-----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, QgnWsdqD12PwHYjFmVWUOiwH2SNmYlIHrQHYnRN5BpoFiaQCi6pxEzuS63bASIvg LEu0tV3Gb8zj5KqosUcRLA== 0000893220-01-500164.txt : 20010511 0000893220-01-500164.hdr.sgml : 20010511 ACCESSION NUMBER: 0000893220-01-500164 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20010331 FILED AS OF DATE: 20010510 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONECTIV CENTRAL INDEX KEY: 0001029590 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 510377417 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-13895 FILM NUMBER: 1627647 BUSINESS ADDRESS: STREET 1: 800 KING ST STREET 2: P O BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 BUSINESS PHONE: 3024293114 MAIL ADDRESS: STREET 1: 800 KING ST STREET 2: P O BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 10-Q 1 w48793e10-q.txt FORM 10-Q CONECTIV 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q /X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-13895 CONECTIV (Exact name of registrant as specified in its charter) Delaware 51-0377417 (State of incorporation) (I.R.S. Employer Identification No.) 800 King Street, P.O. Box 231, Wilmington, Delaware 19899 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 302-429-3018 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 Shares Outstanding at March 31, 2001 Common Stock, $0.01 par value 82,967,179 Class A Common Stock, $0.01 par value 5,742,315 2 CONECTIV Table of Contents
Page Part I. Financial Information: Item 1. Financial Statements Consolidated Statements of Income for the three months ended March 31, 2001, and March 31, 2000................................. 1 Consolidated Statements of Comprehensive Income for the three months ended March 31, 2001, and March 31, 2000.................... 2 Consolidated Balance Sheets as of March 31, 2001, and December 31, 2000.................................................. 3-4 Consolidated Statements of Cash Flows for the three months ended March 31, 2001, and March 31, 2000........................... 5 Notes to Consolidated Financial Statements......................... 6-14 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................................15-24 Item 3. Quantitative and Qualitative Disclosures About Market Risk......... 25 Part II. Other Information Item 1. Legal Proceedings.................................................. 26 Item 5. Other Information.................................................. 26 Item 6. Exhibits and Reports on Form 8-K...................................26-27 Signature ............................................................. 28
i 3 PART 1, FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS CONECTIV CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts) (Unaudited)
THREE MONTHS ENDED MARCH 31, ------------------------------- 2001 2000 ---------- ---------- OPERATING REVENUES Electric $766,879 $630,295 Gas 638,085 274,493 Other services 149,685 140,557 ---------- ---------- 1,554,649 1,045,345 ---------- ---------- OPERATING EXPENSES Electric fuel and purchased energy and capacity 485,726 331,304 Gas purchased 629,390 251,619 Other services' cost of sales 120,144 118,437 Operation and maintenance 112,700 156,878 Depreciation and amortization 62,400 63,930 Taxes other than income taxes 20,190 21,231 ---------- ---------- 1,430,550 943,399 ---------- ---------- OPERATING INCOME 124,099 101,946 ---------- ---------- OTHER INCOME 2,752 12,315 ---------- ---------- INTEREST EXPENSE Interest charges 53,032 54,157 Capitalized interest and allowance for borrowed funds used during construction (4,931) (1,693) ---------- ---------- 48,101 52,464 ---------- ---------- PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 5,159 5,049 ---------- ---------- INCOME BEFORE INCOME TAXES 73,591 56,748 INCOME TAXES 32,787 24,211 ---------- ---------- NET INCOME $ 40,804 $ 32,537 ========== ========== EARNINGS (LOSS) APPLICABLE TO COMMON STOCK Common stock $ 39,912 $ 34,990 Class A common stock 892 (2,453) ---------- ---------- $ 40,804 $ 32,537 ========== ========== COMMON STOCK AVERAGE SHARES OUTSTANDING (000) Common stock 82,704 85,568 Class A common stock 5,742 5,742 EARNINGS (LOSS) PER AVERAGE SHARE--BASIC AND DILUTED Common stock $0.48 $0.41 Class A common stock $0.16 ($0.43) DIVIDENDS DECLARED PER SHARE Common stock $0.22 $0.22 Class A common stock $0.80 $0.80
See accompanying Notes to Consolidated Financial Statements. -1- 4 CONECTIV CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (DOLLARS IN THOUSANDS) (Unaudited)
THREE MONTHS ENDED MARCH 31, ------------------------------- 2001 2000 -------- -------- Net Income $ 40,804 $ 32,537 -------- -------- Other comprehensive income, net of taxes Energy commodity hedging: Cumulative effect of a change in accounting resulting from adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," net of taxes of $2,380 3,445 -- Unrealized loss from cash flow hedges net of reclassification adjustments and net of taxes of $10,710 (15,502) -- Unrealized loss on marketable securities net of reclassification adjustments and net of taxes of $44 (82) -- -------- -------- Comprehensive income $ 28,665 $ 32,537 ======== ========
See accompanying Notes to Consolidated Financial Statements. -2- 5 CONECTIV CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited)
MARCH 31, DECEMBER 31, 2001 2000 --------------- ------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $44,268 $123,562 Accounts receivable, net of allowances of $31,697 and $31,339, respectively 982,974 792,843 Inventories, at average cost Fuel (coal, oil and gas) 64,653 54,578 Materials and supplies 53,572 62,675 Deferred energy supply costs 21,198 22,094 Prepayments 25,575 23,354 Deferred income taxes, net 11,369 13,155 --------------- ------------------- 1,203,609 1,092,261 --------------- ------------------- INVESTMENTS Investment in leveraged leases 53,999 53,706 Funds held by trustee 125,387 122,387 Other investments 73,643 70,780 --------------- ------------------- 253,029 246,873 --------------- ------------------- PROPERTY, PLANT AND EQUIPMENT Electric generation 1,581,768 1,576,550 Electric transmission and distribution 2,746,397 2,711,907 Gas transmission and distribution 281,241 277,650 Other electric and gas facilities 390,702 390,313 Telecommunications, thermal systems, and other property, plant, and equipment 263,140 251,567 --------------- ------------------- 5,263,248 5,207,987 Less: Accumulated depreciation 2,222,856 2,179,951 --------------- ------------------- Net plant in service 3,040,392 3,028,036 Construction work-in-progress 465,905 406,884 Leased nuclear fuel, at amortized cost 25,129 28,352 Goodwill, net of accumulated amortization of $35,893 and $33,437, respectively 341,918 344,514 --------------- ------------------- 3,873,344 3,807,786 --------------- ------------------- DEFERRED CHARGES AND OTHER ASSETS Recoverable stranded costs, net 981,494 988,153 Deferred recoverable income taxes 82,450 84,730 Unrecovered purchased power costs 13,988 14,487 Unrecovered New Jersey state excise tax 7,163 10,360 Deferred debt refinancing costs 20,031 20,656 Deferred other postretirement benefit costs 29,356 29,981 Prepaid pension costs 76,377 69,963 Unamortized debt expense 25,105 25,553 License fees 21,612 21,956 Other 68,198 65,236 --------------- ------------------- 1,325,774 1,331,075 --------------- ------------------- TOTAL ASSETS $6,655,756 $6,477,995 =============== ===================
See accompanying Notes to Consolidated Financial Statements. -3- 6 CONECTIV CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited)
MARCH 31, DECEMBER 31, 2001 2000 ---------------- ---------------- CAPITALIZATION AND LIABILITIES CURRENT LIABILITIES Short-term debt $738,522 $709,530 Long-term debt due within one year 100,751 100,721 Variable rate demand bonds 158,430 158,430 Accounts payable 631,232 490,887 Taxes accrued 68,871 10,877 Interest accrued 46,699 45,296 Dividends payable 27,161 27,111 Deferred energy supply costs 30,479 34,650 Current capital lease obligation 15,596 15,591 Above-market purchased energy contracts and other electric restructuring liabilities 23,719 23,891 Other 88,217 107,025 ---------------- ---------------- 1,929,677 1,724,009 ---------------- ---------------- DEFERRED CREDITS AND OTHER LIABILITIES Other postretirement benefits obligation 90,747 90,335 Deferred income taxes, net 807,120 823,094 Deferred investment tax credits 63,044 64,316 Regulatory liability for New Jersey income tax benefit 49,262 49,262 Above-market purchased energy contracts and other electric restructuring liabilities 95,783 103,575 Deferred gain on termination of purchased energy contract 74,968 74,968 Long-term capital lease obligation 10,491 13,744 Other 61,770 67,751 ---------------- ---------------- 1,253,185 1,287,045 ---------------- ---------------- CAPITALIZATION Common stock: $0.01 per share par value; 150,000,000 shares authorized; shares outstanding - - 82,967,179 in 2001, and 82,859,779 in 2000 831 830 Class A common stock, $0.01 per share par value; 10,000,000 shares authorized; shares outstanding - - 5,742,315 in 2001 and 2000 57 57 Additional paid-in capital - - common stock 1,030,941 1,028,780 Additional paid-in capital - - Class A common stock 93,738 93,738 Retained earnings 60,784 42,768 Treasury shares, at cost: 135,604 shares in 2001; 130,604 shares in 2000 (2,786) (2,688) Unearned compensation (2,896) (1,172) Accumulated other comprehensive income (14,183) (2,044) ---------------- ---------------- Total common stockholders' equity 1,166,486 1,160,269 Preferred stock and securities of subsidiaries: Not subject to mandatory redemption 95,933 95,933 Subject to mandatory redemption 188,950 188,950 Long-term debt 2,021,525 2,021,789 ---------------- ---------------- 3,472,894 3,466,941 ---------------- ---------------- Commitments and Contingencies (Note 10) ---------------- ---------------- TOTAL CAPITALIZATION AND LIABILITIES $6,655,756 $6,477,995 ================ ================
See accompanying Notes to Consolidated Financial Statements. -4- 7 CONECTIV CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)
THREE MONTHS ENDED MARCH 31, --------------------------------- 2001 2000 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 40,804 $ 32,537 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 65,640 70,280 Investment tax credit adjustments, net (1,272) (1,273) Deferred income taxes, net (3,533) (14,733) Net change in: Accounts receivable (194,925) (114,397) Inventories (2,341) 12,511 Accounts payable 140,678 27,136 Accrued / prepaid taxes 68,710 113,201 Other current assets & liabilities (1) (54,557) 39,896 Other, net (14,082) (16,254) --------- --------- Net cash provided by operating activities 45,122 148,904 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (122,642) (63,455) Investments in partnerships (2,820) (2,845) Proceeds from assets sold 1,060 12,849 Deposits to nuclear decommissioning trust funds (825) -- Acquisition of businesses, net of cash acquired -- (798) Leveraged leases, net -- 795 Other, net (1,784) 2,456 --------- --------- Net cash used by investing activities (127,011) (50,998) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock dividends paid (22,778) (23,496) Common stock redeemed -- (22,678) Long-term debt redeemed (294) (48,414) Principal portion of capital lease payments (3,240) (6,350) Net change in short-term debt 28,992 28,531 Cost of issuances and refinancings (85) (1,193) --------- --------- Net cash provided (used) by financing activities 2,595 (73,600) --------- --------- Net change in cash and cash equivalents (79,294) 24,306 Cash and cash equivalents at beginning of period 123,562 56,239 --------- --------- Cash and cash equivalents at end of period $ 44,268 $ 80,545 ========= =========
(1) Other than debt and deferred income taxes classified as current. See accompanying Notes to Consolidated Financial Statements. -5- 8 CONECTIV NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1. FINANCIAL STATEMENT PRESENTATION Conectiv's consolidated condensed interim financial statements contained herein include the accounts of Conectiv and its majority owned subsidiaries and reflect all adjustments, consisting of only normal recurring adjustments, necessary in the opinion of management for a fair presentation of interim results. In accordance with regulations of the Securities and Exchange Commission (SEC), disclosures that would substantially duplicate the disclosures in Conectiv's 2000 Annual Report on Form 10-K have been omitted. Accordingly, Conectiv's consolidated condensed interim financial statements contained herein should be read in conjunction with Conectiv's 2000 Annual Report on Form 10-K and Part II of this Quarterly Report on Form 10-Q for additional relevant information. As previously disclosed, on February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger (Conectiv/Pepco Merger Agreement) under which Pepco will acquire Conectiv for a combination of cash and stock. The transaction is subject to various statutory and regulatory approvals and approval by the stockholders of Conectiv and Pepco. See Note 5 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K for additional information. There is no significant new information to report concerning this matter. NOTE 2. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Conectiv actively participates in the wholesale energy markets and engages in commodity hedging activities to minimize the risk of market price fluctuations associated with the purchase and sale of energy commodities (natural gas, petroleum, electricity, and other energy commodities). Some of Conectiv's hedging activities are conducted using derivative instruments designated as "cash flow hedges," which are designed to hedge the variability in cash flows of forecasted transactions. Conectiv also hedges by backing physical transactions with offsetting physical positions. In the first quarter of 2001, Conectiv did not hold any derivative instruments designated as "fair value hedges," which include hedges of exposure to changes in the fair value of unrecognized firm commitments. Conectiv's energy commodity hedging objectives, in accordance with its risk management policy, are primarily the assurance of stable and known cash flows and the fixing of favorable prices and margins when they become available. These hedging objectives generally apply to all of Conectiv's energy commodity hedging activities, including hedging activities conducted through derivative instruments designated as cash flow hedges and physical transactions. Some derivative instruments are held by Conectiv for trading purposes with the intention of enhancing earnings. Conectiv implemented the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended, effective January 1, 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS No. 133 requires all derivative instruments, within the scope of the statement, to be recognized as assets or liabilities on the balance sheet at fair value. Changes in the fair value of derivatives that are not hedges, under SFAS No. 133, are recognized in earnings. The gain or -6- 9 loss on a derivative that hedges exposure to variable cash flow of a forecasted transaction is initially recorded in other comprehensive income (a separate component of common stockholders' equity) and is subsequently reclassified into earnings when the forecasted transaction occurs. If a forecasted transaction is no longer probable, the deferred gain or loss in accumulated other comprehensive income is immediately reclassified to earnings. Changes in the fair value of other hedging derivatives result in a change in the value of the asset, liability, or firm commitment being hedged, to the extent the hedge is effective. Any ineffective portion of a hedge is recognized in earnings immediately. The accounting prescribed by SFAS No. 133 may cause increased volatility in Conectiv's earnings, revenues and common stockholders' equity. The initial impact on Conectiv's financial statements of adopting SFAS No. 133 effective January 1, 2001 included the following: (a) recognition of $43.8 million of assets and $38.0 million of liabilities for the fair value of certain contracts, which are classified as derivatives under SFAS No. 133; (b) derecognition (or elimination) of $0.2 million of deferred credits and $3.1 million of current assets associated with deferred gains and losses from hedging derivatives; and (c) a "cumulative effect" type of adjustment, which was recorded as a $5.8 million pre-tax ($3.4 million after-tax) credit to other comprehensive income. For the twelve months ending December 31, 2001, Conectiv expects to have reclassified into earnings approximately $7.6 million before taxes ($4.4 million after taxes) of the cumulative effect adjustment recorded in other comprehensive income. During the three months ended March 31, 2001, for derivative instruments designated as cash flow hedges and for the related hedged transaction (i) the net gain recognized in earnings for hedge ineffectiveness was $0.4 million before taxes ($0.2 million after taxes) and (ii) the net gain recognized in earnings for the portion of the derivative instruments' gain excluded from the assessment of hedge effectiveness was $0.5 million before taxes ($0.3 million after taxes). These gains are reported as operating revenues in the Consolidated Statement of Income. During the three months ended March 31, 2001, a net loss of $0.8 million before taxes ($0.5 million after taxes) was reclassified from accumulated other comprehensive income into earnings because the forecasted energy commodity transactions were no longer expected to occur within the forecasted period. Amounts in accumulated other comprehensive income related to energy commodity cash flow hedges are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. During the twelve-month period ending March 31, 2002, a net loss of $16.8 million before taxes ($10.1 million after taxes) associated with energy commodity hedging is expected to be reclassified from accumulated other comprehensive income into earnings. Also, a net gain on the hedged transactions, which would offset the net hedging loss, is expected to be realized during the same time period. As of March 31, 2001, the maximum length of time over which Conectiv was hedging the variability in future cash flows for forecasted energy commodity transactions was 45 months; however, most of such hedges are for 12 months or less. NOTE 3. PROCEEDS FROM TERMINATION OF MEMBERSHIP IN MUTUAL INSURANCE COMPANY As discussed in Note 10 to the Consolidated Financial Statements, NEIL is a nuclear industry mutual insurance company, which provides replacement power cost coverage in the event of a major accidental outage at a nuclear power plant. Atlantic City Electric Company (ACE) is a member of NEIL, and as discussed below, Delmarva Power & Light Company (DPL) terminated its membership in NEIL on February 19, 2001. Under changes in NEIL's by-laws effective December 31, 2000, member account balances no longer exist. NEIL members who sell their interests in nuclear electric generating plants after December 31, -7- 10 2000, may choose either (1) to continue to receive certain policyholders' distributions from NEIL (if, as, and when declared) over a 5-year period or (2) to remain a NEIL member by purchasing other insurance products from NEIL and thus remain eligible for policyholders' distributions (if, as, and when declared) for a longer period. NEIL members that sold their interests in nuclear electric generating plants on or before December 31, 2000, could also elect prior to February 28, 2001, to be paid their member account balances by NEIL for terminating their NEIL insurance coverages. DPL sold its interests in nuclear electric generating plants on December 29, 2000, as discussed in Note 14 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. On February 19, 2001, DPL elected to terminate its NEIL membership and received $16.3 million for its member account balance. As a result of DPL's NEIL membership termination, Conectiv's operation and maintenance expenses for the three months ended March 31, 2001 include a $16.3 million pre-tax credit ($9.8 million after taxes or $0.12 per share of common stock). If the sale of ACE's ownership interests in nuclear electric generating plants is completed, then ACE will be able to choose one of the two options available to it under NEIL's current by-laws. NOTE 4. INVESTMENTS As discussed in Note 8 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K, an indirect Conectiv subsidiary holds a limited partner interest in EnerTech Capital Partners, L.P. and EnerTech Capital Partners II, L.P. (the EnerTech funds). The EnerTech funds are venture capital funds that invest in energy related technology and Internet service companies. Conectiv also has other investments, including other venture capital funds, an Internet start-up project, and marketable securities. Conectiv's investment income was not significant for the three months ended March 31, 2001 and was $0.8 million after income taxes ($0.01 per share of common stock) for the three months ended March 31, 2000. During the first quarter of 2001, Conectiv received a distribution from the EnerTech funds of 990,838 shares of Capstone Turbine Corporation (Capstone). Capstone develops, designs, assembles, and sells micro-turbines worldwide in the distributed power generation market and hybrid electric vehicle market. Primarily due to the distribution of the Capstone shares, the carrying amount of Conectiv's investment in the EnerTech funds decreased to $14.2 million as of March 31, 2001, from $38.6 million as of December 31, 2000. The carrying amount of Conectiv's investment in the Capstone shares was $28.1 million as of March 31, 2001 and is included in "Other Investments" on the Consolidated Balance Sheet. NOTE 5. AGREEMENTS FOR THE SALES OF ELECTRIC GENERATING PLANTS For information concerning agreements for the sale of electric generating plants, see Note 14 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. The operating results of the electric generating plants to be sold are included in the Energy business segment shown in Note 12 to the Consolidated Financial Statements included herein. There is no significant new information to report concerning this matter. On April 11, 2001, ACE entered into a purchased power agreement with an affiliate of NRG Energy, Inc. (NRG), the party with which ACE has an agreement for the sale of certain of its fossil fuel-fired electric generating plants. The purchased power agreement provides for ACE to begin purchasing 400 megawatts of capacity and energy over a period that begins when the sale of certain of ACE's electric generating plants to NRG is completed and ends on August 31, 2002. -8- 11 NOTE 6. REGULATORY MATTERS An update to the information previously reported in Note 10 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K is presented below. NEW JERSEY ELECTRIC UTILITY INDUSTRY RESTRUCTURING As previously disclosed, the New Jersey Board of Public Utilities (NJBPU) issued a Summary Order to ACE in July 1999 concerning restructuring ACE's electricity supply business and indicated that a more detailed order would be issued at a later time. The Final Decision and Order of the NJBPU, dated March 30, 2001, for ACE was publicly posted on the NJBPU's website in mid-May 2001. The Final Decision and Order supersedes a Summary Order issued on July 15, 1999, which was the subject of a Form 8-K filing made by Conectiv and ACE on July 15, 1999. The Final Decision and Order and the 1999 Summary Order were issued in conjunction with a June 9, 1999 settlement in the NJBPU's restructuring proceeding relating to ACE's stranded costs, unbundled rates, and other provisions relevant to establishing competitive retail electric supply markets within ACE's franchised service area in southern New Jersey. After an initial review, management believes that the substantive provisions of the Final Decision and Order largely track the substantive provisions of the Summary Order filed with and discussed in Conectiv's and ACE's July 15, 1999 Form 8-K filings. Differences between the Summary Order and the Final Decision and Order that have been identified, in management's view, are not material and include: 1) establishing August 1, 2002, as the date for submission of a filing regarding the level of all unbundled rate components proposed to be applicable on and after August 1, 2003; 2) with respect to deferred costs to be recovered in future rates, establishing an interest rate to be applied to the deferred balances that is tied to 7-year Treasury constant maturities rather than tied to intermediate-term maturities actually issued by Conectiv or ACE; 3) finding that such deferred balances and interest are recoverable over a "reasonable period of time" to be determined by the NJBPU rather than the four-year period explicitly set forth in the Summary Order; and 4) striking a provision in the settlement that identified a statutory right for ACE to make an early filing for rate modifications under certain specified conditions. NOTE 7. INCOME TAXES For the three months ended March 31, 2001, the amount computed by multiplying "Income before income taxes" by the federal statutory rate is reconciled in the table below to income tax expense.
Three Months Ended March 31, 2001 ----------------------- Amount Rate ------- ------ (Dollars in Thousands) Statutory federal income tax expense $25,756 35% State income taxes, net of federal benefit 5,809 8 Depreciation 1,474 2 Amortization of investment tax credits (1,272) (2) Other, net 1,020 2 --------- -------- Income tax expense $32,787 45% ========= ========
-9- 12 NOTE 8. DEBT The $738.5 million of short-term debt outstanding as of March 31, 2001 had an average interest rate of 6.0%. As of March 31, 2001, Conectiv (the holding company) had a $300 million credit agreement with a five-year term that expires in February 2003 and a $730 million credit agreement, which was renewed on April 5, 2001 for an additional year and increased to $735 million. Conectiv's credit agreements require a ratio of total indebtedness to total capitalization of 70% or less and the ratio was 64% as of March 31, 2001, computed in accordance with the terms of the credit agreements. On February 12, 2001, DPL reduced the commitments under its revolving credit facility, which expires January 31, 2003, from $150 million to $105 million; this credit facility provides liquidity for DPL's $104.8 million of Variable Rate Demand Bonds and also may be used for general corporate purposes. NOTE 9. CONECTIV CLASS A COMMON STOCK For general information about Class A common stock, and information about dividend payments, conversion and redemption provisions, and allocation of consideration in a subsequent merger, refer to Note 19 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. For the three months ended March 31, 2001, dividends declared per share of Class A common stock were $0.80 compared to earnings per share of Class A common stock outstanding of $0.16. During the three-year period ended March 31, 2001, or the "Initial Period," the quarterly dividend on shares of Class A common stock was $0.80. As disclosed at the time DPL and ACE became wholly owned subsidiaries of Conectiv (1998 Merger), Conectiv intends, following the Initial Period, subject to declaration by Conectiv's Board of Directors and the obligation of the Board of Directors to consider the financial condition and regulatory environment of Conectiv and the results of its operations, to pay annual dividends on the Class A common stock at a rate equal to 90% of annualized earnings of the Class A common stock (taking into account the notional fixed charge of $40 million per year in accordance with Conectiv's Restated Certificate of Incorporation). Notwithstanding Conectiv's intention with respect to dividends on the Class A common stock following the Initial Period, to the extent that the annual dividends paid on the Class A common stock during the Initial Period exceed the earnings that were applicable to the Class A common stock during the Initial Period, Conectiv's Board of Directors may consider such fact in determining the appropriate annual dividend rate on the Class A common stock following the Initial Period. As previously reported, during the Initial Period, the earnings applicable to Class A common stock were substantially less than the dividends on the Class A common stock. Management expects Conectiv's Board of Directors to determine the new quarterly dividend per share of Class A common stock in June 2001. -10- 13 COMPUTATION OF EARNINGS (LOSS) APPLICABLE TO CONECTIV CLASS A COMMON STOCK (Dollars in Thousands)(unaudited)
THREE MONTHS ENDED MARCH 31, --------------------------------- 2001 2000 -------- --------- Net earnings of ACE $ 8,743 $ 1,040 Exclude non-utility activities of ACE (25) (24) Net earnings of Conectiv Atlantic Generation, LLC (CAG) 4,550 -- -------- -------- Net income of Atlantic Utility Group 13,268 1,016 Pro-rata portion of fixed notional charge of $40 million per year (10,000) (10,000) -------- -------- Company Net Income (Loss) Attributable to the Atlantic Utility Group 3,268 (8,984) Percentage applicable to Class A Common Stock 27.3% 27.3% -------- -------- Earnings (Loss) applicable to Class A Common Stock $ 892 $ (2,453) ======== ========
SUMMARIZED COMBINED FINANCIAL INFORMATION OF ACE AND CAG (Dollars in Thousands)(unaudited) INCOME STATEMENT INFORMATION
THREE MONTHS ENDED MARCH 31, ------------------------- 2001 2000 ------------ ----------- Operating revenues $241,836 $208,886 Operating income $35,479 $22,680 Net income $13,826 $1,573 Earnings applicable to common stock $13,293 $1,040
BALANCE SHEET INFORMATION
MARCH 31, DECEMBER 31, 2001 2000 ------------- ---------------- Current assets $361,248 $348,958 Noncurrent assets 2,227,177 2,239,297 ------------- -------------- Total assets $2,588,425 $2,588,255 ============= ============== Current liabilities $330,878 $308,801 Noncurrent liabilities 1,463,176 1,481,548 Preferred stock 125,181 125,181 Common stockholder's equity 669,190 672,725 ------------- -------------- Total capitalization and liabilities $2,588,425 $2,588,255 ============= ==============
-11- 14 NOTE 10. CONTINGENCIES ENVIRONMENTAL MATTERS Conectiv's subsidiaries are subject to regulation with respect to the environmental effects of their operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use by various federal, regional, state, and local authorities. Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. Costs may be incurred to clean up facilities found to be contaminated due to past disposal practices. Conectiv's liability for clean-up costs is affected by the activities of these governmental agencies and private land-owners, the nature of past disposal practices, the activities of others (including whether they are able to contribute to clean-up costs), and the scientific and other complexities involved in resolving clean up-related issues (including whether a Conectiv subsidiary or a corporate predecessor is responsible for conditions on a particular parcel). Conectiv's current liabilities include $9.2 million as of March 31, 2001 ($9.8 million as of December 31, 2000) for potential clean-up and other costs related to sites at which a Conectiv subsidiary is a potentially responsible party or alleged to be a third party contributor, including $6.5 million for remediation and other costs associated with environmental contamination that resulted from an oil leak at the Indian River power plant. Conectiv does not expect such future costs to have a material effect on its financial position or results of operations. NUCLEAR INSURANCE In conjunction with the ownership interests of ACE in Peach Bottom Atomic Power Station (Peach Bottom), Salem Nuclear Generating Station (Salem), and Hope Creek Nuclear Generating Station (Hope Creek), ACE could be assessed for a portion of any third-party claims associated with an incident at any commercial nuclear power plant in the United States. Under the provisions of the Price Anderson Act, if third-party claims relating to such an incident exceed $200 million (the amount of primary insurance), ACE could be assessed up to $30.7 million on an aggregate basis for such third-party claims. In addition, Congress could impose a revenue-raising measure on the nuclear industry to pay such claims. The co-owners of Peach Bottom, Salem, and Hope Creek maintain property insurance coverage of approximately $1.8 billion for each unit for loss or damage to the units, including coverage for decontamination expense and premature decommissioning. An industry mutual insurance company (NEIL) provides replacement power cost coverage to members in the event of a major accidental outage at a nuclear power plant. Under these coverages, ACE is subject to potential retrospective loss experience assessments of up to $1.9 million on an aggregate basis. OTHER On October 24, 2000, the City of Vineland, New Jersey, filed an action in a New Jersey Superior Court to acquire ACE electric distribution facilities located within the City limits by eminent domain. The City has offered approximately $11 million for these assets, including the right to provide electric service in this area. ACE believes that, properly evaluated, the assets sought by the City are worth approximately $40 million. Management cannot predict the outcome of this matter. -12- 15 NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION
THREE MONTHS ENDED MARCH 31, ------------------------ 2001 2000 ----------- ----------- (Dollars in Thousands) CASH PAID (RECEIVED) FOR: Interest, net of amounts capitalized $ 45,357 $ 46,103 Income taxes, net of refunds $(17,525) $(74,832)
The $74.8 million of income tax refunds received during the three months ended March 31, 2000 were primarily related to the tax benefit associated with ACE's payment of $228.5 million on December 28, 1999 to terminate ACE's purchase of electricity under a contract with the Pedricktown Co-generation Limited Partnership, as discussed in Note 11 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. NON-CASH INVESTING ACTIVITY As discussed in Note 4 to the Consolidated Financial Statements, during the first quarter of 2001, Conectiv received a distribution from the EnerTech funds of 990,838 shares of Capstone. The carrying amounts of Conectiv's investment in the Capstone shares was $28.1 million as of March 31, 2001 on the Consolidated Balance Sheet. NOTE 12. BUSINESS SEGMENTS The following information is presented in accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." Conectiv's business segments under SFAS No. 131 are as follows: "ENERGY" includes (a) the generation, purchase, trading and sale of electricity, including the obligations of DPL and ACE to supply electricity to customers who do not choose an alternative electricity supplier; (b) gas and other energy supply and trading activities, (c) power plant operation services, and (d) district heating and cooling systems operation and construction services provided by Conectiv Thermal Systems, Inc. "POWER DELIVERY" includes activities related to delivery of electricity and gas to customers at regulated prices over transmission and distribution systems. "TELECOMMUNICATIONS" represents services provided by Conectiv Communications Inc. (CCI), including local, regional and long-distance telephone service and Internet services. "HVAC" represents heating, ventilation, and air conditioning services provided by Conectiv Services Inc. (CSI), prior to the sale of this business in the latter-half of 2000. -13- 16 The operating results for business segments are evaluated based on "Earnings Before Interest and Taxes," which is generally equivalent to Operating Income plus Other Income, less certain interest charges allocated to the business segments. "Earnings Before Interest and Taxes" for the Energy business segment include the operating results of certain electric generating plants that are expected to be sold subsequent to receipt of required regulatory approvals, as discussed in Note 14 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. For the three months ended March 31, 2001, "Earnings Before Interest and Taxes" for the Energy business segment include $16.3 million from DPL's termination of its membership in NEIL, as discussed in Note 3 to the Consolidated Financial Statements. The "Earnings Before Interest and Taxes" of "All Other" business segments include the equity in earnings of the EnerTech funds and other investment income, which are discussed in Note 4 to the Consolidated Financial Statements.
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2001 MARCH 31, 2000 --------------------------------- -------------------------------------- EARNINGS EARNINGS BEFORE INTEREST BEFORE INTEREST BUSINESS SEGMENTS REVENUES AND TAXES REVENUES AND TAXES - ----------------- -------- --------------- -------- --------------- (Dollars in Thousands) Energy $1,573,489 $65,710 $950,295 $64,973 Power Delivery 196,241 69,799 188,060 63,262 Telecommunications 14,792 (7,208) 12,563 (13,577) HVAC -- -- 31,863 (3,506) All Other 2,617 (2,880) 2,640 (344) ---------- --------- ---------- -------- Total $1,787,139 (1) $ 125,421(2) $1,185,421 (3) $110,808 (4) ========== ========= ========== ========
(1) Includes intercompany revenues, which are eliminated in consolidation as follows: Energy business segment--$231,238; Telecommunications business segment--$1,064; All Other business segments--$188. (2) "Earnings before interest and taxes" less $51,325 of interest expense and preferred stock dividends and $505 of consolidation adjustments equals consolidated income before income taxes. (3) Includes intercompany revenues, which are eliminated in consolidation as follows: Energy business segment--$137,654; Telecommunications business segment--$1,026; All Other business segments--$1,396. (4) "Earnings before interest and taxes" less $53,555 of interest expense and preferred stock dividends and $505 of consolidation adjustments equals consolidated income before income taxes. NOTE 13. SUBSEQUENT EVENT, MANDATORY REDEMPTION OF PREFERRED STOCK On May 1, 2001, ACE redeemed 115,000 shares of its $7.80 annual dividend rate preferred stock, which has mandatory redemption provisions, at the $100 per share stated value or $11.5 million in total. -14- 17 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act) provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been made in this report. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "intend," "will," "anticipate," "estimate," "expect," "believe," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: the effects of deregulation of energy supply and the unbundling of delivery services; the ability to enter into purchased power agreements on acceptable terms; market demand and prices for energy, capacity, and fuel; weather variations affecting energy usage; operating performance of power plants; an increasingly competitive marketplace; results of any asset sales; sales retention and growth; federal and state regulatory actions; future litigation results; costs of construction; operating restrictions; increased costs and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; and credit market concerns. Conectiv undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing list of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made prior to the effective date of the Litigation Reform Act. COMMON STOCK EARNINGS SUMMARY Earnings applicable to common stock were $39.9 million, or $0.48 per share of common stock (82,704,000 average shares outstanding) for the first quarter of 2001, compared to $35.0 million, or $0.41 per share of common stock (85,568,000 average shares outstanding) for the first quarter of 2000. A summary of common stock earnings is shown in the table below. AFTER-TAX CONTRIBUTION TO EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Three Months Ended March 31, ----------------------- 2001 2000 ---------- ---------- (1) Telecommunications (CCI) $(0.08) $(0.12) (2) HVAC (CSI) -- (0.03) (3) Investment Income -- 0.01 (4) Energy, Power Delivery, and Other 0.56 0.55 --------- ------- $0.48 $0.41 ========= =======
-15- 18 (1) Telecommunications (CCI) As a competitive local exchange carrier (CLEC) providing local, regional, and long distance telephone and internet services, CCI operates in a highly competitive industry. CCI's business competitors include Verizon, which as the incumbent local exchange carrier has inherent competitive advantages, and other CLECs. Market conditions, which have continued to decline over the past year, have resulted in very low CLEC gross margins and in difficulties for many CLECs in arranging any external financing. CCI's operating results have reflected these business conditions. Despite this, the loss per share of common stock which resulted from CCI's operations decreased to $0.08 for the first quarter of 2001 from $0.12 for the first quarter of 2000. The improvement in CCI's operating results was primarily due to a $4.6 million decrease in operating expenses for the first quarter of 2001, compared to the first quarter of 2000. Operating expenses decreased mainly due to a reduction in the number of employees. As previously disclosed, Conectiv initiated a process in 2000 to identify a strategic partner for CCI. Conectiv's management is currently considering various potential alternatives for this business, including sale in whole or in part. This process has been made more difficult by market conditions in this business sector, and, while alternatives are considered, CCI has focused on reducing its operating expenses and capital outlays. Conectiv's investment in CCI was approximately $190 million as of March 31, 2001. (2) HVAC (CSI) As discussed in Note 6 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K, Conectiv sold the HVAC businesses of CSI during mid- to late-2000. (3) Investment Income Conectiv's investment income was not significant for the three months ended March 31, 2001 and was $0.8 million after income taxes ($0.01 per share of common stock) for the three months ended March 31, 2000. During the first quarter of 2001, Conectiv received a distribution from the EnerTech funds of 990,838 shares of Capstone Turbine Corporation (Capstone). Capstone develops, designs, assembles, and sells micro-turbines worldwide in the distributed power generation market and hybrid electric vehicle market. Primarily due to the distribution of the Capstone shares, the carrying amount of Conectiv's investment in the EnerTech funds decreased to $14.2 million as of March 31, 2001, from $38.6 million as of December 31, 2000. Conectiv's investment in the Capstone shares had a $28.1 million carrying amount as of March 31, 2001 on the Consolidated Balance Sheet. (4) Energy, Power Delivery, and Other As shown in the preceding table, the contribution to earnings per share of common stock outstanding by "Energy, Power Delivery, and Other" was $0.56 for the first quarter of 2001 compared to $0.55 for the first quarter of 2000. As discussed in Note 3 to the Consolidated Financial Statements, on February 19, 2001, DPL elected to terminate its membership in NEIL (a nuclear industry mutual insurance company) and received $16.3 million for its member account balance. As a result of DPL's NEIL membership termination, the Energy business segment's operation and maintenance expenses -16- 19 for the three months ended March 31, 2001 include a $16.3 million pre-tax credit ($9.8 million after-taxes, or $0.12 per share of common stock). Excluding the earnings that resulted from DPL's termination of its NEIL membership, the contribution to earnings per share of common stock from "Energy, Power Delivery, and Other" decreased by $0.11 in the first quarter of 2001. This decrease primarily resulted from higher average energy costs for supplying electricity to DPL's default service customers and gas trading losses, partly offset by increased profits from strategic electric generation activities, which benefited from higher energy prices, and gains on coal and oil trading. Conectiv's participation in energy markets results in exposure to commodity market risk. Conectiv has controls in place that are intended to keep risk exposures within certain management-approved risk tolerance levels. For additional information concerning commodity market risk, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk," included herein. DIVIDENDS ON COMMON STOCK Conectiv's Board of Directors declared quarterly dividends per share of common stock of $0.22 for the first quarter of 2001, which represented approximately 46% of earnings per share of common stock. For additional information concerning dividends on common stock, see "Dividends on Common Stock" on page II-10 in Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), included in Item 7 of Part II of Conectiv's 2000 Annual Report on Form 10-K. CLASS A COMMON STOCK EARNINGS SUMMARY As provided in Conectiv's Restated Certificate of Incorporation, Class A common stock has an interest in earnings of the Atlantic Utility Group (AUG) in excess of a notional fixed charge of $40 million per year. The AUG includes the assets and liabilities of the electric generation, transmission, and distribution businesses of ACE which existed on August 9, 1996 and were regulated by the NJBPU. Accordingly, the AUG includes the earnings of the power plants which were transferred on July 1, 2000, from ACE to Conectiv Atlantic Generation, LLC (CAG). For any reporting period, if the AUG earns less than the pro-rata portion of the annual fixed notional charge, a loss will be applicable to Class A common stock. For additional information concerning the computation of earnings applicable to Class A common stock and other general information concerning Class A common stock, including information about dividend payments, conversion and redemption provisions, and allocation of consideration in a subsequent merger, refer to Note 19 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. For the first quarter of 2001, earnings applicable to Class A common stock were $0.9 million, or $0.16 per share of Class A common stock. In comparison, the net income of the AUG for the first quarter of 2000 was less than the $10.0 million notional charge, which resulted in a $2.5 million loss applicable to Class A common stock, or a loss of $0.43 per share of Class A common stock. The increase in earnings per share of Class A common stock was mainly due to improved operating results for deregulated electric generating units and higher volumes of electricity sold and delivered, reflecting the positive effect of colder winter weather on sales of electricity to customers using electric heating systems. Although ACE experienced higher average energy costs in serving its Basic Generation Service (BGS) customers, additional revenues were recognized based on the regulated cost-based, rate-recovery mechanism that exists for BGS, as discussed in Notes 1 and 10 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K. -17- 20 DIVIDENDS ON CLASS A COMMON STOCK For the three months ended March 31, 2001, dividends declared per share of Class A common stock were $0.80 compared to earnings per share of Class A common stock of $0.16. During the three-year period ended March 31, 2001, or the "Initial Period," the quarterly dividend on shares of Class A common stock was $0.80. As disclosed at the time DPL and ACE became wholly owned subsidiaries of Conectiv (1998 Merger), Conectiv intends, following the Initial Period, subject to declaration by Conectiv's Board of Directors and the obligation of the Board of Directors to consider the financial condition and regulatory environment of Conectiv and the results of its operations, to pay annual dividends on the Class A common stock at a rate equal to 90% of annualized earnings of the Class A common stock (taking into account the notional fixed charge of $40 million per year in accordance with Conectiv's Restated Certificate of Incorporation). Notwithstanding Conectiv's intention with respect to dividends on the Class A common stock following the Initial Period, to the extent that the annual dividends paid on the Class A common stock during the Initial Period exceed the earnings that were applicable to the Class A common stock during the Initial Period, Conectiv's Board of Directors may consider such fact in determining the appropriate annual dividend rate on the Class A common stock following the Initial Period. As previously reported, during the Initial Period, the earnings applicable to Class A common stock were substantially less than the dividends on the Class A common stock. Management expects Conectiv's Board of Directors to determine the new quarterly dividend per share of Class A common stock in June 2001. For additional information concerning dividends on Class A common stock, see "Dividends on Class A Common Stock" on page II-12 of the MD&A included in Item 7 of Part II of Conectiv's 2000 Annual Report on Form 10-K. MID-MERIT ELECTRIC GENERATION The following discussion updates the "Mid-Merit Electric Generation" disclosure, which begins on page II-15 in the MD&A included in Item 7 of Part II of Conectiv's 2000 Annual Report on Form 10-K. Conectiv is increasing its mid-merit electric generating capacity by building combined cycle units, which are constructed with combustion turbines, waste heat recovery boilers and a steam turbine. In 2000, Conectiv ordered 21 combustion turbine units, which, with additional equipment, could be configured into 8 combined cycle plants. Each combined cycle plant would have approximately 550 megawatts (MW) of capacity, allowing Conectiv to add up to 4,400 MW of electric generating capacity, representing a potential total investment of about $2.6 billion. Under an accelerated schedule, construction would occur in phases and would be completed by the end of 2004, with delivery of the combustion turbines occurring in phases through 2003. Conectiv is actively working on developing sites for combined cycle plants within the region of the PJM Interconnection, L.L.C. (PJM) and, as discussed below, is currently constructing a new plant at the Hay Road site. Three new combustion turbines, which are currently being installed at the Hay Road site, are expected to be operational during the summer of 2001 (adding 330 MW of capacity). The waste heat recovery boiler and steam turbine needed for the new combined cycle operation at Hay Road are expected to be completed by the third quarter of 2002 (resulting in 550 MW of total capacity for the combined cycle plant). The number of combined cycle plants ultimately built under Conectiv's mid-merit construction program and the timing of construction will depend on various factors including the following: growth in demand for electricity; construction of generating units by competitors; fuel prices; availability of suitable financing; possible construction delays; and the timing and ability to obtain required permits and licenses. -18- 21 The construction program could also potentially be affected by the planned acquisition of Conectiv by Pepco. As of April 24, 2001, Conectiv's Board of Directors has authorized cumulative expenditures of approximately $860 million for new mid-merit construction, including (i) $650 million of expenditures expected to be required to complete construction of 2 combined cycle plants (utilizing a total of 6 combustion turbines) at Hay Road and another site, and (ii) $210 million of expenditures related to building up to 6 additional combined cycle plants, including payments on the 15 combustion turbines (total commitment of $466 million), other equipment, and sites necessary for construction of these 6 combined cycle plants. Management expects to fund these and all other future capital requirements from internally generated funds, leasing, external financings (including securitization of stranded costs), and proceeds from the sales of electric generating units. Should Conectiv choose not to build all 8 combined cycle plants, then Conectiv would attempt to sell its related investment in such combustion turbines, other equipment and site development. The ability to find a buyer and the amount of the proceeds from such a sale would be determined by market conditions. The current market for combustion turbines is strong due to demand for such units in the region served by the PJM and other regions throughout the United States. The units would be portable to other markets. Through March 31, 2001, Conectiv had invested approximately $71 million in the 15 combustion turbines, other equipment, and sites needed to build up to 6 combined cycle plants in addition to the 2 combined cycle plants for which full funding has been approved. NEW JERSEY ELECTRIC UTILITY INDUSTRY RESTRUCTURING As previously disclosed, the NJBPU issued a Summary Order to ACE in July 1999 concerning restructuring ACE's electricity supply business and indicated that a more detailed order would be issued at a later time. The Final Decision and Order of the NJBPU, dated March 30, 2001, for ACE was publicly posted on the NJBPU's website in mid-May 2001. The Final Decision and Order supersedes a Summary Order issued on July 15, 1999, which was the subject of a Form 8-K filing made by Conectiv and ACE on July 15, 1999. The Final Decision and Order and the 1999 Summary Order were issued in conjunction with a June 9, 1999 settlement in the NJBPU's restructuring proceeding relating to ACE's stranded costs, unbundled rates, and other provisions relevant to establishing competitive retail electric supply markets within ACE's franchised service area in southern New Jersey. After an initial review, management believes that the substantive provisions of the Final Decision and Order largely track the substantive provisions of the Summary Order filed with and discussed in Conectiv's and ACE's July 15, 1999 Form 8-K filings. Differences between the Summary Order and the Final Decision and Order that have been identified, in management's view, are not material and include: 1) establishing August 1, 2002, as the date for submission of a filing regarding the level of all unbundled rate components proposed to be applicable on and after August 1, 2003; 2) with respect to deferred costs to be recovered in future rates, establishing an interest rate to be applied to the deferred balances that is tied to 7-year Treasury constant maturities rather than tied to intermediate-term maturities actually issued by Conectiv or ACE; 3) finding that such deferred balances and interest are recoverable over a "reasonable period of time" to be determined by the NJBPU rather than the four-year period explicitly set forth in the Summary Order; and 4) striking a provision in the settlement that identified a statutory right for ACE to make an early filing for rate modifications under certain specified conditions. -19- 22 ELECTRIC REVENUES
Three Months Ended March 31, --------------------- 2001 2000 ------- ------- (Dollars in millions) Regulated electric revenues $485.3 $461.9 Non-regulated electric revenues 281.6 168.4 ------- ------- Total electric revenues $766.9 $630.3 ======= =======
The table above shows the amounts of electric revenues earned that are subject to price regulation (regulated) and that are not subject to price regulation (non-regulated). "Regulated electric revenues" include revenues for delivery (transmission and distribution) service and electricity supply service within the service areas of DPL and ACE. REGULATED ELECTRIC REVENUES "Regulated electric revenues" increased by $23.4 million to $485.3 million for the first quarter of 2001, from $461.9 million for the first quarter of 2000. The increase was primarily due to higher sales to electric space-heating customers, due to colder winter weather, and additional revenues recognized under the regulated cost-based, rate-recovery mechanism that exists for BGS. Other variances in "regulated electric revenues" include an increase in revenues due to sales during the first quarter of 2001 to customers who previously purchased electricity from alternative suppliers and a decrease in revenues due to rate reductions related to electric utility industry restructuring. Although "regulated electric revenues" increased by $23.4 million for the first quarter of 2001, the gross margin (revenues less related energy and capacity costs) from "regulated electric revenues" decreased by approximately $35.2 million mainly due to higher average energy costs incurred in supplying the default service customers of DPL. NON-REGULATED ELECTRIC REVENUES "Non-regulated electric revenues" result primarily from electricity trading activities, strategic generation, (the sale of electricity, capacity and ancillary services from deregulated electric generating plants), and competitive retail sales. Conectiv began exiting its competitive retail energy business in late-2000, which has caused revenues from this activity to decrease. For the first quarter of 2001, the composition of "non-regulated electric revenues" was approximately 50% electricity trading, 45% strategic generation and 5% competitive retail sales. "Non-regulated electric revenues" increased by $113.2 million, to $281.6 million for the first quarter of 2001 from $168.4 million for the first quarter of 2000. The revenue increase reflects higher strategic generation sales, increased volumes of electricity traded, and higher selling/trading prices, partly offset by lower competitive retail energy sales. Strategic generation sales increased primarily because some of the output of the deregulated power plants was used in the first quarter of 2000 to supply the default service customers of DPL. The gross margin earned from "non-regulated electric revenues" increased by approximately $17.3 million for the first quarter of 2001, reflecting higher volumes and selling prices. -20- 23 GAS REVENUES
Three Months Ended March 31, ---------------------- 2001 2000 ------- ------- (Dollars in millions) Regulated gas revenues $72.1 $44.9 Non-regulated gas revenues 566.0 229.6 ------ ------ Total gas revenues $638.1 $274.5 ====== ======
DPL earns gas revenues from on-system natural gas sales, which generally are subject to price regulation, and from the transportation of natural gas for customers. Conectiv subsidiaries also trade and sell natural gas in transactions that are not subject to price regulation. The table above shows the amounts of gas revenues earned from sources that were subject to price regulation (regulated) and that were not subject to price regulation (non-regulated). "Regulated gas revenues" increased by $27.2 million to $72.1 million for the first quarter of 2001, from $44.9 million for the first quarter of 2000. The $27.2 million revenue increase was primarily due to higher rates charged under the gas rate clause to recover higher costs of purchased natural gas. DPL's gross margin (gas revenues less gas purchased) from supplying regulated gas customers is insignificant, so earnings were not affected by the additional revenues from the rate increase under the gas rate clause. "Regulated gas revenues" also include an increase for higher volumes of gas delivered to customers, reflecting colder winter weather, which resulted in a $2.5 million increase in the gross margin earned for gas delivery. "Non-regulated gas revenues" increased by $336.4 million, to $566.0 million for the first quarter of 2001 from $229.6 million for the first quarter of 2000. This revenue increase was primarily due to higher selling prices of natural gas traded. Although "non-regulated gas revenues" increased, the gross margin earned from "non-regulated gas revenues" decreased by approximately $16.6 million, mainly due to a loss on gas trading activities in the first quarter of 2001. OTHER SERVICES REVENUES Other services revenues were comprised of the following:
Three Months Ended March 31, ---------------------- 2001 2000 -------- -------- (Dollars in millions) Petroleum sales and trading $93.6 $71.4 HVAC -- 31.9 Telecommunications 14.8 12.6 Operation of power plants 15.5 9.3 Thermal systems 8.7 6.1 All other 17.1 9.3 ------ ------ Total $149.7 $140.6 ====== ======
-21- 24 "Other services" revenues increased $9.1 million to $149.7 million for the first quarter of 2001, from $140.6 million for the first quarter of 2000. The most significant variances contributing to the $9.1 million revenue increase were the following: (i) a $22.2 million increase in petroleum sales and trading revenues that resulted from higher prices and sales volume; (ii) a $6.2 million increase due to more contracts for the operation of power plants for third-parties; (iii) a $7.8 million increase in "All other" revenues, mainly due to an unrealized gain on trading coal; and (iv) a $31.9 million decrease in HVAC revenues due to the sale of these businesses in mid- to late-2000. The gross margin from "other services" revenues (revenues less costs of sales) increased by $7.4 million in the first quarter of 2001 primarily due to the unrealized gain on trading coal. OPERATING EXPENSES Electric Fuel and Purchased Energy and Capacity "Electric fuel and purchased energy and capacity" increased by $154.4 million to $485.7 million for the first quarter of 2001, from $331.3 million for the first quarter of 2000. This increase was primarily due to more purchased power for expanded electricity trading activities and for electricity supplied to the default service customers of DPL. The sale of the interests of DPL in nuclear electric generating plants in December 2000 and dedication of the output of strategic generation plants to non-regulated market sales in the first quarter of 2001 caused DPL to purchase more power to serve default service customers. On April 11, 2001, ACE entered into a purchased power agreement with an affiliate of NRG Energy, Inc. (NRG), the party with which ACE has an agreement for the sale of certain of its fossil fuel-fired electric generating plants. The purchased power agreement provides for ACE to begin purchasing 400 megawatts of capacity and energy over a period that begins when the sale of certain of ACE's electric generating plants to NRG is completed and ends on August 31, 2002. Gas Purchased Gas purchased increased by $377.8 million to $629.4 million for the first quarter of 2001, from $251.6 million for the first quarter of 2000. This increase was mainly due to higher prices paid for non-regulated natural gas purchased for trading activities. The increase also reflects higher costs for supplying natural gas to customers in DPL's regulated service area, due to higher prices paid for natural gas and a larger volume of natural gas purchased. Other Services' Cost of Sales Other service's cost of sales increased $1.7 million in the first quarter of 2001. Cost increases due to a higher volume of petroleum purchased at higher prices and more power plant operating services provided were largely offset by a decrease from the sale of the HVAC business and other decreases. Operation and Maintenance Expenses Operation and maintenance expenses decreased by $44.2 million to $112.7 million for the first quarter of 2001, from $156.9 million for the first quarter of 2000. This decrease was due to proceeds ($16.3 million) received by DPL for termination of its membership in NEIL, the sale of the interests of DPL in nuclear electric generating plants, the sale of HVAC businesses, and staffing reductions in the telecommunications business. -22- 25 Depreciation and amortization Depreciation and amortization expenses decreased $1.5 million for the first quarter of 2001 primarily due to expiration of the amortization of a regulatory asset, which was largely offset by higher depreciation expense for improvements to the electric transmission and distribution systems. OTHER INCOME Other income decreased $9.6 million in the first quarter of 2001 mainly due to prior year earnings from a non-utility generation joint venture, a prior year gain on the sale of an investment in a leveraged lease, prior year earnings from jointly-owned projects of Conectiv Thermal Systems, Inc. which were sold, lower investment income, and other miscellaneous decreases. INTEREST EXPENSE Interest expense, net of capitalized amounts, decreased $4.4 million for the first quarter of 2001, primarily due to more interest expense capitalized as a result of higher levels of construction work-in-progress associated with mid-merit electric generation plants. INCOME TAXES Income tax expense increased $8.6 million primarily due to higher pre-tax income in the first quarter of 2001. LIQUIDITY AND CAPITAL RESOURCES Due to $45.1 million of cash provided by operating activities, $127.0 million of cash used by investing activities, and $2.6 million of cash provided by financing activities, cash and cash equivalents decreased by $79.3 million during the first quarter of 2001. Net cash flows from operating activities decreased by $103.8 million to $45.1 million for the first quarter of 2001, from $148.9 million for the first quarter of 2000. The $103.8 million decrease was mainly due to lower income tax refunds received and increased working capital requirements associated with gas trading activities. Primarily due to a higher level of gas trading activities, the balances of accounts receivable and accounts payable increased by $190.1 million and $140.3 million, respectively, from December 31, 2000 to March 31, 2001. Capital expenditures of $122.6 million for the first quarter of 2001 included $84.3 million for the capital requirements of Conectiv's mid-merit electric generation strategy, which were mainly payments for combustion turbines. The remainder of the capital expenditures for the first quarter of 2001 were primarily for the electric transmission and distribution systems of ACE and DPL. Capital expenditures increased by $59.2 million for the first quarter of 2001 compared to the first quarter of 2000, mainly due to increased capital requirements for mid-merit electric generation, partly offset by lower expenditures for CCI's telecommunications business. As discussed in Note 4 to the Consolidated Financial Statements, during the first quarter of 2001, Conectiv received a distribution from the EnerTech funds of 990,838 shares of Capstone. This non-cash investing activity is excluded from the Consolidated Statement of Cash Flows for the three months ended March 31, 2001. The carrying amounts of Conectiv's investment in the Capstone shares was $28.1 million as of March 31, 2001 and is included in "Other Investments" on the Consolidated Balance Sheet. -23- 26 Conectiv's financing activities for the first quarter of 2001 included the payment of $22.8 million of common dividends and $29.0 million of net cash provided from an increase in short-term debt. As of March 31, 2001, Conectiv (the holding company) had a $300 million credit agreement with a five-year term that expires in February 2003 and a $730 million credit agreement, which was renewed on April 5, 2001 for an additional year and increased to $735 million. Conectiv's credit agreements require a ratio of total indebtedness to total capitalization of 70% or less and the ratio was 64% as of March 31, 2001, computed in accordance with the terms of the credit agreements. On February 12, 2001, DPL reduced the commitments under its revolving credit facility, which expires January 31, 2003, from $150 million to $105 million; this credit facility provides liquidity for DPL's $104.8 million of Variable Rate Demand Bonds and also may be used for general corporate purposes. Conectiv's capital structure including short-term debt and current maturities of long-term debt, expressed as a percentage of total capitalization, is shown below.
March 31, December 31, 2001 2000 --------------- -------------- Common stockholders' equity 26.1% 26.2% Preferred stock of subsidiaries 6.4% 6.4% Long-term debt and variable rate demand bonds 48.7% 49.2% Short-term debt and current maturities of long-term debt 18.8% 18.2%
On May 1, 2001, ACE redeemed 115,000 shares of its $7.80 annual dividend rate preferred stock, which has mandatory redemption provisions, at the $100 per share stated value or $11.5 million in total. Conectiv's ratio of earnings to fixed charges under the SEC Method is shown below. See Exhibit 12, Ratio of Earnings to Fixed Charges, for additional information.
12 Months Ended Year Ended December 31, March 31, --------------------------------------- 2001 2000 1999 1998 1997 1996 -------------- -------- ---- ---- ---- ----- Ratio of Earnings to Fixed Charges 2.20 2.13 1.98 2.38 2.63 2.83 (SEC Method)
-24- 27 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As previously disclosed under "Quantitative and Qualitative Disclosures About Market Risk" on pages II-26 to II-27 of Conectiv's 2000 Annual Report on Form 10-K, Conectiv is subject to market risks, including interest rate risk, equity price risk, and commodity price risk. An update appears below. INTEREST RATE RISK Conectiv is subject to the risk of fluctuating interest rates in the normal course of business. Conectiv manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term and variable rate debt was approximately $5.2 million as of March 31, 2001 and $6.1 million as of December 31, 2000. The decrease in the effect of a 10% change in interest rates was mainly due to lower short-term interest rates. EQUITY PRICE RISK As discussed in Note 4 to the Consolidated Financial Statements included herein and Note 8 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv's 2000 Annual Report on Form 10-K, Conectiv holds investments in venture capital funds, which invest in securities of energy-related technology and Internet service companies, and in marketable securities. Conectiv is exposed to equity price risk through the securities held by the venture capital funds and the marketable securities held directly by Conectiv. The potential change in the fair value of these investments resulting from a hypothetical 10% change in quoted securities prices was approximately $4.4 million as of March 31, 2001 compared to $4.0 million as of December 31, 2000. Due to the nature of these investments and market conditions, the fair value of these instruments may change by substantially more than 10%. COMMODITY PRICE RISK Conectiv's participation in wholesale energy markets includes trading and arbitrage activities, which expose Conectiv to commodity market risk. To the extent Conectiv has net open positions, controls are in place that are intended to keep risk exposures within management-approved risk tolerance levels. Conectiv engages in commodity hedging activities to minimize the risk of market fluctuations associated with the purchase and sale of energy commodities (natural gas, petroleum and electricity). Some of Conectiv's hedging activities are conducted using derivative instruments designated as "cash flow hedges," which are designed to hedge the variability in cash flows of forecasted transactions. Conectiv also hedges by backing physical transactions with offsetting physical positions. Conectiv's energy commodity hedging objectives, in accordance with its risk management policy, are primarily the assurance of stable and known cash flows and the fixing of favorable prices and margins when they become available. Conectiv uses a value-at-risk model to assess the market risk of its electricity, gas, and petroleum products commodity activities. The model includes fixed price sales commitments, physical forward contracts, and commodity derivative instruments. Value-at-risk represents the potential gain or loss on instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Conectiv estimates value-at-risk across its power, gas, and petroleum commodity businesses using a delta-normal variance/covariance model with a 95 percent confidence level and assuming a five-day holding period. Conectiv's calculated value-at-risk with respect to its commodity price exposure associated with contractual arrangements was approximately $23.1 million as of March 31, 2001, in comparison to $16.9 million as of December 31, 2000. The increase in value-at-risk was primarily due to an increased level of gas trading activities. The average, high and low value-at-risk for the quarter ended March 31, 2001 was $26.0 million, $39.2 million, and $19.9 million, respectively. -25- 28 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Information reported under the heading "Other" in Note 10 to the Consolidated Financial Statements under Item 1 in Part I herein, concerning an action filed in a New Jersey Superior Court by the City of Vineland, is incorporated by reference. ITEM 5. OTHER INFORMATION As previously disclosed, the Board of Directors set July 17, 2001 as the date for the 2001 Annual Meeting of Stockholders. Also as previously disclosed, any stockholder who wishes to present a proposal from the floor to be considered at the Annual Meeting must submit that proposal in writing to Conectiv, to be received at its principal executive offices no later than May 18, 2001. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit Number 10-A Purchase and Sale Agreement By and Between Delmarva Power & Light Company and NRG Energy Inc. (wholly owned electric generating plants), (incorporated by reference from Exhibit 10-A to the 2000 Annual Report on Form 10-K for Delmarva Power & Light Company) 10-B Purchase and Sale Agreement By and Between Delmarva Power & Light Company and NRG Energy Inc. (jointly owned electric generating plants), (incorporated by reference from Exhibit 10-B to the 2000 Annual Report on Form 10-K for Delmarva Power & Light Company) 10-C Purchase and Sale Agreement By and Between Atlantic City Electric Company and NRG Energy Inc. (wholly owned electric generating plants), (incorporated by reference from Exhibit 10-B to the 2000 Annual Report on Form 10-K for Atlantic City Electric Company) 10-D Purchase and Sale Agreement By and Between Atlantic City Electric Company and NRG Energy Inc. (jointly owned electric generating plants), (incorporated by reference from Exhibit 10-C to the 2000 Annual Report on Form 10-K for Atlantic City Electric Company) 12 Ratio of Earnings to Fixed Charges (filed herewith) 99 New Jersey Board of Public Utilities, Final Decision and Order, dated March 30, 2001 (filed herewith) -26- 29 (b) Reports on Form 8-K The following Current Reports on Form 8-K were filed during the first quarter of 2001: On January 8, 2001, Conectiv filed a Current Report on Form 8-K dated December 29, 2000 reporting on Item 5, Other Events, and Item 7, Financial Statements and Exhibits. On February 13, 2001, Conectiv filed a Current Report on Form 8-K dated February 13, 2001 reporting on Item 5, Other Events, and Item 7, Financial Statements and Exhibits. On March 2, 2001, Conectiv filed a Current Report on Form 8-K dated March 2, 2001 reporting on Item 5, Other Events. -27- 30 SIGNATURE 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. Conectiv ------------ (Registrant) Date: May 10, 2001 /s/ John C. van Roden ------------ --------------------------------------------- John C. van Roden, Senior Vice President and Chief Financial Officer -28- 31 EXHIBIT INDEX Exhibit 12, Ratio of Earnings to Fixed Charges Exhibit 99, New Jersey Board of Public Utilities, Final Decision and Order, dated March 30, 2001 EX-12 2 w48793ex12.txt RATIO OF EARNINGS TO FIXED CHARGES 1 Exhibit 12 Conectiv Ratio of Earnings to Fixed Charges (Dollars in Thousands)
12 Months Ended Year Ended December 31, March 31, --------------------------------------------------------------------- 2001 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- --------- Income before extraordinary item $ 179,097 $ 170,830 $ 113,578 $ 153,201 $ 101,218 $ 107,251 --------- --------- --------- --------- --------- --------- Income taxes 142,090 133,514 105,816 105,817 72,155 78,340 --------- --------- --------- --------- --------- --------- Fixed charges: Interest on long-term debt including amortization of discount, premium and expense 163,099 166,256 149,732 133,796 78,350 69,329 Other interest 63,382 60,818 37,743 26,199 12,835 12,516 Preferred dividend require- ments of subsidiaries 20,493 20,383 19,894 17,871 10,178 10,326 --------- --------- --------- --------- --------- --------- Total fixed charges 246,974 247,457 207,369 177,866 101,363 92,171 --------- --------- --------- --------- --------- --------- Nonutility capitalized interest (12,717) (9,278) (3,264) (1,444) (208) (311) --------- --------- --------- --------- --------- --------- Undistributed earnings of equity method investees -- (4,496) -- -- -- -- --------- --------- --------- --------- --------- --------- Earnings before extraordinary item, income taxes, and fixed charges $ 555,444 $ 538,027 $ 423,499 $ 435,440 $ 274,528 $ 277,451 ========= ========= ========= ========= ========= ========= Total fixed charges shown above $ 246,974 $ 247,457 $ 207,369 $ 177,866 $ 101,363 $ 92,171 Increase preferred stock dividend requirements of subsidiaries to a pre-tax amount 5,776 5,531 6,123 4,901 3,065 6,025 --------- --------- --------- --------- --------- --------- Fixed charges for ratio computation $ 252,750 $ 252,988 $ 213,492 $ 182,767 $ 104,428 $ 98,196 ========= ========= ========= ========= ========= ========= Ratio of earnings to fixed charges 2.20 2.13 1.98 2.38 2.63 2.83
For purposes of computing the ratio, earnings are income before extraordinary item plus income taxes and fixed charges, less nonutility capitalized interest and undistributed earnings of equity method investees. Fixed charges include gross interest expense, the estimated interest component of rentals, and preferred stock dividend requirements of subsidiaries. Preferred stock dividend requirements for purposes of computing the ratio have been increased to an amount representing the pre-tax earnings which would be required to cover such dividend requirements. EX-99 3 w48793ex99.txt N.J. BOARD OF PUBLIC UTILITIES, FINAL DECISION 1 EXHIBIT 99 Agenda Date: 7/15/99 [STATE OF NEW JERSEY LOGO] STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES TWO GATEWAY CENTER Newark, NJ 07102 ENERGY - ----------------------------------- ------ IN THE MATTER OF ATLANTIC CITY ELECTRIC COMPANY - RATE FINAL DECISION AND ORDER UNBUNDLING, STRANDED COST AND ------------------------ RESTRUCTURING FILINGS BPU DOCKET NOS. EO97070455, - ----------------------------------- EO97070456 and EO97070457
(SERVICE LIST ATTACHED) BY THE BOARD: This Decision and Order memorializes and provides the reasoning for the action taken by the Board of Public Utilities ("Board' or "BPU") in these matters, by a vote of three Commissioners, at its July 15, 1999 public agenda meeting, which action was summarized in our Summary Order dated July 15, 1999. This Final Decision and Order supersedes the Board's July 15, 1999 Summary Order. 2 TABLE OF CONTENTS
Page No. ------- I. BACKGROUND AND PROCEDURAL HISTORY........................................................................2 --------------------------------- II. INITIAL DECISION.........................................................................................8 ---------------- A. Stranded Costs.....................................................................................8 B. Rate Reductions...................................................................................12 C. Rate Unbundling...................................................................................13 III. EXCEPTIONS AND REPLY EXCEPTIONS.........................................................................14 ------------------------------- A. Exceptions........................................................................................14 1. ACE......................................................................................14 2. Ratepayer Advocate.......................................................................17 3. BPU Staff................................................................................21 4. Independent Energy Producers of New Jersey...............................................23 5. New Jersey Public Interest Intervenors...................................................23 6. New Jersey Industrial Customer Group and New Jersey Business Users (Joint Filing).................................................24 B. Reply Exceptions..................................................................................28 1. ACE......................................................................................28 2. Ratepayer Advocate.......................................................................32 IV. RESTRUCTURING PROCEEDING................................................................................36 ------------------------ A. Basic Generation Service..........................................................................36 B. Horizontal Market Power...........................................................................38
BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 i 3
Page No. ------- V. SETTLEMENT PROPOSALS....................................................................................39 -------------------- A. Stipulation Filed by ACE and Other Parties....................................................39 B. Stipulation Filed by RPA and Other Parties.....................................................48 VI. COMMENTS ON THE SETTLEMENT PROPOSALS....................................................................55 ------------------------------------ A. Comments on Stipulations.......................................................................55 1. ACE...................................................................................55 2. Ratepayer Advocate....................................................................58 3. Enron.................................................................................65 4. Independent Energy Producers of New Jersey............................................66 5. Mid-Atlantic Power Supply Association.................................................66 6. New Jersey Commercial Users...........................................................67 7. New Jersey Industrial Customer Group..................................................68 VII. DISCUSSION AND FINDINGS.................................................................................69 -----------------------
BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 ii 4 Agenda Date: 7/15/99 I. BACKGROUND AND PROCEDURAL HISTORY The New Jersey Energy Master Plan Phase I Report ("Phase I Report") released in March 1995, presented a vision for the State in which energy markets in New Jersey would be guided by market-based principles and competition. The Phase I Report recognized that increased competition in New Jersey's energy markets could potentially help reduce the high energy prices existing in the State, further the State's economic development goals, and provide an opportunity to streamline the regulatory review process. The Phase I Report provided a policy framework for the transition from energy industry monopolies to competitive markets. The Phase I Report also made several policy recommendations to be implemented as short term or interim measures to address immediate competitive pressures in the State and to prepare for the transition to competition. These included the adoption of legislation allowing rate flexibility and alternative regulation to enable New Jersey's electric utilities to compete to retain certain "at risk" customers and attract new customers, while stimulating efficiency and innovation. The Phase I Report further recommended the adoption of significant consumer protection standards to ensure that captive ratepayers do not subsidize competitive activities and that all ratepayers benefit from the transition to competition. In addition to the recommendations for interim action, the Phase I Report also directed the BPU to investigate possible changes to the structure of the electric power industry in New Jersey as a longer term means of achieving lower costs of electricity in the State. In response to the identified need for interim measures, the Rate Flex and Alternative Regulation Act, N.J.S.A. 48:2-21.24 et seq. ("the Rate Flex Act"), was enacted in July 1995. The Legislature found that during a transitional phase aimed at achieving the long-term goal of lowering electric and natural gas costs to consumers, it might be necessary for the BPU to implement short-term measures to promote economic development and employment in the State, and to permit New Jersey utilities to compete for customers with competitive alternatives. The Rate Flex Act allowed the State's electric utilities to enter into off-tariff rate agreements with customers for a period of seven years and provided that electric or gas utilities could petition the BPU be regulated under alternatives to rate base/rate of return regulation. The Rate Flex Act further declared that it is the policy of the State to foster the production and delivery of electricity and natural gas in a manner that lowers costs and rates while improving the quality and choices of service for all energy consumers; to ensure that New Jersey remains economically competitive on a regional, national and international basis; and to enhance the economic vitality of the State by attracting and retaining business and creating and retaining jobs. The Legislature also found that competitive market forces can improve the quality and choices of energy services at lower costs, while promoting efficiency, reducing regulatory delay and fostering productivity and innovation. Consistent with the Phase I Report, and the Legislature's stated desire that increased competition in energy markets be explored as a long-term means to reduce the cost of electricity in New Jersey for all customers, the BPU, by Order dated June 1, 1995, initiated a Phase II proceeding under Docket No. EX94120585. The proceeding was intended to accomplish several goals. By investigating the long-term structure of the electric power industry in the State, it was hoped that an electric power industry policy could be developed to facilitate the emergence of a competitive marketplace to foster the production and delivery of electricity in a manner which would lower costs and rates and improve the quality and choices of service. In BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -2- 5 areas where effective competition developed, ongoing regulation in its present form might be unnecessary. A further goal was to facilitate the development of competition in areas where competitive services did not yet exist, but where increased competition could benefit consumers. Finally, the BPU recognized the need to continue to regulate the quality and price of energy supplies and services where effective competition does not exist and where consumers are best served by continued regulation. Thus, a proceeding was initiated by the BPU to investigate: the appropriateness and feasibility of electric power supply competition and electricity wheeling at the retail level; the actions necessary to establish a fully efficient, competitive wholesale marketplace for electric generation; the need for retail wheeling if an efficient, competitive wholesale electric power market is achieved; the need for divestiture of electric utility generation assets or alternatively, the unbundling and corporate separation of electric services; and the definition and equitable treatment of stranded investments. Consistent with State policy goals expressed in the Rate Flex Act, the BPU specifically directed that the proceeding investigate: the appropriate manner of continuing existing consumer and environmental protections in a restructured competitive market; ensuring universal, non-discriminatory access to service; guaranteeing the provision of a safe and adequate power supply and system reliability; and achieving the State's environmental and energy efficiency goals. The Board sought to obtain guidance and input on the many issues raised from the widest possible array of interests. The BPU solicited and received several rounds of written comments and testimony, conducted public and legislative-type hearings and, through its Staff, formed and facilitated informal working groups and a negotiating team to explore certain issues in more depth and to attempt to develop consensus positions, where possible. On January 16, 1997, the BPU released a draft report containing its proposed findings and recommendations in the Phase II proceeding ("Draft Report"). The BPU held public hearings to receive oral comments on its Draft Report in Newark on February 4, 1997, in Blackwood on February 5, 1997, and in Trenton on February 11, 1997. The BPU received written comments from 39 parties and heard testimony from 42 parties relative to the Draft Report. On April 30, 1997, after careful consideration of the input received regarding its Draft Report, the Board issued an Order Adopting and Releasing Final Report. The BPU's Final Report, entitled "Restructuring the Electric Power Industry in New Jersey: Findings and Recommendations" ("Final Report"), was submitted to the Governor and the Legislature for their consideration and contained the BPU's findings and recommendations concerning the future structure of the electric power industry in New Jersey, including the recommendation to offer electric consumers a choice of electric power suppliers, beginning in October 1998, to effectuate substantial economic benefits, in the form of lower electric bills and more service options to the State's residents and businesses. In the introductory letter presenting the Final Report to the Legislature, Governor and residents and business owners of the State, the BPU indicated its willingness to work with the Legislature and the public to develop legislation necessary to adopt appropriate consumer protection measures and to implement its policy findings and recommendations. In order to implement the recommended policies and prepare for the commencement of retail competition, the BPU, in its April 30, 1997 Order, directed each of the State's four investor owned BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -3- 6 electric utilities, Atlantic City Electric Company ("ACE" or "Company"), Jersey Central Power and Light Company, d/b/a GPU Energy ("GPU"), Public Service Electric and Gas Company ("PSE&G") and Rockland Electric Company ("RECO") to make three filings by July 15, 1997. These included a rate unbundling petition, a stranded costs petition and a restructuring plan. The BPU also recognized that there were a number of issues which needed to be addressed generically for all four electric utilities, including fair competition standards, affiliate relationship standards, a market power analysis, and the mechanics for the phase-in of customer choice. The BPU anticipated that these issues would be reviewed generically for all four electric utilities. By Order dated June 25, 1997, the BPU directed its Division of Audits, in cooperation with the Division of Energy, to initiate management audits on ACE, GPU, PSE&G and RECO, pursuant to N.J.S.A. 48:2-16.4, and to solicit the assistance of qualified consulting firms to perform said audits under the supervision of BPU Staff. The audits were to include, but not be limited to focused reviews of each utility's unbundling, stranded costs and restructuring filings. A Request for Proposals was issued on June 27, 1997, and after receipt and review of numerous proposals, the BPU selected the Barrington-Wellesley Group ("BWG" or "the Auditors") to perform an audit of ACE's unbundling, stranded costs and restructuring filings, under BPU Docket No. EA97060395. On July 11, 1997, the BPU issued an Order Establishing Procedures, wherein it determined to transmit each utility's rate unbundling and stranded costs filing to the Office of Administrative Law ("OAL") for hearings and Initial Decision, and to retain the restructuring plan filings for review and hearings, with the intention of issuing a Final Decision and Order in these matters before the anticipated start date of competition. On July 15, 1997, ACE filed verified petitions with the BPU setting forth its unbundling, stranded costs and restructuring proposals. The unbundling and stranded costs petitions, which were assigned BPU Dkt. Nos. EO97070455 and EO97070456, respectively, were transmitted to the OAL on July 22, 1997 as contested cases, and were assigned to Administrative Law Judge ("ALJ") William Gural. The restructuring petition, which was assigned BPU Dkt. No. EO97070457, was retained by the Board. On September 15, 1997, the BPU issued an Order on Motions to Intervene/Participate and for Pro Hoc Vice Admission, wherein it considered and ruled upon numerous motions for intervention, participation and pro hac vice admission in the restructuring proceedings retained by it. Motions to intervene in the ACE unbundling and stranded costs proceedings were considered at the OAL.(1) - ---------------------- (1) In addition to ACE, BPU Staff, and the Ratepayer Advocate, intervenor status was granted to: New Jersey Public Interest Intervenors ("NJPII"), Enron Capital and Trade Resources ("Enron"), New Jersey Business Users ("NJBUS"), Coalition for Fair Competition ("CFC"), Pennsylvania Power and Light Company, d/b/a/ PP&L Energy Plus ("PP&L"), New Jersey Commercial Users ("NJCU"), New Jersey Industrial Customer Group ("NJICG"), Independent Energy Producers of New Jersey ("IEPNJ"), and Mid-Atlantic Power Supply Association ("MAPSA"). BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -4- 7 On September 19, 1997, the Board issued an Order in response to a letter motion filed by the Division of the Ratepayer Advocate ("RPA"), wherein, among other things, the BPU provided certain clarifications and guidance as to the scope of the proceedings before the OAL, offered further guidance on the issue of securitization, the level of rate reductions and divestiture, and extended, by one month, the date by which Initial Decisions were to be rendered by the OAL in the various electric utilities' rate unbundling and stranded costs proceedings. By Order dated September 25, 1997, the BPU established procedures for the restructuring proceedings retained by it, and identified the specific issues to be considered. The BPU identified issues which it anticipated would likely be contested, as well as generic issues which might lend themselves to a collaborative review. For the latter issues, the BPU created three working groups on customer processes, reliability and competitive issues, to discuss specific details, narrow the issues in contention and attempt to develop a consensus position, if possible. The working groups were directed to provide status reports to the BPU by January 10, 1998, identifying areas of consensus, as well as areas where consensus was unlikely. The BPU indicated that a further procedural schedule would need to be established for issues where consensus was unlikely. Additional Orders were issued by the BPU between October 1997 and March 1999 in the various proceedings, addressing motions filed by various parties, including motions for intervention, pro hac vice admission, schedule modifications, clarification and reconsideration of earlier rulings, and interlocutory review of certain ALJ rulings. By Order dated January 28, 1998, the BPU established a procedural schedule to review the following generic restructuring issues: the potential for exercise of market power by the State's electric utilities regarding their generation assets; functional separation plans; divestiture of generation assets; basic generation plans, including the cost to provide service to low-income and bad-debt customers; mechanics of the phase-in of retail competition; the customer enrollment process; load balancing and a settlement system requirements for alternative supplier deliveries; and demand side management ("DSM") and renewable issues. A prehearing conference on ACE's unbundling and stranded costs petitions was held at the OAL on August 13, 1997. A prehearing order was issued on October 1, 1997. Nine days of hearings were conducted at the OAL between February 17, 1998 and February 27, 1998, at which time 22 witnesses, on behalf of ACE, the RPA, NJBUS, NJICG, Enron, NJPII, and IEPNJ testified and were cross-examined. In addition, Staff offered the testimony of two principals of BWG, as well as BWG's final Management Audit Reports on ACE's unbundling and stranded costs petitions, which were accepted as received by the BPU and released to the parties. After the close of hearings, briefs and reply briefs were filed by the parties in March and April 1998. After the ACE rate unbundling and stranded costs hearings and briefing were completed at the OAL, approximately twenty additional days of hearings were held before former Commissioner Carmen J. Armenti between April 27, 1998 and May 28, 1998, for testimony and cross-examination by the parties on the identified generic restructuring issues retained by the BPU. This Order also incorporates, as they apply to ACE, issues considered in the restructuring proceeding before the Board, including market power and basic generation service ("BGS"). Direct and/or rebuttal or surrebuttal testimony was filed by ACE (Joseph R. Bartalone, Jr., Tsion M. Messick, Thomas S. Shaw, Jerrold L. Jacobs, Henry K. Levary, Eileen Unger, Ashley C. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -5- 8 Brown, Rodney Frame, Paul L. Joskow); the CFC (Raymond E. Makul); GPU (Dennis Baldassari, Douglas J. Howe, Charles A. Mascari, William Hogan, Almarin Phillips); International Brotherhood of Electrical Workers ("IBEW") Local 94 (Charles Wolfe); IEPNJ (Steven Gabel); MAPSA (Steven Gabel, Dr. Craig Roach); NEV (Barbara Kates Garnick); NJBUS (Henry Riewerts, John Parodi); NJICG (Fred Mazurski): NJPII (not including the NRDC) (Nathaniel Greene, Bruce Biewald, Edward Smeloff, Thomas Bourgeois): NorAm (Keith Sappenfield); PSE&G (Gerald W. Schirra, Frederick W. Lark, Colin Loxley, Lawrence R. Codey, Alfred E. Kahn, Rodney Frame, Paul Jaskow); the RPA (Barbara Alexander, Peter Lanzalotta, Andrea Crane, Peter A. Bradford, Roger Colton, James D. Cotton, Dr. David A. Nichols); RECO (Terry L. Dittrich, Frank P. Marino, John C. Dalton, John Lombardi); and SESCO (Richard Esteves). In addition, representatives of the four consulting firms (Vantage/ICF Consulting, Stone and Webster, Inc., Barrington-Wellesley, Inc., and Hagler Bailey, Inc.) which submitted Management Audit Reports to the Board on the four electric utilities' restructuring filings2 also testified and were cross-examined. During the hearings, various motions, including motions to strike certain portions of the prefiled testimony, were ruled upon by former Commissioner Armenti, whose rulings are HEREBY AFFIRMED by the entire Board, essentially for the reasons set forth by former Commissioner Armenti in the transcripts. After the close of hearings before former Commissioner Armenti, briefs and reply briefs on the restructuring issues were filed on June 26 and July 17, 1998, respectively. After requesting and receiving an extension of time from the BPU, ALJ Gural issued an Initial Decision on ACE's rate unbundling and stranded costs petitions in August 1998. Exceptions and reply exceptions to the Initial Decision were filed with the BPU in October and November, 1998. On February 9, 1999, Governor Whitman signed into law the Electric Deregulation and Energy Competition Act, N.J.S.A. 48:3-49 et seq. ("the Act" or "EDECA"). EDECA authorizes the BPU to permit competition in the electric generation and natural gas supply marketplace and such other traditional utility areas as the BPU determines. EDECA required the BPU to have a complete revised regulatory scheme in place for each of the State's four electric utilities by August 1, 1999. Specifically, by that date, the BPU was required to order each of the State's electric utilities to simultaneously: open 100% of its franchise area to retail generation competition, N.J.S.A. 48:3-53(a); unbundle its rate schedules into discrete services and charges, N.J.S.A. 48:3-52(a); provide basic generation service at approved rates for customers who do not choose an alternate power supplier; provide approved "shopping credits" to be deducted from the bills of customers who choose an alternate power supplier, N.J.S.A. 48:3-52(b); reduce its aggregate level of rates for each customer class by "no less than five percent," N.J.S.A. 48:3-52(d)(2); implement a Societal Benefits Charge ("SBC") to recover the cost of previously approved social, environmental and demand side management programs which were included in each utility's bundled rates, N.J.S.A. 48:3-60(a); and implement an approved - ------------------------- (2) By Order dated March 5, 1998, the BPU accepted as received and released to all parties in the restructuring proceeding, copies of the Management Audit Report regarding ACE's restructuring filing, which had been prepared by BWG. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -6- 9 Market Transition Charge ("MTC") to allow each utility the opportunity to recover an approved level of stranded costs as determined by the BPU. N.J.S.A. 48:3-61(a), (c), (i) and (j). While recognizing that competition in the electric generation area would "reduce the aggregate energy rate currently paid by all New Jersey consumers," N.J.S.A 48:3-50(c)(1), the Legislature made it clear that, in effectuating a transition to competition, the BPU must not impair the financial integrity of the utilities, which remain obligated pursuant to Title 48 to provide safe, proper and reliable service to customers. N.J.S.A. 48:2-23, N.J.S.A. 48:3-50(c)(4) and 61(h). By Order dated February 11, 1999, the BPU established guidelines and a schedule for the commencement of settlement negotiations among the parties in each of the State's four electric utilities' stranded costs, rate unbundling and restructuring proceedings. The BPU set a deadline for the submission of a negotiated settlement for each utility, which deadline for ACE was later extended. No comprehensive settlement was reached among all the parties in the ACE proceedings; however, on June 9, 1999, a proposed stipulation of settlement ("Stipulation I") was filed by ACE, Enron, PP&L, NJCU, and IEPNJ. On June 15, 1999, an alternative Stipulation of Settlement ("Stipulation II") was filed by the RPA, MAPSA, NJBUS, and NJICG. Parties were provided the opportunity to submit comments to the BPU on both stipulations. By Order dated July 13, 1998, the BPU ruled on various motions, including a motion dated April 22, 1998 by the CFC for the BPU to disclose any ex parte communications in accordance with N.J.A.C. 1:1-14.5(a), which is part of the Uniform Administrative Procedure Rules, which were adopted by the OAL and pertain to contested case proceedings. This regulation provides: Except as specifically permitted by law or this chapter, a judge may not initiate or consider ex parte any evidence or communications concerning issues of fact or law in a pending or impending proceeding. Where ex parte communications are unavoidable, the judge shall advise all parties of the communications as soon as possible thereafter. On this issue the BPU ruled that "to the extent there are communications on issues of fact or law being adjudicated in the unbundled rates and stranded costs filings, as opposed to policy and legal issues being considered in the generic, legislative-type proceeding, the Board would be required to comply with N.J.A.C. 1:1-14.5(a). Therefore, the Board does not grant or deny the CFC's motion itself because the Board is required, in any event, to comply with applicable law." By a subsequent motion dated February 22, 1999, the CFC again moved pursuant to N.J.A.C. 1:1-14.5(a), for disclosure of ex parte communications. No responses or other filings were made with regard to the CFC's motion. At its agenda meeting of April 21, 1999, the BPU confirmed that there had not been ex parte communications on issues of fact or law to be adjudicated by the BPU in ACE's unbundled rates and stranded costs proceedings. Accordingly, there are no disclosures to be made pursuant to N.J.A.C. 1:1-14.5(a) and the Board's ruling on the CFC's prior motion. Thus, the BPU determined to dismiss the CFC's motion as it pertained to the ACE's proceedings. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -7- 10 II. INITIAL DECISION On August 19, 1998, ALJ Gural filed his Initial Decision ("ID") with the Board. The ID contains a description of the nature and background of the proceedings, a procedural history, brief summaries of the original filing and testimonies of each of the parties' witnesses, and discussion, findings of fact and conclusions with respect to ACE's rate unbundling and stranded costs petitions. Key elements of the ID are summarized below. A. Stranded Costs ACE advanced a constitutional issue over its right to recover 100 percent of its stranded costs, asserting that any disallowance would constitute confiscation. The Company opposes any sharing of stranded costs, as this would be tantamount to a disallowance of lawful recovery. ID at 39. ACE witness Gibson testified in support of the Company's projections of Operation and Maintenance ("O&M") costs for wholly owned fossil-generating stations, including two fossil fueled generating plants (B.L. England and Deepwater) with 667 megawatts ("mw") of capacity and eight combustion turbine generators ("CTs") with 521 mw of capacity. The five-year plant-specific forecast presented through 2001 indicates O&M expenses totaling $106.44 million and capital expenditures totaling $60.97 million. Gibson recommends that stranded costs be calculated using a December 31, 1998 investment balance. ID at 12-13. ACE witness Goetz testified concerning projected expenses at ACE's jointly-owned nuclear, fossil and pumped storage generating stations, including Peach Bottom, Salem and Hope Creek (nuclear), Keystone and Conemaugh (fossil) and Merrill Creek (pumped storage), in which the Company has minority ownership interests. Goetz presented a six-year plant specific O&M expense history for each of the units, totaling $336.15 million, and five-year O&M expense forecast totaling $229.55 million. Historical six-year capital expenditures ending 1996 totaled $125.67 million for these units, and the five-year total capital expenditure projection ending 2001 for the units is $41.49 million. The ALJ notes the downward trend in both O&M and capital expenditures. ID at 14-17. ACE witness Baron testified that ACE presently holds four Non-Utility Generation ("NUG") contracts representing 579 mw of capacity, which represent stranded costs originally estimated by the Company at $965 million, and subsequently revised to $911.3 million. The Company is engaged in ongoing discussions for the buyout of those contracts. ID at 7. The RPA asserts that ACE has not aggressively pursued NUG contract mitigation, and that the Company's stranded costs estimates are overstated by $300 million. ID at 29. IEPNJ witness Gabel testified regarding the inviolability of NUG contracts once approved by the BPU, citing various limitations acknowledged by the Board in the Final Report and the decision by the United States Court of Appeals, Third Circuit, in Freehold Cogeneration Associates, L.P. v. Board of Regulatory Commissioners, 44 F.3rd 1178 (3rd Cir. 1995) cert. denied, 116 S. Ct. 68 (1995) ("Freehold"). IEPNJ does not foreclose NUG contract renegotiation, but insists that it be on a voluntary, not mandatory basis. ID at 22-23. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -8- 11 ACE witness Camp testified with respect to the forecast of future electricity market prices, and resultant stranded costs. The original testimony quantified total stranded costs at $1.328 billion, comprised of $413.6 million for owned generation, $272.4 million for utility purchased power agreements, and $914.3 million for NUG contracts. This total was later revised downward based upon specific revisions recommended in the Management Audit Report. The revised figures are as follows:
Source Revised Stranded Costs ------ ---------------------- (millions) ---------- Owned Generation $ 396.8 Utility Contracts $ 2.6 NUG Contracts $ 812.1 --------- $ 1,211.5
[ID at 18-19]. RPA witness Smith testified with respect to future market electricity prices in the Pennsylvania-New Jersey-Maryland interchange ("PJM") market. He agrees that ACE witness Camp's market price forecasts are generally reasonable. Smith's market price forecast has energy prices starting at 2.16 cents per killowatthour ("kwh") and capacity prices starting at $19.72 per kw-year, for a total market price of 2.39 cents per kwh in 1999, rising to 4.74 cents per kwh for energy and $66.78/kw-year for capacity, for a total market price of 5.50 cents per kwh in the year 2015. His forecast of ACE weighted generation prices for Company-owned generation ranges from 2.80 cents in 1999 to 5.54 cents in 2015. ID at 35. RPA witness Rosen testified regarding pricing of retail generation services, defining the retail price of electricity as the wholesale market price plus a retail margin. Rosen asserts that ACE has overstated stranded costs, since its computation relies upon the wholesale price rather than the retail price for generation, thereby understating the revenue it can collect from customers taking BGS service. He asserts that regulators in Pennsylvania, New York and New Hampshire have officially recognized that a retail margin needs to be added to the wholesale cost of power to arrive at a reasonable estimate of market prices for retail generation services. He asserts that a lower bound on the appropriate retail margin is 0.57 cents per kwh, reflecting ACE's current generation-related Administrative and General ("A&G") costs, although the true margin will likely be higher given the necessary future incurrence of marketing costs. Rosen recommends use of the .57 cents retail margin as an interim value, adding that it be corrected to reflect actual market data at the time that stranded costs reconciliations are performed. ID at 36-37. RPA witness Bradford testified that ACE's proposals for recovery of stranded costs are not consistent with the Final Report, since, rather than proposing a sharing of responsibility for stranded costs, they merely shift revenue requirements among generations of customers and taxpayers. The RPA asserts instead that ACE's level of recovery of stranded costs recovery should be conditioned upon the achievement of future rate reductions/levels and competitive market structures. ACE's proposals do not adequately contribute to these objectives, which are designed to benefit both ratepayers and shareholders into the future. Bradford disputes ACE's asserted basis for full recovery of stranded costs. He argues that ACE's theory of the regulatory compact does not substantiate its constitutional claim to full recovery, and that utility regulators BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -9- 12 have broad discretion to determine cost recovery methodologies as long as the result strikes a reasonable balance between the interests of ratepayers and shareholders. ID at 35-40. RPA witness LaCapra calculated ACE's stranded costs proposal at $1.895 billion. LaCapra recommends an $839.6 million reduction to this stranded costs request, producing a recoverable stranded costs amount of $1.055 billion, subject to further reductions resulting from an additional write-down recommended by RPA witness Rothschild. ID at 29-30. RPA witness Rothschild recommends that the Company take a $245 million pre-tax write-off to reduce stranded costs which would still enable it to maintain an investment grade bond rating; indeed, Rothschild asserts that ACE could take a $412 million write-off and maintain an investment grade bond rating. Rothschild asserts that ACE could recoup some of the equity loss of the write-off by issuing new common stock or reducing the common stock dividend. He asserts that ACE investors have enjoyed generous returns: an equity investment in 1975, including reinvested dividends, has achieved a compound annual rate of return of about 12.5%; an investment in the Company in 1980 has earned a compound annual return of 13.11%; and an investment in 1985 has earned a compound annual return of 10.25%. The ALJ notes that ACE has demonstrated the "disastrous results" of the write-off mandated by the Pennsylvania Public Utilities Commission ("PAPUC") in its decision In the Application of PECO Energy Co. for Approval of its Restructuring Plan, PAPUC Docket R-00973953. The write-off and the consequent reduction in its dividend caused PECO Energy's stock to plummet. The ALJ stated that this "is not a desirable result." ID at 34-35. NJPII witness Marcus argues that ACE's proposed administrative determination of stranded costs is flawed and cannot be relied upon to determine an accurate stranded costs valuation for owned generation. NJPII recommends divestiture as the most accurate way to value such costs. Marcus argues that ACE has used faulty assumptions to overestimate stranded costs and that the Company is obligated to take all measures to mitigate stranded costs. If the Board does adopt an administrative valuation of stranded costs, NJPII recommends that certain adjustments be included. Specifically, NJPII recommends exclusion of $30 million of costs incurred at the Salem Nuclear Generating Station since 1995 and $79 million associated with the installation of a sulfur dioxide (" SO2") scrubber at B.L. England; exclusion of prospective operating subsidies of $6.4 million for the Salem Station, $45 million for B.L. England and $4.2 million for Deepwater. Marcus cites a number of errors that can be made in estimating decommissioning costs, and the NJPII supports the RPA's argument that decommissioning costs should be excluded from stranded costs. Marcus also asserts that post-rate case capital additions should not be included in stranded costs, since ACE has not met the Board's criteria for their inclusion; i.e., ACE failed to demonstrate that the post- rate case capital additions were the least-cost alternative at the time the investments were made. NJPII recommends that B.L. England and Deepwater be eliminated from stranded costs recovery since they are unprofitable on a going-forward basis. NJPII argues that if ACE does not divest its owned fossil units and make a good faith effort to sell its interests in its nuclear facilities, it should be limited to recovery of only 50% of owned-generation stranded costs. NJPII recommends that NUG stranded costs be recovered over the lives of the contracts and measured against market prices as they actually occur; any NUG buyout costs should be recovered over time up to the length of the contract, at an interest rate not to exceed the after-tax cost of capital used as a discount rate, with no allowance for income taxes. NJPII argues that there should be no securitization of stranded NUG costs and that securitization of owned generation stranded costs be permitted BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -10- 13 only after mitigation of such costs, and consistent with levels specified under Board policy. ID at 23-28. Enron witness Kuhn supports recovery of "truly" stranded costs, but testified that customers should not pay for enhancements that improve the utility's competitive position. Excessive recovery of stranded costs that enhance the Company's competitive stature is detrimental to customers and competitors. He testified that the accuracy of stranded costs estimates is particularly important if such costs are securitized; once the assets are securitized, it is much more difficult to revisit the issue. Kuhn criticizes the automatic true-up aspect of the MTC, testifying that it would dampen the Company's incentive to mitigate stranded costs. He criticizes the allowance for an assured return on stranded costs, since, even under traditional rate regulation, utilities are only provided an opportunity, not a guarantee to earn a return on investments. Finally, Kuhn recommends against ACE's proposal to recover NUG stranded costs over the 20 to 25-year contract lives, recommending instead a four to eight-year recovery. ID at 21-22. Among many individual findings of fact, ALJ Gural finds as follows with respect to stranded costs: ACE has conducted a detailed review of its stranded costs; the greatest source of ACE's stranded costs are four NUG contracts for 5.79 mw executed in 1988 with terms ending in 2024, totaling approximately $812 million; BPU jurisdiction to change the terms of the NUG contracts it previously approved has been pre-empted by Federal legislation; stranded costs attributed to owned generation amounts to $397.844 million; both ACE and the RPA used a discounted cash flow method to calculate generation-related stranded costs; decommissioning costs for fossil fuel plants should not be included in the calculation of stranded costs; ACE should not be permitted to include the $38 million generation-related portion of the Financial Accounting Standards ("FAS")-109 deferred tax regulatory asset as an offset to deferred taxes; ACE's O&M costs have been reduced by 39% since 1991 and that the assumption that O&M costs will grow at the rate of inflation should be disallowed; and that RPA witness LaCapra's approach be adopted for fuel cost forecasts. ID at 45-47. With regard to market price projections and stranded costs forecast sensitivities, the ALJ finds that ACE's market energy and capacity price forecasts are reasonable when compared to those sponsored by the RPA, the BWG report contains the only sensitivity analysis; and that ACE's methodology does not adequately reflect the emerging PJM market structure. With regard to stranded costs mitigation strategies, the ALJ finds that ACE is actively involved in negotiations with NUG owners to renegotiate and lower the above-market costs of those contracts, but that the NUG owners have an advantageous negotiating position. ID at 47-48. Further, ALJ Gural concludes that the Company failed to meet its burden requiring it to demonstrate that it had no more effective resource alternatives available to it at the time it made the commitment to capital costs incurred after the last base rate case. ID at 53. The ALJ recommends that ACE witness Stotz's testimony regarding securitization as a means of recovering stranded costs and the elements of the legislation needed to enable such securitization transactions in New Jersey be referred to the Legislature. ID at 17-18. With regard to securitization, the ALJ finds as follows: the issuance of asset backed securities is a relatively risk-free mitigation tool for utilities; securitized bond interest rates will be lower and the bond proceeds should only be used to buy down NUG contracts or retire debt and equity, BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -11- 14 legislation must be enacted to permit securitization financing in New Jersey; securitization increases the certainty of recovery of stranded costs; ACE proposes to securitize all of its stranded costs to buy down NUG contracts, repurchase debt, preferred and common stock; and that by utilizing a lower cost of debt through securitization, savings could be passed on to customers through lower rates. ID at 49. Further, ALJ Gural concludes that ACE has not provided compelling justification for securitization of more than 50% of its allowable, non-mitigatable stranded costs, and should therefore not be allowed to do so. ID at 53. B. Rate Reductions ACE witness Walters testified to the financial impacts of the case upon the Company. On a book basis ACE showed an 8.13% earned return on equity ("ROE") in 1996; on a regulated basis, the 1996 ROE was calculated as 9.85%, based upon earnings available for common stock of $78.9 million. This compares to the currently allowed ROE from the last base rate case of 12.5%. The ALJ summarizes Walters' testimony concerning past mitigation efforts by ACE, including the Southern New Jersey Economic Initiative, in which ACE chose to forego recovery of $28 million of energy costs in 1994/95 and another $10 million in 1995/96 in order to phase-in the rate impacts of NUG contracts coming on line. Refinancing of $430 million in long-term debt and $112 million of preferred stock has reduced the long-term cost of debt from 9.1% to 7.5% and the embedded costs of preferred stock form 7.7% to 7.4%. The Company has reduced its work force by over 500 positions resulting in labor cost reductions of more than $14 million annually. Post-retirement benefits changes will produce an additional $3.3 million in savings, security guard costs have been reduced by $.750 million, and a residential deposit requirement should produce another $1 million in savings. Amendments to NUG contracts have produced $6 million in savings. Out of total 1996 revenues of $982.5 million, NUG contracts amount to $232.9 million (23% of total revenues) and state tax payments were another $95.3 million (about 10% of total revenues), leaving "net" revenues of $654.3 million. ID at 19-20. ACE witnesses Jacobs and Shaw jointly made a number of key recommendations, including: that rate reductions must be implemented in a manner which preserves the Company's financial health; that 100% of stranded costs must be recovered, and this can be achieved while delivering the proposed rate reductions through a combination of true cost savings and NUG contract renegotiations; and that all participants must commit to negotiate significant reductions in the above-market cost of NUG contracts. They emphasized that rate reductions not based on cost savings would result in higher capital and operating costs, and arbitrary revenue reductions would be confiscatory. ACE witness O'Connor testified that rate reductions should be approached with caution and be properly financed, and that full recovery of stranded costs should be afforded. ID at 9-10. ACE witness Levari testified that the "regulatory compact" entitles the Company to a fair return on its investment, and the recovery of its stranded investments, in return for the Company having met its obligation to serve through the years. He notes that a four to eight-year recovery period for stranded costs is not realistic in the face of mandated rate reductions. Levari presented the Company's rate reduction proposal as follows: BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -12- 15
Element % Reduction in Rates ------- -------------------- Start of Transition: ------------------- Merger savings sharing 1.25% Securitization of Owned Assets 2.00% NUG Contracts 1.75% ----- 5.00% By End of Transition: -------------------- Reduced Expenses 4.00% ----- Total Rate Reduction 9.00% -------------------- [ID at 11-12].
The RPA asserts that rates should be reduced by at least 10%, that the 1.2% merger-related rate reduction should not count towards the rate reductions in this proceeding, and that a 2% rate reduction from securitization should not be considered a "genuine" reduction, since it represents a long-term ratepayer commitment to pay debt service costs. ID at 29. ALJ Gural does not offer findings regarding the appropriate level of rate reductions but concludes that in the event a satisfactory rate reduction is not provided, the BPU Staff, the RPA, or both, may institute a proceeding pursuant to N.J.S.A. 48:2-21(b)(1), which, in turn, could lead to a proceeding pursuant to N.J.S.A. 48:2-21.1. ID at 53. C. Rate Unbundling The Company presented a 1996 cost of service study ("COSS") using 1996 rate base, revenue and expense data, which the ALJ acknowledges deviates from the Final Report requirement that data from the last base rate case be used to unbundled rates. ACE's revised COSS (Rebuttal Exhibit CWSR-6 of Exhibit ACE-23) allocates production costs on the basis of class average demands; transmission costs have been allocated on the basis of the average of twelve monthly system coincident peaks; distribution costs have been allocated according to class peak demand; and customer costs have been allocated according to the criteria in the Final Report. ID at 6. ACE witness Setterman testified concerning unbundled rates. Setterman advanced an MTC, NUG stranded costs and a net non-utility generation charge ("NNC") to recover NUG stranded costs, both of which would be non-bypassable, as well as a service charge, energy and capacity charges, a securitization charge, transmission charge, distribution charge, SBC and tax charge. An ancillary service charge to recover load balancing and system operations costs was also postulated. ID at 20-21. RPA witness Stutz criticized ACE's unbundling filing as inconsistent with the Final Report in a number of areas. ACE used a "new" cost of service study rather than the study from its last base rate case; the proposed rates are not revenue neutral within rate classes; the Company did not analyze the range of rate reductions required by the Board; and the rate reductions are based in part on cost reductions unrelated to restructuring. Stutz recommends that ACE's BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -13- 16 proposals be rejected and that it be ordered to revise its filing to include the following: the 1988 COSS from the last base rate case; unbundled rates which are revenue-neutral on both intra and interclass bases; unbundled generation, transmission, distribution, customer and SBC; and that it separate the generation charge into discrete market price, MTC and NTC charges. Stutz compared the 1988 COSS to the 1996 COSS to show that total plant in service had increased by $921 million (58%), including an increase in distribution plant of $316 million (76%), that operating revenues had increased by $376 million (60%), and that net operating income had increased by $28 million (24%). ID at 32-33. The ALJ concludes that resurrecting the 1988 COSS creates a difficult task with questionable accuracy. He recommends that the Board's requirements that the Company use the COSS from the last base rate case be modified to permit the use of an updated study, and concludes that in this case the 1996 study presented by ACE may be the best source for developing unbundled rates. ID at 41. With respect to rate unbundling, the ALJ finds as follows: the last base rate case was decided in 1991 and was based upon a Board approved stipulation; the 1988 COSS offered in that case was not used to establish the stipulated rates; the use of the COSS using 1996 data does not comply with the Final Report; the 1996 COSS used the base intermediate peak allocation method previously approved by the BPU; since the records and work papers related to the 1988 COSS are no longer available, it would serve no useful purpose to require the Company to replicate the 1988 COSS when the degree of accuracy would be in doubt; a revenue neutral unbundled rate design was provided, and that there is no basis for varying from this revenue neutral rate design; the Company allocated transmission costs in the same manner as it did for the Federal Energy Regulatory Commission ("FERC"); the Company allocated its distribution costs consistent with the 1996 COSS, which allocation was based upon class demands; FERC has jurisdiction over transmission rates, which will be established by an independent system operator; ACE appropriately functionalized costs within the COSS; ACE has designed its NNC appropriately to recover $812 million of stranded NUG costs; ACE provided unbundled rates and an accompanying tariff, but such tariff is "incomplete" to the extent that legislation must first be enacted in order to precisely effect a securitization charge. ID at 41, 46, 49-52. III. EXCEPTIONS AND REPLY EXCEPTIONS Numerous parties filed exceptions and reply exceptions to the Initial Decision. These largely reiterate the positions advocated by the parties during the hearings. In some instances, the exceptions and reply exceptions go beyond the ALJ's specific findings of fact, addressing related issues. Key arguments advanced by the parties in their exceptions and reply exceptions are summarized below. A. Exceptions 1. ACE ACE concurs with the ALJ's findings of fact regarding rate unbundling, reiterating that its proposed tariff has been offered merely as a framework for the design of final rates. Final Board determinations regarding the levels of stranded costs recovery, rate reductions, securitization, BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -14- 17 as well as certain other restructuring decisions, will be incorporated into the rate design format adopted in the ID. Regarding stranded costs recovery issues, ACE takes exception to a number of the ALJ's findings of fact and reemphasizes its central position that it is entitled to full recovery of its stranded costs as a matter of law. ACE takes exception to the following findings of the ALJ related to stranded costs: the exclusions of fossil fuel plant decommissioning costs and a $38 million generation related portion of the FAS-109 regulatory asset; the rejection of ACE's contention that O&M costs will grow at the rate of inflation; the use of RPA witness LaCapra's fuel cost forecast; and the conclusion that ACE failed to demonstrate that capital costs incurred since its last base rate case were the least cost alternative available. ACE argues that the exclusion of fossil fuel decommissioning costs represents an exclusion of real costs that the Company will incur when these units are decommissioned; fossil decommissioning costs are a future operating cost that should be included in the determination of future cash flows used to derive the stranded costs valuations for such units. Their exclusion from the stranded costs calculation would thus distort the entire calculation by overstating the residual values of these units. ACE contends that the ALJ's finding for the exclusion of the $38 million generation component of the FAS-109 regulatory asset is based upon the faulty recommendation of BWG. BWG relied upon the Final Report directive that regulatory assets should continue to be recovered within the distribution charge; ACE contends, however, that this regulatory asset is not currently being recovered in its rates. As a result, adoption of the ALJ's finding would require an unwarranted write-off of these legitimately-incurred costs; even the BWG witness concurred that these costs should be collected and not written off. ACE argues for MTC recovery of the generation related portion of FAS-109, with the balance to be recovered via the distribution rates at some future time. Regarding O&M costs, ACE maintains that its use of the inflation rate represents a conservative growth estimate and should be adopted. ACE reiterates its position that O&M expenses at its wholly owned units are significantly lower now than in the early 1990s, with the Company reducing this expense by 39% since 1991 to an "absolute bare bones level." ACE asserts that adoption of the ALJ's recommendation would force the Company to cut O&M expenditures down to a level that would jeopardize the safety and reliability of these units. The Company makes similar assertions regarding historic and current O&M expenditures at its jointly owned facilities. ACE asserts that the ALJ's finding has no basis in fact and fails to recognize that O&M levels, prior to escalation, already incorporate substantial reductions. ACE takes exception to the ALJ's adoption of the RPA's fuel cost forecasts, highlighting that the ALJ failed to indicate how LaCapra's forecasts were to be used. LaCapra utilized RPA witness Smith's annual fuel costs; according to Smith, the Company's forecasted fuel costs are reasonable and similar to the fuel costs that he employed. ACE argues that use of the RPA's forecasts would not necessarily lower the stranded costs calculation. The Company therefore argues for Board rejection of the ALJ's finding, reaffirming the legitimacy of its own fuel cost forecasts. ACE expresses concern over the ALJ's conclusion that the Company failed to demonstrate that post- rate case capital additions were the most cost-effective resource alternatives available at the time. ACE asserts that the ALJ's finding is faulty, in that it neither cites to record evidence nor provides any analysis as to how such a conclusion was reached. Furthermore, ACE notes that the ID is unclear as to whether the finding is intended to apply to all post-rate case capital BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -15- 18 additions, as advocated by the RPA, or to specific projects that may not be eligible for stranded costs recovery, such as those identified by BWG. The Company maintains that it has demonstrated that all of its post-1991 investments were economic, reasonable, prudent and should be included in the calculation of stranded costs. Each of the subject capital projects was extensively analyzed by BWG, with the Company supplying on the record detailed substantiation for the limited number of projects identified by BWG as possibly ineligible for recovery. None of the subject investments represented new generating facilities, repowerings or major upgrades. Rather, ACE asserts that the capital additions were "necessary to meet regulatory or legal requirements, to resolve safety issues, and to maintain routine plant operations and overall system reliability," (3) and as such, these capital additions are not subject to the market test required by the Board for stranded costs consideration. ACE notes that the Final Report prescribes that new supply resources and major investments in existing generating facilities be subject to the market test requirement. Further, ACE argues that its statutory obligation to serve includes meeting the energy and capacity needs of its customers; to do so requires investment in the operation and maintenance of its generating facilities. These necessary investments would not be made by the utility without the expectation that utility shareholders would be permitted a reasonable opportunity to earn a fair return of and on their investment. This regulatory compact, woven through numerous court decisions, has not been lawfully reduced or removed since the 1991 base rate case, during which time ACE continued to engage in these capital projects. Thus, any current imposition of a market test for investment made since 1991 would represent a retroactive imposition of a standard for recovery never before applied to such investments; any disallowance resulting from such exercise would represent an unconstitutional confiscation of the shareholders' property. ACE argues for Board rejection of the ALJ's finding; however, if the Board does adopt the ALJ's conclusion, it must first render findings and conclusions based upon the record and extant law. ACE argues that the Board should permit the securitization of 100% of its stranded costs, rather than the maximum of 50% specified in the Final Report. The Company acknowledges the ALJ's conformance with the Final Report in finding that ACE be permitted to securitize a maximum of 50% of its stranded costs, but argues that if the Board does not permit the securitization of up to 100% of stranded costs, it would deny the Company an opportunity to simultaneously effectuate customer rate reductions and stranded costs recovery. ACE states that it would employ the increased savings from securitization to mitigate stranded owned generation and NUG costs; lower interest rates, interest costs, capital costs and dividend requirements would permit a dollar-for-dollar pass through of savings to customers, while ensuring a sound financial position. ACE argues that there is no objective basis upon which to limit securitization to 50% of stranded costs and that the Board should permit the maximum possible securitization of stranded costs. - ------------------------------ (3) ACE asserts that this is the type of evidentiary demonstration relied upon by ALJ McAfoos in his recommendation in the PSE&G Initial Decision on stranded costs that the majority of post-rate case capital additions at the Salem Nuclear Generating Facility be included in the calculation of stranded costs. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -16- 19 2. Ratepayer Advocate The RPA takes exception to certain findings rendered by the ALJ with respect to stranded costs and rate unbundling, as well as to the absence of findings on other issues raised by the RPA. As is the case with the exceptions of a number of other parties, the RPA's exceptions exceed the scope of the ALJ's findings and address the range of issues to be considered by the Board in rendering final determinations. Regarding stranded costs, the RPA takes exception to certain of the ALJ's findings on the quantification and mitigation of stranded costs, as well as to ACE's stated legal right to their full recovery. The RPA criticizes the ALJ for failing to rule on the threshold issue of whether utilities are legally entitled to full recovery of stranded costs. The ID states that the regulatory compact proffered by ACE has not been adopted by the New Jersey courts or the Legislature, a point which the RPA argues supports its contention that the Company has no right to full stranded costs recovery. The RPA cites the policy statement in the Final Report that utilities are not necessarily entitled to the unconditional recovery of 100% of their eligible stranded costs; stranded costs recovery is necessarily constrained by the achievement of other objectives, notably the ratepayers' right to pay just and reasonable rates and experience near-term benefits from competition, including a minimum five to ten percent rate reduction. According to the RPA, a disallowance of the recovery of and return on investments is not, as maintained by ACE, tantamount to an unconstitutional confiscation of property. Rather, the RPA argues that there exists no legal basis for the Company's full and accelerated recovery of uneconomic i.e., stranded, investments. ACE's objection is not that the Board's action might deprive it of the value of its investment, but that absent Board action the value of these assets would fall precipitously in the competitive market. The RPA asserts that it is not the role of government (i.e., the Board) to guarantee the value of a shareholder's investment over time and cites U.S. Supreme Court decisions rejecting the notion that investments deemed to be prudent are guaranteed full recovery by the regulated entity. Furthermore, the "used and useful" standard for the inclusion of plant in rate base is well-established in New Jersey law as a basis upon which the Board may disallow plant that has become uneconomic or is physically incapable of providing service. ACE's common equity shareholders have been adequately compensated for the potential risk of disallowance through returns that have significantly exceeded returns on risk-free securities. Finally, the RPA points to a number of recent state public utility commission decisions that have rejected utility claims to full recovery of stranded costs. The RPA urges the Board to reaffirm its policy set forth in the Final Report, and supported in the ID, that ACE has no legal, equitable or regulatory entitlement to full recovery of stranded costs. The RPA urges the Board to adopt its estimates of stranded costs, which are as follows: negative $127.53 million for owned generation; $649.651 million for stranded NUG costs; and zero for the Philadelphia Electric Company ("PECO") contract, of which $2.61 million is included in ACE's $812 million estimate for NUGs contained in the ALJ's findings. The net level of stranded costs recommended for MTC and NNC charge recovery is thus $522.12 million under the RPA recommendation, rather than the $1.21 billion derived under the Company's proposal. The RPA's stranded costs recommendation is approximately $700 million less than ACE's, a fact that the RPA notes is misstated as a $300 million difference by the ALJ in the ID. The RPA urges the Board to reject BWG's estimate of $1.24 billion for stranded costs on the basis that it BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -17- 20 does not incorporate many of BWG's own recommended inputs to the calculation. The RPA points out that the wide disparity in the stranded costs estimates of the parties should cause the Board to view with skepticism all administrative estimates. These variations should also cause the Board to periodically adjust the stranded costs recovery charges for actual market prices and changes in sales; the need for periodic reconciliations has been previously endorsed by the Board in the Final Report. The RPA asserts that the ALJ's indication that stranded generation costs stand at $397 million does not incorporate his subsequent findings for the disallowance of certain costs from stranded costs recovery. The RPA calculates the ALJ's net generation stranded costs finding at $2 million, based upon the ALJ's $397 million initial estimate and the following disallowances contained in the ALJ's findings: post-rate case capital additions of $318 million; $38 million for the generation portion of the FAS-109 regulatory asset; and $19 million for fossil fuel plant decommissioning costs. In its quantification of the net stranded costs amount indicated in the findings of the ID, the RPA assumes that the ALJ found for the exclusion of all capital additions made subsequent to the conclusion of the Company's last base rate case in July 1991, including the Company's investments made between October and December 31, 1998, consistent with the prescription contained in the Final Report. The RPA urges the Board to adopt the disallowance of all post-rate case capital additions on the basis that the Company failed to substantiate them as the most economically efficient alternatives available at the time. Such adjustment would reduce the net book value for generation assets from the Company's recommended $723.935 million to the $405.468 million level calculated by RPA witness LaCapra, which the RPA urges the Board to adopt as the starting point for the derivation of stranded generation costs. The RPA takes exception to the ALJ's failure to address its argument that the discount rate used in the net present value calculation of future cash flows is overstated, producing an overestimation of stranded costs. ACE utilized a discount rate of 9.71% (pre-tax) based upon the Company's December 1996 capital structure and the 12.5% allowed return on equity authorized in the 1991 base rate case. The RPA urges rejection of this "hybrid proposal," arguing that the Company's current cost of capital should be employed. The RPA analyzed the Company's current cost of capital and advanced an adjusted overall pre-tax cost of capital of 8.25% and an after-tax rate of 6.77%. The RPA urges the Board to adopt its current cost of capital rate as the discount rate for determining the net present value of ACE's generation stranded costs. Despite the proximity of results in the market price forecasts of ACE and the RPA, the RPA argues that the differences in input assumptions warrant a closer consideration of the competing simulations and the ultimate adoption of its forecast as the more precise of the two. In particular, the Company's model employs a cost-based bidding system for plant dispatch, while the RPA's employs a market-based approach which it asserts to be a more accurate reflection of impending movement by the PJM to market priced dispatch, a move that has met with the concurrence of the Board as expressed in the Final Report. The ALJ failed to address the issue of assumed capacity additions needed to meet expected load growth and plant retirements. The RPA urges the Board to adopt its recommended $560/kw cost for a combined cycle unit ("CC") and $297/kw for a combustion turbine ("CT"); these assumptions are slightly lower than ACE's assumed costs of $580/kw for a CC and $350 for a CT. The RPA also argues for use of its lower heat rate. Both of these recommendations, the RPA concedes, would BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -18- 21 increase the level of stranded costs when compared against the use of ACE's assumptions in these areas, a fact that the RPA states is evidence of the conservative nature of its market price forecast. Additionally, the RPA asserts that the ALJ failed to rule on the issue of the carrying charge rate applied to capital additions assumed in the forecasts. The RPA urges rejection of ACE's fixed carrying charges of $97/kw-year for a new CC and $45/kw-year for a CT, both escalated at 1.5% annually. Arguing that the merchant nature of the assumed capacity additions carry higher risk than regulated plant additions, the RPA recommends use of a 12.75% carrying charge escalated at the general inflation rate. According to the RPA, use of the outdated ACE carrying charge approach and quantification systematically understates the forecasted market prices. The RPA concurs with the ALJ's finding that ACE's assumed growth rate for O&M costs should be disallowed. However, the RPA asserts that the ALJ failed to address the other reasons underlying ACE's inflated O&M projections. Specifically, ACE escalated its 2001 starting value for jointly owned facilities at 3.8% over the 2000 value, resulting in an artificially high starting point for O&M costs. Similarly, its year 2001 starting value for wholly owned plants is 10% higher than the forecasted 1997 costs. The RPA argues that competition itself will place downward pressure on O&M costs, not the upward pressure evidenced in ACE's assumptions, and urges their rejection in favor of RPA witness Smith's inflation assumption, with O&M levels additionally adjusted at a rate of 0.2% to reflect productivity gains in response to competitive pressures. Finally, the RPA urges the Board to reject the substantial O&M adders included in ACE witness Camp's rebuttal testimony as without foundation in either historical experience or FERC accounting. The RPA argues that the ALJ failed to address its position that the Company improperly priced BGS service by ignoring the costs of providing retail service. The effects of ACE's pricing of BGS at wholesale rather than retail levels are an overstatement of stranded costs and the deflation of the BGS rate to levels below which alternative suppliers can compete. The RPA urges the Board to adopt its recommended conservative 5.7 mills/kwh retail adder which is based upon current average generatio-related A&G expense. The RPA urges Board rejection of the inclusion of $2.61 million of stranded costs associated with the PECO contract, an issue not addressed in the ID. The RPA asserts that the PECO contract was not demonstrated to be the least cost alternative available to the Company; ACE was aware of the potential for stranded above-market costs when it consummated the contract; the Board never issued an Order approving the contract; and the contract was entered into more than a year after FERC's cutoff date for the recovery of stranded wholesale contract costs. The RPA takes exception to the ALJ's failure to address the Company's future mitigation of stranded generation costs. The RPA notes that ACE offered no specific mitigation proposals, raising only voluntary NUG contract renegotiation, possible stranded asset securitization and other minor cost reduction measures to which ratepayers would be entitled in the absence of industry restructuring. The RPA further notes that ACE failed to proffer or assess a reduced return on its stranded investments as a mitigation measure despite this approach having been specifically identified by the Board. Rather, ACE advanced a position calling for full recovery of its stranded costs at the full return authorized in its last base rate case. The ALJ did not address the Company's failure to evaluate divestiture as a means of mitigating stranded costs. The RPA asserts that ACE advanced through rebuttal testimony a divestiture approach that would permit it keep all of the proceeds while its ratepayers continued paying the BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -19- 22 administratively-determined level of stranded costs through an eight-year MTC. The RPA urges Board rejection of this proposal. The RPA takes exception to the ALJ's lack of consideration of both ACE's failure to propose measures for the prospective mitigation of stranded NUG costs and the specific mitigation proposals advanced by RPA witness LaCapra. The RPA quantified three specific mitigation opportunities that ACE was likely to achieve, accounting for a 20% reduction to stranded NUG costs. Accordingly, the RPA urges the Board to reject ACE's $812 million quantification of stranded NUG costs and adopt LaCapra's mitigation estimates which reduce stranded NUG cost to $649.651 million. While the RPA concurs with the ALJ's finding that securitization not exceed 50% of the Company's stranded costs, it offers the following specific recommendations for Board adoption. Based upon its quantification of negative stranded costs for owned generation, the RPA urges the denial of any securitization of wholly or jointly owned assets; however, if the Board finds for some level of owned- generation stranded costs recovery, it should limit securitization to 50% of the net, non-mitigatable amount (on a net present value basis), over a term not to exceed eight years. The Board should deny ACE any securitization of administratively determined NUG stranded costs; securitization should be limited to NUG costs mitigated via buyouts or buydowns. Finally, the proceeds of securitization should be used exclusively to reduce stranded costs and not to subsidize any other activity of the utility. Regarding rate reductions, the RPA takes exception to the lack of findings or recommendations regarding ACE's proposal and argues that the Board should implement a 10% rate reduction upon the commencement of competition. The RPA contends that ACE's proposed reduction is composed of either savings that are unrelated to restructuring or are speculative and have no basis in fact. The RPA further contends that ACE has artificially inflated its proposed rate reduction by comparing the level of reduced revenues to total revenue net of Gross Receipt and Franchise Taxes ("GR&FT") and NUG contract revenues, and that ACE has violated the Board's directives by not offering minimum rate reductions relative to the rates in effect on April 30, 1997. Regarding the specific components of ACE's proposed first year rate reduction of 5%, the RPA argues that the 1.2% merger related savings should not be credited as an offset to the rate reduction as it is unrelated to Board ordered reductions in the instant proceeding; ACE's 2% reduction related to securitization is speculative and assumes securitization of 100% of stranded costs; and its 1.75% reduction associated with NUG contract renegotiation is speculative. Of the proposed 4% reduction for 2001, the RPA argues that 75% of this reduction is associated with savings unrelated to restructuring: i.e., the amortization of GR&FT book expenses and the termination of the PP&L contract. The remaining 1% of the year 2001 reduction is speculative in that it is based upon unsubstantiated O&M savings. The RPA recommends that the Board reject ACE's rate reduction proposal as failing to meet the minimum requirements set forth in the Final Report. The RPA argues that ACE can implement a rate reduction of at least 10% at the outset of competition if the RPA's recommendations regarding stranded costs are adopted. The RPA asserts that it has demonstrated that ACE could effectuate such a rate reduction while maintaining both an investment grade bond rating and the market value of its stock above book value. The RPA urges the Board to order a reduction to ACE's rates by a minimum of 10% upon the start of retail competition. The RPA concurs with the ALJ's finding that ACE failed to file a COSS consistent with the Final Report, but takes exception to his corollary finding that it would serve no useful purpose for the BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -20- 23 Company to replicate its 1988 COSS since its accuracy would be in doubt. The RPA argues that the ALJ's finding contravenes the Final Report, in that the Company's COSS employs calendar 1996 data rather than data from the last base rate case. The RPA points to the Board's February 9, 1998 decision on interlocutory review in the GPU proceeding; viz. in order to properly unbundle current rates, it is necessary to have the underlying COSS utilized to set those rates in the last base rate proceeding. The RPA maintains that its comparison of functionalized costs in the 1996 and 1988 COSSs corroborates a substantial shift in costs between functions to the extent that unbundling on the basis of the 1996 study would produce cross-subsidies and anti-competitive rate results in violation of Board directives. Additionally, the RPA asserts that substantial cost shifting occurred from unregulated generation service to regulated service functions. Despite the fact that rates were stipulated in the last base case, the RPA argues that the 1988 COSS is nevertheless more useful to the unbundling process than the new 1996 COSS, which data has never been subject to Board review. The RPA asserts that ACE's claimed loss of the 1988 COSS reflects poorly on the Company, and that ACE should have endeavored to recreate the study to the greatest extent practicable. The RPA urges the Board to direct that ACE file its 1988 COSS and unbundled rates based upon it; additionally, the Board should order a technical conference of the parties to reach agreement on the form of ACE's revised COSS filing. The RPA takes exception to the ALJ's implication that ACE's filing sufficiently segregates costs into the specified functional rate categories. The RPA asserts that ACE's failed to unbundle production costs into MTC and NNC components as required in the Final Report: the MTC and NNC rates are set at zero in the proposed tariff and it is thus impossible to assess the extent to which functionalized costs will be reflected in the final rates. The RPA urges the Board to order ACE to re-file an unbundled rate proposal containing discrete rates for production, transmission, distribution, SBC, customer costs, MTC, NNC, and securitization charges. 3. BPU Staff BPU Staff raises a number of issues regarding the ALJ's stranded costs findings. Staff notes that the $1.2 billion level of stranded costs is stated on a net-of-tax basis, and that on a revenue requirement basis (i.e., after-tax) the amount is $2.2 billion. Staff takes exception to the ALJ's finding of $397 million for generation stranded costs, citing the potential for wide variations between administratively-determined stranded costs estimates and the disparity between these estimates and actual market value. Staff notes that the Company's market price forecast methodology is better suited to a vertically integrated utility than to an emerging competitive market. The Company's methodology fails to account for congestion management and ancillary services such as spinning and non-spinning reserves, replacement reserves, automatic generation control, voltage support and black-start capability. Staff concurs with the ALJ's findings regarding the disallowance of certain costs for recovery, but notes that the ALJ did not render a finding with respect to its recommendations regarding deferred Salem costs and the Salem outage costs. Staff argues for Board adoption of the 0.2% O&M productivity factor recommended by the RPA but not addressed in the ID. Regarding stranded NUG costs, Staff notes the volume of historical errors concerning NUG cost projections. Staff argues that the Board should focus upon NUG mitigation strategies. Staff BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -21- 24 asserts that, in adopting the Company's overall stranded costs estimates, the ALJ likely overstated the level of actual stranded costs. Regarding ACE's rate reduction proposal, Staff takes exception to the ALJ's failure to find that the Company's proposal does not comply with the Board's mandated 5% reduction. The ALJ's denial of 100% securitization of stranded costs implies a denial of the 2% rate reduction associated with the Company's securitization proposal. Absent this component, ACE's rate reduction falls short of the mandated 5% reduction at the outset of competition; Staff argues that the ALJ should have made such an explicit finding. Staff takes exception to the ALJ's finding that the benefit of securitization is the increased certainty of stranded costs recovery. The benefits of securitization flow from reduced capital costs and the mitigation of stranded costs. Staff believes this essential point should be reflected in the findings in this case. Regarding the ALJ's finding for use of ACE's COSS, Staff argues that the Final Report was unclear regarding the vintage of the costs to be used as inputs; rather, the most critical element of the unbundling process is ensuring that costs are properly functionalized between components. Although a comparison of the 1988 and 1996 COSS functionalizations does not indicate a massive shift in the relative cost structure of the Company, Staff notes the shift away from production costs to the distribution and general plant functions, and urges the Board to carefully consider this shift prior to rendering its final determination. Staff notes that no specific COSS methodology was adopted in the stipulation of rates in the Company's last base rate case, but that the stipulation did specify a prospective production cost allocation methodology to be used in ACE filings, namely, the Base/Intermediate/Peak ("BIP") method for classification purposes and the Hourly Cost Allocation Method ("HCAM") for allocation purposes. While not employing the 1991 production cost allocation methodology, the Company's COSS in the instant proceeding embodies a methodology that is both accurate and represents the most recent Board approved COSS methodology: i.e., the BIP method. However, Staff argues that the Company's COSS filing should be revised to include those non-production classifications and allocations described in Staff's briefs. Given the lack of time to fully review the Company's February 1998 COSS filing, Staff argues that this limited area be left open for further review by the Board. Regarding rate unbundling, Staff notes that the ALJ failed to render certain findings fundamental to the rate design process. Staff urges the Board to adopt BWG's use of the Company's authorized rate of return in setting the revenue requirement targets of functionalized rate components; the Company and the RPA employed ACE's higher actual rate of return in deriving functional revenue requirements for the various rate components. The ID is also silent on the Company's failure to unbundle production charges into discrete MTC and NNC components for the recovery of stranded costs. The Company's proposal rather includes placeholders for the MTC and NNC pending final determinations of these costs. Staff argues for Board adoption of BWG's rate cap approach rather than the stranded costs amortization rate design approach employed by the Company; ACE's approach would make implementation of rate reductions difficult and create the potential for customer confusion. While Staff points out the relative benefits of the BWG rate cap approach, it also outlines a number of ancillary issues that must be resolved prior to executing the rate design, such as whether to employ a fixed or floating MTC, the duration of the rate cap and whether the cap should apply to the overall level of unbundled rates and/or the discrete unbundled rates. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -22- 25 Regarding specific unbundled rate designs, Staff urges the Board to determine a number of issues not addressed in the ID. The Board must decide whether the BGS rate will be set on a class specific basis or a system average basis. Staff argues for annual adjustments to the market energy and capacity rates embodied in the BGS rates; ongoing reviews of under and overrecovery balances, and that if such balance exceeds a Board determined percentage of annual BGS costs, the rates should be revised; any interest on over-recovered balances should be set according to the method prescribed in N.J.A.C. 14:3-13; and that the BGS rate be set at the retail price for this service and not merely the wholesale level. Staff urges the Board to adopt its recommendations regarding the SBC and reduce the distribution revenue requirement consistent with its position on brief. Staff urges adoption of the Company's proposed NNC design conditioned on adoption of Staff's stranded costs mitigation recommendations. Staff concurs with ACE's general recommendation for a discrete Regulatory Assets Recovery Charge ("RARC"), but argues that the allocators for this function within the COSS are faulty and should be corrected to reflect the energy related nature of these costs, consistent with the BWG Report. In the alternative, the Board may opt for the recovery of these costs through the distribution charge. Finally, Staff argues that ACE has not complied with the Board mandated 5% rate reduction, nor has it demonstrated how the reduction would be designed in rates. Staff urges the Board to require the Company to submit such rate design. 4. Independent Energy Producers of New Jersey IEPNJ's concurs with the findings of the ID regarding its central concerns in the proceeding: that the Freehold case prevents the Board from unilaterally modifying NUG contracts, disallowing utility recovery of contract costs, or ordering utilities or independent generators to renegotiate previously approved NUG contracts. IEPNJ argues that the ALJ failed to articulate the logical extension of the Freehold decision, however, in not finding that the full cost of NUG contracts must be recovered over the life of the contracts. This recovery is appropriately executed through a mechanism similar to utility Levelized Energy Adjustment Clauses ("LEACs"). ACE's proposed NNC is designed to provide for such recovery, but IEPNJ argues that the NNC should be incorporated in the MTC in order to avoid lengthy and confusing customer bills. 5. New Jersey Public Interest Intervenors NJPII takes exception to the ALJ's failure to address its recommendation that divestiture represents the most accurate means of valuing stranded costs. Divestiture provides both a market-based evaluation of stranded costs and an objective, effective mitigation mechanism. NJPII argues that administrative determinations of stranded costs are inherently flawed and should be rejected. This is especially evident in the potential for disparate evaluations of stranded costs for single units jointly owned by the State's utilities, and the resultant disparate impacts upon ratepayers in different parts of the State for the same stranded costs. The forecasts underlying previously approved above- market NUG contracts are further evidence of the failure to accurately predict future energy prices; the same mistake should not be made through an administratively-determined valuation of stranded costs. NJPII asserts that divestiture bears great potential for the near total elimination of stranded costs, as new power BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -23- 26 suppliers are willing to pay a premium for market entrance. NJPII urges the Board to adopt policies that encourage utilities to divest their generating assets. NJPII takes exception to the ALJ's failure to rule on its recommendation to disallow nuclear decommissioning costs from the stranded costs valuation. The extension of stranded costs recovery to nuclear decommissioning costs would shelter nuclear generation from the market and provide plant owners a competitive advantage over other generators. Further, the provision of stranded costs recovery may permit the utility to keep in service plant that would otherwise be uneconomic. NJPII argues for continued utility recovery of nuclear decommissioning costs through rates only up to the date that competition begins, after which they should be treated like fossil fuel plants with such going forward costs ineligible for stranded costs recovery. NJPII takes exception to the ALJ's finding for $397 million in stranded generation costs, given his conclusion that ACE failed to meet its burden of proof justifying stranded costs treatment for its post- rate case capital additions. NJPII argued on brief that $30 million in Salem costs incurred since the 1995 shutdown and $79 million in scrubber costs for B.L. England should be excluded from stranded costs recovery. To account for the exclusion of these two post-rate case capital additions would require an adjustment to the book values for wholly and jointly owned generation found by the ALJ, and a resultant reduction to the $397 million level of stranded generation costs to a corrected level of $288 million. NJPII takes exception to the ALJ's failure to explicitly exclude stranded NUG costs from his 50% cap on securitized assets. NJPII argues that the securitization of NUG costs would effectuate the imposition of incremental interest costs on ratepayers where no such interest costs currently exist. Additionally, securitization of NUG costs would lock the estimated contract obligations into debt obligations where currently such contract obligations fluctuate with market prices. NJPII argues that these contracts should instead be collected over their terms. To the extent that the Board authorizes securitization of stranded costs, the proceeds should be used to buy down NUG contracts and not to subsidize other activities of the Company, consistent with the Final Report. 6. New Jersey Industrial Customer Group and New Jersey Business Users NJICG and NJBUS filed joint exceptions to the ID which extensively criticize the findings and conclusions of the ALJ. NJICG and NJBUS point to both the lack of findings on a number of substantive issues and the ALJ's lack of discussion or consideration of the evidence and arguments proffered by NJICG and NJBUS via the expert testimony of Dr. Rosenberg and on brief. NJICG and NJBUS concur with the ALJ's finding that ACE's claim to full stranded costs recovery on the basis of a regulatory compact is without legal merit and should be rejected. However, NJICG and NJBUS take exception to a number of specific stranded costs findings of the ALJ including the finding that ACE's market price forecasts appear reasonable. NJICG and NJBUS argue that ACE's forecast of future market prices is severely flawed and should be rejected. The Company's forecast utilizes wholesale rather than retail market prices, thus overstating the level of stranded costs. Further, the Company's use of a production cost model to forecast optimal marginal costs as a proxy for future market clearing prices results in an BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -24- 27 underestimation of energy prices and an overestimation of stranded costs. NJICG and NJBUS argue that ACE's use of CT costs as a proxy for market capacity costs is not well suited to a competitive market and may underestimate the cost of building new capacity. Further, NJICG and NJBUS adopt the criticism leveled by BWG that ACE failed to incorporate asset values other than the commodity cost of energy; such unaccounted for services include payments for congestion management and various ancillary services, resulting in understated market generation value estimates and overstated stranded generation costs. NJICG and NJBUS agree with the use of ACE's free cash flow approach, but recommend use of the 8.48% after-tax cost of capital as the discount rate for determining the net present value. ACE employed a 9.71% pre-tax cost of capital as the discount rate despite the fact that the cash flows themselves are stated on an after-tax basis. ACE's approach understates the present value of the cash flows and results in an overstatement of stranded costs. The ALJ did not render a specific determination on this issue; thus, NJICG and NJBUS recommend that the Board adopt their proposed after-tax cost of capital as the appropriate discount rate. NJICG and NJBUS take exception to the ALJ's failure to address what they deem to be the essential issue related to stranded costs recovery implied in the Freehold decision, namely, whether ACE can absorb stranded costs associated with NUG contracts. This issue is different from a mandate that the utility renegotiate NUG contracts, which is proscribed under Freehold; rather, it goes to the question of whether ACE can continue to recover all such costs from its ratepayers, an issue assertedly not addressed in Freehold. NJICG and NJBUS argue that the Final Report provides that the non-mitigatable portion of NUG contracts are eligible for, but not guaranteed stranded costs recovery. Indeed, the Final Report explicitly states that there is no guarantee for 100% recovery of eligible stranded costs, and that the opportunity for such recovery is constrained by other restructuring objectives such as rate reductions. If ACE is unable to achieve its rate reduction requirements through mitigation, then all stranded costs, including NUG costs, should be subject to disallowance. Further, NJICG and NJBUS argue that ACE executed at least one NUG contract with an operator outside of its service territory, a contract for 75 mw with Delaware Resource Management, Inc., located in Chester, Pennsylvania. NJICG and NJBUS assert that the Public Utilities Regulatory Policy Act ("PURPA") did not obligate purchases from entities outside of a utility's service territory; thus, the stranded costs associated with such NUG contracts should be excluded from stranded costs recovery. Another issue raised by NJICG and NJBUS, but not addressed in the ID, regards the recommendation to deny any return on unamortized stranded costs; ACE applied a full return on equity to these balances. Stranded costs are, by definition, not used and useful plant; moreover, the Final Report identifies a reduced return on uneconomic assets as a means of mitigating stranded costs. The denial of a return on this investment will encourage ACE to divest the assets and thereby effect stranded costs mitigation. NJICG and NJBUS urge the Board to reject ACE's full return on stranded investment. NJICG and NJBUS urge the Board to subject ACE's MTC to true-up consistent with the Final Report. ACE failed to incorporate such a reconciliation provision in its proposal and stated a number of difficulties with its implementation. NJICG and NJBUS argue that these objections are insignificant and offer no justification for abandoning the Final Report's requirement. NJICG and NJBUS witness Dr. Rosenberg testified to the mechanics of such a reconciliation mechanism for both stranded generation and NUG costs, demonstrating how both the MTC and NNC may be simply reconciled as BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -25- 28 actual market values are realized. The ID is silent on the issue and on NJICG and NJBUS's recommendations. NJICG and NJBUS urge the Board to adopt their recommended annual reconciliation mechanisms applicable to stranded generation and NUG cost recovery. NJICG and NJBUS take exception to the ALJ's failure to find that ACE did not comply with the Final Report with respect to the design of the MTC and NNC. Specifically, ACE's final filing did not state initial rate levels for the MTC and NNC, while its original filing did include such projected rates. NJICG and NJBUS urge the Board to direct ACE to provide calculations of its proposed MTC and NNC charges. Furthermore, NJICG and NJBUS recommend that the Board adopt their proposed three-year MTC period which will assertedly permit the introduction of "pure competition" in the territory faster than would the eight-year MTC period recommended by ACE. Regarding the NNC, NJICG and NJBUS recommend that it be limited to an initial four-year term, at which point ACE could petition for its continuation, with authorization based upon a demonstration that it had not overrecovered other stranded costs and that it had made a good faith effort to mitigate stranded costs and encourage competition. NJICG and NJBUS urge the Board to adopt Dr. Rosenberg's revenue-neutral MTC and NNC rate designs. NJICG and NJBUS take exception to the ALJ's failure to address the numerous stranded costs mitigation measures offered by the parties; the ID only addresses ACE's ongoing efforts to renegotiate NUG contracts. The Final Report admonishes utilities to employ all reasonable means of mitigating stranded costs and lists a number of specific mitigation measures that may be used. Despite this directive, ACE cited its past practices of prudent management and cost control that are generally unrelated to stranded costs mitigation. The only prospective mitigation measures identified by ACE are its continued efforts to renegotiate NUG contracts - the fruits of which total a meager $6 million saving to NUG costs - and securitization. NJICG and NJBUS argue that the lack of a substantive future mitigation strategy within the filing constitutes noncompliance by ACE with the requirements of the Final Report. NJICG and NJBUS urge the Board to order ACE to engage in specific mitigation efforts, including divestiture of owned generation with the possibility for sharing proceeds with shareholders if assets are sold at prices significantly in excess of book values; otherwise, NJICG and NJBUS urge that such divestiture proceeds be used to reduce the stranded costs balance. Additionally, NJICG and NJBUS recommend that revenue derived from the Company's provision of customer energy services during the transition period be credited to the stranded costs balance; that ACE renegotiate the Pedricktown Cogeneration Limited Partnership NUG contract given that its affiliate, Atlantic Generation, holds a 50% interest, or face exclusion of the entire affiliated portion of the contract from stranded costs recovery(4); and that the Board deny a return on unamortized stranded costs balances. NJICG and NJBUS take exception to the ALJ's failure to find ACE's rate reduction proposals inadequate in light of the Final Report's requirement for a near-term rate reduction of between 5 and 10%. ACE's proposed reduction does not meet the minimum 5% when measured against NJICG and NJBUS take exception to the ALJ's failure to find ACE's rate reduction proposals inadequate in light of the Final Report's requirement for a near-term rate reduction of between 5 and 10%. ACE's proposed reduction does not meet the minimum 5% when measured against - --------------------------- (4) Dr. Rosenberg proposed that the portion of NUG purchases from Pedricktown that are attributable to ACE's affiliate be excluded from stranded costs recovery because these costs can be mitigated. For example, Atlantic Generation may transfer its above market profits back to ACE, thereby mitigating its stranded costs, while retaining a margin for itself. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -26- 29 April 30, 1997 rates. Its proposal to reduce rates by 2% as a result of securitization will likely produce a maximum of a 1% rate reduction; the assumed 1.75% reduction associated with NUG renegotiations is speculative; and the final 4% reduction associated with expense reductions is speculative and would, if the savings were in fact realized, be implemented too late to effect the mandated minimum rate reduction. NJICG and NJBUS argue that the rate reduction be implemented by reducing the MTC and NNC to levels necessary to achieve the desired rate reduction. ACE could sustain an additional 10% rate reduction on top of the 2.2% reduction that Dr. Rosenberg estimates from the merger savings and securitization components of ACE's proposal. Such rate reduction would require ACE to absorb approximately $96 million of eligible stranded costs and would reduce rates for most rate classes by 8.8% to 13.7%. The incremental 10% rate reduction would allow ACE to maintain an investment grade BBB bond rating assuming that the Company takes certain steps consistent with business practices in competitive markets. NJICG and NJBUS concur with the ALJ's finding that ACE be permitted to securitize a maximum of 50% of its stranded costs. However, NJICG and NJBUS argue that the ALJ should have found ACE's proposal inadequate to justify any use of securitization at this time. While the Company apparently intends to securitize all of its stranded costs, it did not proffer a specific proposal for consideration in the proceeding. The Board cautioned that securitization not be viewed as a panacea but as part of the solution for stranded costs; it established an "appropriately high" burden of proof on the utilities for justifying the use of securitization given the immutable ratepayer commitments embodied in securitized debt. ACE did not present a comprehensive securitization proposal in its filing. What little the Company provided does not meet the Board's exacting standards. NJICG and NJBUS argue that until such time that a detailed securitization proposal is filed and revised, the Board should withhold approval of securitization as a stranded costs mitigation measure. NJICG and NJBUS take exception to a number of the ALJ's findings regarding rate unbundling. On the issue of the COSS, they assert that the ALJ's decision to utilize ACE's study, filed February 1998, should be rejected on the basis that it is not the 1988 COSS prescribed by the Final Report for use in unbundling current rates and that the Board's decision on interlocutory review in the GPU proceeding supports the rejection of the ACE COSS. NJICG and NJBUS take exception to the ID's failure to find ACE in noncompliance with the Final Report for not filing an unbundled rate design in timely fashion. ACE filed a summary of its unbundling proposal by the July 15, 1997 deadline, but delayed the requisite complete filing until two weeks prior to the commencement of hearings, providing an insufficient period for review by the parties. NJICG and NJBUS thus urge that the Board provide no weight to the Company's February 5, 1998 rate unbundling filing; the Board should require the Company to resubmit its unbundled rate filing and provide a substantial period for its review by the parties. NJICG and NJBUS cite the Final Report's prescription that only FERC-approved transmission rates be used in a utility's rate unbundling. Whether ACE in fact complied with this requirement is unclear and the issue is not addressed in the ID. Dr. Rosenberg's limited review of ACE's untimely filing indicated that the Company utilized its current FERC transmission rate revenue requirement rather than revenue generated from the previously approved rate; the difference was apparently shifted to distribution charges. NJICG and NJBUS argue that these excess transmission revenues should either be absorbed by ACE or be made the subject of a distribution rate case. NJICG and NJBUS further argue that ACE's functionalization of 69 BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -27- 30 kilovolt ("kv") facilities within the transmission component in anticipation of FERC's prospective designation of these facilities as transmission and not distribution related is premature and should be rejected. Only those facilities currently designated as transmission by the FERC should be functionalized to the transmission revenue requirement. B. Reply Exceptions 1. ACE ACE replies to the exceptions of several parties with respect to stranded costs, rate unbundling and rate reduction issues arising in this proceeding. The Company maintains that the restructuring of the electric utility industry has not altered its legal right to a full recovery of and return on its investments. The Company asserts its constitutional right to full recovery of stranded costs, a right that it maintains is based upon settled New Jersey law and a regulatory compact that, until this proceeding, has not been questioned. ACE urges the Board to reject the arguments of the RPA, Staff and other parties whose recommendations either explicitly or implicitly abridge the Company's legal right to full recovery of stranded investment. The Company asserts that customer rate reductions should be the product of competition, not the product of illegal confiscations of property or earnings of the Company. The Company asserts that all of its investment is used and useful in the current provision of service to its customers. ACE owns the same generating capacity today as it did when rates were set in the 1991 base rate case, during which the prudency standard was most recently applied. ACE addresses the case law raised by the RPA in its exceptions, arguing that it either supports the Company's position or is simply not relevant to the fundamental legal issue raised in the debate over stranded costs recovery: Can the Board legally deny the recovery of a utility's assets that are being employed to meet the service requirements of its customers? ACE refutes the RPA's argument that utility shareholders have always been cognizant of the potential for recovery disallowances and have been adequately compensated for that risk. To the contrary, utility shareholders have been afforded returns on investment at levels lower than those realized in competitive markets in exchange for a greater, not lesser, certainty of recovery. The Board's awarding of lower than competitive market returns to ACE shareholders means that they have not been compensated for the risk that their investments could be denied recovery. Instead of assessing the historical returns earned by ACE's shareholders against short-term treasury bills, as the RPA has done, a more appropriate comparison made with the Standard and Poor's 500 stock index reveals that the Company's shareholders have earned substantially less than competitive market returns. Rather than seeking a guaranteed recovery of all of its stranded costs, as the RPA characterizes the Company's position, ACE seeks the same reasonable opportunity to recover its investments, with a fair return, to which it is currently entitled; once stranded costs are appropriately determined and competition ensues, the risk for the recovery of that level of investment will rightfully shift to the shareholders. ACE urges the Board to reject the positions of the RPA, Staff and NJPII regarding the Company's divestiture of stranded generation assets and uphold the ALJ's finding that ACE has properly determined its stranded costs. Once an administrative determination of stranded generation cost is made, it should not be subsequently revised to reflect actual future sale BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -28- 31 prices; rather, ACE argues that its shareholders would bear the responsibility for the loss or gain resulting from the sale. The Company replies to a number of recommendations made by other parties regarding the composition and calculation of stranded costs. ACE maintains that nuclear decommissioning costs represent a substantial liability that is incurred even before the commercial operation of a nuclear unit, that the Board approved the ongoing recovery of these costs, and that their recovery should not be altered without the benefit of a full proceeding to examine the policy, factual and legal implications of the issue. NJPII's recommendation for the disallowance of nuclear decommissioning costs should therefore be rejected. Fossil decommissioning costs, although not as yet recovered in rates, are inherent to the Board approved construction and operation of such units. Their disallowance from stranded costs and prospective rate recovery would cause ACE shareholders to unfairly bear these costs; NJPII's recommendation to disallow these costs from the stranded costs valuation should also be rejected. ACE argues that the RPA mischaracterizes the ALJ's finding regarding the exclusion of post-rate case capital additions from stranded costs recovery. Rather than recommending the disallowance of all such costs, ACE argues that the finding refers to the disallowance of a specific project, though it concedes that the finding is ambiguous. The ALJ did not discuss the individual capital projects in light of the market test and record evidence, nor did he address the fundamental issues raised by ACE regarding the reasonableness or substantive standards comprising such market test. Given the lack of substance in the ID on this issue, ACE urges the Board to reject any disallowances of post-rate case capital additions. ACE points to the IDs issued in both the GPU and PSE&G proceedings to support its argument that capital additions that are not major investments and are incurred for the continued operation and maintenance of plant are not subject to the market test. ACE urges the Board to include all post-1991 capital additions in the stranded costs valuation. ACE replies to the recommended exclusions of certain purchased power and NUG contract costs from stranded costs recovery raised in the exceptions of other parties. The Company argues for rejection of the RPA's recommendation to exclude PECO contract costs, stating that the PECO contract replaced a higher cost purchased power agreement and thus served to mitigate stranded costs. ACE urges rejection of the NJICG/NJBUS recommendation for the exclusion of the costs of the Delaware Resource Management Inc. ("DRMI") NUG contract on the basis that its location did not require ACE's purchase of DRMI power. ACE maintains that FERC requires that a utility purchase NUG power made available to it, even if that power is generated outside of its service territory. Citing FERC Order No. 69, the Company asserts that it was indeed obligated to purchase the DRMI power. Furthermore, the contract was a direct product of the Board's Standard Offer process that ACE was required to implement and it was under the auspices of that process that the Board approved the contract in 1989. ACE urges the Board to reject the RPA's recommendation for the arbitrary disallowance of 20% of NUG contract costs in anticipation of the achievement of mitigation measures that the Company perceives as unrealistic. ACE rejects the notion that such disallowance will serve as an incentive to mitigate these contracts; given the lack of incentive on the part of the NUG contract holders to voluntarily reduce their prices, the RPA's recommendation would likely effect an illegal disallowance. ACE urges rejection of NJICG/NJBUS's recommended disallowance of a portion of stranded costs associated with the Pedricktown NUG contract. ACE argues that it BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -29- 32 controls neither the project nor the activities of its affiliate, Atlantic Generation. Furthermore, the Pedricktown contract was also approved as a product of the BPU's Standard Offer process and any disallowance would constitute a breach of ACE's legal right to recover its costs. ACE urges the Board to adopt its position that it will continue its attempts to mitigate NUG contracts, but that failure to do so should not result in a stranded costs disallowance. ACE replies to the exceptions of certain parties regarding the appropriate method of calculating stranded costs. The RPA's argument for use of an 8.25% discount rate should be rejected and the Board should adopt the ALJ's finding for use of ACE's most recently approved 9.71% cost of capital as the discount rate in the stranded costs calculation. ACE argues that assumptions of the cost of capital should not be modified outside of a base rate case and that the RPA substantially erred in its derivation of the 8.25% recommended discount rate. The Company objects to NJICG/NJBUS's recommendation that stranded costs not receive any rate of return because the assets are assertedly not used and useful, a measure that ACE characterizes as an illegal disallowance that would jeopardize its financial integrity. NJICG/NJBUS's recommendation for use of an after-tax cost of capital to discount future cash flows should also be rejected because it would inappropriately double count the benefits of the deductibility of interest associated with long-term debt. ACE urges rejection of the NJICG/NJBUS recommendation that the relevant market price for energy is the retail rather than the wholesale price used in the Company's forecast. ACE cites the similarity in the results of the market price forecasts of the RPA, BWG and the Company as support for the ALJ's finding for use of its forecasts. The Company explains the wide disparity in forecasts alleged in the RPA's exceptions by pointing out that the RPA, unlike the Company and BWG, excluded post-rate case capital additions in its derivation of net stranded costs. Thus, the disparity between approaches lies within the resultant net stranded costs derivation, not in the similar energy and capacity forecasts which serve as one component of that derivation. The market clearing prices produced under the ACE and RPA methodologies are similar and there is no compelling factual basis upon which to reject the finding that ACE's forecasts be used. ACE asserts that the RPA has mischaracterized the ALJ's finding that the Company's O&M costs are significantly overstated. The Company argues that the RPA and Staff mistakenly presume a continued downward trend in the cost of O&M; ACE argues that O&M costs will escalate at the rate of inflation and that its demonstrated substantial reduction to these costs since the early 1990's cannot be sustained into the future. Having achieved such cost reductions, ACE maintains that similar prospective reductions cannot be achieved without jeopardizing the safety and reliability of the generation system. Rather, the Board should recognize the Company's achievements in O&M cost reductions and adopt a prospective growth rate for these costs based on inflation. ACE replies to the RPA's recommendation that it write off $245 million of stranded costs as a means of funding the RPA's recommended 10% rate reduction. The RPA's recommendation lacks sound financial support, and would have a substantial negative impact upon the Company. ACE cites the ALJ's acknowledgment of this and his comment that such result would not be desirable. The RPA's use of market-to-book ratios to justify the write-off is flawed, and the Board has never recognized the relevance of market-to-book ratios as a justification for either rate reductions or write-offs. Furthermore, the internal assumptions employed in the BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -30- 33 RPA's market-to-book analysis are substantially flawed in a number of areas, and ratios are thus inappropriate measures for assessing whether ACE can absorb the RPA's recommended write-off of stranded costs. ACE points to the testimony of NJICG/NJBUS which acknowledged that their recommended write-off of $96 million would reduce the Company's cash flows to levels that would drive its securities below investment grade. ACE asserts that the Board's adoption of the RPA's recommendation would cause disastrous financial harm to the Company and deprive it of the ability to continue to provide safe, adequate and proper service to its customers. ACE reasserts its argument against limiting the potential benefits of securitization by capping its use at a maximum of 50% of stranded costs. Characterizing the Board's cap as a preliminary statement on the issue, ACE urges that it be permitted to securitize up to 100% of its stranded costs. ACE views the RPA's recommendation to limit securitization as one that would cause harm to ratepayers by denying them the benefit of lower rates generated by securitization. Since securitization provides the potential for further rate reductions and stranded costs mitigation, it does not make sense to condition its use upon meeting required rate reduction levels or fully mitigating stranded costs. Parties who advocate the conditional authorization to employ securitization are thus viewing the issue backwards: securitization would reduce an otherwise higher level of stranded costs recovery. Securitization is a means of reducing costs not to be confused with the determination of stranded costs. ACE argues that the RPA misunderstands its proposed securitization of NUG stranded costs, believing that ACE seeks to securitize the administratively- determined amount of these stranded costs. Rather, ACE affirms that its proposal is to securitize the cost of NUG buyouts and buydowns after such cost are actually determined via negotiation. ACE urges the Board to reject the arguments of the parties against full utilization of securitization and authorize the Company to securitize up to 100% of its net stranded costs. ACE replies to the criticisms of other parties regarding its COSS contained in its unbundling filing. The RPA has failed to draw a relevant nexus between the 1988 COSS and the rates that were stipulated in that base rate case; ACE maintains that the parties' stipulation of rates in the 1991 proceeding made no reference to a COSS, rendering the necessity of employing the 1988 COSS moot for purposes of this proceeding. ACE points to the testimony of RPA witness Dr. Stutz that the results of at least three COSSs are reflected in the 1991 stipulated rates. The RPA's assertion that cost shifts are evident between generation and other functions belies the fact that generation costs have, as a percentage of total plant, remained relatively the same between 1988 and 1996. ACE refutes a similar argument of Staff in its exceptions that cost shifts from generation to other functions can impact upon unbundled rates. ACE maintains that these apparent cost shifts are fundamentally the product of ACE adding no new investment in generation plant over the subject time period; incremental supply requirements during the period were met with the 569 mw of NUG capacity contracted since the 1991 rate case, which costs are not reflected in the Company's generation plant in service. The RPA's and Staff's lack of consideration for this fact has led both parties to conclude a questionable cost shift that has actually not occurred. ACE replies to Staff's recommended use of the authorized rate of return to set unbundled rates rather than the current actual return produced by the Company's rates. The Company maintains that the Staff's recommendation would violate the revenue neutrality directives of the Board by shifting revenue requirements between production and non-production related rates. Staff's recommended classification and allocation of non-production plant should be rejected since they are based on a 1993 Board decision in a GPU base rate BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -31- 34 proceeding; the appropriateness of their application to ACE's costs can not be determined outside of a base rate case. Regarding its proposed unbundled rate design, ACE defends its proposed MTC and NNC against the arguments of parties made in exceptions. ACE replies to the parties that have alleged that the Company has failed to comply with filing requirements by not proposing a specific MTC and NNC. ACE reasserts its argument that it has proposed rate design methodologies for these charges but is unable to specify meaningful numerical charges until such time that the underlying stranded costs have been determined and the issues surrounding securitization have been resolved. The proposed NNC is designed to recover actual above market NUG costs, with annual adjustments to reflect credits for the actual sale of NUG energy and capacity in the competitive marketplace. NJICG/NJBUS's argument that this approach presents an opportunity for overrecovering NUG costs is flawed and their recommended true-up mechanism is unwieldy and unnecessary. The MTC will be set on the basis of net stranded generation costs but will be offset to reflect final securitization levels and rates reflected in the securitization charge. ACE argues that this is a rational approach that does not constitute noncompliance. ACE argues against the RPA and Staff recommendations for a rate cap approach in setting unbundled rates through the transition period. ACE argues that this approach would afford ratepayers protections that they do not currently enjoy under regulation and would certainly not be afforded in a competitive market. ACE urges rejection of this effort to insulate ratepayers and recommends that the Board allow rates to follow increases and decreases in the competitive market. Further, the rate cap approach could effectuate unjustified stranded costs recovery disallowances through the transition. 2. Ratepayer Advocate The RPA replies to a number of exceptions raised by ACE regarding stranded costs, rate reductions and rate unbundling. Regarding the Company's assertion that it possesses a legal right to recover stranded costs, the RPA maintains that ACE cannot cite to a single statute, case law or Board Order establishing this right on the basis of the regulatory compact. Though extant law provides ACE with a reasonable opportunity to recover prudently incurred investment and fair return, there is no guarantee for the full recovery of stranded costs. ACE's attempt to introduce scholarly support for its position through the introduction of a law review article, after the close of the record, authored by Sidak and Spulber on the theory of the regulatory compact represents hearsay evidence and should be given no weight. In its exceptions, ACE cites United States Trust Company of New York v. New Jersey, 431 U.S. 1, 97 S. Ct. 1505 (1977). The RPA maintains that the holding in that case is inapposite to the instant proceeding: in U.S. Trust Company, the issue was whether the State could repeal an existing state law which guaranteed bond investors revenues to meet the bond obligations. There, bondholders had the right to 100% recovery of their investment written into state law. ACE's equity holders have never been similarly guaranteed a return on their investment by the state of New Jersey through legislation. The RPA reiterates its earlier arguments opposing ACE's claim that anything less than 100% recovery of stranded costs constitutes confiscation in violation of the Fifth and Fourteenth Amendments to the U.S. Constitution. The Company's cites to State Farm Mutual Ins. Co. v. State, 124 N.J. 32, 48 (1991) and Valley Road Sewerage Company Request for BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -32- 35 Approval of an Increase to its Rates for Sewer Service, 285 N.J. Super. 202 (App. Div. 1995) support the conclusion that utilities have a right to a reasonable opportunity to recover costs in rates, not that the grant of a franchise guarantees a 100% return. The RPA asserts that, contrary to ACE's claim made in its exceptions, the ALJ has found for a level of stranded costs that is less than $1.2 billion. The RPA bases this conclusion on the ALJ's findings that certain costs incurred subsequent to the Company's last base rate case should be disallowed from stranded costs recovery. The RPA argues that the ALJ excluded from the total potential $397 million generation stranded costs recovery the following amounts: $318 million of post-rate case capital additions; $38 million associated with the generation component of the FAS-109 regulatory asset; and $19 million of fossil decommissioning costs. Further, the ALJ found for use of the RPA's fuel cost forecast for ACE's generating units and found that the Company's growth rate for O&M costs is incorrect. ACE's assertion on exceptions that it is unclear from the ID how much of the Company's post-rate case capital additions should be excluded from stranded costs recovery is erroneous. The ALJ's finding is clear in its exclusion of the entire $318 million of post-rate case capital additions based upon the Board's prescription for the presumptive exclusion of such costs pending a clear demonstration that such capital projects represented the least cost alternative available at the time. ACE did not meet this heightened burden of proof, offering no credible evidence to support the inclusion of any of the subject capital projects in the stranded costs valuation. The RPA argues that the ALJ's alleged lack of discussion of the merits of these projects in the ID properly reflects the fact that he was presented with no evidence by ACE to consider inclusion of any of the capital additions. ACE's argument that the market test standard only applies to new plant additions, and not to capital projects engaged to maintain existing plant, should be rejected for lack of credible legal argument; nowhere in the Final Report or subsequent clarifying Orders is the market test exemption for plant maintenance stated. The RPA replies to ACE's argument in its exceptions that the ALJ improperly excluded the $38 million generation component of the FAS-109 regulatory asset. The ALJ properly excluded these costs because they are not currently being recovered in rates and should therefore not find their way into stranded costs recovery. Furthermore, the Final Report provides for the recovery of regulatory assets through the utility's regulated rates. The RPA asserts that ACE has offered no new argument to support its position that the ALJ erred in excluding fossil fuel decommissioning costs from stranded costs. These costs were properly excluded pursuant to the Final Report's prescription that generation related costs incurred after the introduction of competition are fully subject to market risk. ACE's arguments that prospective revenues will be insufficient to cover decommissioning costs is unsupported in the record; the Company employed speculative decommissioning estimates that did not consider the residual value of the plant sites, which could be used for a variety of revenue generating purposes. The RPA points to utility commission decisions in other states that have ruled to exclude such costs from stranded costs valuations. The RPA urges the Board to uphold the ALJ's finding on fossil decommissioning costs exclusion. The RPA agrees with the ALJ's finding that rejects use of ACE's O&M cost escalation rate, but concurs with the Company's criticism that the ID failed to recommend an alternative. Further, the RPA points to the ALJ's failure to discuss other O&M cost assumptions used by ACE that serve to inflate the overall stranded costs determination. ACE erred in assuming a general upward trend in O&M and by including such expense adders as fringe benefits, fuel handling, BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -33- 36 A&G, PJM membership fees and other costs. The RPA replies to ACE's claim made in its exceptions that it has reduced its O&M costs to the bare minimum by pointing to the Company's own five-year (1997-2001) forecast which indicates that forecasted O&M expenses will be "significantly lower than historic levels." Furthermore, ACE witness Goetz testified that ACE has initiated cost cutting measures in anticipation of competition. ACE's claim that O&M reduction assumptions below those contained in its forecast will jeopardize safety and reliability thus contradicts the testimony of one of its own witnesses. The Company's failure to provide detailed information regarding its O&M adders until its rebuttal testimony left the parties little opportunity for meaningful discovery; thus, the Board should reject ACE's recommended O&M adders. The Board should adopt the RPA's recommended O&M forecast, including its 0.2% productivity factor. The RPA asserts that the reasonable proximity in the results of the Company's and RPA's market clearing price forecasts should not be the basis for the Board's adoption of the ALJ's finding for the ACE forecasts. The RPA argues that the cost inputs used in its forecasts, notably those associated with fuel costs and the cost of new capacity, most accurately reflect such costs in the prospective competitive environment. The Board's potential reliance on the forecast methodology in the future, rather than the simple reliance upon its results for this proceeding only, requires the selection of the most accurate inputs and methodology. Accordingly, the RPA urges the Board to adopt its forecast method and underlying assumptions for use in estimating prospective market prices. The RPA replies to ACE's continued reliance in its exceptions on past cost reduction initiatives as evidence of stranded costs mitigation efforts. The Company has failed to advance specific mitigation measures contrary to Final Report directives to do so. Contrary to ACE's assertion, the ALJ did not reject the RPA's recommended mitigation measures but only failed to render determinations regarding their use. Similarly, ACE misinterprets the ALJ's failure to rule upon RPA witness Rothschild's cost of capital recommendation as a rejection of the proposal. The RPA further argues that ACE has misconstrued Rothschild's testimony to suggest that the RPA recommends that ACE should take a $245 million write-off of stranded costs. The RPA argues that its position is merely that the Board could order a write-off of up to $245 million without significantly impacting the Company's financial health. Regarding mitigation of NUG stranded costs, ACE misinterprets the RPA's proposal to set the initial NNC at a level that assumes the future achievement of mitigation efforts. ACE improperly characterizes this RPA recommendation as a disallowance that would violate the holding in the Freehold case. The RPA points to Staff's recommendation on determining stranded NUG costs as fundamentally consistent with its own. The RPA urges the Board's adoption of its recommended NUG mitigation proposal. Regarding securitization, the RPA replies to ACE's argument that the Board should approve up to 100% securitization of stranded costs. The RPA characterizes the ACE proposal as an effort to insulate its shareholders by shifting the burden for stranded costs recovery to its ratepayers through a statutory obligation to pay down the securitized debt. Because the level of stranded costs is only being estimated in this proceeding, the securitization of such amount would unfairly expose the Company's ratepayers to overpayments well into the future. Rate reductions should not be achieved utilizing an instrument that shifts the burden of cost recovery from shareholders to ratepayers. The Board should reject the Company's proposal for securitization of up to 100% of its stranded costs and the underlying argument that such authorization would enable the BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -34- 37 achievement of the mandated rate reduction. On the issue of the rate reduction, the RPA points to both the ALJ's lack of a specific determination, his failure to find ACE's proposal insufficient, and to the Company's failure to specifically address the issue beyond its argument for full securitization of stranded assets. The RPA cites the Staff's conclusion that ACE's proposed rate reduction falls short of the mandated reduction and urges the Board to render such finding. Finally, the RPA recommends that the Board find that ACE can implement the RPA's recommended 10% rate reduction, without suffering undue financial harm, at the outset of competition. Regarding the issue of the appropriate COSS used to unbundle rates, the RPA replies to the exceptions of ACE which continue to support the use of its 1996 vintage COSS. The RPA reiterates its arguments made on brief and through its exceptions, namely, that ACE's COSS violates the Final Report's prescription regarding the COSS used to unbundle rates, and the Company filed the COSS late in the process and made revisions to it which the parties had insufficient time to analyze. The RPA replies to Staff's position, taken in its exceptions, that the Final Report is ambiguous regarding the question of the vintage of COSS inputs, arguing that the Board was clear in directing that cost data used in the 1988 COSS be employed. The RPA points to the Board's decision on interlocutory review in the GPU proceeding to support its contention that the issue of COSS data vintage raised by the Staff is moot: i.e., the Board has directed the use of data which vintage corresponds to that used in the COSS from the utility's last base rate decision. In response to ACE's claimed inability to rerun the 1988 COSS due to the loss of that study, the RPA urges the Board to reject the Company's COSS and order it to perform a COSS that employs 1988 cost inputs utilizing a methodology previously approved by the Board. The RPA argues that ACE failed to provide the rate unbundling filing required in the Final Report. Citing similar conclusions reached by the Staff, the RPA asserts that the ACE's failure to unbundle the generation charge into discrete MTC, NNC and BGS components should be rejected by the Board. The Board should order ACE to re-file its unbundled rates with discrete charges identified for the functional categories and charges identified in the Final Report and which ensures revenue neutrality on inter and intra-class bases. Finally, the RPA replies to the tax issues raised by Staff for the first time in its exceptions, citing the lack of supporting testimony submitted during the proceeding. The RPA issues its preliminary response to these issues, but argues that should the Board decide to issue rulings on them, the parties should be afforded full opportunity to explore them within the context of supplemental hearings. The RPA takes issue with Staff's tax gross-up of both owned generation and NUG stranded costs, arguing that the purpose of this proceeding is not to render a revenue requirements determination but to determine the market value, book value and net stranded costs of the Company's plant. According to the RPA, Staff's gross-up of ACE's owned generation accounts for a $314 million overstatement in stranded generation costs. Regarding NUG costs, Staff erred in assuming a need to state on a revenue requirements basis costs that are pre-tax expenses to ACE. Moreover, ACE's request to recover on a dollar-for-dollar basis NUG contract costs over their terms, combined with the fact that the Board will not likely permit securitization of an administrative estimate of stranded NUG costs, renders the Staff's gross-up of NUG stranded costs academic. The RPA reserves its right to supplement its comments on this Staff proposal given the substantial economic impacts engendered within it. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -35- 38 IV. RESTRUCTURING PROCEEDING As noted above, evidentiary hearings were held before former Commissioner Carmen J. Armenti on certain identified restructuring issues from April 27, 1998 through May 28, 1998. This was followed by the submission of briefs and reply briefs on generic and non-generic restructuring issues. Key elements of the briefed positions of various parties with regard to certain specific, non-generic restructuring issues of relevance to the ACE filing are summarized hereinbelow, by issue. A. Basic Generation Service ACE did not propose a specific BGS rate, but rather has proposed a monthly and annual pricing option, whereby the Company will buy power, through a competitive bid process, from the wholesale market to supply BGS customers. The ACE BGS rate would be based on the monthly and annual bid price plus associated administrative costs. Under the ACE proposal, the BGS rate would change monthly or annually, depending on the option chosen by the customer. (ACE Initial Restructuring Brief ("lRB") at 66-70). ACE proposes that BGS be priced based on a pass-through of the market-based cost of supply which may increase due to market forces. ACE argues that customers today face price increases through the energy adjustment clauses and therefore, there is no reason to insulate customers from the effects of future market forces. (ACE Reply Brief at 46). The RPA proposes that all utilities solicit competitive bids for sufficient capacity and energy to supply BGS for an initial two-year period. The RPA proposes that energy suppliers would put in a bid to the local distribution company to provide energy and capacity for BGS for a two-year period. (Exhibit RA-13, at 49). The RPA indicates that this could include short-term, as well as portfolio purchases. The RPA asserts that this will ensure that BGS customers will benefit from a competitive energy market, and will also result in less price volatility than with a BGS price that fluctuates over a short time frame. The RPA points out that under its proposal there would be no need for a true-up, because the risk of market price fluctuations would be on the successful bidder. The RPA proposes that the BGS rate/shopping credit be based on a competitive bid process for both energy and capacity. (Exhibit RA-15, at 4). The RPA asserts that the competitive low bid, which should be reviewed by the Board, would become that utility's standard offer rate for generation under BGS, and would also need to include a retail margin encompassing administrative and general costs incurred serving retail customers, including a cost for marketing. The RPA argues that the competitive bid process will also provide the Board with a benchmark price for both energy and capacity, which will provide a starting point for the determination of the appropriate shopping credit, including a retail margin composed of marketing, A&G costs, ancillary services, advertising, taxes and profit associated with generation for customers who exercise their right to choose an alternative supplier. The RPA proposes that the shopping credit be set at a level that appropriately reflects ACE's generation costs to serve retail customers, and is sufficient to attract alternative energy suppliers. The RPA asserts that the ACE proposal ignores retail costs associated with providing BGS service. (RPA Reply Brief, at 26-27). BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -36- 39 Enron proposes that the rate for BGS should be the sum of the prices for the unbundled components of BGS, capped (after any Board mandated rate reductions) as approved by the Board. In Enron's view, the sum of these components would also become the shopping credit for those customers who choose to use an alternative energy supplier. (Exhibit Enron-35, pp.34-35). Enron defines the shopping credit for generation as the amount remaining after the individual prices for transmission service, distribution service, and intangibles (societal benefits, stranded costs, securitization bond charge, etc) are deducted from the total rate cap. Enron asserts that the shopping credit should equal the utility's fully embedded cost for generation less the market transition charge, which is a fixed charge. (Enron IRB at 104). Enron argues that in developing the shopping credit, in order to ensure that competition develops in New Jersey, the Board should impute a cost to the wholesale price of energy for BGS that bears a meaningful relation to the cost of electricity for retail customers. As such, Enron asserts that the shopping credit would be the benchmark against which customers would determine whether it is financially beneficial for them to remain with BGS or consider choosing an alternative supplier. Enron proposes a fixed shopping credit to ensure that BGS customers not only benefit from mandated rate reductions, but to also provide a visable, stable and predictable environment in which customers can compare BGS with proposals from alternative suppliers. (Enron Reply Brief at 49). MAPSA asserts that in order to set the proper generation rate, all components of retail cost must be reflected in the BGS rate. MAPSA indicates that the BGS rate will be the retail rate against which all suppliers will compete. As such, MAPSA asserts that the BGS rate should include the wholesale price of energy and capacity, as well as marketing and administrative costs involved in providing competitive retail service, thus reflecting the full cost of supplying electricity at retail. MAPSA indicates that these marketing and administrative costs would result in about a 0.4 to 0.5 cents per kilowatt-hour increase to the BGS rate. (MAPSA IRB at 28). NJBUS agrees with the structural approach of ACE, i.e., BGS should be regarded as a separate service, separately priced based on the wholesale cost of electricity and other costs related to BGS. (NJBUS Reply Brief at 29). NJBUS indicates that a BGS price based on market pricing without market distortions could be achieved by a fixed or express MTC for both customers who switch and those that are on BGS, coupled with BGS prices based on competitive bids for wholesale power, together with additional costs that reflect the full cost of providing retail generation service. Those additional retail costs include an allocated portion of embedded generation-related administrative and general costs, the procurement cost of the supply portfolio, and the costs of ancillary services, transmission and congestion charges directly related to the provision of retail generation service. (NJBUS IRB at 36). New Jersey Citizen Action indicates that, to the greatest extent possible, BGS pricing should be at the same level as the market clearing price, plus additional costs incurred by the LDC for purchasing electricity for BGS customers. (NJCA IRB at 13). Staff, in its Initial Brief, supports the concept advocated by several of the utilities in this proceeding by which the utility/basic generation provider would match supply commitments with customer commitments. (Staff IRB at 70). Proposed options include a monthly pricing option BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -37- 40 for customers who do not want a long term BGS commitment, where supply is purchased from the spot market, geared to customers to whom price stability is not of greatest concern and who will most likely choose to participate in customer choice; or an annual or a six-month fixed pricing option for customers not choosing to participate in customer choice, who are looking for price stability similar to that experienced prior to restructuring, where supply is purchased by the utility on either an annual or bi-annual contract. Staff points out that the aim of any matching concept is to have a portfolio of supply commitments that match customer commitments, both in terms of price paid versus the price received for power by the utility and the duration of the purchase commitments. Staff further indicates that under the matching concept there is a limited opportunity for a large under or over recovery of deferred balances to accumulate, thus limiting any distortion of the prices for basic generation service. Id. Staff maintains that price distortion has the potential to lead to gaming by market participants, and can otherwise send incorrect pricing signals to customers. Accordingly, it is Staff's position that, in order to provide a smooth transition to competition, the Board should require each electric utility to provide BGS customers the opportunity to select from either a fixed price option, or a monthly pricing option for BGS service. (Id. at 70-72). Staff, in its Initial Restructuring Brief, takes the position that the BGS price and/or the shopping credit should be based on market prices, resulting in BGS customers having access to market based pricing. (Staff IRB at 72). As such, Staff asserts that a BGS price and/or shopping credit that is based upon the market will most appropriately reflect the value of supply and therefore send the most appropriate price signals. Staff further asserts that a BGS price which reflects current market conditions will provide the most appropriate benchmark for comparison shopping by BGS customers considering offers from competing alternative suppliers. Staff asserts that the BGS price must equal the shopping credit, that is, the amount being charged for generation services being supplied by the utility must be the same as the amount deducted (e.g. credited) from the utility portion of the bill if the customer no longer takes generation service. Staff also shares the concern express by many of the alternative suppliers in this proceeding that a market-based BGS price or shopping credit must reflect the full cost of providing retail generation service and not simply reflect the wholesale price index. Id. at 75. Staff, however, points out that an artificial adder or margin should not be included in the BGS rate simply to stimulate the marketplace, since such artificial stimuli will only serve to distort the marketplace. Staff asserts that in order to provide alternative suppliers with a fair opportunity to compete, appropriate retail-related generation costs must be included in the BGS price as an adder to the wholesale cost of power. Id. B. Horizontal Market Power ACE argues that it neither has exercised nor will it be able to exercise, horizontal market power following the advent of retail competition, and that no party has presented conclusive evidence that ACE could exercise market power. ACE further asserts that FERC's oversight of the transmission system, combined with existing antitrust law as well as the BPU's authority over the distribution companies, will ensure against the exercise of market power. (ACE Reply Brief at 59). BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -38- 41 The RPA, relying upon the testimony of its witness Peter Lanzalotta and MAPSA witness Craig Roach, asserts that none of the electric utilities have complied with the Board's directive to supply a comprehensive market power analysis, since those submitted by the electric utilities are flawed. (RPA IRB at 112). The utilities have failed to evaluate any geographic regions smaller than PJM East. This failure leaves the Board with no record upon which to make findings regarding market power within the ACE service territory, or smaller markets which may exist within the ACE service territory. (RPA Reply Brief at 63). The RPA asserts that the record in this proceeding demonstrates a significant potential that, absent corrective action, one or more of New Jersey's incumbent electric utilities will be able to exercise horizontal market power within their service territories and in more localized areas. As such, in order to mitigate the potential for horizontal market power, the RPA urges the Board to direct each electric utility within New Jersey to submit a comprehensive market power analysis and mitigation plan, which should include divestiture, and to establish information reporting requirements and monitoring procedures. (RPA IRB at 121). Enron asserts that because serious issues exist regarding the potential exercise of horizontal market power by New Jersey's utilities, the Board should actively monitor the competitive marketplace as it develops and take all necessary steps to prevent the exercise of market power by the utilities both within New Jersey and the PJM control area. (Enron IRB at 132.) Staff asserts that on a region-wide basis and, importantly, based upon the current ownership configurations, there is no conclusive evidence of imminent market power problems in the PJM power pool. Staff recommends that an empirical market power study should be part of an ongoing regulatory monitoring process of potential or actual market power abuse, including a look at localized load pockets during certain hours. This monitoring process must include a cooperative effort of the Board and the PJM Independent System Operator ("ISO"). Staff asserts that the Board should obtain regular reports from the PJM ISO on information being obtained through its Market Monitoring Plan. (Staff IRB at 86-92). V. SETTLEMENT PROPOSALS By Order dated February 11, 1999, the Board, noting the enactment of the Electric Discount and Energy Competition Act, adopted a preliminary schedule to render decisions in the pending ACE and other electric public utility restructuring related proceedings. In so doing, the Board encouraged the parties in each of the litigated proceedings to attempt to negotiate a settlement, and established a preliminary deadline for the submission of any negotiated settlement, in advance of the Board's anticipated decision date. The time frame for the Board's decision and the deadline for the submission of any negotiated settlement was subsequently extended. A. Stipulation Filed by ACE and Other Parties Via letter dated June 9, 1999, ACE filed a Stipulation ("Stipulation I" or "Stipulation") on behalf of itself, IEPNJ, Enron, PP&L, and the NJCU ("the stipulating parties"). The key elements of Stipulation I are summarized as below: 1. The rate reductions shall be implemented as follows in compliance with N.J.S.A. 48:3-52(d). BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -39- 42 (a) The stipulating parties acknowledge that the Company's rates are already lower by a total of 1.3%, as a result of actions taken by the Board in recognition of the pending restructuring proceedings. This includes a January 1998 reduction of 1.2% to reflect the savings associated with the merger between the Company's parent and Delmarva Power and Light Company, less expenses due to post-retirement benefits other than pensions, and a June 1998 rate reduction of 0.1% as a result of the Board's decision to remove base rate expense items from the Company's rates during the 1997 LEAC proceeding. (b) An additional rate reduction of 3.9% from current rates as of August 1, 1999, to be achieved in part by offsetting $36 million of current regulatory asset charges with current DSM and LEAC credits, reducing charges for electric power to market levels, and setting the MTC at the necessary level to achieve the reduction. (c) Additional rate reductions after August 1, 1999 will be implemented to give effect to savings related to any NUG contract buyout or buydown, or securitization. (d) To the extent that the rate reductions provided for in paragraphs 1 (a), (b), and (c) do not provide an aggregate 10% rate reduction from April 30, 1997 rates, the Company will implement a rate credit for the period August 1, 2002 through July 31, 2003, to achieve, together with the earlier rate reductions, such aggregate 10% rate reduction from April 30, 1997 rates. (e) The parties recognize that it may be necessary to defer recovery of certain BGS, NUG or other costs, in order to achieve the rate reductions; such deferral will be subject to the provisions of paragraph 27 of the Stipulation. 2. The Company's agreement to the rate reductions and rate credit is based upon the Board's approval of the Company's divestiture of certain generating units, and securitization of 100% of the net stranded costs associated with those assets. 3. The four year period from August 1, 1999 through July 31, 2003 is referred to as the "Transition Period." 4. Unbundled rates have been developed using the Company's 1996 Cost of Service Study. Transmission rates are subject to FERC revision, either upward or downward; transmission rates and distribution rates are subject to revision, therefore, in order to maintain revenue neutrality with respect to the rates set forth in Appendix A. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -40- 43 5. Average shopping credits during the Transition Period shall be the greater of the following, or as determined pursuant to paragraph 6, inclusive of BGS rates and transmission rates:
- ----------------------------------------------------------------------------------------------------- Rate Class 1999 2000 2001 2002 2003 - ----------------------------------------------------------------------------------------------------- RS 5.15 5.20 5.20 5.25 5.30 RS-TOU 5.10 5.15 5.20 5.25 5.30 MS-Secondary 5.45 5.50 5.60 5.70 5.80 MS-Primary 5.28 5.33 5.43 5.53 5.63 AGS-Secondary 5.40 5.45 5.55 5.65 5.75 AGS-Primary 5.17 5.22 5.27 5.32 5.37 AGS TOU-Sec 5.15 5.20 5.25 5.30 5.35 AGS TOU-Pri 5.05 5.10 5.10 5.10 5.10 AGS TOU-SubTrans 4.30 4.30 4.30 4.30 4.30 AGS TOU-Trans 4.25 4.25 4.25 4.25 4.25 TGS 4.30 4.30 4.30 4.30 4.30 SPL/CSL 2.97 3.05 3.07 3.10 3.12 DDC 3.58 3.68 3.71 3.75 3.78 - ----------------------------------------------------------------------------------------------------- System Average 5.09 5.14 5.17 5.23 5.28 - -----------------------------------------------------------------------------------------------------
6. The Company shall provide BGS in the following manner: (a) BGS rates shall include the costs provided for in N.J.S.A. 48:3-57(a), including losses and taxes; (b) Customers who switch to an electric power supplier will not pay the BGS rate and will not be billed for transmission charges; (c) The sum of the BGS and transmission charges shall be the shopping credit. If the shopping credit for any rate class is the amount provided for in paragraph 5(a) of the Stipulation, the BGS rate for the class shall be the shopping credit less the transmission charge. If the BGS rate as calculated pursuant to paragraph 6(a) of the Stipulation, added to the average transmission rate, produces a shopping credit higher than that provided in paragraph 5(a), then such BGS rate and resulting shopping credit shall be utilized; (d) The calculated shopping credit, and resulting shopping credit, may be limited to the extent any portion of such BGS costs need to be deferred pursuant to paragraph 1(e) of the Stipulation; (e) Shopping-related savings, resulting from customers receiving electric generation service from a supplier at a price below the BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -41- 44 shopping credit, are above and beyond the rate reductions set forth in paragraph 1 of the Stipulation. 7. ACE shall procure power for BGS through an open, competitive bidding process. Through July 31, 2002, ACE plans to solicit proposals for the provision of wholesale power supply for BGS in twelve-month pricing cycles, or such other cycles as ACE deems necessary and prudent. ACE's plans for the RFP process will be submitted to the Board by September 15, 1999, and the RFP process will commence after Board approval, with the goal of concluding such process and entering into a BGS supply contract by December 15, 1999. The Company will apply NUG contract supply towards the BGS supply requirement and conduct the bidding process for the net BGS supply requirement. 8. Customers who switch from an electric power supplier ("EPS") back to BGS shall be required to remain on BGS for a minimum 12-month period; however a customer switching from one EPS to another may return to BGS for thirty days without being required to remain on BGS, however this exception is not available to any customer who returned to BGS and then switched to an EPS within the previous 12 months. However, any residential customer who returns to BGS due to the refusal or inability of the EPS to continue service to that customer shall not be required to stay on BGS for a minimum 12-month period. The Company may review with the parties and the BPU the need for a filing to request a separate residential billing tariff for the summer 2000 season and beyond, to avoid subsidies between seasonal and year round customers. 9. From August 1, 1999 until the time that BGS supply arrangements are made pursuant to the RFP process, the Company may have to procure supply for BGS through PJM, and the pricing shall be based upon capacity prices and locational marginal energy prices as reported by the PJM Office of Interconnection. Such prices shall also be used as the market value of NUG resources which may be employed for BGS, and for purposes of establishing the level of the NNC in accordance with paragraph 23 of the Stipulation. 10. The Company may utilize its affiliated service company to make arrangements for BGS supply, and such arrangements shall be conducted on behalf of the Company on a regulated basis. Neither the Company nor its affiliated service company shall provide information relevant to the provision of BGS service to any competitive affiliate of the Company, unless that information is provided contemporaneously to all others bidding to provide BGS service to ACE. The Company and the affiliated service company shall receive and maintain all BGS bids in a confidential manner, unless otherwise determined by law, regulatory act or agreement with the provider of the information. Any employees of the affiliated service company who transfer to any competitive affiliate of the Company shall be kept separate from any proposal by the competitive affiliate to provide BGS service to ACE. 11. The Company may, at its option, use energy and capacity obtained through "parting contracts," as described in paragraph 20, for the provision of BGS, and may utilize certain financial instruments, for example hedging, to decrease BGS customer exposure to price volatility. Although use of such financial instruments could result in costs which exceed the spot market, such costs, as well as other reasonably and prudently incurred costs associated with the procurement and provision of BGS, shall be recoverable in rates pursuant to N.J.S.A. 48:3-57(e). BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -42- 45 12. The Company has a minimum obligation to provide BGS through July 31, 2002. The responsibility for BGS for the fourth year of the transition period shall be bid out during the third year. The bids shall be based on the minimum shopping credits for the applicable periods as set forth in paragraph 5(a), and the bids shall provide for either (i) a payment by the bidder to the Company, to provide BGS at a price based on the minimum shopping credit described in paragraph 6; (ii) the provision of BGS at a rate which results in shopping credits for the applicable period, as set forth in paragraph 6; or (iii) a payment from the Company to the bidder if the winning proposed BGS rate is such that a portion of BGS revenues must be deferred. A net payment by the winning bidder to the Company shall be applied to reduce the balance of the Deferred Revenues pursuant to paragraph 27, or any other underrecovered balance. A net payment by the Company to the winning bidder shall be subject to deferral and subsequent recovery as part of Deferred Revenues, pursuant to paragraphs 27-29. At the conclusion of the Transition Period, BGS will no longer be offered by ACE. 13. A competitive affiliate of the Company may be permitted to bid to provide wholesale supply for BGS service, and to provide BGS service pursuant to paragraph 12, subject to affiliate relations standards to be adopted by the Board. If a competitive affiliate participates in any such bid, the Company and its affiliated service company shall utilize the services of an independent consultant to review the bids and present the results to the Company so as not to reveal which bid is from the competitive affiliate. 14. BGS bidding procedures shall be conducted on behalf of the regulated utility, and all competitive information relating to tendered bids shall be treated as proprietary and confidential, and shall not be made available to a competitive affiliate of the Company. 15. The Company shall not promote BGS as a competitive alternative. 16. The Company shall be permitted to recover 100% of its net stranded costs, including NUG contract stranded costs. 17. The Company has agreed, subject to the terms of the settlement, to divest its interests in the B.L. England, Keystone, Conemaugh, Peach Bottom, Salem and Hope Creek generating stations. The net divestiture proceeds will be used to determine Company's generation-related stranded costs, which shall be defined as the excess of net book value as of the closing date(s) of the sale(s) over net divestiture proceeds. Net divestiture proceeds are defined as the excess of the selling price(s) of the selling price(s) of the generating assets over the reasonably-incurred and verifiable and necessary transaction costs. 18. Final determination of the net divestiture proceeds shall be undertaken upon the completion of the transfer of all of the generation assets listed in paragraph 17 of the Stipulation. (a) Such final determination shall be made within a separate divestiture proceeding, to be filed by ACE pursuant to Board-established standards and pursuant to the terms of the Stipulation as approved by the Board. The final determination of the net divestiture proceeds shall constitute only a true-up of actual selling BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -43- 46 price(s), book value(s) and transaction costs, and not a further review on the merits of the transaction. (b) The Board Order in this matter shall constitute a Board determination that the transfer of the Company's generation and related assets to third parties will be approved by the Board in the future divestiture dockets without condition, addition or modification, at the agreed upon selling price(s), shall be considered "full market value" of the assets for purposes of N.J.S.A. 48:3-60(c)(i). The stipulating parties acknowledge that such transfers require various regulatory approvals or waivers. (c) With respect to the proceedings referenced in paragraph 18(b), IEPNJ, while supporting the divestiture concept, reserves its right to move before the Board to seek the review of any specific transfer of any generating asset listed in paragraph 17 of the Stipulation. (d) Any party who participates as a bidder in any sale conducted as part of such divestiture shall have the same rights as any other bidders in any Board proceeding concerning such sale. (e) Nothing in the Stipulation shall prevent any party from intervening in any such proceeding solely for monitoring purposes. 19. For purposes of timeliness, the Board will finalize divestiture standards applicable to ACE's generating assets within 30 days of a submission by the Company. 20. The use of parting contracts entered into by ACE with the purchaser(s) of the Company's generating assets as part of the sale of those assets, to the extent they make possible or enhance the sale of the assets and are approved by the Board, are in the public interest and in accordance with applicable law. The term of any parting contracts will not exceed four years. The Company may flow-through, and fully and timely recover from its customers, the rates specified in the parting contracts and resulting costs. If such rates and costs are above market, they will be recovered through a mechanism similar to the NNC described in paragraph 23 of the Stipulation. 21. The Company agrees to forego $9 million in net stranded costs associated with its Deepwater Station and its combustion turbines. (a) The stipulating parties will not object to Board approval of the transfer of the transferred units to an unregulated affiliate of the Company at a transfer value equal to the net book value of the assets at the time of the transfer, adjusted for the application of FAS- 121. Such transfer price(s) will and are intended to ensure that the Company receives full and fair compensation for the assets and that ACE will not retain any liabilities or bear any expense associated with the assets after the transfer. The Company will have auditable accounting protocols in place no BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -44- 47 later than the date of the transfer. If within three years of the date of the Stipulation, any transferred unit is sold to an unaffiliated company, the net after- tax gain over the adjusted book value will be shared equally between the Company and the customers. (b) It is the position of Enron that if the transfer takes place, the transferred units should be maintained as a capacity resource within PJM during the transition period. (c) The parties, other than Enron and IEPNJ, recognize that the Board will be adopting affiliate relationship standards pursuant to the Act prior to the completion of the transfer and that such standards will be applied to the relationship between ACE and its affiliates. Enron and IEPNJ contend that the following specific standard should apply: The competitive generation affiliate shall not offer power or other services to any of its affiliates which are not made generally available to non-affiliated companies, nor shall it offer such power or other services to affiliates at prices more favorable than those generally available in the competitive marketplace and/or to those offered to non-affiliated companies. 22. There shall be no amortization of generation asset stranded costs during the period between August 1, 1999 and the divestiture of the generating assets. Once divestiture has occurred and the actual stranded costs thereof have been determined, amortization of such stranded costs shall commence. 23. The Company is entitled to full and timely recovery of 100% of the costs associated with NUG contracts, and shall be permitted to fully recover, dollar-for-dollar, such costs over the life of each such contract. A Net Non-Utility Generation Charge component of the MTC shall be utilized to recover NUG stranded costs, such charge to equal the difference, adjusted to reflect reasonable marketing and administrative costs, between the cost of NUG contract power and either (a) the proceeds realized from the sale of that power in the wholesale market; (b) the BGS pricing set forth in paragraph 7, to the extent NUG power is utilized for BGS supply as set forth in paragraph 7; or (c) the BGS pricing as set forth in paragraph 9, to the extent NUG power is utilized as set forth in paragraph 9. The NNC shall also include swap breakage costs incurred in connection with an amendment to one of its NUG contracts, which costs have been recovered to date via the Company's Energy Adjustment ("EA") clause charge. The Company will be provided an incentive for a buyout, buydown or restructuring of a NUG contract, equal to 10% of the net savings, except for the Pedricktown Project for which the incentive will be 5%. The parties agree to 100% securitization, over the remaining contract term, of associated buyout, buydown or restructuring costs. Prior to securitization, such costs shall be included in the MTC. 24. The Company may recover restructuring-related costs that are capital in nature, as listed in Schedule C, through securitization of up to 75% of total capital expenses for terms up to BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -45- 48 15 years, and recovery of the balance via the MTC over a period of 8 years with a full rate of return. 25. Net stranded costs for restructuring related costs of an operating nature other than consumer education costs, as listed in Schedule D, shall be recoverable on a full and timely basis through a component of the MTC. 26. If the Company were required to write-off or otherwise absorb stranded costs in amounts in excess of the amounts contemplated in the Stipulation, the Stipulation shall be deemed modified to the extent necessary to permit the Company to recover such amounts that would otherwise be required to be written off, through the MTC. 27. The Company may have to defer recovery of some portion of its revenues attributable to BGS, the NNC and the MTC (referred to as the "Deferred Revenues"). During the transition period the company will utilize a deferred accounting mechanism to provide for full recovery of any Deferred Revenues. BGS revenues will only be deferred to the extent necessary to fund the rate reductions and rate credit set forth in paragraphs 1(a) through 1(d), and then only after deferral of any other item of Deferred Revenues identified in this paragraph. Deferred Revenues, together with a full rate of return identified as the Company's authorized rate of return, will be recovered by the Company no later than August 1, 2007. The Board Order approving the Stipulation shall constitute final approval of the recovery of the Deferred Revenues; any repayment of the Deferred Revenues by ratepayers will not be included within operating income or considered in any ratemaking proceedings. 28. The balance of Deferred Revenues shall be recovered after the transition period through a charge included in regulated rates which shall generate a regulated cash flow stream, and the balance of Deferred Revenues shall be reversed from Company's balance sheet as it is recovered, in accordance with and in satisfaction of applicable Financial Accounting Standards Board ("FASB") standards. 29. In the event that at any point during the transition period the balance of Deferred Revenues exceeds $50 million or the Company's senior secured debt is downgraded or the Company is placed by a credit agency on credit watch, the Company may petition the Board for appropriate relief pursuant to N.J.S.A. 48:3-61(h). Nothing in the Stipulation shall limit the Company's right otherwise to petition the Board for any relief deemed necessary by the Company at any time. 30. The Company shall be permitted to securitize, over a term not to exceed 15 years, 100% of the net stranded costs associated with its divested generation assets. Taxes related to securitization, reflecting the gross-up revenue requirement number associated with the level of stranded costs as determined in paragraph 17, are to be legitimately recovered via a separate component of the MTC with a term identical to the securitization financing. The Company is entitled to full and timely recovery of all transition bond charges, along with applicable taxes. 31. The Company shall be permitted to securitize 100% of the net stranded costs associated with NUG contract restructuring buyout or buydown; the term of such related financing to be no longer than the remaining terms of the respective NUG contracts. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -46- 49 32. The Company shall be permitted to securitize 75% of all restructuring-related costs that are capital in nature, as set forth in paragraph 24, over a term not to exceed 15 years. 33. The Board Order approving this Stipulation shall constitute a Board determination that, if appropriate creditworthiness standards applicable to any third parties that may ultimately provide billing and collection services are not in place before the Company undertakes securitization, such standards will be incorporated in the applicable bondable stranded costs rate order. 34. The Company will establish a societal benefits charge which will include costs related to: (1) social programs; (2) nuclear plant decommissioning costs; (3) demand side management costs; and (4) consumer education. 35. The SBC will be set at the level of costs for the identified items already in rates as of the date of the Stipulation. Funding of SBC initiatives may vary from the level of funding currently in rates, and parties reserve their rights in proceedings related to the Comprehensive Resource Analysis. An annual true-up will be established to provide full and timely recovery of SBCs, except that the Company agrees to defer a portion of the SBC recovery, subject to the same terms and conditions as in paragraph 27, to the extent necessary to achieve the rate reductions provided in paragraphs 1(b) and 1(d). 36. All tax expenses shall be determined on a utility stand-alone basis, not by imputing the tax effects of a consolidated return. The Company is entitled to full and timely recovery of all taxes in connection with restructuring and divestiture. 37. The Company shall be authorized to continue to provide service under Off-Tariff Rate Agreements ("OTRAs"), and it agrees not to transfer any OTRA to an unregulated affiliate, although it may utilize an affiliated energy trading segment to procure supply to serve an OTRA customer. The Company agrees that any OTRA customer may choose to end its contract and shop for an alternative supplier and be provided unbundled service under ACE's tariffs, and agrees to notify OTRA customers of same. 38. The Board shall review and render a decision within 45 days of filing of a NUG contract restructuring proposal by ACE. 39. The Board shall order that the existing FAS-109 transmission and distribution asset regulatory asset shall be preserved and shall be addressed by the Board in a future regulatory proceeding. 40. The experimental Residential Time-Of-Use ("TOU") rates shall be discontinued as of August 1, 2000. The AGS Time-of-Use rate will be closed to any new customers on August 1, 1999, and the rate will continue through the transition period unless the number of customers taking such service drops below 25. Current AGS-TOU customers shall be provided with at least 90 days notice of the discontinuation, and shall be advised that electric power suppliers may offer time-differentiated pricing. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -47- 50 41. The Interruptible Rider shall be discontinued as of December 31, 1999. Customers currently served under this rate will be advised that electric power suppliers may provide interruptible pricing. 42. Standby and Large Standby Riders shall reflect reductions and credits to be made in accordance with the Stipulation and shall be modified to provide for fixed, unbundled transmission, distribution and customer services, and to provide that standby power shall be provided at the BGS rate. 43. Expenses to redeem and retire outstanding capital in connection with the recovery of stranded costs shall be recognized as stranded costs and included in the MTC. 44. In setting the annual level of BGS charges during the transition period, for any MTC that continues beyond the transition period, and for the SBC, NNC and the Transition Bond Charge ("TBC"), the Company will utilize a methodology to that employed in setting the EA clause charges. These charges will be set annually based upon projections of costs and sales. Actual costs will be accounted for on a deferred accounting basis, and each of the rate components will be set to recover any underrecovery in the deferred balance as well as projected costs for the upcoming year. Overrecoveries will be applied as a credit. The setting of these charges will be subject to providing the rate reductions as set forth in paragraph 1 of the Stipulation. 45. With regard to actions within the Company's control, the Company agrees to make good faith efforts to handle electronic data interchange in relation to the delivery of electricity from suppliers to retail customers by October 1, 1999. 46. The stipulating parties agree to work cooperatively to conclude the required metering and billing proceeding in an expedited fashion, which proceeding the parties request that the Board conclude by May 1, 2000. 47. The stipulating parties acknowledge that ACE has not waived legal rights with respect to assertions regarding the effect of the Act or the Board Order in these matters. B. Stipulation Filed by RPA and Other Parties Via letter dated June 15, 1999 the Division of Ratepayer Advocate stated its opposition to Stipulation I, and filed on behalf of itself, MAPSA, NJICG and NJBUS, an alternative Joint Settlement Agreement ("Stipulation II"), representing an alternative proposed resolution of these matters. The key terms of Stipulation II are summarized as follows. 1. Electric rate reductions shall be implemented as follows: (a) ACE shall reduce its rates by 5% from current levels on August 1, 1999. Subsequent to August 1, 1999, the Company will immediately implement additional rate reductions to give effect to any savings achieved via NUG contract buyout or buydown, generation asset divestiture, and securitization. ACE must pass BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -48- 51 through the full amount of any NUG buyout or buydown tax benefits as part of these rate reductions; (b) ACE shall reduce its rates for all customers by an additional 1% on August 1, 2000, unless an aggregate 6% reduction or more has already been achieved prior to that date through measures addressed in paragraph 1(a); (c) ACE is deemed to have implemented an additional 1.2% rate reduction as of August 1, 2001, to bring the total reduction achieved to 7.2%, in consideration of the 1.2% merger savings-related rate reduction implemented in 1998. However, any incremental rate reductions achieved through cost reductions addressed in paragraph 1(a) shall also be implemented and passed through to customers on the date such cost reductions are achieved, and may be used to reduce stranded costs and enhance the shopping credit as well as to revise other portions of unbundled rates in a way that will reduce rates to customers; (d) ACE will implement a rate reduction on August 1, 2002 which, together with the rate reductions provided in paragraphs 1(a), (b) and (c) results in an aggregate 10% reduction from April 30, 1997 rates, and such level of rate reduction will be sustained at least through July 31, 2003, and thereafter until such time that ACE's overall rates are reset by the Board after an appropriate rate case proceeding. 2. ACE shall credit the actual amount of its LEAC overrecovery as of August 1, 1999 back to its customers, through a credit to the starting balance of its NNC or SBC, or other ratemaking mechanism approved by the Board. This refund shall not be included as part of the rate reductions ACE is required to implement pursuant to the Act. 3. ACE shall credit the actual amount of its over collected DSM revenues as of August 1, 1999 back to its customers through a credit to the starting balance of its NNC or SBC, or other mechanism as approved by the Board. The refund of the over collected DSM amount shall not be included as part of the rate reductions ACE is required to implement pursuant to the Act. 4. The four-year period from August 1, 1999 through July 31, 2003 is referred to as the "Transition Period." 5. Unbundled rates to be effective August 1, 1999 have been developed using the 1996 Cost of Service Study; however, ACE shall file a rate case to review and re-set its unbundled rates no later than January 2, 2003, to become effective at the end of the Transition Period. 6.(a) For the Transition Period, the average shopping credits for each customer rate class shall be the greater of the amounts determined in accordance with paragraph 7, inclusive of the BGS and transmission rates, or the floor shopping credits as set forth below, which are inclusive of ACE's FERC transmission rate and taxes: BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -49- 52
- ---------------------------------------------------------------------- Rate Class 1999 2000 2001 2002 2003 - ---------------------------------------------------------------------- RS 5.82 5.85 5.89 5.94 5.94 RS-TOU 5.82 5.85 5.90 5.95 5.95 MGS Sec. 5.70 5.73 5.77 5.82 5.82 MGS Prim. 5.82 5.85 5.90 5.95 5.95 AGS Sec. 5.43 5.46 5.50 5.54 5.54 AGS Prim. 5.39 5.42 5.46 5.51 5.51 AGS TOU Sec. 5.34 5.37 5.41 5.45 5.45 AGS TOU Prim. 5.13 5.16 5.20 5.24 5.24 AGS TOU SubT. 4.67 4.69 4.73 4.77 4.77 AGS TOU Trans. 4.72 4.74 4.78 4.82 4.82 TGS 4.54. 4.57 4.60 4.64 4.64 - ---------------------------------------------------------------------- System Average 5.16 5.18 5.22 5.26 5.26 - ----------------------------------------------------------------------
(b)If the shopping credits are established pursuant to paragraph 7, the BGS rates shall be set so that the shopping credits for each customer class remain in the same proportion to the system average shopping credit as provided in paragraph 6(a). 7. ACE shall provide BGS at rates which include the costs of energy, capacity, ancillary services, administration, losses and taxes. Customers who switch to an Electric Power Supplier will not pay the BGS charge and will not be billed for transmission charges. The sum of BGS and transmission charges shall be the shopping credit, subject to the provisions of paragraph 6. (a) If the shopping credit for any rate class is the amount set forth in paragraph 6, then the BGS rate for the class shall equal the shopping credit, less the transmission charge. (b) If the BGS rate calculated in accordance with paragraph 7(a), when added to the transmission rate, produces a shopping credit in excess of that provided in paragraph 6, then the higher such shopping credit shall be used. If the FERC-authorized transmission rate increases, the transmission rate charged to BGS customers (and shopping credit) will increase in the same amount. (c) Additional shopping-related savings, resulting from a customer receiving electric generation service from an EPS at a price less than the shopping credit, are above and beyond the rate reductions set forth in paragraph 1. (d) ACE will solicit bids from interested EPSs in the third year of the transition period to become the retail BGS supplier in the fourth year, such bids to reflect a payment or series of payments based upon the pre-established shopping credit for the fourth BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -50- 53 year. If the bid results in a payment to ACE, it will considered as an offset to the MTC. If the bid requires a payment by ACE, it will be subject to deferral and subsequent recovery with interest. Specific BGS bid rules will be established by the Board in a collaborative process. 8. ACE shall solicit proposals from RPSs for the provision of BGS in twelve-month pricing cycles, or such other cycles as may be beneficial (the "RFP Process"). Such process will be submitted to the BPU for approval by September 15, 1999, with the intention of Ace entering into a contract by December 31, 1999. Any such agreements shall be subject to BPU approval. No ACE affiliate shall bid to provide BGS. BGS supply requirements shall be net of available NUG resources. 9. During the third year of the Transition Period, ACE will solicit competitive bids for BGS, which reflect payments based upon the pre-established shopping credit floor for the fourth year. If the bid results in a payment to ACE, said payment will be applied as an offset to the MTC. In the alternative, payments by ACE shall be subject to deferral and future recovery with interest. Bidding rules, including those for year five and thereafter, will be established by the Board prior to the first bid out. 10. Customers who voluntarily switch back into BGS from an EPS shall be required to remain on BGS for a minimum 12-month period; provided however that this requirement shall not apply to any residential customer, nor to any customer who returns to BGS due to the refusal or the inability of the customer's EPS to continue to provide service to that customer. In addition any customer, while switching between EPSs in accordance with Board-approved switch rules, may return to BGS for 30 days without being required to remain on BGS; however this exception shall not be available to any non-residential customer who voluntarily returned to BGS and then switched to an TPS within the previous 12 months. 11. From August 1, 1999 until supply arrangements are made in accordance with paragraph 7, ACE may procure BGS supply from the PJM spot market, its own generating facilities (prior to divestiture) or other resources, provided that such power procurement for this interim period shall be from the lowest cost sources. However, in no event shall the shopping credit and BGS rate be lower than provided in paragraph 6. 12. The Company, may at its option, utilize its affiliated service company to make BGS supply arrangements, such arrangements to be conducted as a regulated service and only after approval by the Board of a service contract and cost allocation methodology. 13. The Company may use energy and capacity obtained from one or more parting contracts for the provision of BGS, if priced lower than power generally obtainable in the open market or through the BGS RFP procurement process. Such costs, as well as other reasonably and prudently incurred costs to procure and provide BGS shall be recoverable in rates, subject to the Company meeting its burden of proof. In no event shall such costs result in lower shopping credits than set forth in paragraph 6. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -51- 54 14. During the Transition Period the Board shall review and approve any BGS contract negotiated by the Company with a third party supplier. After the Transition Period, the Company shall no longer offer BGS. 15. Bidding procedures conducted for the BGS supply shall be conducted on behalf of the regulated utility, and all competitive information relating to bids which may be tendered shall be treated as proprietary and confidential, and shall not be provided to a competitive affiliate of the Company. 16. ACE shall not promote BGS as a competitive alternative. 17. The Company shall be permitted to recover 100% of its net stranded costs, including 100% of the stranded costs associated with the Company's NUG contracts. 18. ACE shall divest its ownership interests in all of its generating assets, including the Company's combustion turbines. No ACE affiliate shall bid on the divested generating assets. The net proceeds will be used to determine the net generation-related stranded costs. If the divestiture results in net negative stranded costs, meaning net proceeds are greater than net book value, the full amount of such excess proceeds shall be returned to ACE's ratepayers via a rate refund, rate credit via the NNC or SBC, or other Board-approved mechanism. 19. Final determination of the net divestiture proceeds shall be made within a separate divestiture proceeding to be filed by the Company with the Board. 20. The parties will support the Board's efforts to finalize divestiture standards applicable to ACE within 30 days of the Company's filing. (a) If ACE is unable to divest of all the generating assets, and therefore desires to transfer the ownership or operating rights of such assets to an affiliate: (i) the Board should conduct a review of the then-current market value of the transferred assets, in which an independent audit shall be conducted, with full intervention rights for parties; (ii) any affiliate of ACE that owns or operates the transferred units, or any other affiliate that owns or sells generation to ACE (hereinafter "Genco") should operate pursuant to the following principles: 1) Genco shall not offer power or other services to any of its affiliates on terms that are not made generally available to non-affiliated companies nor shall it offer such power or other services to affiliates at prices more favorable than those generally available in the competitive marketplace; 2) While ACE is collecting transition costs or is acting as the BGS provider, whichever is longer, the Genco must sell all the generation output of the transferred assets, or the output from any other BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -52- 55 assets now owned or operated by ACE and purchased as part of the asset divestiture (excluding output sold to ACE for BGS) into the wholesale market; 3) Genco shall be a separate subsidiary from ACE's retail marketing or its distribution/BGS function; 4) Generation capacity transferred to Genco will be maintained as a capacity resource within the PJM system for the transition period. During that period Genco will be permitted to sell said capacity outside PJM for periods of less than one year after it makes a good faith effort to sell the transferred capacity into the PJM system at market rates. 21. ACE may enter into parting contracts with purchasers of its generating assets as part of asset sale transactions. The term of such contracts shall not exceed four years. If the cost of energy and/or capacity under such contracts is below the Company's average BGS cost, ACE shall use such power for the provision of BGS, and shall ensure that its customers receive the appropriate credit for BGS cost savings attributed to the parting contracts. In no event shall customers be responsible for any above-market costs associated with any parting contracts. The prudence of parting contracts should be reviewed by the Board in a separate divestiture proceeding. 22. Any amounts that ACE collects via a MTC during the interim period before the divestiture and securitization shall be credited back to customers as an offset to stranded costs recovery, through either a deduction from the net stranded costs determined via divestiture or if, after divestiture the Company has net owned generation stranded costs, the MTC revenues shall be credited to customers through the NNC, SBC or some other ratemaking mechanism approved by the Board. 23. ACE shall not recover any stranded costs associated with the Company's 1995 power purchase contract with PECO. 24. The Company shall be permitted to recover NUG stranded costs, representing the difference between the cost of NUG contract purchases and the proceeds realized from the sale of NUG power in the competitive wholesale market, via a NNC which shall continue over the actual term of each NUG contract. ACE has a continuing, affirmative obligation to mitigate above-market NUG contract costs, both by obtaining the highest possible price for such NUG contract power in the open market and by continuing efforts to renegotiate contract terms. In the event of a contract buyout, buydown or restructuring the Company will immediately flow-through via the NNC all savings associated therewith, including any tax benefits. ACE may seek to securitize 100% of NUG contract costs remaining after such NUG contract buyout or buydown, provided that securitization will result in reduced rates and otherwise comply with the Act, and that resultant cost savings are flowed through to customers on a dollar-for-dollar basis. 25. Deferral of some costs during the transition period may be reasonable, however, in periods when ACE is able to supply BGS service at a cost that is less than the pre-established BGS rate/ shopping credit, the Company must recognize this cost differential as an offset to BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -53- 56 other deferred costs. The Company will utilize a deferred accounting mechanism to track any deferred revenues. Such deferred revenues, together with a return at the Company's mid-term debt rate on the unrecovered balance, will be recovered over an appropriate timeframe and as deemed necessary by the Board in a future ratemaking proceeding. Any deferred overcollection shall be credited back to customers, with accrued interest, via a rate refund. 26. The balance of deferred revenues shall be recovered (or credited back) after the transition period through a charge (or credit) after the transition period through a charge (or credit) to be included in post-transition period regulated rates, and the deferred balance shall be reversed from the Company's balance sheet as it is recovered. 27. The Company shall be permitted to securitize 100% of any net stranded costs associated with its divested generation assets, to be calculated in accordance with paragraph 17, over a term not to exceed 15 years. Related taxes are to be recovered via a separate MTC with a term identical to the term of securitization financing. 28. The Company shall be permitted to securitize 100% of the net stranded costs associated with NUG contract buyout, buydown or restructuring, over terms not to exceed the remaining lives of the respective NUG contracts, subject to the terms of paragraph 24. 29. Reasonable and necessary securitization issuance costs are to be shared 50%/50% between the Company and customers. 30. The Company will establish a SBC, will include costs related to: 1) social programs; 2) nuclear plant decommissioning costs; 3) DSM programs; and 4) consumer education. Recover/deferral of DSM generation-related lost revenues, if any, will end as of August 1, 1999. 31. The SBC will be set at a level of relevant costs as currently in rates. Actual program funding levels may vary during the transition period, and if SBC costs increase during this time, ACE may defer a portion of BSC recovery subject to the terms and conditions of paragraph 27. Any SBC overcollection at the end of the transition period will be immediately returned to customers via a rate refund. 32. ACE shall be authorized to continue to provide service under its existing OTRAs. No revenue reduction from under any OTRA shall ever be recovered from any other customer. The Company should not transfer any OTRA to an unregulated affiliate. Any ACE OTRA customer may choose to end its contract and take BGS service, or purchase generation supply from an electric power supplier, as of August 1, 1999. 33. The current Standby and Large Standby Riders tariffs shall be modified to provide for fixed, unbundled charges for transmission, distribution and customer services, and to provide that standby power supply shall be provided from time to time, as required by the customer, at market prices. 34. The parties agree to work cooperatively to conclude the statutorily required metering and billing proceeding in an expedited fashion, and request a conclusion of such proceeding by May 1, 2000. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -54- 57 35. In order to facilitate municipal aggregation: a) Within two weeks of receipt of a customer's request, ACE shall provide the usage data or customer profile for the past twelve-month period to the customer making the request; b) ACE shall provide area-based aggregate load profile by municipal boundaries and rate class upon request by a government aggregator, and shall also provide the government aggregator with a list of addresses of all energy customers who receive service within the boundaries of the town or municipality. At a minimum, ACE will provide, in both hardcopy and electronic form, if possible, a customer list by zip code, broken down by rate class, upon request; c) ACE shall maintain and disseminate a list of licensed third party suppliers approved to provide service in its territory to its customers, at least twice per year, and will post such list on its website. 36. ACE shall cooperate with the Board and the parties in the establishment of a universal service fund and should continue to support the "New Jersey Shares" fuel fund. 37. The Board should direct ACE to offset stranded costs with 50% of the net revenues from its competitive telecommunications affiliate, pursuant to N.J.S.A. 48:3-55(b). 38. Third Party Supplier Agreement and retail Tariff issues must be satisfactorily resolved, including the establishment of the Agreement as a supplier tariff. Customers should be permitted to change suppliers at will, without incurring switching fees, and should not be locked in for a minimum time period. VI. COMMENTS ON THE SETTLEMENT PROPOSALS A. Comments on Stipulations The Company, RPA, Enron, IEPNJ, MAPSA, NJCU, NJICG filed comments in response to the stipulations. Key arguments raised in the submitted comments are summarized below. 1. ACE ACE filed detailed comments in support of Stipulation I, as well as reply comments in reply to other parties' criticisms of Stipulation I. ACE also filed comments regarding Stipulation II. In general, the Company asserts that Stipulation I properly reflects a careful balancing of the diverse and competing interests of the numerous stakeholders represented in this proceeding, while Stipulation II represents a narrowly conceived resolution of the issues raised in the proceeding. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -55- 58 ACE asserts that the rate reductions in Stipulation I satisfy the statutory obligations, while attempting to preserve the Company's financial health. ACE asserts that the rate reduction plan proposed in Stipulation I incorporates past BPU commitments, including reflection of the expected cost savings of 1.2% from the merger between Atlantic Energy, Inc. and Delmarva Power and Light Co. and a .1% reduction corresponding to the removal of certain expense items from the Company's base rates ordered by the Board in the 1997 LEAC proceeding. In addition, ACE proposes to reduce rates an additional 3.9% to affect an aggregate August 1, 1999 rate decrease in excess of the 5% statutory minimum. The Company will implement other rate reductions achieved through the buyout or buydown of NUG contracts, and the securitization of stranded generation costs and NUG buyout and buydowns. If such additional decreases are insufficient to meet the statutory minimum 10% reduction by August 1, 2002, the Company will implement a rate credit such as to reduce rates between August 1, 2002 and July 31, 2003 by the requisite 10% level from April 30, 1997 rates. ACE asserts that Stipulation I provides for rate reductions that are based on actual cost reductions rather than the arbitrary denial of revenue recovery contained in Stipulation II. According to ACE, Stipulation II fails to identify any of the cost savings required to effectuate the proposed rate reduction; rather, it reflects the RPA's position that the confiscation of ACE assets is an appropriate means of effecting the rate reductions. Stipulation II would limit ACE's internal cash flows and its ability to cover its debt service obligations, thereby jeopardizing the Company's investment grade rating, in violation of N.J.S.A. 48:3-61(h). ACE reasserts its argument that it is constitutionally impermissible to arbitrarily change rates without appropriate allowances for a reasonable return on rate base and recovery of legitimate expenses. ACE argues that the Board expressly agreed that the merger related rate decrease should be credited toward rate reductions specified in the Final Report, since it represented an early mitigation effort in advance of restructuring. ACE takes issue with the RPA's objection to the Company's use of the LEAC overrecovery and DSM balance to fund rate reductions, arguing that EDECA does not prescribe the funding source for the mandated rate reductions, but rather provides the Board the flexibility to fashion rate reductions appropriate to each utility. ACE refutes the argument that Stipulation I conflicts with the rate reduction sustainability provisions of the Act, asserting that N.J.S.A. 48:3-52(j) requires only that the maximum level of rate reduction be sustained through July 31, 2003, which is precisely what Stipulation I provides. Moreover, that portion of the 10% rate reduction based on real cost savings will continue to be incorporated in rates after the close of the Transition Period. ACE contests the assertion that Stipulation I will not reflect all of the benefits of securitization in rates, arguing that paragraph 1 of Stipulation I specifically calls for the implementation of rate reductions reflecting any and all net savings due to securitization to be implemented on a "real time" basis, that the "mid-term" rate reductions are not arbitrarily limited, and that no securitization savings are subsumed in the initial rate reductions. Moreover, ACE asserts that to the extent rate reductions are tied to actual cost savings it avoids the need to achieve rate reductions through MTC, NNC or BGS cost deferrals. Some level of deferrals will, however, undoubtedly accrue in order to achieve the mandated rate reductions and rate caps. ACE also contends, contrary to the RPA's arguments, that its proposal to adjust distribution rates after FERC's final decision concerning transmission rates is rational. Since transmission and distribution costs together represent the cost of delivery, once FERC decides how much BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -56- 59 of that cost should be apportioned to transmission, the remaining cost should appropriately be assigned to distribution. ACE contends that Stipulation I will implement a true market-based price for basic generation service, and is therefore both fair to customers who remain on BGS and to marketers seeking to develop business within the ACE territory. The BGS mechanism provides that, if the true market cost for obtaining BGS supply is greater than the cost implicit in the minimum, pre-determined shopping credits, then the actual market cost is employed and the shopping credits will rise commensurately. The arguments of the RPA and other parties that the stipulated shopping credits do not compare favorably to other utilities' shopping credits are therefore incorrect and misleading. Moreover, with a mechanism in place for upward adjustments to reflect actual market prices, a lower minimum shopping credit provides greater protection against overcharging BGS customers who do not switch suppliers, an effect particularly important for low-income BGS customers. ACE contends that Stipulation II's minimum shopping credits are presented without record support or legal justification, relying upon an affidavit, attached to the stipulation and submitted outside of the record, similar to one presented and rejected in the PSE&G and GPU restructuring proceedings. If the assertions made in the affidavit about higher market prices come to fruition, then the shopping credits implemented in the ACE territory would rise pursuant to the BGS mechanism contained in Stipulation I. ACE rejects the RPA's arguments with respect to the Company's proposal to prevent gaming of its system. Contrary to the RPA's arguments, ACE asserts that customers who return to BGS, for any reason, would be allowed to switch to a new supplier within 30 days, and that Stipulation I allows residential customers who are involuntarily returned to BGS to leave again at any time for an alternate supplier. This strikes a reasonable balance between the need to prevent gaming and the legitimate concern that customers who find themselves returned to BGS through no fault of their own have a fair opportunity to select another supplier. Under unlimited switching provisions, as proposed in Stipulation II, suppliers will have the ability serve customers during non-summer months, dump them back onto ACE's BGS for the high-cost summer months, and take them back after the summer when costs are again lower. This would only serve to benefit suppliers at the expense of BGS customers who do not have a choice, but who would nonetheless have to pay the costs incurred to serve these "summer-only" BGS customers. ACE also criticizes the RPA's contention that the provision for deferral of BGS costs will eviscerate the minimum shopping credit levels, asserting that the RPA misunderstands the provision. ACE argues that if BGS costs are indeed being deferred, this could only mean that the BGS rate has already been raised far above the stipulated minimums. The Company criticizes Stipulation II's proposed elimination of the ability of ACE's affiliate to bid to provide BGS, asserting that the Board's affiliate relations standards will prevent any unfair practices and that such elimination will remove a potential bidder and thereby harm competition. ACE indicates that while the Board has no legal authority to order divestiture, the Company's announcement that it will voluntarily divest itself of all base load generating plants - retaining only its CTs and its Deepwater stations - is driven by the anticipation that these assets will have a greater value in today's marketplace than they would if retained. The Company asserts that all of the prospectively divested plants, as well as the CTs and Deepwater, have been through a detailed process of numerous reviews and analyses in these proceedings. ACE is taking a step urged by many parties and separating its generating units by selling them, for the most part, and it is functionally separating the remaining units from the utility pursuant to N.J.S.A. 48:3-59. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -57- 60 There is simply no legal authority for the Board to order ACE to sell its remaining generation assets, as argued by RPA. ACE has proposed to not seek recovery of the net stranded costs of $9 million of those retained units. The Company asserts that its estimate of the stranded costs of the retained units is conservative, since its market price forecast was at the high end of the range in the proceedings, and fully supported by the record developed before the ALJ. ACE further asserts that the RPA ignores the benefit provided in Stipulation I for a sharing of benefits between the Company and its customers from any subsequent sale of the assets occurring within three years. ACE rebuts the position of the NJPII that the cost of recent repairs at the Salem plant should be deducted from recoverable stranded costs, asserting that those repairs have maintained the value of the plant, which value will be reflected to the benefit of customers when the plant is sold. ACE contests Enron's position that the transferred CTs and Deepwater plant should be maintained as a capacity resource within PJM, arguing that such requirement would disrupt the flow of the free market. ACE contends that certain low-income customer issues being raised by the RPA are not relevant to these proceedings. The Company asserts that these issues will be addressed in the separate Universal Service Fund proceeding which the Board is obligated to conduct pursuant to N.J.S.A. 48:3-60(b). Similarly, the RPA's proposals for ACE's provision of information pertaining to municipal aggregation should be rejected, as they were in the PSE&G and GPU proceedings. The Company also asserts that the Board should not adopt any particular affiliate standard of conduct in this matter, arguing that standards to govern the actions of the regulated utility, as opposed to unregulated affiliates as requested by Enron and IEPNJ, are in the process of being separately adopted by the Board. ACE also urges rejection on the basis of factual inaccuracies and lack of record support the RPA's contention that certain of the net revenues of Conectiv Communications, Inc. should be applied to offset stranded costs; ACE asserts that this was not, in fact, the decision of the Board in the GPU matter referenced by the RPA. 2. Ratepayer Advocate The RPA recommends that the Board reject Stipulation I, and instead adopt Stipulation II, which, along with several other parties executed and submitted to the Board on June 15, 1999. A summary of the comments of the RPA, specific to each paragraph of the two Stipulations, is provided as follows. Paragraph 1: Stipulation I's proposed initial rate reduction of 3.9% directly conflicts with the requirements of N.J.S.A. 48:3-52(d)(2), which requires a minimum rate reduction of 5% on August 1, 1999. At the time the Board issued its Final Report, it was the controlling authority over restructuring rate reductions. The Final Report required rate reductions of 5% and 10% from rates in effect on April 30, 1997. EDECA, however, makes no reference to the April 30, 1997 benchmark in mandating the August 1, 1999 rate reduction of 5%. The RPA states that with the passage of EDECA, the controlling authority on rate reductions passed to the Legislature and its prescription must be followed in this proceeding. The Legislature's mandated rate reduction supersedes any rulings the Board may have rendered regarding any prior rate decreases being credited toward the required minimum reduction. EDECA does, however, reference April 30, 1997 rate levels with respect to the required minimum 10% rate BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -58- 61 reduction effective August 1, 2002. Accordingly, ACE must reduce its rates by 5% from current levels on August 1, 1999, and any crediting of the 1.2% merger-related savings would only apply to the total 10% reduction from April 30, 1997 rates that must be achieved by no later than August 1, 2002. Stipulation II recognizes EDECA's August 1, 1999 rate reduction requirement, while Stipulation I falls short of the 5% minimum reduction. Additionally, while ACE attempts to take credit for a 0.1% rate reduction it claims took place in June 1998, in fact no such rate reduction actually occurred and, indeed, ACE's rates were increased by 1.52% on June 4, 1998 in a LEAC proceeding (BPU Docket No. ER97020105). Moreover, Stipulation I's proposed 3.9% rate reduction would be achieved, in large part, through offsetting $36 million of current regulatory asset charges with projected LEAC and DSM overrecoveries; accordingly, the initial rate reduction would be largely funded by giving back money that it has already overcollected from its customers. This is inconsistent with regulatory and legal principles, the clear language of EDECA, and the Board's recent decisions in the PSE&G and GPU restructuring cases, where it required that any overcollected LEAC revenues be returned to ratepayers, in addition to providing the statutory rate reductions. Moreover, ACE has repeatedly delayed its pending LEAC proceeding, thereby delaying an appropriate LEAC reduction and causing the overrecovery, which it proposes to use to fund rate decreases, to continue to grow. The RPA argues that the Board should reject Stipulation I's rate reduction proposal and instead require that customers receive a proper crediting of the over collected LEAC and DSM revenues. Finally, ACE proposes a one-time rate credit to fund the final phase of required rate reduction, which credit would expire on July 31, 2003. The RPA asserts that this violates the requirements of the Act that the rate reduction be sustainable. The RPA argues that the Board should direct ACE to sustain its total rate reduction until the Company proves, through an appropriate rate case filing, that it needs to increase rates. Paragraph 2: The RPA notes that Stipulation I conditions all of its proposed rate reductions on divestiture and securitization of 100% of ACE's net stranded costs, and that the Board has already rejected similar conditioning of rate reductions in the PSE&G and GPU matters, finding that there is no statutory support in the Act for such conditional rate reductions. The RPA asserts that the Board should not adopt this paragraph of Stipulation I. Paragraph 3: The RPA notes that while the transition period in Stipulation I is identified as having a term of four years, ACE proposes an MTC charge lasting eight years and a transition bond charge lasting from 15 to more than 20 years, without any assurance that customers will receive the full amount of capital cost savings that securitization will continue to provide over the life of the bonds, as required in the Act. In contrast, Stipulation II provides for sustainable rate reductions that will continue beyond the Transition Period and which are not contingent upon securitization. Paragraph 4: In contrast, Stipulation II proposes unbundled rates which are based on the 1996 cost of service study filed in this case, which utilizes 1996 cost data rather than the cost data from the last base rate case, as required by the Board in the Final Report. This cost of service data was never the subject of review in a base rate case and was not approved by the Board in any rate proceeding. Moreover, the RPA objects to the provision in Stipulation I that distribution and transmission rates are subject to revision if the FERC approves a transmission rate change BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -59- 62 for ACE. While acknowledging that shopping credits would appropriately be modified in the event of such a FERC decision, since the shopping credits include transmission costs, the RPA asserts that the distribution rate should not be affected by such change. The RPA asserts that it would nonetheless accept the Company's use of the 1996 COSS if the Board were to adopt all other elements of Stipulation II. Paragraphs 5 through 8: The RPA's main concern with respect to Stipulation I's proposed BGS/rate shopping credit is the assertedly inadequate level of the floor shopping credits, particularly for residential customers. The proposed residential credits are nearly one cent below the level necessary to foster vibrant competition, and between 35 and 50 mils per kwh lower than the proposed commercial customer credits. Moreover, the RS shopping credits are substantially lower than the residential credits recently approved for both PSE&G (5.71 cents) and GPU (5.65 cents), even though ACE's residential rates are the highest in the State. With the highest rates in the State, the RPA argues that ACE's residential shopping credit should be set higher than PSE&G's 5.82 cents/kwh. Moreover, the transmission rate for ACE, which is included in the shopping credit, is 0.13 cents/kwh higher than GPU's corresponding rate. The RPA argues that ACE's shopping credit would have to be set higher than GPU's by at least the amount of the transmission differential just to be equivalent. RPA proposes the following shopping credit floors (inclusive of transmission rates and taxes):
- ------------------------------------------------------------------------------------------- Rate Class 1999 2000 2001 2002 2003 - ------------------------------------------------------------------------------------------- RS 5.82 5.85 5.89 5.94 5.94 RS-TOU 5.82 5.85 5.90 5.95 5.95 MGS-Sec 5.70 5.73 5.77 5.82 5.82 MGS-Pri 5.82 5.85 5.90 5.95 5.95 AGS-Sec 5.43 5.46 5.50 5.54 5.54 AGS-Pri 5.39 5.42 5.46 5.51 5.51 AGS-TOU-Sec 5.34 5.37 5.41 5.45 5.45 AGS-TOU-Pri 5.13 5.16 5.20 5.24 5.24 AGS-TOU-SubT 4.67 4.69 4.73 4.77 4.77 AGS-TOU-Trans 4.72 4.74 4.78 4.82 4.82 TGS 4.54 4.57 4.60 4.64 4.64 - ------------------------------------------------------------------------------------------- System Average 5.16 5.18 5.22 5.26 5.26 - -------------------------------------------------------------------------------------------
The RPA also objects to the language in paragraph 5(d) of Stipulation I which conditions the level of shopping credits on the Board's adoption of the Company's proposed rate reductions and the balance of the Stipulation, and paragraph 6(d) of Stipulation I, which limits the shopping credits if certain BGS deferrals are necessary. Paragraphs 7 and 13: The RPA objects to the provisions in Stipulation I that would permit an affiliate to bid to become the BGS wholesale supplier and the Company's use of an unidentified affiliated service company to conduct the bidding process. The RPA recommends that no ACE affiliate be eligible to supply BGS supply during the transition period. The RPA asserts that the mechanism for determining if actual BGS supply cost is higher than the floor price is unclear in Stipulation I. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -60- 63 Paragraph 8: Stipulation I contains limitations on the movement of customers into and out of BGS, purportedly to prevent customers from gaming the system by switching to BGS during the high cost summer months. The RPA recommends that residential customers should be exempted from all BGS switching prohibitions (as the Board recently determined in the GPU decision), and all customers who are involuntarily switched to BGS (due to default of an EPS) should be free to choose to leave BGS without restriction. Paragraph 9: Stipulation I proposes to secure BGS energy and capacity through the PJM spot market power exchange until it finalizes the competitive BGS procurement is finalized. The RPA argues that ACE should be required to acquire BGS power at the lowest possible cost, and not simply impute the PJM clearing price, and the Board should clarify that the floor shopping credits also apply during the interim period. Paragraph 10: Any use of an affiliated service company to make BGS supply arrangements must be subject to the Company first receiving Board approval of a service contract with the affiliate pursuant to N.J.S.A. 48:3-7.1. Paragraph 11: ACE should only be permitted to use parting contracts if their use lowers BGS supply costs; it is not clear why ACE would need to engage in hedging; the Board must first approve any parting contracts before their implementation; and ACE must prove, through an appropriate filing, that its BGS purchases are reasonable and prudent pursuant to N.J.S.A. 48:3-57(e), prior to recovery of such costs from customers. Paragraph 16: The Board should reject this paragraph of Stipulation I, since it provides a guarantee for the recovery of stranded costs, not simply an opportunity for recovery as provided for in N.J.S.A. 48:3-61(a), and because ACE is only entitled to 100% recovery if it can meet the rate reduction requirements, which it has not met. Paragraph 17: Stipulation I includes a proposal for ACE to divest some but not all of its generating units and use the proceeds to calculate stranded costs for the units. ACE would likely retain the most valuable units, its combustion turbines while it recovers the stranded costs of its least valuable units from ratepayers. ACE's CTs have an administratively determined net above-book value of from $63 million to $160 million, and would likely command an even greater above-book sales price if they were sold in an auction. The RPA argues that ACE would transfer its CTs to its affiliate, which would, in turn, sell the power on the open market. The Board should, therefore, order ACE to divest all its generating assets, including the CTs, with the total net stranded costs eligible for recovery. In the alternative, the Board should impute a greater stranded costs adjustment for the retained CTs than the $9 million write-off which ACE proposes; since in the proceeding the RPA calculated a $160 million net above-book value for the CT's and Deepwater, the Board should make a downward adjustment of $160 million to any net generation stranded costs remaining after divestiture. Further, the Board should not pre-approve the broad "laundry list" of potential transaction costs listed in Stipulation I. Paragraph 18: The RPA objects to the blanket pre-approval language in Stipulation I with respect to future generation asset sales contracts. The Board should reject most of this paragraph in light of the Board's authority and obligation to conduct a full review of the proposed BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -61- 64 terms of sale once they are known, pursuant to N.J.S.A. 48:2-13 and 48:3-7 and N.J.S.A. 48:3-59(b) and (c). Paragraph 20: For the reasons that it recommends rejection of the pre-approvals of contracts in paragraph 18, the RPA recommends that the Board reject the pre-approval language of this paragraph of Stipulation I as well, and reserve its ability to review the reasonableness of costs associated with parting contracts. Paragraph 21: The RPA refers to its comments regarding paragraph 17 as applicable to the proposed terms of this paragraph of Stipulation I. The RPA additionally observes that if ACE divests all its generating assets, subparagraphs 21(a), (b) and (c) of Stipulation I will be unnecessary. If the CTs and Deepwater are retained by ACE, they should only be transferred if the value reflects a $160 million above-book premium, and the transfer should further be conditioned so that the unregulated affiliate may not engage in retail electric sales. Finally, if any retained generating assets are subsequently sold to an unaffiliated company, any net after tax-gain should be shared equally by the Company and its customers during the subsequent five-year period rather than the subsequent three-year period proposed by ACE. Paragraph 22: As part of Stipulation I, ACE proposes to retain all MTC revenues collected between August 1, 1999 and the indeterminate date of completion of generation divestiture, rather than apply these proceeds to it stranded costs balance. ACE would apparently use the retained revenues to fund unidentified general operating expenses. Since Stipulation I does not specify the expected level of MTC revenues during the transition period, the Board would be unable to assess whether the MTC is over or underrecovering stranded costs. This would appear to violate N.J.S.A. 48:3-61(g) which requires the Board to assess the MTC during periodic reviews, and to adjust the MTC to ensure against overrecovery of actual stranded costs. The RPA asserts that this proposal embodies bad policy and is illegal under N.J.S.A. 48:3-61; thus, the Board should reject it. The Board should adopt Stipulation II, which provides that any MTC revenues collected during the transition period should be credited back to ratepayers as an offset to stranded costs recovery. Paragraph 23: The RPA recommends rejection of the proposal that ACE retain a percentage of net savings from any NUG contract buyout, buydown or restructuring. ACE has a statutory duty to mitigate all of its stranded costs, including NUG stranded costs. Furthermore, the Board's decisions in the PSE&G and GPU restructuring proceedings provide that 100% of any NUG renegotiation savings be passed on to customers. The Board should also state that ACE has a continuing affirmative obligation to mitigate above market NUG contract costs, both by obtaining the highest possible price for such NUG contract power when it is sold on the open market, and by attempting to renegotiate contract terms, passing all resultant savings, including tax benefits, through to customers. Paragraph 24: Stipulation I proposes that ACE be permitted to securitize 75% of restructuring-related items that are capital in nature, however, the specific costs which the Company seeks to recover were not requested during the proceeding and are, therefore, not in the record. As a result, the reasonableness of these costs and their categorization as restructuring related cannot be determined. The Board should also disallow recovery of any restructuring related expense pending resolution of what level of transition costs ACE will be permitted to charge BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -62- 65 suppliers through Third Party Supplier Agreement fees. Finally, the RPA objects to the proposal that these costs be collected through an eight-year MTC, with a "full return." Paragraph 25: The RPA expresses similar concerns regarding Stipulation I's proposed recovery of "restructuring related items of an operating nature," as it expressed with respect to paragraph 24. The Board should reject the recovery of $16.5 million of unspecified costs that are wholly unsupported by the evidentiary record in this proceeding. Paragraph 26: The RPA asserts that paragraph 26 of Stipulation I should be rejected in its entirety, for the reasons detailed with respect to paragraph 18, since it attempts to abrogate the Board's statutory authority and responsibilities. Paragraphs 27 and 28: In these paragraphs of Stipulation I, ACE proposes to defer recovery of BGS, NNC and MTC costs during the Transition Period if necessary to achieve its statutory rate reductions. As a compromise position detailed in Stipulation II, the RPA does not object to the concept of certain cost deferrals. However, it asserts that such deferred costs should not be pre-approved, and ACE should be required to prove that it requires recovery of deferred amounts prior to commencing recovery. Moreover, ACE's proposal that it defer costs in order to achieve the required rate reductions results in a situation wherein ACE's customers receive rate reductions and shopping credits during the transition, but then pay them back, with interest, starting in the fifth year of competition. This proposal nearly guarantees a rate shock scenario in the fifth year. Further, the Board is being asked to pre-approve these deferrals in the absence of any estimates or explanations of the level of deferrals. The Board should similarly reject ACE's proposal to recover all deferred amounts by August 2007. The Board should also reject Stipulation I's proposal that ACE earn a full rate of return on the unamortized deferred balance; instead, ACE should receive a return based upon the mid-term (seven year) debt rate, consistent with the Board's decisions in the PSE&G and GPU proceedings. In addition, the proposal that repayment of Deferred Revenues not be included in operating income for prospective ratemaking purposes should be rejected, since a utility's entire financial situation, including all sources of revenues, must be considered in a base rate case. Stipulation I also fails to explicitly state that BGS overrecoveries during periods when BGS costs are less than the pre-established BGS rate/shopping credit should be used as an offset to deferred costs. Stipulation I does not account for the treatment of any net over recovery at the end of the transition period. Overrecoveries should be refunded to customers, with interest, as provided for in Stipulation II. Paragraph 29: Stipulation I permits the Company to file for a rate increase if its deferred revenues reach $50 million or its debt rating is downgraded during the transition period. The RPA asserts that this paragraph should be rejected in its entirety, since nothing prevents ACE from filing a petition alleging financial impairment, in which it would have the burden of proof, and there is no need to set an arbitrary level of a deferral balance which could trigger such a petition. In any event, the Board would have to review all aspects of the Company's financial integrity in such a proceeding, not just the level of the deferral. Paragraph 30: ACE should only be permitted to securitize 100% of its net stranded costs after divestiture if it satisfies the criteria set forth in N.J.S.A. 48:3-62(c)(1)(a), which requires that it meet the minimum rate reductions required in N.J.S.A. 48:3-52 Moreover, securitization BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -63- 66 issuance costs should be shared 50%/50% between shareholders and customers. As a compromise position, the RPA would accept securitization of 100% of post-divestiture, stranded generation costs, provided the Board adopts the rate reduction provisions and the balance of Stipulation II. Paragraph 31: ACE should only be permitted to securitize NUG contract buyout, buyout or restructuring costs if it results in lower rates for customers, and if the Company is required to flow through to customers the full amount of resultant cost savings, including any tax benefits, and immediately reduce its NNC. Paragraph 32: The RPA references its comments pertaining to paragraph 24 as applicable to the proposed terms of paragraph 32 of Stipulation I. Paragraphs 34 and 35: ACE should be required to file a more detailed list of all cost categories that may be deferred in the SBC to ensure compliance with the categories specified in EDECA. ACE should be required to cease recovery and deferral of any DSM generation-related lost revenues as of August 1, 1999. It is unclear how an annual SBC true up would be implemented during the Transition Period under a price cap. Finally, interest on SBC deferrals should be accrued at the seven-year debt rate. Paragraph 36: Stipulation I requests that the Board rule that all tax expenses be determined on a utility stand alone basis and not by imputing the tax effects of a consolidated return. The RPA asserts that this paragraph should be rejected out of hand. Whether or not the Board should impute the consolidated tax adjustment is a base rate case issue which should not be a subject of this case. Moreover, there is no evidence in the record on this issue, which was raised for the first time in Stipulation I. The proposed language is also unduly broad in requesting that ACE be entitled to recover all taxes in connection with restructuring and divestiture, and it fails to request a corresponding ruling that customers are entitled to all tax benefits associated with the divestiture and restructuring, buyout or buydown of NUG contracts. Paragraphs 40 and 41: Stipulation I proposes to either discontinue or close to new customers rate schedules RS-TOU, AGS-TOU and the Interruptible Rider. These paragraphs should be rejected in their entirety since there is no explanation or rationale provided to support the tariff changes. Paragraph 43: The language in this paragraph of Stipulation I is overly broad and must be rejected. While certain securitization transaction costs may be recovered via the transition bond charge, routine refinancing or debt retirement costs are not stranded costs under N.J.S.A. 48:3-61 and may not be recovered via the MTC. Paragraph 44: It is unclear how an annual true-up of the BGS, SBC, NNC, MTC and TBC rates will be accomplished under the mandatory rate reductions and price cap and the BGS pricing mechanisms set forth elsewhere in Stipulation I. Paragraph 46: The RPA does not object to this paragraph of Stipulation I, but more specific language is necessary. The Board should require ACE to implement metering and billing unbundling by May 1, 2000, and should require ACE to commit to having EDI systems operational and in place by November 1, 1999. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -64- 67 Paragraph 47: The RPA asserts that this paragraph of Stipulation I should be rejected in its entirety, as similar provisions were rejected by the Board in its GPU decision. The RPA also raises a number of additional issues which it asserts should be included in the Board's decision and which are addressed in Stipulation II. First, the RPA recommends that 50% of the net revenues from its telecommunications affiliate (Conectiv Communications, Inc.) be used to offset stranded costs surcharges. This would be consistent with the Board's finding via Order dated December 17, 1997 (Docket No. EE97050350), that GPU utilize all of the net revenues that its GPU Telcom subsidiary derives from its Telcom Agreements to either offset stranded costs or as a reduction to its transmission and distribution revenue requirements. If ACE has no deferred balance at the end of the transition period, then the accrued affiliate revenues should be returned to ratepayers through an appropriate refund mechanism. Additionally, ACE should be compelled by the Board to comply with the municipal aggregation recommendations set forth in Stipulation II. ACE should be required to provide and maintain specified load data and customer and supplier lists to facilitate municipal aggregation. Further, the Board should order ACE to cooperate in the establishment of a Universal Service Fund to assist low-income families in meeting their energy costs and continue its support of the "New Jersey Shares" fuel fund for energy consumers facing crises. Finally, the Board should require ACE to cooperate in the resolution of Third Party Supplier Agreement and retail tariff issues, including the establishment of the Third Party Supplier Agreement as a supplier tariff. A process should be initiated that is specific to the ACE's service territory. 3. Enron Enron, a signatory party to Stipulation I, asserts that Stipulation I meets an overall objective of the Act to reduce the high cost of energy by placing greater reliance on competitive markets. The shopping credits are consistent with N.J.S.A. 48: 3-52(b), and build on the foundations established in the PSE&G and GPU cases by establishing credits that are among the highest in the nation. Enron also supports the unique aspect of the shopping credits in Stipulation I, which establish minimum credits that can increase if BGS costs or transmission rates increase. This should allow power marketers to more fully compete in the ACE service territory should generation prices rise during the Transition Period. Enron strongly supports the cooperative effort by the stipulating parties to conclude the billing and metering procedures no later than May 1, 2000, bringing competition to the customer account service area. Enron asks the Board to consider the affiliate relationship standard language provided in paragraph 21(c) of Stipulation I, so that the generation affiliate receives no unreasonable benefits or preferences from its relationship with ACE and that no market abuses occur in the early stages of competition. Enron is concerned that the affiliate and the utility could package products and could provide services which competitors would not be allowed to receive and that an affiliate could offer more favorable pricing than those available in a competitive market. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -65- 68 4. Independent Energy Producers of New Jersey IEPNJ, a signatory party to Stipulation I, submitted a letter dated June 16, 1999, indicating its full support for Board adoption of Stipulation I. IEPNJ argues that the settlement provides for rate reductions, competitive shopping credits, and the reduction of ACE's stranded costs and otherwise promotes the objectives of the EDECA, while balancing the interests of ACE, its ratepayers and the parties to the proceeding. 5. Mid-Atlantic Power Supply Association MAPSA, a signatory to Stipulation II, filed comments criticizing Stipulation I and urges Board rejection of Stipulation I in favor of Stipulation II. MAPSA asserts that Stipulation II presents reasonable unbundled rates while affording the Company a reasonable opportunity to recover stranded costs remaining after ACE auctions all of its generating plants. Stipulation II would also minimize the level of deferrals during the Transition Period and effect shopping credits that will facilitate competition over the short and long-term. MAPSA asserts that Stipulation II is more consistent with the Board's determinations rendered in the PSE&G and GPU restructuring proceedings. MAPSA cites as the greatest deficiency of Stipulation I the level of the shopping credits, which keep pace with neither the PSE&G nor GPU shopping credits that have been adopted by the Board. For example, if the Board approved GPU residential shopping credit was adjusted to reflect ACE's transmission cost component, the shopping credit would be 5.83 cents/kwh in 1999 as compared to the 5.15 cents/kwh set forth in Stipulation I. The inadequate level of the residential service shopping credit will result in the inability of alternative suppliers to offer competitive prices for service, which will ultimately result in the failure of competition in the ACE territory. MAPSA argues that the Board must, at a minimum, increase the ACE shopping credits to levels on par with those approved in the PSE&G and GPU territories if it is to avoid discriminatory pricing results. MAPSA proffers a schedule of 1999 minimum shopping credits based upon a forecast of future wholesale energy and capacity costs, transmission costs and a portion of retail service costs: the residential shopping credit derived by MAPSA is 5.82 cents/kwh and 6.82 cents/kwh when retail costs are added. In comparison to these conservative shopping credits, those embodied in Stipulation I are set too low to encourage competition. Even suppliers such as Green Mountain, which does not rely upon price alone to market power, would have a difficult time, given that customers' willingness to pay more for an environmentally friendly product is not unlimited. MAPSA perceives that the PSE&G and GPU shopping credits were partially designed on the basis of credits established for PECO in Pennsylvania. When the PECO shopping credit is adjusted for costs specific to New Jersey and ACE, the result is a residential credit of 5.77 cents/kwh, a credit well above that proposed in Stipulation I. MAPSA urges the Board to adjust the shopping credits contained in Stipulation I upward to reflect what it has denominated as PECO-adjusted or GPU-adjusted levels. MAPSA favors the establishment of any stipulated credits as mere minimums, a provision set forth in paragraph 6 of Stipulation I, and argues that the Board should adopt such proposal for whatever level of credits it finally adopts. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -66- 69 MAPSA opposes Board adoption of the provisions set forth in paragraph 8 of Stipulation I, which requires customers who switch from an electric power supplier back to BGS service to remain on BGS for a minimum 12-month period based upon the circumstances that precipitated the return to BGS. MAPSA argues that this provision will effectuate an unnecessary barrier to competition by encouraging customers to remain with the utility, especially at the outset of competition. MAPSA urges the Board, at a minimum, to exempt residential customers from the 12-month minimum BGS requirement as it did in its GPU decision. While MAPSA does not object to ACE's proposed deferral of cost underrecoveries specified in Stipulation I, it urges the Board to add the following conditions for such deferrals. First, the Board should require ACE to pursue its maximum effort in mitigating NUG costs; there should be an annual review, including public evidentiary hearings, to evaluate any above-market costs to ensure that their deferral was necessary, reasonable and prudent. Secondly, the Board should require that during periods when ACE is able to supply BGS at rates lower than the established BGS rates, the cost differential should be recognized as a contribution by non-shopping customers to offset other deferred costs. The Board has implemented this requirement for both PSE&G and GPU. MAPSA argues that the Board should require ACE to completely divest its generation assets as a condition for acceptance of Stipulation I. Stipulation I provides that the Company will auction some but not all of its generation facilities. By auctioning off only some of its facilities, MAPSA argues that ACE could retain the most valuable units for its generation affiliate while saddling ratepayers with the stranded costs of its least efficient units. If the Board rejects this MAPSA proposal, Green Mountain urges the Board to adopt certain generation affiliate code of conduct principles to be determined in a generic proceeding. Those principles require that if ACE is unable to divest all of its assets and wishes to transfer ownership or operating rights to an affiliate, that affiliate is required to operate the unit(s) under the following strictures: 1) the generation affiliate cannot offer power or services to any of its affiliates on terms unavailable to non-affiliated companies or under prices more favorable than those either available in the competitive marketplace or offered to non-affiliated companies; 2) during the period that ACE is collecting transition costs or acting as the BGS provider, whichever is longer, the generation affiliate must sell the output of its assets previously owned/operated by ACE into the wholesale market, excluding output sold to ACE for BGS; 3) the generation affiliate must be a subsidiary separate from ACE's retail, marketing or distribution/BGS function; and 4) the transferred generation shall serve as a capacity resource within PJM through the transition period, during which time it may sell capacity outside of PJM after good faith efforts are made to sell it within at market rates. Finally, MAPSA argues that allowing ACE or an affiliate to bid for the supply of wholesale or retail BGS as part of the competitive bidding process would create the potential for harm to the competitive process and should not be permitted. Thus, the Board should reject the provision of Stipulation I providing for such affiliate bidding. 6. New Jersey Commercial Users NJCU, a signatory party to Stipulation I, indicates that it entered into Stipulation I because it believes its interests are best served by entering into the Stipulation rather than having the Board decide the cases in the absence of an agreement. NJCU asserts that the terms and BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -67- 70 conditions of Stipulation I are within the range of reasonableness, and recommends adoption of Stipulation I. NJCU asserts that the rate reductions provided in Stipulation I meet the requirements of both the Final Report and the Act, and are consistent with the NJCU's litigated position that there should be at least a 10% base rate decrease. The Stipulation provides shopping credits for commercial customers, which meet the principle that such credits must be set at a level to foster adequate competition in each customer class, and the Stipulation meets NJCU's requirement that the savings resulting from shopping be over and above the mandated 10% rate reduction. NJCU indicates that any changes in the shopping credits, which adversely effect commercial customers will be viewed by NJCU as rendering Stipulation I null and void. NJCU asserts that Stipulation I satisfies its litigated position and the legislative mandate that rates must be fully unbundled in a revenue-neutral manner in order to avoid cross-subsidization and to allow customers to comparison shop; Stipulation I provides separate charges for BGS, transmission, distribution and customer services, SBC, NNC, and MTC. It further provides shopping credits for both energy and capacity. Finally, NJCU believes that ACE has done the right thing by agreeing to divest itself of most of its generating assets, which should reduce generation stranded costs by a significant amount. NJCU also finds the incentives which Stipulation I provides ACE, for the mitigation of its NUG contracts costs to be appropriate, stating that it is in the best interests of all parties to achieve such costs reductions through consensual means. 7. New Jersey Industrial Customer Group NJICG, a signatory party to Stipulation II, urges the Board to reject Stipulation I and to adopt Stipulation II. NJICG argues that Stipulation I exempts ACE from the Board's mandate that all stakeholders must share the costs of implementing retail competition. According to NJICG, Stipulation I contravenes the Act and is disadvantageous to ratepayers in that it fails to meet three essential criteria: (1) sustainable rate relief for all consumers, (2) robust retail competition, and (3) equitable apportionment of restructuring's cost among stakeholders. NJICG asserts that, contrary to the mandatory reductions required by the Act, Stipulation I conditions its rate reductions upon the Board's approval of the divestiture of certain generating assets, securitization of 100% of net stranded costs. Stipulation I further conditions its minimum shopping credits upon the Board's approval of its proposed rate reductions. In contrast, Stipulation II fully satisfies EDECA's rate reduction mandate. Stipulation I calls for a 1.3% rate reduction resulting from the merger to be included towards satisfying EDECA's minimum rate reduction, but fails to mention that it was fully offset by a significant increase in the 1997 LEAC. NJICG asserts that the 3.9% rate reduction in Stipulation I denies ratepayers the full extent of the Act's minimum rate relief requirement right by using LEAC and DSM overrecoveries to fund the rate reductions. Stipulation I allows for the deferral of certain costs such as BGS and NUG costs to fund the remaining rate reduction if ACE's plan does not result in a 10% rate relief. This will force consumers to pay for the mandated rate reduction, including carrying costs on the deferred costs, after the Transition Period ends. Instead, NJICG asserts that ACE should offset the cost BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -68- 71 of this latter rate reduction through increased operating efficiencies and related cost savings. Any additional rate reductions realized from NUG contract buyouts/buydowns, divestiture of generation assets, and securitization should be passed through to customers. After one year, ACE should be required to provide an additional 1% rate reduction. Only then should the rate reductions resulting from the merger be applied. NJICG asserts that, unlike Stipulation II, Stipulation I provides a shopping floor that is not sufficient to establish a robust competitive market for smaller customers, especially residential and small commercial consumers. According to NJICG, Stipulation I's requirement that commercial and industrial customers who were switched back to BGS remain on BGS for a minimum of 12 months is unduly discriminatory and should be rejected. In the alternative, the Board, at a minimum, should modify ACE's proposed requirement so that the minimum 12-month BGS requirement for customers switching back to BGS should only apply to those customers that choose to return to BGS, and not to those customers forced onto BGS due to an emergency or EPS failure. NJICG notes that Stipulation II sets out an exemption to any customer who returns to BGS due to the refusal or the inability of the customer's EPS to continue to provide service to that customer. NJICG asserts that Atlantic's divestiture plan and any associated use of parting contracts should be considered and approved by the Board when they are filed and not in advance. ACE should also be required to divest ownership in all its generation plants, including Deepwater Station and the CTs, to determine stranded cost levels as accurately as possible. If ACE is unable to divest such assets, an initial market-value determination should be conducted in a separate divestiture proceeding before any transfer to an affiliate. According to NJICG, NUG marketing and administrative costs associated with the sale of the NUG contract power into the wholesale market should not be treated as stranded and should not be paid by customers through the NNC. Furthermore, costs associated with the retirement of outstanding capital and those considered as restructuring operating costs, which by definition are "going forward" costs should not be recovered as stranded. Similarly those stranded costs for which the Board requires a write-off or the Company to absorb should not be paid for by customers through the MTC. Lastly, NJICG asserts that ACE should not receive a guarantee to recover deferred revenue and should not earn its authorized rate of return on such balances. VII. DISCUSSION AND FINDINGS As noted above, after the close of hearings in these proceedings, the New Jersey Legislature passed, and on February 9, 1999, Governor Whitman signed into law, the Electric Discount and Energy Competition Act of 1999, N.J.S.A. 48:3-49 et seq. The Act in numerous areas sets forth explicit directives with respect to the implementation of electric retail choice and, during a four-year transition period, establishes minimum aggregate rate reduction levels for electric public utilities. EDECA also provides specific guidelines and parameters for the BPU to follow with BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -69- 72 respect to numerous restructuring related issues, but in many areas leaves important decision-making details to the BPU's expertise, consistent with those guidelines and parameters(5). EDECA requires that each electric public utility submit rate unbundling, stranded costs and restructuring filings to the BPU, in a form to be determined by it, and explicitly provides that filings submitted and proceedings conducted prior to EDECA's effective date satisfy such requirements, provided that the BPU shall take such actions as may be necessary, if any, to ensure that the Act's requirements are met in all regulatory actions related thereto which were commenced prior to its enactment. N.J.S.A. 48:3-98. The Board HEREBY FINDS that this requirement of the Act has been met and that the filings submitted and the proceedings conducted prior to the Act's effective date were thorough and complete and provide an adequate record, and therefore satisfy EDECA's requirements. As summarized in some detail hereinabove, the Board has, by virtue of the issuance of its April 30, 1997 Order Adopting and Releasing the Final Report and subsequent BPU-directed electric public utility filings on July 15, 1997 and ensuing hearings at the OAL and before the BPU, caused an extensive evidentiary record to be developed in these proceedings, and has provided substantial opportunity for public input in both the development of its policy findings and recommendations as set forth in its Final Report, and in the subsequent rate unbundling, stranded costs and restructuring filings and related proceedings. As noted above, nine days of evidentiary hearings were held at the OAL on the stranded costs and rate unbundling issues, and an additional twenty days of hearings were held before former Commissioner Armenti on the restructuring-related issues. In reviewing the voluminous record before us, it is clear that many of the significant issues in these proceedings are factually interrelated, with the outcome of one materially impacting decisions in other areas. This is particularly the case with respect to the level of rate reductions, the level of shopping credits, stranded costs recovery, and the various components of unbundled rates. In transmitting these matters to the OAL, the Board, in anticipation of the enactment of legislation in this area, requested that the ALJs in this and the other electric public utility proceedings develop a broad record on stranded costs and rate unbundling issues and, specifically with respect to the issues of rate reductions, stranded costs and securitization, issue a range of recommendations. With the passage of EDECA, with its explicit directives, guidelines and parameters, the Board is now prepared to render decisions with respect to the subject issues in these proceedings in conformance therewith, based upon the record developed and comments submitted, and in a time frame necessary to comply with the retail choice time line set forth in the Act. - -------------------------- (5) Subsequent to the BPU's issuance of its Summary Order in this matter, appeals were taken from the BPU's Final Order in PSE&G's stranded costs, rate unbundling and stranded costs proceeding. The Appellate Division affirmed the BPU's decision in that case in its entirety, In re PSE&G Co.'s Rate Unbundling, 330 N.J. Super, 65 (App. Div. 2000), ("PSE&G appeal"), and by preliminary Order dated December 6, 2000, the Supreme Court summarily affirmed the Appellate Division's decision and indicated that a fuller opinion would be forthcoming. N.J. (2001). The Appellate Division found in its decision, that "[d]eference must be accorded the legislative judgment and the BPU's judgment concerning interpretation of the Act." (citations omitted). 330 N.J. Super. at 98. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -70- 73 The Board acknowledges and appreciates the efforts of ALJ Gural in presiding over the stranded costs and unbundling proceedings and in producing a detailed and thorough Initial Decision. In light of the enactment of the new legislation and the subsequent developments in the case as summarized herein and, consistent with our previously issued decisions in the PSE&G and GPU cases, the Board HEREBY MODIFIES the Initial Decision as described below. Subsequent to the close of hearings and the issuance of the Initial Decision, shortly after the Act was signed into law, and with the encouragement of the BPU, as set forth in its February 11, 1999 Order, settlement conferences were held among the parties to the ACE proceedings. These discussions ultimately led to a crystallization of the issues and the proffer of two alternative settlement proposals which are before us for consideration along with the Initial Decision and the extensive record developed before ALJ Gural and the Board. The Board is cognizant of the fact that each of the proposed stipulations before us is non-unanimous. Nonetheless, it is well-established that the Board may consider and rely upon non-unanimous stipulations as fact-finding tools so long as the non-signatory parties have had an opportunity to argue against them and the Board independently examines the existing record and expressly finds that the stipulated rates yield rates that satisfy the statutory standards. I/M/O Petition of PSE&G, 304 N.J. Super 247, 270 (App. Div. 1997), cert. den. 152 N.J. 12 (1997). The Board continues to believe that, in complex and technical cases such as this one, "the adversary parties themselves are often in the best position to work out the framework of a reasonable resolution of the issues." Id. at 259. The Board FINDS that, in the instant matter, all of the parties in this case were given an opportunity and, indeed were encouraged by the Board, by Order dated February 11, 1999, to participate in an attempt to negotiate a settlement and that all parties were given an opportunity, via the submission of written comments, to raise their concerns to the Board with respect to the alternative stipulations which were proffered to the Board for its consideration. Id at 270. The Board FURTHER FINDS that the evidentiary record before it as summarized hereinabove, is sufficiently comprehensive and detailed to allow the Board to fully consider all of the issues before it. (6) As stated in the Board's Summary Order in this matter, and as will be explained in more detail below, based on its review of the extensive record in these proceedings, as well as the proposed two alternative stipulations and the comments received thereupon, the Board FINDS Stipulation I, sponsored by ACE and other parties, to be, overall, more financially prudent and consistent with the Act's requirements and consistent with the record. The Board FURTHER FINDS that with the modifications and clarifications to a number of key elements, as initially set forth in the Board's Summary Order and as amplified and clarified herein, Stipulation I can serve as a reasonable framework for a fair resolution of these matters based upon and consistent with the record before us. Conversely, as described below, the Board FINDS Stipulation II, sponsored by the Ratepayer Advocate and other parties, to be, in many significant areas, not supported by the record, reliant upon miscalculations and inappropriate assumptions or conclusions, and not reflective of a balanced consideration of all the issues in these matters. However, a number of specific and legitimate concerns have been raised by various - ------------------------- (6) In the PSE&G appeal, the Appellate Division addressed and affirmed the BPU's decision to consider and rely upon elements of a non-unanimous stipulation, where similar procedures were followed as in the instant case. 330 N.J. Super. at 111. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -71- 74 commentors, including the proponents of Stipulation II, and, where appropriate, and as discussed herein, these have been addressed by the modifications and clarifications to Stipulation I set forth below. First, as to the magnitude of rate reductions and the shopping credits, the Board notes the following with respect to the provisions of the Act. N.J.S.A. 48:3-52(d) (2) requires that, as of August 1, 1999, each electric public utility must reduce its aggregate level of rates, inclusive of all unbundled rate components by at least 5%.(7) N.J.S.A. 48:3-52 (d) and (j) further provide that the Board may adopt a schedule for the phase-in of additional rate reductions over the ensuing 36 months, except that, in any event, by no later than August 1, 2002, each electric public utility shall reduce its aggregate level of rates by at least 10% relative to the level of bundled rates in effect as of April 30, 1997 and shall sustain such final level of rate reduction for at least 12 months, through at least July 31, 2003. These provisions essentially establish a price cap under which all unbundled rate elements must fit during the four-year period from August 1, 1999 through July 31, 2003. As such, to the extent one unbundled rate component is increased, all other things remaining equal, either one or more other unbundled rate components must be decreased, or the overall aggregate level of rate reduction must be reduced from what it otherwise would or could have been. This relationship is particularly relevant given the requirements and provisions of N.J.S.A. 48:3-52(b) and (f), specifically those provisions which require the Board to establish shopping credits applicable to the bills of retail customers who choose to purchase electric generation service from a duly licensed power supplier, at levels which, among other things, encourage the development of a competitive retail supply marketplace, while, at the same time, providing and sustaining the required aggregate level of rate reductions. Under the price cap mandated by the Act, once the other unbundled rate components, including provisions for stranded costs recovery, are established, higher shopping credits would result in lesser rate reductions, and vice versa, absent a deferral of the recovery of costs into some future period. In a very real sense then, the Board is required by the Act to balance the achievement of two crucial, yet potentially conflicting factors. All other things being equal, a movement too far in one direction, in favor of larger shopping credits at the expense of lesser rate reductions, would benefit electric power suppliers and/or shopping customers, at the expense of customers who do not choose to switch suppliers. Conversely, a move too far in the other direction, in favor of smaller shopping credits at the expense of larger rate reductions, would benefit non-shopping customers, while potentially inhibiting the development of a competitive market by making it less attractive for third party suppliers to enter the marketplace, thus resulting in diminished opportunities for customers to switch suppliers. The Board FINDS that the rate reductions proposed in Stipulation I do not comply with N.J.S.A. 48:3-52(d)(2), which requires a minimum rate reduction of 5% from current rates, effective August 1, 1999. The Board FURTHER FINDS that this requirement in EDECA supersedes our previous ruling in the merger proceeding, issued prior to EDECA's enactment, that the 1.2% rate reduction implemented at the conclusion of the merger may be counted towards the required restructuring-related rate reductions. Allowing the pre-EDECA merger-related rate reductions to count towards EDECA's mandated 5% rate reduction on August 1, 1999, would violate both the intent and specific directive of the Act that customers receive certain specified - ------------------------- (7) In the PSE&G appeal, the Appellate Division upheld the BPU's interpretation that the initial 5% is to be measured relative to then-current rates. 330 N.J. Super. at 103. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -72- 75 minimum guaranteed rate reductions over a four-year transition period as a direct result of the legislatively-mandated electric restructuring process. Accordingly, the Board HEREBY FINDS that rate reductions agreed to and approved by the Board to resolve prior proceedings cannot be used to fulfill EDECA's minimum rate reduction requirements. Significantly, EDECA does not prescribe the potential sources of the mandated rate reductions but, rather, leaves this determination to the discretion and expertise of the Board. Having considered the arguments of the parties on this issue, the Board is of the view that Stipulation I's proposal to use the LEAC and DSM overrecovery balances to fund a substantial portion of the Act's mandated initial rate reductions is inappropriate. These overrecovery balances represent monies which were collected from ratepayers via a Board-approved deferred accounting mechanism over the past several years at levels which exceeded the relevant costs incurred by the Company. Under the deferred accounting ratemaking already in place for these two items, these overrecoveries would be owed to ratepayers, and refunded or credited back to customers, with interest, when these accounts are periodically trued up. As such, the Board FINDS it inappropriate that monies already owed to ratepayers as a result of such overcollections, which occurred largely prior to the passage of EDECA, be utilized to meet the Act's restructuring-related rate reduction requirements. Conversely, the Board does not believe it appropriate that such overcollection balances be refunded to customers in a manner which would artificially and temporarily inflate the rate reductions implemented as a result of this Order. This is particularly the case in light of the possibility that ACE could, under certain conditions, accrue separate underrecovered deferred balances during the period of the price cap, which monies would have to be collected from customers after the Transition Period. As such, the Board FINDS it more appropriate and HEREBY DIRECTS that the LEAC and DSM overcollection balances as of August 1, 1999 shall be credited to, and become the starting balance of, the Deferred Balance established pursuant to paragraph 27 of the findings section of this Order below. In this manner, such overrecovered amount will be available, with accrued interest, to offset and mitigate the impacts of any separate undercollections during the Transition Period and thereby mitigate against the potential need for a rate increase after the Transition Period. If there is no underrecovered Deferred Balance at the close of the Transition Period, the overrecovered balance, with interest, will be refunded to customers, or otherwise credited to ratepayers at the conclusion of the Transition Period. The Board further concludes that Stipulation I's proposal to implement a rate credit during the last year of the Transition Period is not inconsistent with N.J.S.A. 48:3-52, which mandates that the maximum rate reduction level ordered by the BPU, which, beginning on August 1, 2002 must be at least 10% from April 1997 rates, must be sustained through July 31, 2003. The Board is, however, concerned as to the potential rate impact of such a proposal on the rates for year five and beyond. Accordingly, as discussed below, and consistent with its Final Decisions and Orders in the PSE&G and GPU rate unbundling cases, the Board will require and HEREBY DIRECTS ACE to make a filing, no later than August 1, 2002, as to the proposed level of all unbundled rate components beginning August 1, 2003, so that the Board can consider this BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -73- 76 matter prior to the end of the Transition Period(8). The Board emphasizes that all parties will be afforded an opportunity to participate in this proceeding. Additionally, consistent with the authority and flexibility afforded to the Board by the Act, including N.J.S.A. 48:3-52(d) and (e), the Board FINDS that ACE can achieve rate reductions in excess of the minimum-prescribed amounts, by the implementation of an interim rate reduction step beyond the 10% minimum. The Board FINDS it appropriate and HEREBY DIRECTS that the Company further reduce its aggregate level of rates by at least an additional 2% by no later than January 1, 2001. The Board recognizes that ACE is actively pursuing negotiations with NUG owners to buy out, buy down or restructure its NUG contracts and that, if successful, ACE will be requesting permission to securitize related buyout, buydown or restructuring payments. Moreover, ACE has stated its intent to divest its base load generating units, which is permitted, but not required under EDECA. It is both appropriate and consistent with the provisions of the Act that rates be immediately reduced upon the competition of such transactions to reflect the full resultant savings. To the extent that such savings result in aggregate rate savings of less than 2% as of January 1, 2001, the Board DIRECTS that ACE shall, in any event, achieve the 7% total rate reduction ordered herein by that date. To the extent that such savings meet or exceed 2% in savings relative to current rates, the full and actual amount of such savings shall be reflected in rates upon competition of such transactions. In compliance with the Act, the Company shall, in any event, by no later than August 1, 2002, implement at least a 10% rate reduction relative to the aggregate level of rates in effect as of April 30, 1997, inclusive of any and all divestiture, NUG buyout and securitization savings achieved as of that date. In this manner, ACE will have a strong incentive to maximize the sale price for its generating assets, and to achieve the most favorable NUG buyout terms possible, as resultant savings may be applied as a mitigation measure to "count" towards the mandated rate reductions. While the 3.2% rate refund will expire on August 1, 2003, the Board will, as noted above, conduct a review of all unbundled rate components, including the MTC for all four of the State's electric public utilities, including ACE, prior to that date, in order to establish the appropriate level of rates going forward after the Transition Period. Accordingly, there will be no "automatic" 3.2% rate increase for ACE customers after the Transition Period as some of the commentors complained would occur if Stipulation I were adopted. Moreover, the Board emphasizes that the rate reductions which it has ordered herein are in addition to any savings which may be realized by customers as a result of shopping and switching to an electric power supplier, and receiving a shopping credit for the energy supply that is no longer being purchased from the utility. Finally with respect to rate reductions, the Board FINDS that conditioning the rate reductions in Stipulation I on divestiture and/or securitization is not consistent with the Act's mandated minimum rate reduction requirements, as set forth in N.J.S.A. 48:3-52. Accordingly, the Board FURTHER MODIFIES Stipulation I's rate reductions and refund provisions to require that the initial 5% and final 10% rate reductions shall not be contingent on divestiture or securitization. In determining the specific breakdown of unbundled rates to be effective August 1, 1999, which will aggregate initially to a level which is 5% less than the current level of bundled rates, a - ----------------- (8) It should be noted that all four electric public utilities in the State will be required to make such filings. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -74- 77 critical initial determination which must be made by the Board is the quantification of the average unbundled distribution rate included within the aggregate level of rates established in this Order. The Company filed and utilized in the rates proposed in its petition a cost of service study which employs 1996 rate base, revenue and expense data. While the ALJ acknowledged that such proposed use deviates from the Final Report requirement that the COSS from the last base rate case be used to unbundled rates, he concluded that resurrecting the 1988 COSS, which was utilized in the Company's last base rate case and which the Company claims no longer exists in its files, would be a difficult task with questionable accuracy. Thus, the ALJ recommended that the Board modify its requirement and allow use of an updated study, concluding that the 1996 COSS presented by ACE may be the best and most accurate source for developing unbundled rates. Indeed, the unbundled rates proposed in Stipulation I rely upon the 1996 COSS. In addition to the arguments raised before the ALJ and in the parties' exceptions and reply exceptions on this issue, within the context of the submitted stipulations and the extensive comments filed in response thereto, the Board has received and carefully considered additional arguments submitted by the parties with respect to this issue. Moreover, EDECA contains certain provisions and guidelines which deal specifically with electric rate unbundling. Among other things, the Act requires that each electric utility's rates be unbundled concurrent with the implementation date for retail choice and that such unbundled rate components include, among other charges, discrete charges for distribution services. N.J.S.A. 48:3-52(a). The Act further requires that each electric public utility submit rate unbundling filings in a form adopted by the Board, and that the Board, after hearing, shall render a determination as to the appropriate unbundled rates consistent with the provisions of the Act, and that such rates shall not result in a reallocation of utility cost responsibility between or among different classes of customers. N.J.S.A. 48:3-52(c). Within those parameters, the Legislature left to the Board the authority and discretion to determine the "appropriate" level of the unbundled distribution (and other) rate component(s). Having considered the arguments which were made before the ALJ, as well as the comments which were submitted directly to the Board on this issue, the Board is persuaded that, given the particular facts and circumstances of this case, an appropriate and reasonable distribution rate, and other unbundled rate components, can best and most accurately be established on a going-forward basis by utilizing, with certain appropriate modifications, the updated cost information as reflected in the 1996 COSS. It is clear from the record which has been developed in this proceeding that the net investment in distribution plant has increased since the last base rate case and that, were the Board to impose the legislatively-mandated rate reductions and establish going-forward unbundled rates based strictly upon a 1988 COSS, the level of distribution rates would substantially understate ACE's actual level of costs. The Board is mindful of its statutory duty to maintain the financial integrity of the utility during the transition to competition, as well as its responsibility to assure the provision of safe, adequate and proper distribution service to customers. N.J.S.A. 48:3-50 (a) and (c). Moreover, once the distribution rates are established in this proceeding, under the price cap mechanism provided in the Act, ACE will have no ability during the Transition Period to adjust its distribution rates. Unlike all other components of unbundled rates established herein, including the SBC, MTC and any Transition Bond Charges, the unbundled distribution rate set in this case will not be subject to true-up. Accordingly, the Board FINDS it appropriate to utilize the more current 1996 information in this record to establish a just and reasonable distribution rate. We further note in this regard that, even using the 1996 COSS data, by the end BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -75- 78 of the price cap and Transition Period in August 2003, the cost levels set forth in the 1996 COSS will be seven years out of date. Correspondingly, 1988 COSS information, even if it could somehow be resurrected, would be 15 years out of date by the end of the Transition Period. Based on the foregoing, the Board is persuaded by the arguments of the ALJ and the parties supporting use of the 1996 COSS, and FINDS that, subject to appropriate adjustment, the 1996 COSS, rather than a 1988 COSS, should be the basis for establishing the unbundled distribution rates in this matter. The Board notes that the average distribution rate proposed in Stipulation I is 2.58 cents per kwh, not including the Corporation Business Tax, Transitional Energy Facilities Assessment, and Sales and Use Tax, uncollectibles and regulatory asset charges. Based on its review of the record in this proceeding, the Board FINDS that the stipulated system average distribution charge of 2.58 cents per kwh is not consistent with the cost information reflected in the 1996 cost of service study provided in the rebuttal exhibits of Carl Setterman, Volumes I and II, but rather reflects a number of cost elements which are misfunctionalized or otherwise overstated. In developing the distribution rate, certain uniform system of accounts are considered, including the distribution component, meters, meter reading, customer records and collections, customer accounts expense, customer service and information, sales, customer miscellaneous, customer deposit and forfeited discounts and regulatory commission expense. Based upon the Board's review of these accounts in the 1996 cost study, the Board FINDS the stipulated system average distribution charge to be overstated, in that it inappropriately includes production-related costs. When these costs are removed, some of the administrative and general allocators change slightly, causing some portion of A&G costs to also shift to production. Moreover, the Board's review indicates a portion of regulatory commission expense is related to residual transmission, causing the residual transmission portion of the distribution charge to increase slightly. Additionally, two further adjustments are necessary to take into account the March 1, 1998 and January 1, 1999 Board-approved merger savings rate reductions that were implemented subsequent to the 1996 COSS. Giving consideration to and making appropriate adjustments to reflect these elements, the Board FINDS the appropriate average unbundled distribution rate to be 2.1384 cents per kwh. The Board FINDS that this reduction in the proposed distribution rate, to reflect an appropriate level of distribution costs based upon the 1996 COSS, contributes to the ability of the Company to achieve the greater levels of rate reductions ordered herein relative to those proposed in Stipulation I, in a manner which will not compromise the financial integrity of the Company. The Board FINDS that the provisions in Stipulation I concerning adjustments to the unbundled transmission rate to reflect future FERC decisions are appropriate, and in no way present an adverse result for customers. This is so because any change in the FERC-approved transmission rate, either up or down, will translate into a change in costs, either up or down, for both the Company and electric power suppliers serving retail customers, and Stipulation I provides that the BGS rate/shopping credit will go up or down accordingly. Moreover, because the sum of delivery (distribution plus transmission) charges and revenue requirements is being set as a result of this Order, the terms of Stipulation I and this Order provide that any increase (or decrease) in the FERC-approved transmission rate will automatically result in a corresponding decrease (or increase) in the distribution rate, such that no change in overall rates will result. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -76- 79 With regard to the BGS pricing and the level of the proposed shopping credits, the Board generally concurs with the Company's arguments. In fact, the floor shopping credits contained in Stipulation I are, on average, higher than those which the Board recently approved in its decision in the PSE&G restructuring matters; more importantly, the proposed shopping credits are floor numbers which, according to the terms of Stipulation I, will be adjusted upwards to the extent that market prices are indeed higher than those underlying the pre-established credits. The Board concurs with the Company that there is no support in the record for the level of shopping credits being proposed in Stipulation II; however, should the actual level of market power prices rise, the adjustment mechanism in Stipulation I would come into play and the shopping credits would be adjusted upwards accordingly. As such, the shopping credits are truly market priced. The Board has stated in previous Orders that, in light of the volatile nature of market prices, it is loathe to lock-in a four- year schedule of shopping credits based upon a "snapshot" of market prices, as the RPA and others inherently recommend. Moreover, particularly in light of the mechanism in Stipulation I for upward adjustments in the BGS rate/shopping credits, the Board agrees with the arguments expressed by ACE against setting the floor shopping credits too high. To the extent that the floor BGS rate/shopping credits are set at levels in excess of those justified by actual market prices, this could result in an artificially distorted market signal, a potential windfall for electric power suppliers and/or shopping customers, non-switching customers being overcharged for BGS service, and, under the mandated price cap and the residual method for setting the MTC as provided herein, an undercollection in the Deferred Balance which would have to be repaid by customers with interest after the end of the Transition Period. Accordingly, the Board FINDS that the higher levels of shopping credits proposed in Stipulation II are excessive based on the information developed in the record, and will upset the balance addressed above and in the Act between the achievement of competitive shopping credits to stimulate the development of a competitive market and the mandated rate reductions. The Board concurs with the RPA, however, that the proposed level of residential shopping credits is too low, particularly when compared to those proposed for secondary and primary level commercial and industrial ("C&I") customers, and will likely inhibit choice for residential customers. Given the typical power usage profile of a residential customer, as well as the expected higher retail transaction costs associated with residential customers, the Board FINDS it an inappropriate result that the average residential class shopping credit actually be lower than that provided for secondary and primary voltage C&I customers. Accordingly, the Board FINDS it appropriate to increase the residential shopping credits in Stipulation I by 0.50 cents per kwh for 1999 and 2000, and by 0.55 cents per kwh for 2001, 2002 and 2003, and to decrease the credits for secondary and primary voltage level C&I customers (MGS-Sec, MGS-Pri, AGS-Sec, AGS-Pri, AGT-Sec, AGT-Pri) by 0.1 cents per kwh, as set forth below. The Board also FINDS that the proposed bidding out of BGS for year four of the Transition Period is not inconsistent with the Act. N.J.S.A. 48:3-57(a) provides that each electric public utility must provide BGS for at least three years subsequent to August 1, 1999, and thereafter until the Board finds that such provision is no longer necessary and in the public interest. N.J.S.A. 48:3-57 (a) further provides that power procured for BGS shall be purchased at prices consistent with market conditions, that the BGS charges to customers shall be regulated by the Board and "based on the reasonable and prudent cost of ... providing such service...", and that the aggregate rate reductions be sustained notwithstanding the resultant BGS charges. Stipulation I provides that ACE will provide BGS through July 31, 2002, in conformance with the Act. The BGS pricing provided by Stipulation I, as modified herein, both during the first three BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -77- 80 years of the Transition Period when BGS is provided by ACE, as well as during the fourth year when BGS is anticipated to be provided for the first time by a third party as a result of the bid, is based upon market price projections in the record (plus a retail adder). Based on the projections of market conditions developed in the record in this case, the Board FINDS that Stipulation I's proposed BGS pricing for the Transition Period appears consistent with market conditions as required by the Act. The Board anticipates that the proposed bidding out of BGS for the fourth year as provided in Stipulation I should have the added benefit of creating substantial competition among electric power suppliers for the right to provide this service at the pre-established BGS rate/shopping credit price, thereby potentially producing added benefits to customers in terms of a reduction to the Deferred Balance consistent with the provisions of paragraph 6 of Stipulation I. This mechanism is consistent with the intent of the Act to place greater reliance on competitive markets to deliver energy services at lower costs. N.J.S.A. 48:3-50(a)(2). At the same time, however, the mechanism provided to have suppliers bid for the right to provide BGS during the fourth year at the pre-established price will assure that the aggregate rate reductions will be sustained in the fourth year, and should provide price stability as part of a reasonable and appropriate transition mechanism to the reliance on the competitive market for the provision of BGS. Accordingly, subject to the foregoing and to the terms of this Order, it may no longer be necessary and in the public interest for ACE to provide BGS in year four of the Transition Period or thereafter if BGS is successfully bid publicly as proposed in Stipulation I. The Board HEREBY DIRECTS that the Company file, by no later than August 1, 2001, a specific proposal for public comment and review and approval by the Board to implement a request for proposals ("RFP") to supply basic generation service for the period August 1, 2002 through July 31, 2003. Such proposal should include a proposal to assure that any RFP does not provide any undue competitive advantage to an affiliate of ACE, and that the selection process does not allow for favored treatment of an affiliate of ACE, should such affiliate choose to participate in the bidding process. The Board emphasizes however, that consistent with its statutory obligations under N.J.S.A. 48:3-57, as well as N.J.S.A 48:3-50(c) (5), it will continue to monitor market activity and reserves the right to reject or modify such an RFP proposal should market circumstances so warrant. In providing BGS for the first three years of the Transition Period, particularly in light of the price cap at the risk that actual market prices may exceed those underlying the pre-established BGS prices, The Board DIRECTS the Company, consistent with the provisions paragraph 11 of Stipulation I, to endeavor to mitigate such risk. By virtue of the price cap mechanism, a run-up in market prices above those assumed in establishing the BGS rates could result in an underrecovery of NUG stranded costs, which in turn could lead to a buildup in the Deferred Balance. Accordingly, it is in the public interest for ACE to pursue the mechanisms identified in paragraph 11 of Stipulation I to hedge against purchases of power for BGS in the open market. The Board notes in this regard, however, that in encouraging the use of such hedging mechanisms, it is not pre-judging the reasonableness and prudence of the actual parting contracts or financial instruments that the Company may procure in accordance with this Order, and that any such costs are subject to Board review and approval. Further, the Board deems it appropriate, in order to further mitigate the risk attendant to market price run-ups, that ACE apply both NUG contract power and to-be-divested owned generation power (prior to the closing of the sale of the generation assets) towards to the BGS supply requirement, which power shall be credited at the net BGS floor price (the floor shopping credit less transmission costs, sales and use tax, line losses, ancillary services and capacity reserve margin). Thus, a substantial portion of the BGS supply portfolio will be provided at a pre-established price, which will not put BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -78- 81 upward pressure on BGS prices. Such credited prices shall also be employed for purposes of establishing the level of the NNC component of the MTC and establishing the level of owned generation revenue requirement recovery (prior to the completion of divestiture) in accordance with this Order. In this manner, dedicating the NUG power and owned generation power to BGS supply at the net BGS price will also serve to mitigate stranded costs associated with these contracts and assets. There is also a risk of exacerbating the Deferred Balance to the extent that pre-established BGS rates for customer classes do not adequately reflect the seasonality of market prices for power, and suppliers and/or customers game the system through contract or other terms or practices which result in customers switching to third party suppliers during low cost periods and then returning to the utility during high cost periods. Accordingly, the Board HEREBY ADOPTS, subject to the modification below, the protections set forth in paragraph 8 of Stipulation I. While the Board recognizes the importance of such protections against potential gaming, it is concerned that provisions which require returning residential customers to remain with utility BGS for a one-year period may deter residential customers who are already reluctant to switch. The Board is concerned that such provisions may provide enough of a barrier in the residential market, where other barriers may already exist, to stifle retail choice. The Board, therefore, modifies Stipulation I to remove the one-year commitment for returning residential customers, while retaining the commitment for non-residential customers. The Board will, however, continue to monitor market activity and reserve the ability to further modify this decision should circumstances warrant. The Board FINDS that the level and composition of the MTC as proposed in Stipulation I, including the NNC for recovery of NUG stranded costs which it considers a subcategory of the MTC, comports with the provisions of the Act. Recovery of above-market costs associated with NUG contracts, as well as costs associated with NUG contract buyout payments, comports with the provisions of N.J.S.A. 48:3-61(a)(3). Further, early retirement and severance-related costs, which are included in Stipulation I in the calculation of net divestiture proceeds, and which therefore ultimately are reflected in the calculation of any remaining owned generation stranded costs (or stranded benefits) to be recovered from or credited to the MTC, are specifically included within the definition of "restructuring-related costs" in N.J.S.A. 48:3-51, and the Board considers such costs to be recoverable in the manner set forth in Stipulation I pursuant to the provisions of N.J.S.A. 48:3-61(a)(4). Moreover, with respect to owned generation stranded costs, the (non-NNC component) MTC will be recovering costs associated with assets which are in the process of being divested. Accordingly, the competitive sale of these assets will, if found reasonable and compliant with the Act and approved by the Board, should demonstrate the full market value of the assets, and should represent the best and most reasonable available measure to mitigate the stranded costs attendant thereto, in compliance with the standards for MTC recovery set forth in N.J.S.A. 48:3-61. With respect to the anticipated generation asset sales, the Board FINDS that divestiture is a voluntary business decision by the Company which is permitted, but not required by EDECA. N.J.S.A. 48:3-59. EDECA gives electric utilities the flexibility to make economic business decisions regarding the sale of their generation assets and the purchase of energy and capacity to meet the electricity needs of their customers. The Board notes that the concept of divestiture was supported by a number of parties during these proceedings. Additionally, as the Board noted in its September 17, 1997 Order, divestiture represents the most precise way to BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -79- 82 determine the market value of a utility's assets at a specific point in time. Moreover, while there was substantial litigation during the proceedings and attention in the ID to the issue of market price forecasts and related ranges of stranded costs estimates, the Board FINDS that an appropriately conducted asset sale should maximize the market value of the assets and yield a firm market value for the assets that the Board expects will supersede and indeed render moot the administrative estimates of market value provided in this proceeding. Thus, in accordance with the provisions of this Order, the Board FINDS that the net divestiture proceeds resulting from any such sale(s), as determined by the Board, shall be used to determine the remaining recoverable stranded costs (or in the event that net divestiture proceeds are positive, stranded benefits) associated with these assets, in accordance with the provisions of N.J.S.A. 48:3-61. However, the Board emphasizes that a determination by the Board of whether ACE appropriately conducted such asset sale(s), in accordance with the provisions of the Act, and existing Board policy, regulations and law, can only be made after a complete and thorough review of such sale(s) and after an opportunity for comment from interested parties. Such reviews and final determinations are appropriately conducted in the context of separate divestiture proceedings to be conducted by the Board in response to anticipated filings to be made by the Company.(9) The Board also recognizes that the negotiation of transition power purchase agreements or "parting contracts" as part of a generation asset sale, whereby the buyer agrees to sell some or all energy, capacity and/or other services from the purchased generating plants to the seller for some limited period of time, may be negotiated as an integral part of any asset sale agreement in connection with the divestiture(s), and can serve to protect ratepayers from the vagaries of the developing competitive energy market during the transition to competition. Power and other services procured by the Company as part of a parting contract would be utilized by ACE to meet its BGS requirements. Accordingly, it is appropriate that, once such parting contracts are deemed to be reasonable and in the public interest, and approved by the Board, provision be made for the full and timely recovery by ACE via BGS charges of the costs resulting therefrom, in accordance with the provisions of N.J.S.A. 48:3-57. However, the Board deems it appropriate that its determination as to the reasonableness of any parting contracts be rendered within the context of the anticipated divestiture petitions, after thorough review and an opportunity for parties to comment, rather than in the instant matter. With respect to the Deepwater Station and Combustion Turbines, the Board notes that Stipulation I provides that these units will be transferred to an unregulated affiliate of ACE at the asserted market value of these assets. This asserted market value is approximately $9 million less than the book value of the assets, resulting in remaining stranded costs of approximately $9 million, which ACE agreed in Stipulation I not to recover from ratepayers. The RPA asserts - -------------------------- (9) On January 4, 2000, in Docket Nos. EM99080605 and EM99080606, the BPU issued an Order Adopting Auction Standards applicable to the sale of ACE's nuclear and non-nuclear generating assets. On July 21, 2000, in Docket No. EM99110870, the Board issued an Order approving the sale of ACE's minority interest in the Salem Nuclear Generating Station, Units 1 and 2, Peach Bottom Atomic Power Station, Units 2 and 3, and the Hope Creek Nuclear Generating Station to PSEG Power and PECO Energy Company. On February 9, 2000, in Docket No. EM00020106, ACE filed a petition with the BPU requesting the approval of the sale of its fossil generation assets to NRG Energy, Inc. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -80- 83 that this proposed transfer value substantially understates the full market value of these generating assets, and recommends instead that a $160 million above-book premium be imputed to the transfer. The Board notes that the administratively-determined net stranded costs (adjusted book value less free cash flow) associated with the Deepwater Station and CTs, as endorsed by the Auditors in the record (BWG Report Exhibit V-1 and Table V-11, p.15, and Exhibit WRCR-9 ACE Witness Camp Rebuttal Testimony) is $5.1 million. Yet, ACE agreed to transfer the units at a $9 million loss, and to absorb this loss itself without recovery from ratepayers. The Board FINDS that a transfer on these terms will result in an unfair benefit to the ACE affiliate. Accordingly, the Board FURTHER FINDS, in order to more appropriately reflect the market value of the plants as adopted by the Auditors and to avoid a subsidization of the ACE affiliate by ACE, that the appropriate transfer value, which it FINDS reflects the fair market value of the assets, shall be the book value of the assets, which is $9 million higher than the amount provided for in Stipulation I. Nonetheless, recognizing the inherent uncertainty associated with an administrative determination of market value, the Board supports the proposal in Stipulation I that, for some period of time, any gains on the sale of these assets by the ACE affiliate to a third party be shared with the Company's ratepayers. However, the Board FINDS it appropriate that such sharing mechanism be in place for the full duration of the four-year Transition Period, as opposed to the three-year period proposed in Stipulation I. Moreover, recognizing the importance of maintaining adequate capacity in the PJM reliability region and marketplace during periods of heavy power demand, both for reasons of supply reliability as well as mitigation against large spikes in market prices, and recognizing further that these assets have historically been utilized by ACE to meet its PJM capacity reserve requirements, it is appropriate during the Transition Period that these units continue to be available within PJM. Accordingly, the Board FINDS it appropriate and ORDERS that, as a condition of the transfer during the Transition Period, ACE's affiliate shall offer capacity from the transferred units for sale within the PJM control area at market prices, and if the capacity is sold outside the PJM control area, the Company's affiliate shall make the capacity subject to recall by PJM during system emergencies. Stipulation I provides that there shall be no amortization of generation asset stranded costs during the period between August 1, 1999 and the divestiture of the assets, and that only after the completion of the divestiture and determination of actual stranded costs shall such stranded costs amortization commence. The RPA objects to this treatment, arguing that any amounts that ACE collects during the interim period should be credited back to customers as an offset to stranded costs. The Board FINDS that the treatment proposed in Stipulation I has the potential for ACE to reap a windfall, and also will leave ratepayers with no benefit commensurate with the MTC revenues they are contributing. The Board recognizes that, until the divestiture is complete, ACE will continue to incur carrying costs, depreciation expense and operating and maintenance costs associated with continued ownership and operation of the plants. The Board further recognizes that the value of the to-be-divested assets will soon be definitively determined, and that it, therefore, is not necessary or appropriate to set a stranded costs number related to these assets at this time. The Board, therefore, FINDS it appropriate that MTC revenues collected during the interim period be compared to the Company's revenue requirements associated with the units, including continued depreciation, and that upon extinguishment of the owned generation MTC the cumulative differential be applied to the Deferred Balance. In this manner, any collections in excess of ACE's costs will be credited to BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -81- 84 ratepayers, and the continued depreciation of the assets during the interim period will serve to reduce the net book value of the assets, and thereby the net stranded costs, ultimately resulting from the sale. Stipulation I provides that ACE retain as an incentive for a buyout, buydown, or restructuring of a NUG contract 10% of the savings associated with such transaction, except for the Pedricktown Project which for which the incentive would be 5% of savings. The Board emphasizes that it is allowing the Company herein to apply NUG contract buyout, buydown or restructuring savings to the rate reductions set forth in this Order, and mandated in the Act. To the extent that ACE is able to achieve NUG savings which permit it to achieve these reductions, ACE already has a substantial incentive to pursue and indeed maximize NUG savings. The Board HEREBY MODIFIES Stipulation I to provide that, during the Transition Period, ACE will only retain a portion of savings from NUG contract buyouts, buydowns or restructurings once the 10% aggregate rate reduction relative to April 30, 1997 rates is achieved without the use of cost deferrals. Upon application by ACE and a determination by the Board that the conditions of EDECA are met, the Board will issue a financing order consistent with the provisions of the Act, permitting securitization of NUG contract buyout, buydown or restructuring costs which have been approved by the Board and found to be eligible for securitization consistent with the standards in N.J.S.A. 48:3-61 and 62. With respect to the Deferred Balance, the Board FINDS that this should more appropriately be referred to as "Deferred Costs," rather than "Deferred Revenues" as proposed in Stipulation I, to better reflect the nature of the deferral, whereby deferral of recovery of some portion of MTC costs, NUG stranded costs and BGS costs may be necessary to achieve the rate reductions ordered herein, depending on market price conditions and subject to the provisions of this Order. Consistent with our determinations in the PSE&G and GPU cases, the Board FINDS that the appropriate interest rate thereon, for underrecovered balances is the interest rate on seven-year constant maturity treasuries, as shown in the Federal Reserve Statistical Release on or closest to August 1st of each year, plus sixty basis points best reflecting the time period over which the balance of deferred costs will likely be financed. Given the legislatively-imposed rate caps during the Transition Period, there is the potential, particularly if market prices were to escalate such that BGS rates are increased over an extended period of time, that ACE would not be able to fully recover MTC, NNC and/or BGS costs during this timeframe, and that the Deferred Balance could grow as a result to a level could lead to post-Transition Period spikes as those costs are later recovered. Accordingly, in order to avoid such circumstances, it is appropriate that ACE pursue BGS cost hedging mechanisms and that the Deferred Balance be recoverable, with interest, over a reasonable period of time post-Transition Period as may be determined by the Board. The Board FINDS that securitization of the net stranded costs associated with the divested generation assets to the extent permitted by N.J.S.A. 48:3-62(c), over a period of up to fifteen years is appropriate and will provide benefits to ratepayers, since it will enable the amortization of these remaining stranded costs over an extended period of time similar to the extended remaining lives of the assets, at a coupon rate on the bonds which is substantially less than the Company's overall cost of capital which currently supports the Company's investment in these assets. Upon application by ACE and a determination by the Board that the conditions of EDECA are met, ACE will be permitted to securitize its net stranded costs associated with the divested generation assets to the extent permitted by EDECA. ACE will be permitted to recover BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -82- 85 the legitimate "gross-up" for income taxes associated with the recovery of the net plant investment. However, such income tax recovery will be provided for in the MTC. The Board rejects the position of the RPA that the issuance costs associated with securitized bonds should be shared equally between the Company and ratepayers. N.J.S.A. 48:3-51 clearly includes issuance costs as part of the definition of "bondable stranded costs," and thereby permits ACE to recover such reasonably incurred costs in full, via the Transition Bond Charge. The Board FINDS it appropriate that the imputation of tax expenses or tax benefits for purposes of computing divestiture proceeds, MTC revenues divestiture and NUG buyouts be done on a utility stand-alone basis, as this matches the computation of tax effects included in the stranded costs quantification methodologies presented in the record in this matter. Moreover, these are specific and limited applications intended to measure the incremental impact of the transactions on the utility and ratepayers. The Board notes that the issue of consolidated taxes has been a controversial issue in the past in general ratemaking proceedings before the Board, and emphasize that the computation of tax impacts on a utility stand-alone basis as provided in this Order is for the limited purposes identified and has no precedential value with regard to future rate cases pertaining to the regulated rates of ACE. Based on the above, the Board hereby incorporates as a fair resolution of the issues in these proceedings, the elements of Paragraphs 1 to 46 of Stipulation I filed by ACE and others, subject to the modifications and clarifications set forth above, along with the specific modifications and clarifications set forth below. To the extent that the Initial Decision is inconsistent herewith, it is modified to conform herewith. Based upon the foregoing, the Board HEREBY FINDS AND DIRECTS as follows: 1. Electric rate reductions shall be implemented as follows to comply with the provisions of N.J.S.A. 48:3-52(d). The initial aggregate rate reduction, inclusive of all unbundled rate components, to be implemented effective August 1, 1999 shall be 5% from current rates. The average distribution rate for the Company effective on August 1, 1999 shall be 2.1384 cents per kwh. The MTC shall be set as the residual amount necessary to achieve the rate reduction, after accounting for other unbundled rate components established pursuant to this Order, including the distribution rate, regulatory asset charge, State energy taxes including Sales and Use Tax, Corporate Business Tax and TEFA, SBC, NNC, and BGS charge. The DSM and LEAC overrecovery balances, including accrued interest, shall not be utilized to offset regulatory asset charges but shall instead be credited to, and become the starting balance of, the Deferred Balance established pursuant to paragraph 27. Effective no later than January 1, 2001 the Company shall implement a further aggregate rate reduction of at least 2% relative to current rates (bringing the total rate reduction to at least 7%). However, to the extent that the Company completes the divestiture of generating assets and securitization of net owned generation stranded costs, or successfully completes a NUG contract(s) restructuring, buyout or buydown and securitization of net NUG stranded costs prior to January 1, 2001, it shall implement a rate reduction reflecting the full resultant savings no later than the date of the establishment of the resultant TBC. To the extent that such savings result in the implementation of a further rate reduction of less than 2%, ACE shall in any event reduce rates effective January 1, 2001, to achieve the 7% total rate reduction as of that date. To the extent that the savings resulting from divestiture and securitization of net owned generation stranded costs, and/or NUG restructuring buyout or buydown and securitizaton exceeds 2%. ACE shall implement a rate reduction BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -83- 86 beyond 7% to fully pass such savings on to customers, upon the date of the establishment of the resultant TBC. To the extent that the sum of the unbundled rate components as of July 31, 2002 exceeds the price cap resulting from the implementation of a 10% aggregate rate reduction relative to April 30, 1997 rates, which unbundled rate components are to reflect any savings which have resulted from the buyout, buydown, or restructuring and securitization of NUG contracts implemented pursuant to this paragraph, the Company shall consistent with the provisions of this Order implement an additional reduction in the MTC as necessary in order to achieve effective August 1, 2002 the mandated 10% aggregate rate reduction relative to April 30, 1997 rates. ACE shall make a filing, no later than August 1, 2002, as to the proposed level of all unbundled rate components beginning August 1, 2003, so that the Board may consider this matter prior to the end of the transition period. All parties will be afforded an opportunity to participate in this proceeding. In order to fund and sustain the rate reductions and the rate credit set forth in paragraphs 1(a) through 1(d) above, it may be necessary for the Company to defer the recovery of revenues associated with BGS, NUG costs, or other costs. No portion of the costs for BGS shall be deferred prior to the deferral of any other deferrable cost, as more specifically set forth in paragraph 27. 2. The initial 5% (August 1, 1999) and final 10% (August 1, 2002) rate reductions are required by the Act, and shall not be contingent upon divestiture and securitization of generation assets. 3. The four-year period commencing August 1, 1999, and terminating July 31, 2003, shall be referred to as the "Transition Period." 4. The unbundled rates to be effective August 1, 1999, for each rate class in ACE's Tariff for Electric Service have been developed using the Company's 1996 Cost of Service Study. See Appendix A to the Stipulation (rates/tariffs). The Board recognizes that the Company's transmission rates are subject to revision by the Federal Energy Regulatory Commission and may increase or decrease. Accordingly, the transmission and distribution rates are subject to revision, after the final determination of FERC is rendered, in order to produce the same revenues as the rates set forth in Appendix A to the Stipulation. 5. With respect to the shopping credit, in accordance with N.J.S.A. 48:3-52(b): a. For the four years of the Transition Period, up to and including July 31, 2003, the average "shopping credit" shall be the greater of the amounts determined in accordance with paragraph 6, inclusive of BGS rates and transmission rates, or the amounts set forth below: BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -84- 87
- ----------------------------------------------------------------------------------- Rate Class 1999 2000 2001 2002 2003 - ----------------------------------------------------------------------------------- Annual Annual Annual Annual Annual - ----------------------------------------------------------------------------------- RS 5.65 5.70 5.75 5.80 5.85 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- RS-TOU 5.10 5.15 5.20 5.25 5.30 - ----------------------------------------------------------------------------------- On Peak 6.59 6.65 - - - - ----------------------------------------------------------------------------------- Off Peak 4.67 4.72 - - - - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- MGS Secondary 5.35 5.40 5.50 5.60 5.70 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- MGS Primary 5.18 5.23 5.33 5.43 5.53 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS Secondary 5.30 5.35 5.45 5.5 5.6 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS Primary 5.07 5.12 5.17 5.22 5.27 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS TOU Secondary 5.05 5.10 5.15 5.20 5.25 - ----------------------------------------------------------------------------------- On Peak 6.01 6.07 6.13 6.19 6.25 - ----------------------------------------------------------------------------------- Off Peak 4.15 4.19 4.23 4.28 4.32 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS TOU Primary 4.95 5.00 5.00 5.00 5.00 - ----------------------------------------------------------------------------------- On Peak 5.88 5.94 5.94 5.94 5.94 - ----------------------------------------------------------------------------------- Off Peak 4.08 4.12 4.12 4.12 4.12 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS TOU Sub-Transmission 4.30 4.30 4.30 4.30 4.30 - ----------------------------------------------------------------------------------- On Peak 5.08 5.08 5.08 5.08 5.08 - ----------------------------------------------------------------------------------- Off Peak 3.57 3.57 3.57 3.57 3.57 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- AGS-TOU Transmission 4.25 4.25 4.25 4.25 4.25 - ----------------------------------------------------------------------------------- On Peak 5.00 5.00 5.00 5.00 5.00 - ----------------------------------------------------------------------------------- Off Peak 3.54 3.54 3.54 3.54 3.54 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- TGS 4.30 4.30 4.30 4.30 4.30 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- SPL/CSL 2.97 3.05 3.07 3.10 3.12 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- DDC 3.58 3.68 3.71 3.75 3.78 - ----------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------- SYSTEM AVERAGE 5.27 5.31 5.37 5.42 5.48 - -----------------------------------------------------------------------------------
BPU DOCKET NOS. EO97070455 EO97070456 and EO97070457 -85- 88 Shopping credits include the following: Basic Generation Service supply, transmission, ancillary services and administrative costs and taxes. The shopping credits set forth above are rate schedule averages. The actual BGS rates to be charged to customers, and the corresponding shopping credits resulting from those rates, will differ by blocks and load factors for those customers with rates which contain demand and energy components. b. The shopping credits set forth in paragraph 5(a) include a transmission rate component based on the average rate for transmission for each rate class; the actual shopping credit for each customer will be determined based on each customer's actual billing determinants and the transmission rates in the Company's unbundled retail tariff. c. In calculating the BGS rates pursuant to paragraph 6 below, the BGS rates shall be set so that the resulting BGS rate for each rate class remains in proportion to the system average BGS rate, as the BGS rates set forth in Appendix A to the Stipulation have with respect to the system average BGS rate for the BGS rates in Appendix A. to the Stipulation. 6. ACE shall provide BGS, in the following manner: a. The BGS rates shall be inclusive of the costs provided for in N.J.S.A. 48:3-57(a), inclusive of losses and taxes. b. Customers who choose to purchase electricity from electric power suppliers will not pay the BGS rates, and in addition will not be billed for transmission charges by ACE (if such charges are included in their charges from third party suppliers), which will be based on each customer's billing determinants and the transmission rates in the Company's unbundled retail tariff. c. The sum of the BGS and transmission charges shall be the shopping credit, subject to the provisions of paragraphs 5 and 6(b). If the shopping credit for any rate class is the amount set forth in the chart in paragraph 5(a), then the average BGS rate for the class shall be set as the shopping credit less the transmission charge. To the extent the rate for BGS as calculated in the first sentence of this paragraph, added to the average rate for transmission, produces a shopping credit in excess of the shopping credit levels in the chart in paragraph 5(a), then such BGS rate and the resulting shopping credit shall be utilized. The shopping credit mechanism set forth in paragraphs 5 and 6 satisfies the requirements of N.J.S.A. 48:3-52(h). BPU DOCKET NOS. EO97070455 EO97070456 and EO97070457 -86- 89 d. The rates as determined pursuant to paragraph 6(a) may be limited to the extent any portion of such BGS costs need to be deferred pursuant to paragraph 1 above. The shopping credit calculated from the BGS rate would similarly be limited. e. Additional shopping-related savings, resulting from customers receiving electric generation service from an TPS at a price less than the shopping credit, are above and beyond the rate reductions set forth in paragraph 1 of the findings section of this Order. 7. ACE shall apply both NUG contract power and to-be-divested owned generation power (prior to the closure of the sale of the generation assets) towards the BGS supply requirement, which power shall be credited at the net BGS price (the floor shopping credit less transmission cost, sales and use tax, line losses, ancillary services and capacity reserve margin). Such credited prices shall be employed for purposes of establishing the level of the NNC and establishing the level of owned generation revenue requirement recovery (prior to the completion of divestiture), in accordance with this Order. During the first three years of the Transition Period, up to and including July 31, 2002, ACE shall solicit requests for proposals ("RFP Process") for the provision of wholesale supply for BGS in twelve month pricing cycles, or such other cycles as ACE deems necessary or prudent. ACE will submit its plans for the RFP Process to the BPU by September 15, 1999. ACE shall commence the RFP Process as soon as practicable after such date and approval of the plan by the BPU, with the goal of concluding such process and entering into a contract for BGS supply by December 15, 1999. Any agreements for the provision of BGS shall be presented to, and subject to the approval of, the BPU. 8. In recognition of ACE's large seasonal customer base, which results in increased costs for energy and capacity to serve customers from June through September, non-residential customers switching into BGS from an EPS shall be required to remain on BGS for a minimum 12-month period; however, any non-residential customer, while switching service from one EPS to another, in accordance with Board-authorized switch rules, may return to BGS for 30 days without being required to remain on BGS; provided, however, that this exception shall not be available to any such customer who returned to BGS and then switched to an EPS within the previous 12 months. However, any residential customer who returns to BGS shall not be required to remain on BGS for a minimum 12-month period. The Board will monitor this issue and request related reports from the Company, and may revisit this issue if gaming occurs, or if it is otherwise determined by the Board to be appropriate. The Company may review with the parties and Staff, the residential seasonal BGS customer base to determine whether a filing for approval of a separate residential billing tariff, to avoid subsidies within the residential class between seasonal and year-round customers, is necessary for the summer of 2000 and beyond. 9. The Board recognizes that in order to establish BGS commencing August 1, 1999, until supply arrangements are made in accordance with paragraph 7, ACE may have to secure BGS supply requirements net of NUG power and owned generation through PJM for BGS, and that for purposes thereof, the BGS pricing shall be based upon the capacity prices and the applicable locational marginal prices of energy as reported by the Pennsylvania-New Jersey-Maryland Office of Interconnection. BPU DOCKET NOS. EO97070455 EO97070456 and EO97070457 -87- 90 10. The Company may at its option utilize its affiliated service company to make arrangements for the BGS supply pursuant to paragraphs seven through fourteen, and such arrangements shall be conducted on behalf of the Company as a regulated service. Neither the Company nor the affiliated service company shall provide information relevant to the provision of BGS and the bidding process to any competitive affiliate of the Company, either directly or indirectly through the medium of another affiliate of the Company, unless that information is provided contemporaneously to all others bidding to provide BGS to ACE. The Company and the affiliated service company shall receive and maintain all BGS bids, and discussions related thereto, in a confidential manner, and not disclose such information, unless said information is otherwise made public pursuant to law, regulatory act, or agreement with the provider of the information. Employees of the affiliated service company who transfer to any competitive affiliate of the Company shall be kept separate from, and shall not participate in, any proposal by the competitive affiliate to provide BGS to ACE. 11. The Company may, at its option, use energy and capacity obtained through one or more parting contracts, as described in paragraph 20 below, for the provision of BGS. The Company may also utilize certain financial instruments to decrease ratepayer exposure to price spikes and price volatility, for example, hedging. It is recognized by the Board that the use of some of these products could result in costs which exceed the spot market. However, the cost of such parting contracts and financial instruments, as well as all other costs associated with the procurement and provision of BGS, which are deemed by the Board to be reasonably and prudently incurred, shall be recoverable in rates for BGS pursuant to N.J.S.A. 48:3-57(e). Such determinations will be rendered within the context of the anticipated divestiture proceedings after opportunity for the parties to comment thereupon. 12. Pursuant to N.J.S.A. 48:3-57(a), the Company has a minimum obligation to provide BGS through July 31, 2002 to those retail customers who choose to remain with the utility. ACE shall file, on or before August 1, 2001, a specific proposal for public comment and review and approval by the Board to implement a request for proposals to supply to BGS for the period August 1, 2002 through July 1, 2003. The bids shall be based on the minimum shopping credits for the applicable time periods, as set forth in paragraph 5(a). Depending on the bidders' perceived value at the time of the right to provide BGS, the bids shall provide for either: (i) a payment from the bidder to the Company, to provide BGS at a price based on the minimum shopping credit, as described in paragraph 6; (ii) the provision of BGS at a rate which results in shopping credits for the applicable time period, as set forth in paragraph 6; or (iii) a payment from the Company to the bidder, if the BGS rate proposed by the winning bidder is such that some portion of the BGS revenues must be deferred, in accordance with paragraph 1(e), such payment to be equal to the portion of the BGS rate which can not be charged to the customers, but which must be deferred. If the winning bid results in a net payment to the Company, such payment shall be applied to reduce the balance of the Deferred Balance pursuant to paragraph 27, or any other under-recovered balance as determined by the Board. If the winning bid for BGS results in a net payment by the Company, such payment shall be subject to deferral and subsequent recovery, as part of the Deferred Balance as set forth in paragraphs 27-29. The Board shall establish a structure and procedures for the provision of BGS after the Transition Period. BPU DOCKET NOS. EO97070455 EO97070456 and EO97070457 -88- 91 13. A competitive affiliate of the Company may be permitted to bid to provide wholesale supply for BGS service, and bid to provide BGS pursuant to paragraph 12, during the Transition Period, subject to the affiliate relations standards to be adopted by the Board. If a competitive affiliate of the Company participates in any such bid, the Company and its affiliated service company shall utilize the services of an independent consultant to review the bids, pursuant to criteria to be set in developing the RFP process, and present the results to the Company so as to not reveal which bid is from a competitive affiliate. 14. The bidding procedures to be conducted for the BGS supply during the Transition Period as described above shall be conducted on behalf of the regulated utility, and that all competitive information relating to bids which may be tendered shall be treated as proprietary and confidential, and shall not be made available to a competitive affiliate of the Company. 15. The Company shall not promote BGS as a competitive alternative. 16. The Company shall be permitted the opportunity to recovery 100% of its net owned generation stranded costs as established by the Board and its Board approved NUG contract costs. Upon application by ACE and a determination by the Board that the conditions of EDECA are met, the Company shall be permitted to securitize its net owned generation stranded costs, (as established definitively upon completion of the divestiture of such assets), and other securitizable stranded costs to the extent permitted by and in accordance with the provisions of EDECA. 17. The Company has made a business decision to divest its interests in the B.L. England, Keystone, Conemaugh, Peach Bottom, Salem and Hope Creek generating stations. Upon approval of the divestiture by the Board, the net divestiture proceeds as determined by the Board will be used to determine the Company's generation related stranded costs. Generation related stranded costs shall mean the excess of net book value as of the closing date(s) of the sale(s) over net divestiture proceeds. The net book value shall reflect the net investment in each facility, reflective of the gross investment less depreciation reserve less accumulated deferred income tax, and investment tax credits, if appropriate, as of the closing date(s). The tax impacts with respect to taxable gains and/or losses will be considered in calculating net stranded costs. Net divestiture proceeds are defined as the excess of the selling price(s) of the generating assets over the transaction costs incurred by the Company. The transaction costs shall be reasonable, verifiable and necessary, and shall include (but not necessarily be limited to) sales and transfer taxes, state, federal and local taxes, as well as reasonable consultants fees, broker commissions, legal fees, investment banking fees, title transfer fees, real estate transfer and related costs, mortgage and financing costs, real estate taxes, transportation and system-separation costs (including outside contractor, engineering, purchased materials and labor costs) associated with the divestiture activities, paid overtime and out-of-pocket expenses for Company employees associated with the divestiture activities, and any arrangements to address direct and indirect employee impacts from the divestiture including retirement, severance and any other employee-related benefit costs, as shall be determined by the Board. 18. Final determination by the Board of the net divestiture proceeds shall be undertaken only upon the completion of the transfer of all of the generation assets listed in paragraph 17 to each purchaser thereof, as set forth herein. BPU DOCKET NOS. EO97070455 EO97070456 and EO97070457 -89- 92 a. Such final determination shall be made within a separate divestiture proceeding, to be filed by ACE pursuant to standards to be set by the Board, subject to the terms of this Order. The final determination of the net divestiture proceeds shall include a determination of actual selling price(s), book value(s) costs. The Board is not pre-judging at this time ACE's prudence in implementing the RFP and selecting a winner bidder(s). Such final judgment will come at the conclusion of the separate divestiture proceedings. b. The signatory parties to Stipulation I have acknowledged that ACE's proposed asset transfers require various regulatory approvals or waivers, including, without limitation, the Board, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and other agencies. Provided the Company files a proposal for divestiture in accordance with the standards to be set as referenced in paragraph 19, the stipulating parties have mutually agreed that they will neither oppose, nor support any opposition to, any proceeding seeking the approval of such sales or the terms thereof, or seeking any other order or approval as may be required in order to consummate such sales, before the Board or any other ad judicatory or regulatory body, nor will the stipulating Parties seek to intervene in any such proceeding without the consent of the Company, except as to matters not addressed in Stipulation I. c. With respect to the proceedings referenced in paragraph 18(b), the IEPNJ and its current members have stated in Stipulation I that, while they support the concept of the divestiture of assets as set forth in paragraph 17, they reserve the right to move before the BPU to seek the review of any specific transfer of any generation asset listed in paragraph 17. d. Any party who participates as a bidder in any sale conducted as part of such divestiture shall have the same rights as any other bidders in any BPU proceeding concerning such sale. e. The parties to Stipulation I have mutually agreed that nothing herein shall prevent a party from intervening in any such proceeding solely for monitoring purposes. 19. In order to effectuate a timely divestiture of the Company's generation assets, to the benefit of both the Company and the ratepayers, the Board will endeavor to expedite its review and approval of divestiture standards applicable to ACE's generating assets.(10) Nothing - ----------------------- (10) On January 4, 2000, in Docket Nos. EM99080605 and EM99080606, the BPU issued an Order Adopting Auction Standards applicable to the sale of ACE's nuclear and non-nuclear generating assets. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -90- 93 contained in the Stipulation or this Order forecloses any party from participating fully before the BPU in formulating divestiture standards. 20. The Board recognizes that the use of parting contracts entered into by the Company with purchasers of its generation assets, as part of the sale of such assets to those purchasers, to the extent they make possible or enhance the sale of such assets, can be in the public interest. The stipulating parties have agreed that the term of any "parting contract" will not exceed four years. The Board is not pre-judging the prudence of any actual parting contract which may be entered into by ACE; such judgment will be rendered only after Board review in the context of the separate divestiture proceeding. However, to the extent found reasonable and prudent, and that the rates and costs contained therein are an integral aspect of the sale of the generating asset, the Board will permit the Company to flow-through, and fully and timely recover, the rates specified in such parting contracts, and the resulting costs, from its customers in a number to be determined by the Board. 21. The Company agreed in Stipulation I to forego recovery of $9 million in net stranded costs associated with its Deepwater Station and its Combustion Turbines, as set forth in Schedule B of the Stipulation ("Transferred Units"). a. Pursuant to N.J.S.A. 48:3-55(d), the Board hereby approves the transfer of the Transferred Units to an unregulated affiliate of the Company; however the transfer value of the Transferred Units shall be the net book value of the assets at the time of the transfer, thereby resulting in zero stranded costs associated with the Transferred Units and fully mitigating the need for the Company to forego any related stranded costs recovery. Such transfer prices will, and are intended to, ensure that the Company receives full and fair compensation for the Transferred Units and that ACE will not retain any liabilities associated with the Transferred Units. The Company shall not bear any expenses of the Transferred Units after the transfer to an unregulated affiliate. The Company shall have auditable accounting protocols in place no later than the effective date of the transfer to assure that all expenses and capital expenditures related to the Transferred Units will not be borne by the Company. If, within the four year Transition Period any Transferred Unit is sold to a non-affiliate of ACE, the net after-tax gain over the adjusted book value shall be shared equally between the Company and the customers, in a manner to be determined by the Board. b. As a condition of the transfer during the Transition Period, ACE's affiliate shall offer capacity from the transferred units for sale within the PJM control area at market prices, and if the capacity is sold outside the PJM control area, the Company's affiliate shall make the capacity subject to recall by PJM during system emergencies. c. With respect to affiliate issues, the transfer of the Transferred Units to an affiliate, the Board's affiliate relations standards will be applied to the relationship between ACE and its affiliates. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -91- 94 22. During the period between August 1, 1999 and completion of the divestiture of generation assets, MTC revenues shall be applied to owned generation revenue requirements, including continued depreciation of assets, and return on investment, operating and maintenance expenses and fuel expenses, and, between the time of divestiture closing and time of securitization closing, MTC revenues shall be applied to provide a return on the net owned generation stranded costs at 13.0% pre-tax. At time of the termination of the MTC (upon the establishment of the TBC), total MTC revenues and market revenues received from the crediting of owned generation power to BGS in accordance with paragraph 7 (as modified) will be reconciled to the amounts indicated, including a review of the prudence and reasonableness of the Company's operation of the units, and the Deferred Balance will be reconciled accordingly to reflect a resulting shortfall or excess. 23. The Company is entitled to full and timely recovery of 100% of the costs associated with its NUG purchased power contract, in accordance with the provision of N.J.S.A. 48:3-61, which contracts have been previously reviewed and approved for full and timely recovery by the Board. Therefore, consistent with N.J.S.A. 48:3-61(a)(3) and other applicable law, the Company shall be permitted to fully recover, dollar-for-dollar, the costs associated with its NUG contracts, over the life of each such contract. The Company shall utilize a Net Non-Utility Generator Charge as a component of the MTC to recover the stranded costs associated with the purchase of power from NUGs. The NNC shall be equal to the difference between the cost of the NUG-contract purchased power and either (a) the proceeds realized by the Company from the sale of that NUG-contract power in the competitive wholesale market, (b) the pricing set forth in paragraph 7, to the extent NUG resources are utilized as set forth in paragraph 7, or (c) the pricing set forth in paragraph 9, to the extent NUG resources are utilized as set forth in paragraph 9. Such proceeds will be adjusted to reflect a deduction for the reasonable marketing and administrative costs associated with the sale of the NUG-contract power into the wholesale market to the extent such power is indeed sold in the wholesale market. The NNC shall also include swap breakage costs incurred in connection with a previous amendment to one of its NUG contracts, which costs have been recovered to date through the Energy Adjustment clause charge. The NNC shall continue over the actual term of each of the Company's NUG contracts, and shall be applied as a non-bypassable wires charge to retail customers. In the event of a NUG-contract buyout, buydown or restructuring, and to the extent that a 10% aggregate rate reduction relative to April 30, 1999 rates is achieved without the use of cost deferrals, the Company will be provided with an incentive for such restructuring. This incentive shall amount to ten (10) percent of the net savings in excess of the 10% rate reduction, except for the Pedricktown Project for which the incentive will be 5% of such savings, and the NNC shall be adjusted accordingly. Upon application by ACE and a determination by the Board that the conditions of EDECA are met, the Board will issue a financing order consistent with the provisions of the Act, permitting securitization over the remaining contract term, of the costs associated with any buyout, buydown or restructuring of the Company's NUG power contracts which the Board approves and finds to be consistent with the standards in N.J.S.A. 48:3-61 and 62. In the event of such approved buyout, buydown, or restructuring, and prior to the securitization of the costs for same, the Company shall include such costs in its MTC recovery and concurrently reflect in rates any power purchase cost savings resulting therefrom. 24. The Company will incur additional costs for restructuring-related items that are capital in nature, the estimated costs of which are set forth in Schedule C of the Stipulation. The BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -92- 95 Company has proposed to recover these costs through securitization of up to 75% of total capital expenses for terms up to 15 years. The Board renders no determination at this time with respect to any such request for the securitization of restructuring-related costs of a capital nature. The recovery of restructuring-related costs of a capital nature via the MTC shall be subject to a reasonableness and verification review by the Board, and shall be net of other sources of recovery towards such costs including Third Party Supplier Agreement fees. If approved, such costs will be amortized over a period not to exceed eight years. The rate of return on unamortized restructuring-related costs collected via the MTC shall be 13.0% pre-tax. 25. The recovery of restructuring-related costs of an operating nature other than consumer education cost, as listed in Schedule D, of the Stipulation, via the MTC shall be subject to reasonableness and verification review by the Board, and shall be net of other sources of recovery towards such costs, including Third Party Supplier Agreement fees. 26. The Board is not adopting Paragraph 26 of Stipulation I. 27. As described in paragraph 1 above, the Board recognizes that the Company may have to defer recovery of some portion of its costs in order to achieve and/or sustain rate reductions through the end of the Transition Period. The costs which may be so deferred (the "Deferred Costs") are those incurred during the Transition Period to meet the costs of BGS (as set pursuant to paragraph 6), the NNC (as set pursuant to paragraph 23), and the costs recoverable through the MTC (set forth in paragraph 25). Therefore, during the Transition Period, the Company will utilize a deferred accounting mechanism for any Deferred Costs. Revenues for BGS will only be deferred to the extent necessary to fund and sustain the rate reductions set forth in paragraph 1 and then only after the deferral of any other item of Deferred Costs, as set forth in this paragraph. Any Deferred Costs, together with a return on the unrecovered balance, will be audited by the Board and will be recoverable at the end of the Transition Period in a manner and timeframe to be determined by the Board. 28. The balance of the Deferred costs shall be reversed from the Company's balance sheet as it is recovered. The opportunity for recovery, is intended in all respects to comport with and satisfy the standards of the FASB, including those FASB standards under which the Company is permitted to maintain the Deferred Costs as a regulatory asset rather than being required to record the balance as a current expense. 29. The Board does not adopt Paragraph 29 of Stipulation I. 30. Consistent with the provisions of paragraph 16, upon application by ACE and determination by the Board that the conditions of EDECA are met, the Company shall be permitted to securitize the net stranded costs associated with its divested generation assets to the extent permitted by EDECA. This figure shall be calculated in accordance with paragraph 17 above. The term of such securitization financing associated with the divested generation assets shall not exceed 15 years. Taxes related to securitization, reflecting the grossed-up revenue requirement number associated with the level of stranded costs as determined in paragraph 17 above, are legitimate recoverable stranded costs, and the Company shall be provided the opportunity for full recovery through a separate component of the MTC with a term identical to the term of the securitization financing pursuant to the standards set forth in N.J.S.A. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -93- 96 48:3-61 and 62. The Company shall be provided with full and timely recovery of all transition bond charges in conformance with the standards set forth in the Act. 31. Consistent with the provisions of paragraph 16 and 23, upon application by ACE and determination by the Board that the conditions of EDECA are met, the Company shall be permitted to securitize the net stranded costs associated with the restructuring, buyout or buydown of it NUG power contracts to the extent permitted by EDECA. The term(s) of any such securitization financing shall be no longer than the remaining terms of the respective NUG contracts which have been restructured or terminated. 32. The Board renders no determination at this time with respect to the securitization of restructuring-related cost of capital. 33. It is expected that third parties may be authorized to provide billing and collection services in the future as a result of the statutorily required billing and metering proceeding. Even if third party billing and collection has not been so authorized by the time the Company seeks to effect a securitization transaction, appropriate creditworthiness standards applicable to any third parties that may ultimately provide billing and collection services would have to be in place by the time of any securitization transaction in order to satisfy credit rating agencies and the financial community so that securitization may proceed. If such creditworthiness standards are not in place before the Company undertakes securitization of any of its assets, such standards will be incorporated in the applicable bondable stranded costs rate order. 34. Consistent with N.J.S.A. 48:3-60, the Company will establish a Societal Benefits Charge. The SBC will include costs related to: (1) social programs, (2) nuclear plant decommissioning costs, (3) Demand Side Management programs, and (4) consumer education expenses. 35. The SBC will be set at the level of costs for the above items already in rates as of the date of the Board's Summary Order in this matter. During the Transition Period, the funding of SBC initiatives may vary from the level of funding currently in rates. An annual true-up process will be established to provide for the full and timely recovery of SBCs. To the extent that full and timely recovery of the SBC costs prevents the Company from achieving the rate reductions described in paragraph 1 above, the Company will defer a portion of the SBC cost recovery subject to the same terms and conditions as described in paragraph 27. 36. For ratemaking purposes, all tax expenses for the computation of divestiture proceeds, MTC revenues and NUG buyouts or buydowns shall be determined on a utility stand-alone basis, and not by imputing the tax effects of a consolidated return. Such treatment has no precedential value with regard to future rate cases pertaining to the regulated rates of ACE. 37. The Company shall be authorized to continue to provide service under its existing Off-Tariff Rate Agreements. The Company shall not transfer any OTRA to an unregulated affiliate, on the condition that the Company may utilize the services of an affiliated energy trading segment to procure the supply to serve under the OTRA. In addition, any OTRA customer may choose to end its contract, shop for and receive generation from an EPS or go on BGS, and be provided unbundled service under the Company's tariffs. The Company shall provide notice of this provision to the OTRA customers. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -94- 97 38. With regard to the presentation by the Company of future NUG contract restructuring buyout or buydown proposals, the Board recognizes the desire for and potential benefit of expeditious review and approval of such proposals, in order that the benefits thereof to the Company and its customers may commence. Accordingly, the Board will attempt to expedite its review and consideration of same upon receipt and review of an appropriate petition by the Company and after of all outstanding requests for information have been received and fully reviewed. 39. The existing regulatory asset associated with the application of FAS-109 to the transmission and distribution assets of the Company shall be preserved and shall be addressed by the Board in a future regulatory proceeding. 40. Experimental Residential Time-of-Use rates shall be discontinued as of August 1, 2000. The AGS Time-of-Use rates will be closed to any new customers on August 1, 1999, and the rate will continue through the Transition Period, unless the number of customers taking service under that rate schedule drops below 25. Customers currently being served under these rate classes shall be provided with at least 90 days' notice by the Company of the discontinuation, and shall be advised that service provided by third party suppliers may provide electric power supply with time-differentiated pricing.(11) 41. The Interruptible Rider shall be discontinued as of December 31, 1999. Customers currently being served under this rate will be advised by the Company that service provided by third party suppliers may provide electric power supply with interruptible pricing. 42. The Standby and Large Standby Riders contained in the present utility tariff shall reflect reductions and credits to be made in accordance with this Order and shall be modified to provide for fixed, unbundled charges for transmission, distribution and customer services, and shall be modified further to provide that standby power supply shall be provided from time to time, as required by the customer, at the BGS rate. 43. Expenses to redeem and retire outstanding capital in connection with the recovery of stranded costs shall be recognized as stranded costs, and may be included in the MTC for recovery. Recovery via the MTC of expenses to redeem or retire outstanding capital in connection with the recovery of stranded costs is subject to Board review that such costs have been reasonably and prudently incurred. The Board also notes that reasonably and prudently incurred capital retirement and redemption expenses associated with a securitization financing are included the definition of bondable stranded costs in the Act and upon application by ACE and a determination by the Board that the conditions of EDECA are met, may be securitized to the extent permitted by EDECA and recovered via the TBC. In setting the annual level of charges for BGS during the Transition Period, for any MTC that continues beyond the Transition Period, and for the SBC, NNC and the TBC, the Company will utilize a methodology similar to that currently used for setting its Energy Adjustment clause charges. The BGS, SBC, NNC, MTC and TBC components will be reviewed annually, based upon projections of costs and - ----------------- (11) At its July 20, 2000 public agenda meeting, the Board determined to extend and phase-out the Time-of-Use rates. I/M/O The Request for an Order Directing ACE to Continue TOU Service, BPU Docket No. ER00070469. BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -95- 98 of sales. Actual costs will be accounted for on a deferred accounting basis, and when the BGS, SBC, NNC, MTC and TBC are set in the following year, each of those rate components will be set to recover any underrecovery in the Deferred Balance, as well as the projected costs for the upcoming year. The setting of the BGS, SBC, NNC and MTC shall be subject to providing the rate reductions as set forth in paragraph 1, the Deferred Costs provisions of paragraphs 27-29, and the provisions of the Act. Accordingly, notwithstanding the above and in order to satisfy the rate reduction provisions of the Act, the Board may or may not actually adjust the indicated charges (other than the TBC and the BGS price as provided in the Act and/or elsewhere in this Order) during the Transition Period. Any overrecoveries in the Deferred Balances for the BGS, SBC, NNC or MTC will be applied as a credit to the respective rate components in the same manner. The same procedure will be followed for each year in which the BGS, SBC, NNC, MTC and TBC charges are to be set. 44. With regard to actions within the Company's control, the Company shall make a good faith effort to handle electronic data interchange in relation to the delivery of electricity from TPSs to retail customers by October 1, 1999. 45. The parties are directed to work cooperatively to conclude the statutorily required billing and metering proceeding in an expedited fashion. 46. In summary, subject to the conditions embodied herein, the rate discounts provided by ACE, all stated relative to current rates, shall be at a minimum as follows: August 1, 1999 5 % January 1, 2001 7% August 1, 2002 10.2% The average shopping credits during the Transition Period shall be, at a minimum as follows:
- ------------------------------------------------------------------------------------- Rate Class 1999 2000 2001 2002 2003 - ------------------------------------------------------------------------------------- RS 5.65 5.70 5.75 5.80 5.85 RS-TOU 5.10 5.15 5.20 5.25 5.30 MGS-Sec 5.18 5.23 5.33 5.43 5.53 AGS-Sec 5.30 5.35 5.45 5.55 5.65 AGS-Pri 5.07 5.12 5.17 5.22 5.27 AGS-Sec 5.05 5.10 5.15 5.20 5.25 AGT-Pri 4.95 5.00 5.00 5.00 5.00 AGT-SubT 4.30 4.30 4.30 4.30 4.30 AGT-Trans 4.25 4.25 4.25 4.25 4.25 TGS 4.30 4.30 4.30 4.30 4.30 SPL/CSL 2.97 3.05 3.07 3.10 3.12 DDC 3.58 3.68 3.71 3.75 3.78 - ------------------------------------------------------------------------------------- System Average 5.27 5.31 5.37 5.42 5.48 - -------------------------------------------------------------------------------------
BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -96- 99 100 DATED: March 30, 2001 BOARD OF PUBLIC UTILITIES BY: (signed) --------------------------- HERBERT H. TATE PRESIDENT (signed) --------------------------- FREDERICK F. BUTLER COMMISSIONER ATTEST: (signed) ----------------------- FRANCES L. SMITH SECRETARY BPU DOCKET NOS. EO97070455, EO97070456 and EO97070457 -97- -----END PRIVACY-ENHANCED MESSAGE-----