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The Plan will have no anti-competitive effect, representing as it does only a regrouping of assets and businesses under existing ownership (Section 10(b)(1));

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Fees and commissions will be within accepted ranges (Section 10(b)(2));

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The resulting entities will be creditworthy, reflecting capital structures supportive of investment-grade credit ratings (Section 10(b)(3));

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The businesses and assets allocated to discrete entities will be interconnected utility assets in a single region, capable of effective management and in each case subject to effective regulation (Section 10(c)(1));

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The Plan will benefit Debtor and its investors, ratepayers and creditors by (1) permitting its emergence from bankruptcy with payment of all allowed claims in full and (2) not requiring a retail rate increase (Section 10(c)(2)); and

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The Plan will reflect compliance with applicable state law, taking into account federal preemption as determined by the Bankruptcy Court (Section 10(f)).

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On the effective date of the Plan (“Plan Effective Date”) Debtor will transfer its electric transmission and electric generation utility assets and certain associated assets and liabilities to two new public utility companies, ETrans (electric transmission assets) and Gen (and to the GenSub LLCs) (electric generation assets) and will transfer its natural gas transportation assets and certain associated assets and liabilities to a non-utility company, GTrans (ETrans, Gen and GTrans are held by Debtor’s newly created, wholly owned subsidiary, Newco);

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On the same day, Debtor is scheduled to transfer to Parent all the stock in Newco (the “Restructuring”); and

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Parent will transfer to the shareholders of Parent all of the common stock in Reorganized Debtor, also a public utility company, that it holds directly (the “Spin-Off”). All of these transactions are collectively referred to herein as the “Transaction.”

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1

Allowed claims include the amounts owed with respect to the period prior to the Petition Date and applicable interest accrued and unpaid during such period. Interest accrued but unpaid after the Petition Date will be paid on most, but not all, allowed claims.

2

Parent owns directly approximately 94% of Debtor’s common stock. The other approximately 6% of Debtor’s common stock is held by PG&E Holdings LLC, a wholly owned subsidiary of Debtor that was formed for the purpose of holding repurchased shares of Debtor. PG&E Holdings LLC will not participate in this dividend.

3

PG&E Holdings LLC will not participate in this dividend.

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4

Shows only significant subsidiaries. Note that utility assets have not yet been transferred to the subsidiaries of Newco.

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5

Shows only significant subsidiaries. Note that utility assets are scheduled to be transferred to the subsidiaries of Newco on the Plan Effective Date and before the transfer of Newco to Parent, which also is scheduled to occur on the Plan Effective Date.

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6

Shows only significant subsidiaries.

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7

The $8.9 billion represents the amount purchased by Debtor from the Power Exchange pursuant to FERC tariffs and includes $6.6 billion for energy and ancillary services provided by third parties and $2.3 billion for energy and ancillary services supplied by Debtor’s own generation assets. (See Exhibit D-1.2 at 2-3, Testimony of Kent M. Harvey, Senior Vice President—Chief Financial Officer and Treasurer of Debtor, attached hereto).

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8

The net open position is the amount of power not provided from (1) Debtor’s own generation assets and long-term power contracts or (2) contracts entered into by DWR to serve Debtor’s retail load.

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9

FERC will regulate GTrans and Gen because their activities after the Plan Effective Date will be interstate rather than intrastate. Gen will be engaged solely in making sales for resale; such wholesale sales are, by definition, in interstate commerce. See Federal Power Act (“FPA”) §201. Under the Plan, GTrans will acquire certain pipeline assets in Oregon and thereafter conduct business as an interstate pipeline under the Natural Gas Act of 1938, as amended (the “NGA”). FERC has exclusive jurisdiction over such interstate transactions and facilities. FPA §201(b) (the FPA “shall apply to the transmission of electric energy in interstate commerce and to the sale of electric energy at wholesale in interstate commerce” and “[t]he Commission [now the FERC] shall have jurisdiction over all facilities for such transmission or sale of electric energy.”); Federal Power Commission v. Southern Cal. Edison Co., 376 U.S. 205, 215-16 (1964) (“Section 201(b) embodies a clear grant of power. . . . Congress meant to draw a bright line easily ascertained, between state and federal jurisdiction. . . . This was done in the [Federal] Power Act by making FPC [now FERC] jurisdiction plenary and extending it to all wholesale sales in interstate commerce, except those which Congress has made explicitly subject to regulation by the states.”); NGA §717a (“the business of transporting and selling natural gas for ultimate distribution to the public is affected with a public interest, and that Federal regulation in matters relating to the transportation of natural gas and the sale thereof in interstate and foreign commerce is necessary in the public interest.”); Schneidewind v. ANR Pipeline and ANR Storage Co., 485 U.S. 293, 300 (1988) (“The NGA long has been recognized as a ‘comprehensive scheme of federal regulation of all wholesales of natural gas in interstate commerce.’”).

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10

There are two exceptions with respect to the assignment of Franchises: an existing gas Franchise with Modoc County will be assumed by Reorganized Debtor and assigned to GTrans, and an existing gas Franchise with San Bernardino County will be assumed by Reorganized Debtor and assigned to GTrans.

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11

The only “public-utility company” activity or investment of Parent today is Debtor, which conducts all of its public utility activities in California. The activities of Parent’s subsidiaries outside of California fall into two categories, neither of which is a utility activity considered for purposes of determining whether a holding company derives a material portion of its income from public-utility companies under Section 3(a)(1): activities that, while falling within the definition of “public-utility company” under Section 2(a)(5) of the Act, 15 U.S.C. § 79b(a)(5), have been defined as not being “public-utility company” activities by legislative fiat (exempt wholesale generators and qualifying facilities) and activities that do not fall within the definition of “public-utility company” under the Act at all (such as interstate gas transmission). As a result of the Transaction, Parent and its subsidiaries will engage in no additional activities beyond those they conduct today, and therefore Parent will continue to qualify for an exemption under Section 3(a)(1). Similarly, Newco will engage in no additional activities beyond those conducted today by Parent and its subsidiaries, and therefore Newco will qualify for an exemption under Section 3(a)(1).

12

Ass’n of Mass. Consumers, Inc. v. SEC, 516 F.2d 711, 717 (D.C. Cir. 1975); see also Nat’l Propane Corp., HCAR No. 20684, 1978 SEC LEXIS 859, **14-15 (Aug. 24, 1978); Wisc. Energy Corp., 1993 SEC No-Act. LEXIS 1237 (Dec. 17, 1993); SCANA Corp., 1990 SEC No-Act. LEXIS 1038 (Jun. 14, 1990).

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13

The Hunters Point power plant will be shut down and dismantled pursuant to a settlement agreement while the Humboldt Bay power plant includes a small non-operating nuclear power facility that is now in the early stages of decommissioning. Reorganized Debtor will complete the decommissioning activities for these facilities subject to existing CPUC oversight and ratemaking and, in the case of Humboldt Bay, Unit 3, subject to the oversight of the NRC.

14

The Lime Saddle and Coal Canyon facilities are not subject to FERC operating licenses because FERC has disclaimed mandatory licensing jurisdiction over these projects.

15

Debtor will assume under the Bankruptcy Code and transfer to a subsidiary of Gen (Bucks Creek LLC) the sales obligations under one wholesale contract (the “Grizzly Contract”). The Grizzly Contract provides, among other things, for certain power sales to Silicon Valley Power (“SVP”).

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16

The allocation between cash and notes may change based on market conditions and other factors; such changes will be reported by amendment. The amount of cash to be paid by ETrans to Debtor will be reduced by the amount necessary to fund ETrans’ near-term working capital requirements. Further, the amount of ETrans long-term notes to be issued to Debtor is subject to reduction in certain circumstances under terms set out in the Plan.

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17

In December 1999, FERC issued its final rule on RTOs and encouraged utilities that own transmission systems to form RTOs on a voluntary basis. Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC Stats. & Regs. [Regs. Preambles 1996-2000] ¶ 31,089 (2000), order on reh’g, Order No. 2000-A, 65 Fed. Reg. 12,088 (Mar. 8, 2000), 90 FERC ¶ 61,201 (2000), appeals dismissed sub. nom.Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, Nos. 00-1174, et al. (D.C. Cir. Dec. 11, 2001) (per curiam) (“Order No. 2000”). In several orders issued on July 12, 2001, FERC indicated its strong preference for a single RTO that encompasses most of the Western United States, including California, and potentially Canadian provinces as well, that are interconnected in the region encompassed by the Western Systems Coordinating Council. On November 7, 2001, FERC issued an order stating that it will resolve the issues related to geographic scope of RTOs in pending RTO dockets following consultations with state commissions and that “the presence of three sub-regional organizations [in the West] (bound by a workable seams agreement) under a larger umbrella organization has the potential to succeed.” Order Providing Guidance on Continued Processing of RTO Filings, 97 FERC ¶ 61,146 at 61,633 (2001). No RTO is operational in the Western United States at this time. ETrans commits to joining a Western RTO approved by FERC. Until ETrans joins an RTO, ETrans will continue to participate in the CAISO.

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18

The allocation between cash and notes may change based on market conditions and other factors; such changes will be reported by amendment. The amount of cash to be paid by Gen to Debtor will be reduced by the amount necessary to fund Gen’s near-term working capital requirements. Further, the amount of Gen long-term notes to be issued to Debtor is subject to adjustment under certain circumstances under terms set forth in the Plan.

19

Debtor owns approximately 132,000 acres of land that historically have been associated with hydroelectric generating facilities. Approximately sixty percent (60%) (or roughly 78,000 acres) of these lands will be retained or ultimately owned by Reorganized Debtor, provided that the parcel boundaries are adjusted as described below. These lands are comprised of numerous legal parcels. Certain of these legal parcels contain Debtor’s hydroelectric operational facilities (such as generators and reservoirs) or linear project operational facilities (such as canals and flumes) that are defined by FERC-licensed project boundaries. Other parcels contain facilities such as headquarters that support operations. Reorganized Debtor will retain title to parcels of land surrounding Gen’s hydroelectric facilities that are completely outside the FERC boundaries and on which no operational facilities, assets, or rights are located (currently estimated to be approximately 30,000 to 36,000 acres). All other legal parcels wholly or partially encumbered by FERC-licensed project boundaries will be transferred to Gen on the Plan Effective Date. On those legal parcels that contain both FERC-licensed operational facilities and land outside the FERC boundaries, Gen will apply for a lot line adjustment, subdivision approval or other regulatory approval necessary to adjust the parcel boundaries to conform, to the degree feasible, to the FERC-licensed project boundaries or the location of such operational facilities, assets or rights. In any event, Gen must retain rights necessary for the continued operations of its hydroelectric business. Upon such parcel boundary adjustment, which will not take place until after the Plan Effective Date, Gen (or its affiliates or subsidiaries) will reconvey to Reorganized Debtor any such land outside such

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20

See Tucson Elec. Power Co., 1995 SEC No-Act LEXIS 890 (Sep. 26, 1995) (in which the Commission Staff concurred with the interpretation that a holder of title to electric generation assets was not a public utility company where such holder had no assets other than $1,000, the electric generation facilities, rights under various easements related to the property on which the facilities were located, interests in certain leases of “common facilities” associated with the generation facilities, and other nominal rights associated with development of the generation facilities; had no employees other than a nominal number of officers, which were officers and directors of its owner (the public utility company which operated the facilities); consolidated its assets and liabilities with those of its owner for financial reporting and ratemaking purposes; engaged in no other business than the holding of title to the generation facilities; had no right to take any action which could affect the ownership of the generation facilities without consent of its owner; relied upon its owner for development, operation, maintenance and repair of the generation facilities and the payment therefor; received all fuel and payment therefor from its owner; relied upon its owner for service of all debt associated with the generating facilities; relied on its owner for all taxes associated with operation of the facilities or the earnings therefrom; and was subject to the exclusive rights of its owner to have control over the generating facilities and to receive or dispose of all capacity and energy from the generation

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1.

Diablo Canyon LLC: an approximately 2,174-MW nuclear generating facility in San Luis Obispo County, California.

2.

Mokelumne River Project LLC: an approximately 214.5-MW hydroelectric generating facility in Amador County, California.

3.

Rock Creek-Cresta Project LLC: an approximately 182-MW hydroelectric generating facility in Plumas County, California.

4.

Haas-Kings River Project LLC: an approximately 196-MW hydroelectric generating facility in Fresno County, California.

5.

Crane Valley Project LLC: an approximately 28.7-MW hydroelectric generating facility in Madera County, California.

6.

Pit 1 Project LLC: an approximately 61-MW hydroelectric generating facility in Shasta County, California.

7.

Hat Creek 1 and 2 Project LLC: an approximately 17-MW hydroelectric generating facility in Shasta County, California.

8.

Poe Project LLC: an approximately 120-MW hydroelectric generating facility in Butte County, California.

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9.

Pit 3, 4 and 5 Project LLC: an approximately 325-MW hydroelectric generating facility in Shasta County, California.

10.

Upper NF Feather River Project LLC: an approximately 362.3-MW hydroelectric generating facility in Plumas County, California and an approximately 4.8 MW hydroelectric facility in Plumas County, California.21

11.

Spring Gap-Stanislaus Project LLC: an approximately 98-MW hydroelectric generating facility in Tuolumne County, California.

12.

Kern Canyon Project LLC: an approximately 11.5-MW hydroelectric generating facility in Kern County, California.

13.

Kilarc-Cow Creek Project LLC: an approximately 5-MW hydroelectric generating facility in Shasta County, California.

14.

Chili Bar Project LLC: an approximately 7-MW hydroelectric generating facility in El Dorado County, California.

15.

Desabla-Centerville Project LLC: an approximately 26.4-MW hydroelectric generating facility in Butte County, California.

16.

McCloud-Pit Project LLC: an approximately 364-MW hydroelectric generating facility in Shasta County, California.

17.

Drum-Spaulding Project LLC: an approximately 190.1-MW hydroelectric generating facility in Placer County, California.

18.

Merced Falls Project LLC: an approximately 3.5-MW hydroelectric generating facility in Merced County, California.

19.

Bucks Creek Project LLC: an approximately 65-MW hydroelectric generating facility in Plumas County, California.22

20.

Potter Valley Project LLC: an approximately 9.2-MW hydroelectric generating facility in Lake County, California.

21.

Phoenix Project LLC: an approximately 2-MW hydroelectric generating facility in Tuolumne County, California.

22.

Kerckhoff 1 and 2 Project LLC: an approximately 193-MW hydroelectric generating facility in Madera County, California.

23.

Narrows Project LLC: an approximately 12-MW hydroelectric generating facility in Nevada County, California.

24.

Balch 1 and 2 Project LLC: an approximately 139-MW hydroelectric generating facility in Fresno County, California.

25.

Helms Project LLC: an approximately 1,212-MW pumped storage facility in Fresno County, California.

26.

Battle Creek Project LLC: an approximately 37.9-MW hydroelectric generating facility in Shasta County, California.

27.

Tule River Project LLC: an approximately 6.4-MW hydroelectric generating facility in Tulare County, California.

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21

The 4.8 MW Hamilton Branch facility located in Plumas County, California, which is not FERC licensed, will be transferred to the Upper NF Feather River Project LLC with which it is operationally linked and will be incorporated with that project’s FERC license application. This facility may be transferred to Hamilton Branch LLC, a subsidiary of Gen, for a period of time before the transfer of the facilities to Upper NF Feather Project LLC.

22

Debtor is seeking consent of its co-licensee for transfer of this facility. If such consent is not obtained, ownership of this facility may remain with Reorganized Debtor.

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23

Debtor’s ownership interest in Standard Pacific Gas Line Incorporated (“Stanpac”), a non-utility subsidiary, and operational responsibilities for gas transmission facilities owned by Stanpac will also be transferred to GTrans, together with a note for approximately $20 million from Stanpac to Debtor.

24

Although GTrans will directly serve certain large, industrial end-users, it will not be a public utility company under the Act because it will not be engaged in distribution at retail. See, e.g., Enserch Gas Transmission Co., HCAR No. 23515, 1984 SEC LEXIS 188 (Dec. 4, 1984), clarified, HCAR No. 23530, 1984 SEC LEXIS 125 (Dec. 13, 1984) (company providing gas transmission service and sales to industrial end-users as well as local distribution companies is not a “gas utility company,” even with small volume of service and sales to residential, commercial and agricultural customers).

25

The allocation between cash and notes may change based on market conditions and other factors; such changes will be reported by amendment. The amount of cash to be paid by GTrans to Debtor will be reduced by the amount necessary to fund GTrans’ near-term working capital requirements. Further, the amount of GTrans long-term notes to be issued to Debtor is subject to reduction in certain circumstances under terms set out in the Plan.

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26

On January 16, 2001, S&P again reduced the long-term corporate credit ratings of Parent and Debtor to CC from BBB-. On January 17, 2001, Moody’s further reduced Debtor’s senior unsecured debt rating to Caa2 from Baa3 and reduced its short term rating for commercial paper and extendible commercial notes to Not Prime from Prime-3. Moody’s also reduced Parent’s issuer rating to Caa3 from Baa3 and its short-term commercial paper rating to Not Prime from Prime-3. On January 19, 2001, S&P further downgraded the ratings on Parent’s and Debtor’s commercial paper programs to D from C in response to the companies’ failure to pay maturing commercial paper that came due on January 17, 2001. As a result of the defaults, the companies’ long- and short-term corporate credit ratings were also downgraded to D/D from CC/C.

27

See note 8, supra.

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28

The $8.9 billion represents the amount purchased by Debtor from the Power Exchange pursuant to FERC tariffs and includes $6.6 billion for energy and ancillary services provided by third parties and $2.3 billion for energy and ancillary services supplied by Debtor’s own generation assets.

29

Debtor began to collect this average $0.03/kWh rate increase on June 1, 2001, when the CPUC adopted the rate design for the increase.

30

AB 1X directs the CPUC to calculate the California Procurement Adjustment (the “CPA”), which is the portion of each electric utility’s retail rates relating to generation, representing the difference between the generation-related component of such electric utility’s retail rate effective on January 5, 2001, and the total of its costs of generation, purchases of power under existing bilateral contracts and QF contracts, and its cost of ancillary services. The CPUC also is directed to determine the amount of the CPA that is allocable to power sold by the DWR.

31

The TURN Accounting Order was issued by the CPUC on March 27, 2001. It required Debtor to restate all of its regulatory books and accounts retroactively to January 1, 1998 in such a way that has the effect of reversing some previously recorded transition cost recovery. Depending on the amount and timing of generation valuation, it is possible that the effect of the TURN Accounting Order would be that such transition costs have not been fully recovered and the conditions for ending the rate freeze have not been met. The CPUC denied Debtor’s application for rehearing of the TURN Accounting Order (but granted rehearing of certain related issues). Debtor has appealed a decision of the Bankruptcy Court denying Debtor’s request for a stay and an injunction of the Turn Accounting Order.

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32

These include, among others: (1) proceedings pending at FERC regarding the rates charged for wholesale power in California for the period beginning in June 2000; (2) proceedings before the Bankruptcy Court and Federal Court of Appeals regarding the TURN Accounting Order, which had the effect of prolonging the duration of the retail rate freeze; (3) proceedings before the CPUC regarding rates for Debtor’s retained utility generation facilities and procurement costs still incurred by Debtor; (4) proceedings before the CPUC regarding the “market valuation” of Debtor’s remaining non-nuclear generation assets (Debtor believes that under Public Utilities Code Section 367(b) the CPUC was obligated to complete this market valuation by December 31, 2001 and to credit that value against transition costs incurred by Debtor); (5) proceedings before the CPUC regarding DWR’s revenue requirement, which may affect the amount DWR may charge for the power it provides to Debtor and Debtor’s customers; and (6) proceedings before the CPUC regarding the billing and collection services Debtor must provide to the DWR. In addition, the CPUC has initiated an investigation into the obligations of California utility holding company parents under the “first priority condition” of the CPUC’s order(s) approving the formation of such companies. Debtor is a subject of this investigation. On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against Parent and its directors, as well as against the directors of Debtor, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professional Code Section 17200. On February 8, 2002, Parent filed a notice of removal with the Bankruptcy Court

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On October 19, 2001, Debtor formed Newco as a wholly owned subsidiary. On October 29, 2001, Newco formed ETrans, Gen and GTrans as wholly owned subsidiaries. ETrans, Gen and GTrans currently have no assets (other than nominal amounts of cash) and engage in no business activities.

•

Following issuance of the Confirmation Order and receipt of federal regulatory approvals, including approval from the Commission under Section 9(a)(2) of the Act, and other rulings, no-action letters and similar documents, Debtor plans to transfer to ETrans a majority of its electric transmission assets, to transfer to Gen and its subsidiaries a majority of its electric generation assets and to transfer to GTrans a majority of its gas transmission assets. Debtor also will transfer to ETrans, Gen and GTrans certain liabilities, and Debtor may assume certain Parent liabilities for guarantees of Debtor’s own liabilities. These transfers are scheduled to occur on the Plan Effective Date, which is currently expected to occur on or before January 1, 2003. Debtor will retain its gas and electric distribution businesses.

•

Effective on or before the Plan Effective Date, Reorganized Debtor also will issue long-term notes to the public or to third parties in private offerings33 for cash.

•

Effective on the Plan Effective Date, ETrans, Gen and GTrans each will issue (either solely or with one or more non-utility subsidiaries or affiliates as co-issuer or guarantor) long-term notes to the public or to third parties in private offerings34 for cash.35 In addition, effective on the Plan Effective Date, ETrans, Gen and GTrans will issue long-term notes and transfer cash to Debtor.

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33

The offerings of such notes may be effected before the Plan Effective Date and the proceeds placed in escrow until the Plan Effective Date. The notes would be redeemed if the Plan Effective Date does not occur.

34

The offerings of such notes may be effected before the Plan Effective Date and the proceeds placed in escrow until the Plan Effective Date.

35

To the extent any of the original notes are privately placed, the issuer may offer to exchange such privately placed notes for notes that are registered under the Securities Act of 1933, as amended (the “Securities Act”).

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After the transfers of assets to ETrans, Gen and GTrans, the assumptions of liabilities and the issuances of long-term notes and transfers of cash, Debtor is scheduled on the Plan Effective Date to pay a dividend of all of the common stock of Newco to Parent.

•

Reorganized Debtor will transfer cash and long-term notes issued by ETrans, Gen and GTrans to Debtor’s creditors to pay off allowed claims under the Plan.36 Debtor may deposit certain of these long-term notes in one or more escrow accounts or a special purpose entity if certain claims (such as claims subject to ongoing litigation) are not resolved by the Plan Effective Date.

•

On the Plan Effective Date, Reorganized Debtor also will issue long-term mortgage bonds to replace certain existing long-term mortgage bonds.37

•

After the transactions discussed above and either on the Plan Effective Date or as soon as practicable thereafter, Debtor will pay a stock dividend to Parent so that the number of the issued and outstanding shares of common stock of Debtor owned directly by Parent will be the same as the number of issued and outstanding shares of common stock of Parent. Debtor also will establish a rights plan, similar to the plan now in place for Parent, under which Debtor will distribute to each holder of Debtor stock a right to purchase preferred stock or common stock from Debtor under certain circumstances. Then, Parent will implement the Spin-Off by paying a dividend of all the common stock and related stock purchase rights of Debtor owned directly by Parent to the shareholders of Parent.38

•

Debtor obtained shareholder approval at its 2002 Annual Meeting of Shareholders for certain amendments to its Articles of Incorporation and Bylaws of Debtor, which include structural defenses that will only become effective concurrent with or immediately following the Spin-Off. The amendments would (a) divide the Board of Directors into three classes to serve for terms of three years if the authorized number of directors is fixed at nine (9) or greater, or divide the Board of Directors into two classes to serve for terms of two (2) years if the authorized number of directors is fixed within the range of six (6) to eight (8), (b) incorporate a constituency provision that would authorize the Board of Directors to give due consideration to all factors considered relevant, including the interests of constituencies, when evaluating business combinations involving Reorganized Debtor, (c) require that shareholder action be taken only at a meeting, (d) reduce the maximum number of authorized

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36

These transfers will be made either directly or by causing the release of cash and long-term notes from one or more escrow accounts or special purpose entities established to hold proceeds of offerings effected before the Plan Effective Date.

37

To the extent any of the original notes are privately placed, Reorganized Debtor may offer to exchange such privately placed notes for notes that are registered under the Securities Act.

38

Debtor will not be required to register the common stock distributed in the Spin-Off under the Securities Act, but will furnish an information statement meeting the requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), to the holders of common stock of Parent prior to the date of the Spin-Off. The common stock of Debtor will be registered pursuant to the Exchange Act, and generally will be freely-tradable by the recipients on the Plan Effective Date or as soon as practicable thereafter. Debtor will apply to list the common stock of Reorganized Debtor on the New York Stock Exchange. The preferred stock of Debtor will remain in place as preferred stock of Reorganized Debtor.

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•

If the long-term notes deposited in escrow accounts or special purpose entities and any related cash are insufficient once claims are resolved, ETrans, Gen and GTrans may need to issue and deliver to Debtor additional long-term notes to satisfy their respective shares of Debtor obligations associated with these claims.

•

The Plan will secure investor confidence through the realignment of the new companies’ businesses by regulatory jurisdiction. This realignment places each of Debtor’s current businesses under the appropriate regulatory agency and simplifies credit analyses from the perspective of creditors.

•

The Plan permits access to the investment-grade capital markets by ETrans, Gen and GTrans, as is required for Debtor to raise funds needed to pay allowed creditors’ claims in full, based on asset values, without risk premiums associated with rate regulation by the CPUC.

•

The Plan will promote price stability through the long-term PSA between Reorganized Debtor and Gen. The PSA provides for a stable price for a sizable amount of capacity, and the rates and terms of the PSA must be approved by FERC as

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•

The Plan maintains regulatory oversight for each of Debtor’s current lines of business, realigning the existing regulatory structure in order to enhance access to financial markets to enable Debtor to emerge from bankruptcy. The CPUC will continue to regulate Reorganized Debtor, including retail electric and natural gas rates, and will retain a limited non-rate oversight role with respect to ETrans; FERC will have jurisdiction over the licenses for the hydroelectric assets, the rates for Gen’s sales of electric energy and related products and services at wholesale, the rates, terms and conditions of service provided by the electric transmission business, and the facilities, rates and terms of service of GTrans; and the NRC will continue to regulate DCPP. All Californians will benefit because safety and environmental regulatory oversight will remain as it is currently, including oversight of the hydroelectric system and DCPP.

•

The Plan is in keeping with the overall direction of energy policy in the United States, allowing Debtor to emerge from bankruptcy in a manner that (i) provides for market stability in the western power marketplace, (ii) does so in keeping with FERC’s current market framework, (iii) clears the way for progress on RTO issues and (iv) enables adequate investment in and expansion of the distribution system, the electric and gas transmission infrastructures and generation improvements.

•

The Plan effectively keeps the operations of the new businesses in the hands of the same employees who operate them today; customers will continue to receive all of the same reliable utility customer services they currently receive.

•

Implementation of the Plan does not require a retail rate increase,39 nor does it seek to have customers or taxpayers fund or approve any form of state bailout.

•

The Plan avoids selling Debtor’s generation assets to out-of-state state generators or other third parties.

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39

Debtor’s current CPUC-authorized system average electric rates are approximately $0.14 per kWh. These rates are designed to recover all of Debtor’s costs of service and authorized return and taxes associated with its electric distribution, transmission, generation and nuclear decommissioning facilities, as well as the costs of power purchased from third parties, such as QFs and the ISO, and various public purpose programs mandated by the CPUC and the State legislature. The CPUC does not set rates for individual utility facilities or business segments, such as Debtor’s power generating facilities, but instead authorizes a level of revenue, known as the “revenue requirement,” for certain functions. For example, under current CPUC-authorized electric rates, Debtor’s rates are based on CPUC decisions issued in 1996 implementing a freeze on Debtor’s overall electric rates and allowing Debtor to recover the costs of its uneconomic utility generation and power purchase costs based on the residual revenues available to Debtor after recovery of the costs of and return on its other electric utility facilities and operations, including uneconomic distribution, transmission and generating facilities and public purpose programs. In addition, in January and March 2001, the CPUC authorized Debtor to collect additional surcharges in its overall retail rates, amounting to approximately $0.01 per kWh, and $0.03 per kWh on top of its overall rates. The CPUC authorized Debtor to collect these surcharges for the purpose or recovering costs relating to its utility retained generating facilities as well as power procurement costs, and estimated that Debtor’s revenue requirements available for these purposes was equivalent to an “average generation related rate” of $0.09471 per kWh.

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•

The Plan creates a framework by which Debtor can reassume the net open position in the future, without jeopardizing its creditworthy status.

•

The Plan realizes the value of Debtor’s assets by separating Gen from Reorganized Debtor and provides for Gen to sell power at market-based, FERC-approved rates to Reorganized Debtor under the PSA while avoiding the loss of value to tax payments that would have resulted from sale of the assets at an appreciated value.

•

The Plan, by separating Debtor from Parent, also creates a structure which reduces concerns about possible self-dealing between the retail activities of Reorganized Debtor and the upstream activities of Parent’s subsidiaries.

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This forecast remains current as May 31, 2002.

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ETrans was analyzed as having the lowest risk profile, as perceived by the market and the rating agencies, of the four companies and therefore is able to support the highest debt relative to its earnings capacity. The perceived market risk for ETrans is the lowest among the four companies because of limited competition in transmission and lack of dependence on commodities. The transmission technology employed by ETrans is well established, creating moderate operational risk. Also, the regulatory risk for ETrans is perceived to be relatively moderate based on FERC’s supportive regulatory record with respect to electric transmission infrastructure development and cost recovery. ETrans’ debt capacity is somewhat constrained due to very substantial requirements for capital investment into California’s electric transmission infrastructure.

•

GTrans was analyzed as having the second lowest risk profile, as perceived by the market and the rating agencies, of the four companies. GTrans’ perceived market risk is similar

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40

Moody’s Investors Service, Rate Review (October 9, 2001) (attached hereto as Exhibit G-3).

41

Standard & Poor’s News Release, dated January 17, 2002 (attached hereto as Exhibit G-4).

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Reorganized Debtor was analyzed as having a significantly higher risk profile, as perceived by the market and the rating agencies, than the two transmission businesses. This occurs notwithstanding operational risks for Reorganized Debtor, which are relatively moderate, and Reorganized Debtor’s expected ability to fund its capital requirements with relatively modest external financing. The reasons for Reorganized Debtor’s higher risk profile are the perceived risks associated with its procurement obligations and its regulatory risk. Parent’s financial advisor considered market and rating agency skepticism regarding the regulatory environment in California, taking into account recent experience in California energy markets where (a) investor owned utilities have not received timely regulatory approval to increase rates in response to higher commodity prices and (b) there have been repeated changes to regulatory rules in the face of pressure to avoid raising rates. These considerations lead to a relatively higher risk profile for Reorganized Debtor than most distribution companies in other areas of the country.

•

Gen was analyzed as having the highest risk profile of the four companies, as perceived by the market and the rating agencies, because of its perceived market and operational risks. Although the 12-year term of the PSA reduces Gen’s perceived risk, this reduction is offset to some extent by the fact that its counterparty is Reorganized Debtor. Furthermore, its relative market risk increases at the end of the term of the PSA when it will be subject to market price volatility. In addition, Gen is perceived to have relatively higher operating risk due to the potential for weather or equipment-related outages to its power plants, the lack of planned growth in Gen’s business and the fixed terms of its nuclear power plant license and Irrigation District Contracts.

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*

Excludes certain contingent assets and liabilities which would be retained both in the absence of the Plan and after implementation of the Plan. Applicants have not included these contingent assets and liabilities in the projected value of the new entities after the Plan, because the contingent nature of such assets and liabilities does not allow for any practical or reliable quantification for purposes of reasonable financial evaluation.

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**

Based on discounted cash flow valuation.

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*

Discounted cash flow valuation performed by Rothschild Inc. is used instead of book capitalization because, in Applicants’ view, discounted cash flow analysis better reflects the value of the revenue stream associated with Gen’s assets and because of prior accelerated depreciation and write-downs required by Generally Accepted Accounting Principles (“GAAP”) in conjunction with deregulation which reduced Gen’s net plant by approximately $3.6 billion compared to conventional depreciation rates.

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**

The allocation of debt could be different in certain circumstances as set forth in the Plan which could reduce the amount of long-term debt to be issued by the Newco subsidiaries or increase the amount of long-term debt to be issued by Reorganized Debtor.

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The amount of notes to be issued in capital markets and cash to be transferred to Debtor, relative to the amount of notes to be issued to Debtor, may change based on market conditions and other factors. The amount of cash to be paid by the Newco subsidiaries to Debtor will be reduced by the amount necessary to fund those subsidiaries’ near-term working capital requirements. Debtor may issue additional long-term notes in the event that the total amount of financing required exceeds currently planned amounts.

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*

The amount of long-term notes to be issued to Debtor, relative to the amount of notes to be issued in capital markets and cash to be transferred to Debtor, may change based on market conditions and other factors.

**

Of the $1,159 million, $345 million is secured by mortgage bonds of Debtor that are substantially identical to the underlying debt. These mortgage bonds will be replaced by newly issued mortgage bonds of Reorganized Debtor, the issuance of which will not affect the level of debt.

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*

The amount of long-term notes to be issued in capital markets and cash to be transferred to Debtor, relative to the amount of notes to be issued to Debtor, may change based on market conditions and other factors. The amount of cash to be paid by the Newco subsidiaries to Debtor will be reduced by the amount necessary to fund those subsidiaries’ near-term working capital requirements. Further, the amount of long-term notes to be issued to Debtor by each of the Newco subsidiaries is subject to reduction in certain circumstances under terms set forth in the Plan. Debtor may issue additional long-term notes in the event that the total amount of financing required exceeds currently planned amounts.

**

Amounts raised by financing will be used before cash on hand to pay allowed creditor claims.42

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42

Projected cash on hand excluding $330 million mortgage bond payment made March 1, 2002, and planned pre-consummation disbursements of interest and pre-petition obligations of $1.06 billion to qualifying facility suppliers, $89 million of customer deposits, and $768 million of interest.

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the Back-to-Back Agreement between ETrans and Reorganized Debtor enabling continued service for Debtor’s current wholesale electric customers by providing for ETrans to provide to Reorganized Debtor transmission services needed to support contracts assigned to Reorganized Debtor and providing for Reorganized Debtor to provide to ETrans distribution services needed to fulfill contracts assigned to ETrans;

•

a Transmission Availability Agreement for Offsite Power Supply between ETrans and Gen (“Transmission Availability Agreement”) to meet NRC regulatory requirements with respect to the DCPP;

•

three Generation Interconnection Agreements between (1) ETrans and Gen providing for the interconnection between ETrans and Gen’s generation facilities that interconnect at transmission voltages, (2) ETrans and Reorganized Debtor providing for the interconnection between ETrans and Reorganized Debtor’s retained generation facilities and (3) Reorganized Debtor and Gen providing for the interconnection between Reorganized Debtor’s distribution level facilities and Gen’s generation facilities that interconnect at distribution voltages; and

•

a Load Interconnection Agreement between ETrans and Reorganized Debtor providing for the interconnection between ETrans’ transmission facilities and Reorganized Debtor’s load serving facilities.

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43

In the Rate Recovery Litigation, Debtor asks the court to declare that the CPUC was without jurisdiction to enter its decisions prohibiting recovery of Debtor’s wholesale power purchase costs to the extent procurement of that power and incurrence of those costs was otherwise found to have been reasonable, and that state law as interpreted in such decisions is unconstitutional and unenforceable insofar as it prevents Debtor from recovering its entire interstate electric transmission and wholesale power purchase costs in retail rates, in that such prohibition is preempted by federal law and violates the Commerce Clause of the United States Constitution. Debtor also asks that the court declare that state law, as interpreted by the CPUC, is unconstitutional and unenforceable insofar as it produces a confiscatory result and fails to provide just compensation for the taking of private property for public use, in that it violates the Takings and Due Process Clauses of the United States Constitution. Debtor asks for a preliminary and permanent injunction requiring defendants, and each of them, immediately to comply with the court’s declarations and restraining defendants, and each of them, from taking any actions, including maintaining or implementing any rates, contrary to the declarations. If Debtor prevails in the Rate Recovery Litigation, then it would be entitled to require the CPUC to adjust retail electric rates to allow recovery of Debtor’s then-remaining balance of unrecovered interstate electric transmission and wholesale power purchase costs.

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44

Newco will not sell, dividend, pledge or otherwise transfer any part of its 95% interest in such net proceeds at any time prior to the occurrence of a “Litigation Transfer Event.” Under the Plan, a Litigation Transfer Event occurs if the long-term notes of each of ETrans, GTrans and Gen trade at or above par for 30 days (which need not be consecutive days and which need not be the same days for each issue of the long-term notes) during any 60 business day period.

45

As discussed in footnote 32, supra, Debtor is subject to Public Utilities Code Section 367(b) which authorizes the CPUC to determine the market value of Debtor’s non-nuclear generating assets by no later than December 31, 2001 and provide that value to ratepayers through a credit against the obligation of ratepayers to compensate Debtor for its utility generation-related “transition” costs. The amount of this credit once applied for ratemaking purposes could ultimately have the ratemaking effect of offsetting a portion of the amount of proceeds from the Rate Recovery Litigation collected in retail rates.

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46

To the extent that the BFM Contract Seizure Litigation is resolved prior to the Plan Effective Date, (a) Debtor and a specified group of creditors (the “PX Participants’ Committee”) will negotiate in good faith as to the application of any proceeds of the BFM Contract Seizure Litigation and (b) Debtor, the PX Participants’ Committee and the individual participants reserve all rights against each other and other parties who assert claims with respect to or interests in the BFM contracts.

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47

Northeast Utils., HCAR No. 25221, 1990 SEC LEXIS 3898, *34 (Dec. 21, 1990) as modified, HCAR No. 25273, 1991 SEC LEXIS 421 (Mar. 15, 1991), aff’d sub nom.City of Holyoke v. SEC, 972 F.2d 358 (“Northeast Utilities”).

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48

City of Holyoke Gas & Elec. Dept. v. SEC, 972 F.2d 358, 363 (D.C. Cir. 1992) (“City of Holyoke”) (quoting Northeast Utilities, 1990 SEC LEXIS 3898, *39 and citing Municipal Elec. Ass’n v. SEC, 413 F.2d 1052, 1056-57 (D.C. Cir. 1969)).

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49

Northeast Utilities.

50

Wisc. Energy Corp., HCAR No. 24267, 1986 SEC LEXIS 124, *14 (Dec. 18, 1986) (“Wisconsin Energy”); see also Central Maine; 1998 SEC LEXIS 1685, accord BEC Energy, HCAR No. 26874, 1998 SEC LEXIS 941 (May 15, 1998); Energy East Corp., HCAR No. 26834, 1998 SEC LEXIS 355 (Mar. 4, 1998).

51

City of Holyoke, 972 F.2d at 363-64 (quoting Wisconsin’s Envtl. Decade v. SEC, 882 F.2d 523, 527 (D.C. Cir. 1989). See also Envtl. Action, Inc. v. SEC, 895 F.2d 1255, 1261 (9th Cir. 1990) (“Environmental Action”) (the Commission properly relied on FERC’s rate-approval authority under Section 205 of the FPA and on market factors to conclude no anti-competitive effects in acquisition of generating capacity); Northeast Utilities, 1990 SEC LEXIS 3898 (the Commission particularly looks to FERC’s expertise regarding anticompetitive issues regarding transmission access and bulk power markets and may condition approval of an acquisition on obtaining an order from FERC under Section 203 of the FPA).

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52

Pinnacle West Capital Corp., HCAR No. 27386, 2001 SEC LEXIS 841 (Apr. 27, 2001) (“Pinnacle West”); CIPSCO Inc., HCAR No. 25152, 1990 SEC LEXIS 3224 (Sept. 18, 1990) (“CIPSCO”); Wisconsin Energy, 1986 SEC LEXIS 124.

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53

See, e.g., Madison Gas & Elec. Co., HCAR No. 27326, 2000 SEC LEXIS 2873 (Dec. 28, 2000); WPS Res. Corp., HCAR No. 27330, 2000 SEC LEXIS 2876 (Dec. 28, 2000); Energy East Corp., HCAR No. 27128, 2000 SEC LEXIS 139 (Feb. 2, 2000). Entergy Corp., HCAR No. 25952, 1993 SEC LEXIS 3539 (Dec. 17, 1993) (fees and commissions represented approximately 1.7% of the value of consideration); Northeast Utilities, 1990 SEC LEXIS 3898, (fees and expenses represented approximately 2% of the value of assets to be acquired), fees approved by SEC Staff in delegated order, Northeast Utils., HCAR No. 25548, 1992 SEC LEXIS 1329 (June 3, 1992).

54

Pinnacle West, 2001 SEC LEXIS 841, *6 (where a holding company transferred generation assets from one public utility company subsidiary to another subsidiary that became a public utility company as a result of the transaction, the Commission approved a transfer of debt adjusted to maintain the current debt to common stock equity ratio of the transferor subsidiary).

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*

Discounted cash flow valuation performed by Rothschild Inc. is used instead of book capitalization because, in Applicants’ view, discounted cash flow analysis better reflects the value of the revenue stream associated with Gen’s assets and because of prior accelerated depreciation and write-downs required by GAAP in conjunction with deregulation which reduced Gen’s net plant by approximately $3.6 billion over the past five years compared to conventional depreciation rates.

**

The allocation of debt could be different in certain circumstances as set forth in the Plan which could reduce the amount of long-term debt to be issued by the Newco subsidiaries or increase the amount of long-term debt to be issued by Reorganized Debtor.

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*

Based upon the amounts of debt anticipated to be issued under the Plan.

**

Value of common equity is calculated as the difference between the discounted cash flow valuation of Gen’s assets of $5.284 billion performed by Rothschild Inc. and the $2.4 billion debt allocated to Gen. Because of accelerated depreciation and the write-down of assets required by GAAP in conjunction with deregulation, Gen would have no equity on a book capitalization basis (book capitalization of $1.217 billion less allocated debt of $2.4 billion). As discussed below, book capitalization for Gen dramatically understates the economic value of its assets; capitalization based on discounted cash flow valuation more accurately reflects the economic value of its assets.

***

Excludes $1.450 billion of Debtor’s rate reduction bonds, for which the payment obligation flows through to ratepayers and therefore are not viewed from a credit rating perspective as debts of Debtor/Reorganized Debtor. The capitalization of Reorganized Debtor could be different in the event that claims exceed currently estimated amounts, in which case Reorganized Debtor would issue additional long-term notes.

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55

Announcement of Study by Division of Corporate Regulation of the Securities and Exchange Commission Regarding a Proposed Statement of Policy Relative to Capitalization Ratios for Registered Holding Company Systems Subject to the Public Utility Holding Company Act of 1935, HCAR No. 13255, 1956 SEC LEXIS 667, *3 (Sept. 5, 1956) (“Proposed Capitalization Policy”) (quoting Tenth Annual Report to Congress for the fiscal year ended June 30, 1944 at 99).

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56

Id., 3-4 (quoting Report for the SEC Subcommittee of the House Committee on Interstate and Foreign Commerce on PUHCA at 27) (Oct. 15, 1951).

57

NiSource Inc., HCAR No. 27263, 2000 SEC LEXIS 2341 (Oct. 30, 2000); American Elec. Power Co., Inc., HCAR No. 27186, 2000 SEC LEXIS 1227 (Jun. 14, 2000) (“AEP”), vacated and remanded on other grounds sub nom.Nat’l Rural Elec. Coop. v. SEC, 276 F.3d 609, 2002 U.S. App. LEXIS 777 (D.C. Cir. 2002); Nat’l Grid Group plc, HCAR No. 27154, 2000 SEC LEXIS 474 (Mar. 15, 2000) (“National Grid”); Northeast Utilities, 1990 SEC LEXIS 3898, Columbia Gas Sys., Inc., HCAR No. 23971, 1985 SEC LEXIS 30 (Dec. 30, 1985), aff’d sub nom.Garsham v. SEC, 804 F.2d 1248 (3d Cir. 1986); Georgia Power Co., HCAR No. 18517, 1974 SEC LEXIS 2905 (July 31, 1974) (citations omitted).

58

U.S. Sec. & Exch. Comm’n, Div. of Investment Mgmt., The Regulation of Public-Utility Holding Companies at 43 (June 1995) (“1995 Report”) (citation omitted).

59

Sioux City Gas & Elec. Co., HCAR No. 300, 1936 SEC LEXIS 1598 (July 21, 1936); see also Minnesota Power & Light Co., HCAR No. 6032 (Sep. 6, 1945); Consumers Power Co., HCAR No. 6024 (Aug. 30, 1945); Ohio Edison Co., HCAR No. 5697 (Mar. 31, 1945); Southwestern Gas and Elec. Co., 6 SEC 806 (1940); Public Serv. Co. of Colorado, 5 SEC 788 (1939); Republic Serv. Corp., 2 SEC 44 (1937). The Commission subsequently indicated that refinancing issuances should be governed by the same standards as new issuances of securities. See El Paso Elec. Co, 8 SEC 366 at 388 (1940).

60

See also Eastern Utils. Assoc., HCAR No. 35-24245, 1986 SEC LEXIS 314 (Nov. 21, 1986) (allowing an equity structure with 20% equity in the face of certain mitigating circumstances).

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61

Mississippi Valley Generating Co., HCAR No. 12794, 1955 SEC LEXIS 450 (Feb. 9, 1955).

62

Id., *32.

63

Id., *34. See also Ohio Valley Elec. Co., HCAR No. 11578, 1952 SEC LEXIS 387 (Nov. 7, 1952) (authorizing a 95/5 initial capital structure); Central Ill. Pub. Serv. Co., HCAR No. 10340, 1951 SEC LEXIS 857 (Jan. 15, 1951) (authorizing a 95/5 initial capital structure); Electric Energy, Inc., HCAR No. 10639, 1951 SEC LEXIS 1165) (June 26, 1951). The Commission also has approved an application under Section 9(a)(2) by an exempt holding company where the capital structure of the acquired subsidiary wholesale generating company was comprised of 25% equity (without explicitly applying the 30% standard). Sierra Pacific Res., HCAR No. 24566, 1998 SEC LEXIS 26 (Jan. 28, 1988), aff’d, sub nom. Environmental Action, Inc., 895 F.2d 1255 (9th Cir. 1990).

64

Northeast Utils., Release No. 35-27147, 2000 SEC LEXIS 406 (March 7, 2000).

65

Id., *8.

66

Id., *9. However, in the notice of its original application, NU stated that its electric utility companies “request an exemption from the 30% equity standard through December 31, 2012 and NU seeks an exemption from the 30% equity standard through December 31, 2001.” Filings Under the Public Utility Holding Company Act of 1935, as amended, HCAR No. 27105, 1999 SEC LEXIS 2485, *25 (Nov. 19, 1999).

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67

Id., *9-10.

68

See Conectiv, HCAR No. 27111, 1999 SEC LEXIS 2651 (Dec. 14, 1999); West Penn Power Co., HCAR No. 27091, 1999 SEC LEXIS 2231 (Oct. 19, 1999). See also Maine Yankee Atomic Power Co., HCAR No. 19657, 1976 SEC LEXIS 1008 (1976) (authorizing issuance of debt to finance purchase of nuclear fuel where equity would represent 27.4% of capital).

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•

DCPP, with a capacity of 2,200 MW, an operating license which is valid for Unit 1 until September 2021 and for Unit 2 until April 2025, annual energy production of 16,000-17,000 GWh, and one of the finest safety and production records in the industry, will be carried on Gen’s books at nearly zero book value; only its nuclear fuel inventory and future capital additions are expected to be capitalized; and

•

The Helms pumped storage facility, with a total capacity of 1,200 MW is a premier supplier of ancillary services and peaking power; Helms also will be carried on the Gen’s books with a book value of nearly zero.

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69

Amounts written off in 1998 were reclassified as regulatory assets on Debtor’s books at that time but ultimately were written off when Debtor concluded that these regulatory assets were not probable of recovery through regulated rates.

70

This valuation may not be relevant to the extent Gen or its assets are reviewed under a different contractual, regulatory or ratemaking construct than that contemplated by the Plan.

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*

Based upon the amounts of debt anticipated to be issued under the Plan.

**

Value of Gen common equity is based on discounted cash flow analysis of Gen performed by Rothschild Inc. less debt.

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Reorganized Debtor debt excludes Debtor’s revenue reduction bonds.

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71

The Commission has considered indications from credit rating agencies that an applicant’s debt will be rated investment grade in approving issuances of securities under Section 7(d) of the Act where the capital structure of the applicant was less than 30% equity. National Grid, 2000 SEC LEXIS 474, *93.

72

Moody’s Investors Service, Rating Review (October 9, 2001) (attached hereto as Exhibit G-3).

73

Standard & Poor’s News Release, dated January 17, 2002 (attached hereto as Exhibit G-4).

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74

Gaz Metropolitain, Inc., HCAR No. 26170, 1994 SEC LEXIS 3676, *13 (Nov. 23, 1994) (“Gaz Metropolitain”); see also TUC Holding Co., HCAR No. 26749, 1997 SEC LEXIS 1587 (Aug. 1, 1997) (“TUC Holding”). The Staff reaffirmed this result in the 1995 Report at 117. See note 58, supra.

75

Exelon Corp., HCAR No. 27256, 2000 SEC LEXIS 2265, **53-55 (Oct. 19, 2000); Energy East, 2000 SEC LEXIS 139; National Grid, 2000 SEC LEXIS 474.

76

The Commission has recognized reducing tax liability is a valid reason for maintaining an intermediate holding company within the holding company structure. Exelon; National Grid.

77

Under the Commission’s rules, passive owners of jurisdictional electric or gas facilities for purposes of lease financing which meet certain standards are not considered to be public utility companies. 17 C.F.R. § 250.7(d).

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78

1995 Report at 117 (citing Union Elec. Co., HCAR No. 18368, 1974 SEC LEXIS 1509 n.63 (Apr. 10, 1974) (“Union Electric”) and Gaz Metropolitain, 1994 SEC LEXIS 3676). Although the Staff’s statement was made in the context of Section 10(c)(1), it is equally applicable under Section 10(c)(2). See WPS Res. Corp., HCAR No. 27330, 2000 SEC LEXIS 2876 (Dec. 28, 2000) (“WPS Resources”); Sierra Pacific Res., HCAR No. 27054, 1999 SEC LEXIS 1463 (Jul. 26, 1999); CMP Group, Inc., HCAR No. 26977, 1999 SEC LEXIS 308 (Feb. 12, 1999); NIPSCO Indus., Inc., HCAR No. 26975, 1999 SEC LEXIS 289 (Feb. 10, 1999); WPS Res. Corp., HCAR No. 26922, 1998 SEC LEXIS 2097 (Sep. 28, 1998); Sempra Energy, HCAR No. 26890, 1998 SEC LEXIS 1310 (Jun. 26, 1998); BL Holding Corp., HCAR No. 26875, 1998 SEC LEXIS 970 (May 15, 1998) (citing TUC Holding, 1997 SEC LEXIS 1587 and Gaz Metropolitain 1994 SEC LEXIS 3676); BEC Energy, 1998 SEC LEXIS 941; TUC Holding, 1997 SEC LEXIS 1587, *22 (“The Commission has previously determined, . . .. that where a holding company will be exempt from registration under section 3 of the Act following an acquisition of non-integrating utility assets, it suffices for purposes of section 10(c)(2) to find benefits to one integrated system.”) (footnote omitted); CIPSCO, 1990 SEC LEXIS 3224.

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the combined utility assets must be physically interconnected or capable of physical interconnection (“interconnection requirement”);

•

the combined utility assets, under normal circumstances, must be economically operated as a single interconnected and coordinated system (“economic and coordinated operation requirement”);

•

the system must be confined in its operations to a single area or region (“single area or region requirement”); and

•

the system must not be so large as to impair (considering the state of the art in the area or region affected) the advantages of regulation (“no impairment requirement”).80

•

The electric facilities of ETrans and Gen are, and will remain, physically interconnected through step-up transformers located at or near each of Gen’s generating facilities.

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79

Section 2(a)(29)(A) does not require that an integrated electric utility system include all three —or even two— of the types of facilities listed in Section 2(a)(29)(A) (generation, transmission and distribution). Sierra Pacific Res., 1998 SEC LEXIS 26.

80

See e.g., Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing Electric Energy Inc., 38 S.E.C. 658, 668 (1958)).

81

See, e.g., Sempra Energy, 1998 SEC LEXIS 1310.

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The electric facilities of ETrans and Gen will be operated as a coordinated system. Pursuant to the terms of the interconnection agreements between Gen and ETrans, the flow of power from the assets transferred to Gen and its subsidiaries and the use of the assets transferred to ETrans will continue in the same manner as today.82 System reliability operations will continue to be performed within the ETrans organization as they are today. Pursuant to the Back-to-Back Agreement with Reorganized Debtor, ETrans will assume most of the transmission service agreements currently held by Debtor. Service under those agreements will continue under the same rate structure as is in place today, which is and will be subject to the jurisdiction of FERC. As noted previously, Debtor is currently a participant in the CAISO, in which transmission-owning members have turned over operational control of their transmission assets to the ISO. The CAISO functions as a single market and represents a single interconnected and coordinated system to ensure reliability and economically efficient operations. After the consummation of the Transaction, ETrans will continue to be subject to the operational control of the CAISO, and has committed either to remain a participant in the CAISO or to join an FERC-approved regional transmission organization (“RTO”) which, under FERC RTO rules, would also be required to function as a single market and would represent a single interconnected and coordinated system. In addition, all of Gen’s generation assets will continue to be physically and contractually connected to the grid operated through the CAISO. Indeed, generation owners in California, including Gen, must enter into generator participation agreements with the CAISO to assure that all generation is available for its reliable, economic and coordinated dispatch.

•

As described above, the operations of Debtor, as well as ETrans and Gen, will be in central and northern California, a “single area or region . . . not so large as to impair . . . the advantages of localized management, efficient operation, and the effectiveness of regulation.” The Commission has found on several occasions that electric utility operations stretching across more than one state and operating as part of one ISO or power pool (or even more than one ISO or power pool) is still confined to a single area or region.83 Here, the operations of ETrans and Gen will continue to be confined not only to the single geographic region of central and northern California, but, as discussed above, also will be confined to the region administered by a single ISO, the CAISO.

•

The operations of ETrans and Gen will be no larger than they are today and will remain subject to control of Parent. ETrans and Gen have been operated efficiently as separate internal business lines in the past, and placing them in separate companies will not impair their efficient operation. As discussed above,

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82

See, e.g., Pinnacle West, 2001 SEC LEXIS 841; WPS Res., Inc., 2000 SEC LEXIS 2876; UNITIL Corp., HCAR No. 25524, 1992 SEC LEXIS 1016 (Apr. 24,1992).

83

See, e.g., Northeast Utilities, 1990 SEC LEXIS 3898, *53 n.85; UNITIL Corp., 1992 SEC LEXIS 1016; Conectiv, Inc., HCAR No. 26832, 1998 SEC LEXIS 326 (Feb 25, 1998).

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FERC policy encourages separation between generation and transmission.84 ETrans and Gen will be subject to rate regulation by FERC. The Commission has held that “[t]here is no requirement that the Commission, in approving an acquisition under Section 10, find that a utility is subject to any particular degree of state regulation or even that there is any state regulation at all,” as long as it finds that the “holding company system, after the acquisition, will not be ‘so large as to impair . . . effectiveness of regulation.’”85 The Commission has approved the corporate separation of electric transmission from generation and distribution where the applicant stated that such separation would allow the transmission company to provide open access, non-discriminatory service for all customers and that the electric generation, transmission and distribution systems would continue to be operated as a single interconnected and coordinated system.86 Placing Debtor’s electric transmission business in a company that is separate from its generation and distribution businesses similarly will allow ETrans to provide open access, non-discriminatory transmission service, and, as discussed above, the separate businesses will continue to operate as a single interconnected and coordinated system through interconnection and service agreements between the companies and through CAISO’s operational control over the California transmission system and its operation of wholesale markets in California.

•

Reorganized Debtor’s electric distribution system will continue to be physically interconnected.

•

Reorganized Debtor’s electric distribution system will continue to be operated as a single and coordinated system operating in central and northern California.

•

Reorganized Debtor’s electric distribution system will not be “so large as to impair . . . the advantages of localized management, efficient operation, and the effectiveness of regulation.” Reorganized Debtor’s electric distribution system will continue to be owned and operated by a California company under localized

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84

See, e.g., Southwest Gas Corp., 43 FERC ¶ 61,257 at 61,709, reh’g denied, 44 FERC ¶ 61,165 (1988); Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Pub. Utils. and Transmitting Utils., Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996), FERC Stats. & Regs. [Regs. Preambles 1991-1996] ¶ 31,036 at 31,655-56 (1996), clarified, 76 FERC ¶ 61,009 and 76 FERC ¶ 61,347 (1996), order on reh’g, Order No. 888-A, 62 Fed. Reg. 12,274 (Mar. 14, 1997), FERC Stats. & Regs. [Regs. Preambles 1996-2000] ¶ 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in substantial part sub nom. Transmission Access Policy Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, Nos. 00-568 and 00-809 (U.S. Mar. 4, 2002) (“Order No. 888”) (“we again encourage utilities to explore whether corporate unbundling or other restructuring mechanisms may be appropriate in particular circumstances”).

85

Northeast Utilities, 1990 SEC LEXIS 3898, *49.

86

DTE Energy Co., HCAR No. 27229, 2000 SEC LEXIS 1914 (Sept. 13, 2000).

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•

Reorganized Debtor’s gas distribution system will continue to be operated as single and coordinated system operating in central and northern California.

•

Reorganized Debtor’s gas distribution system will not be “so large as to impair . . . the advantages of localized management, efficient operation, and the effectiveness of regulation.” Reorganized Debtor’s gas distribution system will continue to be owned and operated by a California company under localized management and will continue to be subject to regulation by the CPUC, just as it is today.

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87

Debtor’s gas transmission system will be owned by GTrans, which will not be a gas utility company subject to jurisdiction under the Act. GTrans will be subject to regulation by FERC with respect to its facilities and its rates, terms and conditions of service.

88

AEP, 2000 SEC LEXIS 1227, *40-41 (quoting Southern Cos., HCAR No. 25639, 992 SEC LEXIS 2385 (Sept. 23, 1992).

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89

See, e.g., Pinnacle West, 2001, Central Maine, 1998 SEC LEXIS 1685, Atlanta Gas Light Co., HCAR No. 26482, 1996 SEC LEXIS 690 (Mar. 5, 1996), SIGCORP, HCAR No. 26431, 1995 SEC LEXIS 3425 (Dec. 14, 1995); PP&L Res., Inc., HCAR No. 26248, 1995 SEC LEXIS 650 (Mar. 10, 1995); CIPSCO, 1990 SEC LEXIS 3224.

90

The Commission has stated that “reference to the legislative history of [Section 10(f)] makes it clear that the words ‘such State laws as may apply’ mean only such State laws as impose obligations with reference to proceedings before State commissions or State securities commissions.” Texas Utils. Co., HCAR No. 501, 1036 SEC LEXIS 1750 (Dec. 31, 1936); see also Wisconsin Electric Power Co., HCAR No. 24267, 1986 SEC LEXIS 124 (Dec. 18, 1986).

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91

See also Public Utilities Code §§ 451, 728, 761 (potentially conflicting with the Plan’s establishment of conditions under which Reorganized Debtor may resume procurement of the net open position or transfer of any of Debtor’s assets or businesses to any of ETrans, GTrans or Gen); § 453 (potentially preempted if interpreted to preclude Reorganized Debtor from entering into e.g. the PSA with Gen or the Transportation and Storage Services Agreement with GTrans); § 702 (potentially preempted if interpreted to provide independent basis for finding portions of the Plan in conflict with CPUC’s orders, decisions, directions or rules); § 797-98 (potentially preempted if interpreted as restricting or prohibiting Reorganized Debtor or other of the reorganized entities from entering into or performing the PSA or other agreements); § 845 (potentially preempted if interpreted to require each of Gen, ETrans and GTrans to be liable for Debtor’s obligations under its rate reduction bonds); § 851 (potentially preempted because requires CPUC approval before Debtor can dispose of its property); § 852 (potentially preempted if interpreted to require CPUC approval of distribution of common stock of Newco to Parent); and § 854 (potentially preempted if interpreted to require CPUC approval of distribution of common stock of Newco to Parent or of distribution of common stock of Reorganized Debtor by Parent to its public shareholders). Applicants believe that the foregoing laws and regulations are expressly preempted by Section 1123(a) of the Bankruptcy Code, which provides that “Notwithstanding any otherwise applicable nonbankruptcy law,” a plan of reorganization shall “provide adequate means for the plan’s implementation such as,” e.g., sales and transfers of property and issuance of securities. 11 U.S.C. § 1123(a) (1994). However, the Bankruptcy Court disagreed and Applicants are currently appealing that issue. See “Memorandum Decision Regarding Preemption and Sovereign Immunity,” Bankruptcy Case No. 01-30923DM, United States Bankruptcy Court, Northern District of California (the “February 7 Decision”) at 3.

92

February 7 Decision at 3.

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The disaggregation of the Debtor’s assets as provided by the Plan is essential to the ability of the Debtor and its successors to obtain the financing necessary to pay all allowed claims in full, and for the Debtor to emerge from the Chapter 11 Case as a financially healthy, viable going concern.

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A limited number of laws, regulations and decisions administered by the CPUC would effectively prohibit, veto or nullify the restructuring transactions necessary to implement the Plan.

•

Application of the specific CPUC laws to the Plan would effectively veto an effective reorganization within a reasonable time frame, and therefore stand as an obstacle to the objectives of Congress in enacting the Bankruptcy Code.

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93

See the Bankruptcy Court’s February 7 Decision at 30, agreeing that the Bankruptcy Code “would preempt a state regulator’s absolute veto power over bankruptcy restructuring.”

94

The primary purpose of Chapter 11 of the Bankruptcy Code is to foster the successful reorganization of troubled companies and place them on a sound footing going forward. If a reorganization plan is hobbled by requirements of state law that make such a restructuring impossible, or that make it likely that a liquidation or further reorganization will follow, such state laws should and will be preempted. See 11 U.S.C. § 1129(a)(11):

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Under Section 8 of the FPA for approval for Debtor transfer of all of its FERC-licensed hydroelectric projects and licenses to subsidiaries of Gen and the GenSub LLCs and certain transmission-only licenses and certain other transmission line segments to ETrans (see Exhibit D-6.1 and D-6.2, attached hereto).

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Under Section 203 of the FPA for the transfer of certain FERC-jurisdictional assets to ETrans and Gen or the GenSub LLCs and for the indirect transfer of the membership interests in ETrans and Gen, the spin-off of Reorganized Debtor from Parent and related matters (see Exhibit D-1.1, attached hereto);

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Under Section 204 of the FPA for approval of issuances of securities and assumptions of liability by Debtor, Gen and ETrans as required by the Plan (see Exhibit D-4, attached hereto);

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Under Section 205 of the FPA for acceptance of several new contracts which define the relationships necessitated by the creation of Gen and ETrans. These include the PSA pursuant to which Gen will sell power to Reorganized Debtor, various interconnection agreements between ETrans and Gen, between ETrans and Reorganized Debtor and between Gen and Reorganized Debtor, the Back-to-Back Agreement providing for

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Under Section 7 of the NGA, Debtor, GTrans, GTN and Stanpac have sought authorizations permitting: (1) Debtor to extend its existing gas transmission system across the California-Oregon border to a point at which it would interconnect with GTN and another interstate pipeline, Tuscarora Gas Transmission Company near Malin, Oregon, by acquiring approximately three miles of interstate pipeline from GTN; (2) Debtor to transfer to GTrans and GTrans to acquire Debtor’s extended gas transmission system and GTrans to operate that system as an open-access interstate pipeline; and (3) GTrans to provide services to Reorganized Debtor during a limited transition period in accordance with the Transportation and Storage Services Agreement that provides for the continuation of service to Reorganized Debtor’s gas distribution business under rates, terms and conditions that are essentially identical to Debtor’s existing CPUC-approved rates, tariffs, and contracts.

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In addition, Applicants are seeking declaratory orders that the proposed transaction does not violate Section 12 of the NGA or Section 305(a) of the FPA and that the GenSub LLCs are not public utilities under the FPA (see Exhibit D-1.1, attached hereto).

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