 over
the same period in 1995 for the same reasons.
INCOME TAXES
Income taxes decreased 62.3 percent in the second quarter of 1996
compared to the same period in 1995 primarily due to a decrease in
taxable income. Income taxes decreased 14.4 percent for the six months
ended June 30, 1996 compared to the same period in 1995 for the same
reason.
OTHER INCOME
Other income was virtually unchanged in the second quarter of 1996
compared to the same period in 1995. Other income increased 17.1 percent
for the six months ended June 30, 1996 over the same period in 1995
primarily due to a $188,000 increase in earnings reported by Mountain
Energy, Inc., the Company's wholly-owned subsidiary that invests in
electric energy generation and efficiency projects, and a $55,000
increase in earnings reported by Green Mountain Propane Gas Company, the
Company's wholly-owned propane subsidiary.
INTEREST CHARGES
Interest charges were virtually unchanged in the second quarter of 1996
compared to the same period in 1995. Interest charges increased 2.4
percent for the six months ended June 30, 1996 over the same period in
1995 primarily due to interest charges related to an increase in long-
term debt outstanding during the period and a decrease in the allowance
for funds used during construction resulting from lower related
construction work in progress balances. These increases were partially
offset by a reduction in interest charges related to a decrease in
short-term debt outstanding during the period.
AGREEMENT WITH IBM
In February 1995, the Company and IBM entered into an Economic
Development Agreement (EDA) that established the price to be paid by IBM
at its Essex Junction, Vermont, facility for incremental electric usage
during 1995, 1996 and, at IBM's option, 1997. The contract, which is
intended to promote growth in IBM's operations and create jobs in the
Company's service area, applies only to that portion of IBM's load that
exceeds its 1994 consumption level. The EDA price, although lower than
the Company's tariff rate, exceeds the Company's marginal costs of
providing this incremental electric service to IBM. The VPSB approved
the EDA in June 1995. The Company believes that the EDA benefits the
Company because it encourages the incremental purchase of electricity by
IBM at a price above the Company's marginal cost of providing such
incremental service. Sales to IBM represented 12.9 percent of the
Company's operating revenues in 1995.
LIQUIDITY AND CAPITAL RESOURCES
For the six months ended June 30, 1996, construction and conservation
expenditures totaled $8.7 million. Such expenditures in 1996 are
expected to be approximately $29.5 million, principally for expansion
and improvements of the Company's transmission and distribution plant,
for conservation measures and for the construction of a 6 megawatt wind
turbine generating plant located in southern Vermont.
The Company continues to supplement internally generated funds with
external financing to fund construction and conservation expenditures,
refinancings and other cash requirements.
In January 1996, a portion of the proceeds from the sale of $24 million
of the Company's first mortgage bonds in December 1995 was used to
refund $7.2 million of the Company's 10.7 percent first mortgage bonds.
The Company presently anticipates issuing approximately $13 million of
common stock and approximately $13 million of first mortgage bonds in
the second half of 1996. The proceeds will be used to repay short-term
debt, to retire fixed income securities and for other general corporate
purposes.
COMPETITION AND RESTRUCTURING
The electric utility business is being subjected to rapidly increasing
competitive pressures stemming from a combination of trends, including
the presence of surplus generating capacity, a disparity in electric
rates among regions of the country, improvements in generation
efficiency, increasing demand for customer choice, and new regulations
and legislation intended to foster competition. To date, this
competition has been most prominent in the bulk power market, in which
non-utility generators have significantly increased their market share.
Electric utilities have historically had exclusive franchises for the
retail sale of electricity in specified service territories. As a
result, competition for retail customers has been limited to (i)
competition with alternative fuel suppliers, primarily for heating and
cooling, (ii) competition with customer-owned generation, and (iii)
direct competition among electric utilities to attract major new
facilities to their service territories. These competitive pressures
have led the Company and other utilities to offer, from time to time,
special discounts or service packages to certain large customers.
In states across the country, including the New England states, there
has been an increasing number of proposals to allow retail customers to
choose their electricity suppliers, with incumbent utilities required to
deliver that electricity over their transmission and distribution
systems (also known as "retail wheeling"). Increased competitive
pressure in the electric utility industry may restrict the Company's
ability to charge prices high enough to recover embedded costs, such as
the cost of purchased power or of generation. The amount by which such
costs might exceed market prices is commonly referred to as "stranded
costs".
Regulatory and legislative authorities at the federal and state level,
including Vermont, are considering how to facilitate competition for
electricity sales at the wholesale and retail levels. In October 1994,
the VPSB and the Department convened a "Roundtable on Competition and
the Electric Industry" (the Roundtable), consisting of representatives
of utilities (including the Company), customers, environmental groups
and other affected parties. In July 1995, a subgroup of the Roundtable
agreed on a set of 14 principles intended to guide the debate in Vermont
concerning competition. These principles, among other things, call for
exploration of the potential for retail competition, honoring of past
utility commitments incurred under regulation, protection for low income
customers, and continued exploration of renewable resources, energy
efficiency and environmental protections.
On September 14, 1995, Governor Dean of Vermont announced his desire to
provide for competition and a restructuring of the utility industry.
The Governor's announcement included proposed legislative adoption of
restructuring principles in 1996, a VPSB proceeding to address the
issue, filing by Vermont electric utilities of detailed plans by May 1,
1996, and implementation of restructuring by the end of 1997. In
response to a Department petition, the VPSB opened a proceeding on
electric utility industry restructuring by order dated October 17, 1995.
The VPSB has established a schedule for its investigation that calls for
the VPSB to complete its docket and make a presentation to the Vermont
General Assembly for its 1997 session.
On December 29, 1995, the Company released its proposed restructuring
plan. The Company's plan provides for restructuring, enabled by new
Vermont legislation, by January 1, 1998. Under this plan, individual
utilities would be functionally separated into their competitive and
regulated components. The Company advocates a holding company structure
to accomplish this goal, with each component in a separate corporate
subsidiary. The competitive component would consist of generating
assets, purchased power entitlements, electricity sales, energy
efficiency/demand-side management services, and other customer services.
The regulated component would consist of transmission and local
distribution activities, which can be provided more cost effectively by
one firm, rather than multiple providers. In addition, a regional
Independent System Operator (ISO) would coordinate the transmission and
generation functions to ensure non-discriminatory access and the safety
and reliability of the region's transmission systems and an adequate
power supply. This ISO would perform functions similar to those
currently provided by NEPOOL.
Under the Company's plan, all customers would be free to choose any
retail electrical energy supplier that offered service in their
community, and the retail suppliers would be free to offer their
products and services in any state in which they were certified to
operate. A customer who did not choose a new energy supplier would
continue to be served by the retail supplier that was affiliated with
the utility that served the customer before the restructuring.
The Company has proposed in its plan full recovery of stranded costs
through a customer access charge recovered primarily on a fixed monthly
basis from all customers on the transmission and distribution system.
It is the Company's position that equity and economic efficiency require
that utilities be allowed to recover all of their stranded costs which
were incurred to fulfill their obligations to provide reliable service
as a regulated public utility. Certain parties participating in the
Roundtable and related VPSB proceedings described above have taken
positions opposing the recovery of stranded costs.
The Company is unable to predict the outcome of restructuring activities
with respect to stranded cost recovery and other issues. Several
factors, including future legislative enactments, future regulatory and
legal decisions and the future market price of power, which are
currently unknown, will determine the degree to which, if at all, the
Company will be exposed to stranded costs and will be able to recover
stranded costs in rates set by the VPSB. The inability of the Company
to collect most of its stranded costs in rates set by the VPSB would
have a material adverse impact on the Company's restructured operations
and the ability to pay dividends at the current level. The Company is
also unable to predict its ability to retain and attract customers in a
competitive environment.
FEDERAL OPEN ACCESS TARIFF ORDERS
On April 24, 1996, the Federal Energy Regulatory Commission (FERC)
issued Orders 888 and 889 which, among other things, require the filing
of open access transmission tariffs by electric utilities, and the
functional separation by utilities of their transmission operations from
other utility operations. FERC Order 888 also supports the full
recovery of legitimate and verifiable costs previously incurred under
federal and state regulation. The Company is currently in the process
of responding to the orders. On July 9, 1996, the Company filed with
the FERC the non-discriminatory open access tariffs required by Order
888. The Company also intends to functionally separate its transmission
operations by the November 1, 1996 deadline. The Company does not
anticipate any material adverse effects or loss of wholesale customers
due to the FERC Orders mentioned above.
RETAIL COMPETITION PILOT PROGRAMS
The State of New Hampshire has undertaken an experiment to provide
retail customer choice in the purchase of electricity. The Company's
wholly-owned subsidiary (Green Mountain Resources, Inc.), along with the
wholly-owned subsidiaries of three large energy companies -- Hydro-
Quebec, Consolidated Natural Gas Company, and Noverco, Inc. -- is
participating in the New Hampshire pilot program, one of the nation's
first significant attempts to test the viability of retail electric
competition, through a limited liability company (Green Mountain Energy
Partners L.L.C.). Green Mountain Energy Partners L.L.C. has been
competing since May 1996 with approximately two dozen other suppliers to
serve 17,000 eligible customers. The pilot program will extend two
years, with service beginning in June 1996. The Commonwealth of
Massachusetts has also authorized two retail customer choice programs in
which Green Mountain Energy Partners L.L.C. expects to become a
participant. One program, the Massachusetts Electric Company Choice New
England Pilot Program, permits the retail sale of electricity to
approximately 10,000 eligible residential and small
commercial/industrial customers, and will extend for one year with
service beginning on January 1, 1997. The other program, the Bay State
Gas Company Pioneer Valley Customer Choice Residential Pilot Program,
permits the retail sale of natural gas to up to 10,000 residential
customers and will extend for two years with service beginning in
November 1996. Green Mountain Energy Partners L.L.C. may decide to
participate in other retail energy programs that are developed in New
England.
Because of the limited nature of these pilot programs, the Company
anticipates that there will be no material effect on 1996 consolidated
earnings as a consequence of the activities of Green Mountain Energy
Partners L.L.C. in these New England pilot programs. The Company
believes that participation in these New England pilot programs will
enhance the capability of Green Mountain Energy Partners L.L.C. to
compete in additional markets that are opened for retail electric and
natural gas customer choice.
GREEN MOUNTAIN POWER CORPORATION
June 30, 1996
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial
Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
At the Annual Shareholders Meeting held May 16, 1996,
shareholders elected the nominees listed below as Directors of
the company. The voting results are set forth below. There
were no other items brought before the meeting.
Election of Directors
Shareholders elected the nominees for Director as follows:
Broker
Total Votes Total Votes Non-Votes
Nominee FOR WITHHELD Absentions
Class I (term expires 1999)
William H. Bruett 3,993,038 56,705 803,077
Richard I. Fricke 3,982,939 66,804 803,077
Martin L. Johnson 3,985,369 64,374 803,077
Thomas P. Salmon 3,988,617 61,126 803,077
Directors Continuing In Office
Class II (term expires 1997)
Robert E. Boardman
Merrill O. Burns
Douglas G. Hyde
Ruth W. Page
Class III (term expires 1998)
Nordahl L. Brue
Lorraine E. Chickering
John V. Cleary
Euclid A. Irving
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: August 13, 1996 /s/ C. L. Dutton
C. L. Dutton, Vice President, Chief
Financial Officer and Treasurer
Date: August 13, 1996 /s/ G. J. Purcell
G. J. Purcell, Controller
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