-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TdVtovnp8eH6rMuZ3XzQ9mvmCkq65/iLsqjOu4EHu3ras6Vaemycagb8DObX1vWI IKuZVoBLCMnnkgkxS7NU/w== 0000043704-96-000010.txt : 19960814 0000043704-96-000010.hdr.sgml : 19960814 ACCESSION NUMBER: 0000043704-96-000010 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960813 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: GREEN MOUNTAIN POWER CORP CENTRAL INDEX KEY: 0000043704 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 030127430 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-08291 FILM NUMBER: 96610790 BUSINESS ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P.O.BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05402-0850 BUSINESS PHONE: 8028645731 MAIL ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P O BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05402-0850 10-Q 1 FORM 10-Q FOR THE QUARTER ENDED 6/30/96 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 GREEN MOUNTAIN POWER CORPORATION Consolidated Comparative Balance Sheets (Unaudited) Part 1 - Item 1
June 30 December 31 ----------------------------------- ---------------- 1996 1995 1995 ---------------- ---------------- ---------------- (In thousands) (In thousands) ASSETS ELECTRIC UTILITY 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.
GREEN MOUNTAIN POWER CORPORATION Consolidated Comparative Income Statements (Unaudited) Part 1 - Item 1
Three Months Ended Six Months Ended June 30 June 30 ------------------------------- ------------------------------- 1996 1995 1996 1995 ------------ ------------ ------------ ------------ (In thousands, except amounts per share) 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.
GREEN MOUNTAIN POWER CORPORATION Consolidated Statements of Cash Flows (Unaudited) Part 1 - Item 1
Six Months Ended June 30 --------------------------------------- 1996 1995 ----------------- ----------------- (In thousands) 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.
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 EX-27 2
UT This schedule contains summary financial information extracted from the Consolidated Balance Sheet as of June 30, 1996 and the related Statements of Income and Cash Flows for the six months ended June 30, 1996 and is qualified in its entirety by reference to such financial statements. 1,000 6-MOS DEC-31-1996 JUN-30-1996 PER-BOOK 184,683 20,651 24,057 39,561 39,182 308,134 16,503 66,118 25,950 108,571 8,120 810 82,234 18,615 0 0 1,700 0 9,778 0 78,306 308,134 88,881 2,439 79,511 81,950 6,931 1,899 8,830 3,742 5,088 379 4,709 5,171 3,511 19,339 0.96 0.96
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