ML020460373
| ML020460373 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/05/2002 |
| From: | Chaset L State of CA, California Public Utilities Commission |
| To: | NRC/OCM |
| Byrdsong A | |
| Shared Package | |
| ML020500489 | List: |
| References | |
| +adjud/rulemjr200506, -nr, 50-275-LT, 50-323-LT, RAS 3882 | |
| Download: ML020460373 (230) | |
Text
EXHIBIT B I £ 4'
1 GARY M. COHEN, SBN 117215 j * ." 9.. o AROCLES AGUILAR, SBN 94753 2 MICHAEL M. EDSON, SBN 177858 CALIFORNIA PUBLIC UTILITIES COMMISSION -r, * ' 7 3 505 Van Ness Avenue San Francisco, California 94102 4 Telephone: (415) 703-2015 Facsimile: (415) 703-2262 5 U'-" -""J, ALAN W. KORNBERG F3 ,.,4..
6 WALTER RIEMAN, SBN 139365 BRIAN S. HERMANN L 7 ERIC TWISTE MARC F. SKAPOF 8 PAUL, WEISS, RIFKJND, WHARTON & GARRISON 1285 Avenue of the Americas 9 New York, New York 10019-6064 Telephone: 212-373-3000 10 Facsimile: 212-757-3990 11 Attorneys for Defendants, Appellees and Cross-Appellants 12 UNITED STATES DISTRICT COURT NORTHERN DISTRICT OF CALIFORNIA 13 SAN FRANCISCO DIVISION 14 In re Case No. 0 1-2490 VRW (Bankruptcy Case No. 01-30923 DM; 15 Adv. Proceeding No. 01-3072 DM)
PACIFIC GAS AND ELECTRIC COMPANY, a California corporation, 16 Chapter 11 Case Debtor.
17 Federal I.D. No. 94-0742640 18 PACIFIC GAS AND ELECTRIC COMPANY, 19 a California corporation, 20 Plaintiff, Appellant, and Cross-Appellee, 21 - against CROSS-APPELLANTS' REPLY BRIEF AND OPPOSITION TO SUPPLEMENTAL 22 REQUEST FOR JUDICIAL NOTICE BY CALIFORNIA PUBLIC UTILITIES COMMISSION, and LORETTA M. LYNCH, HENRY M. DUQUE, APPELLANT AND CROSS-APPELLEE 23 PACIFIC GAS AND ELECTRIC RICHARD A. BILAS, CARL W. WOOD, and GEOFFREY F. BROWN, in their official capacities as COMPANY 24 Commissioners of the California Public Utilities 25 Commission, 26 Defendants, Appellees,
- =
and Cross-Appellants.
27 28 (ROSS AIPPEI.ANTS" OP'NING BRIEFAND APPEIIJ.EES" OI'P(SIrION 1( API'EI I ANrI"S OPENING BRIEF
TABLE OF CONTENTS Pae 2
PR ELIM INARY STATEM ENT ..................................................................................................... 1 3
STATEM ENT O F FACTS ....................................................................................................... 3 4
A RG U M EN T .................................................................................................................................. 3 5
THE ELEVENTH AMENDMENT BARS THIS PROCEEDING ............................................ 3 6
A. The Bankruptcy Court Incorrectly Determined that PG&E's Claims Against the 7 Individual Commissioners Could Proceed Under the Doctrine of Ex Parte Young..... 4 8 1. PG&E Did Not Seek Prospective Relief to Remedy Any Alleged Actual and 9 Ongoing Violation of Federal Law by the Commissioners ..................................... 4 10 2. The Bankruptcy Court Incorrectly Determined that There Was a Sufficient "Threat" that the Commissioners Would Take Action to Enforce the True-up ...... 9 11
- 3. The Young Doctrine Does Not Apply Because the Relief Requested by PG&E 12 Would Drastically Interfere with California's "Special Sovereignty Interest" in Energy Crisis ........................... 1 13 Using its Police Power to Manage the Statewide B. The Court Should Reject PG&E's Argument, RaisedThat for the First Time on 14 Appeal And Unsupported in the Appellate Record, the Commission 11 15 Waived Its Sovereign Immunity in This Proceeding .............................................
16 1. The Court Should Not Consider PG&E's Waiver Argument Because It Was Raised For the First Time On Appeal .............................................................. 11 17
- 2. PG&E's Request for Judicial Notice Should be Denied Because It Would 18 Create New Disputed Issues of Fact That Should Not Be Resolved by this 12 19 Appellate Court in the First Instance .................................................................
in the First Instance 20 3. This Appellate Court Should Refrain From Undertaking the Highly Fact-Sensitive Inquiry Into Whether the Commission Waived Its Sovereign Im m unity .......................................................................................... 13 21 22 4. Even on the Merits, the Commission Did Not "Waive" Its Sovereign Immunity In Connection With the Claims Asserted 23 By PG& E In This Proceeding ............................................................................ 14 24 C O N C L U S ION ............................................................................................................................. 20 25 26 27 28 (ROSS.APIPELLANTS' OPENING BRIEF AND APPELI.FEF' OPPOSITION 10 API'EI.I.ANT'S OPENING 13RIEF
-I -
1 TABLE OF AUTHORITIES 2 CASES 3 ANR Pipeline Co. v. LaFaver, 150 F.3d 1178 (10th Cir. 1998) ............................................. 11 4 Agua Caliente Band of Cahuilla Indians v. Hardin, 223 F.3d 1041 (9th Cir. 2000),
cert. denied, 121 S. Ct. 1485 (200 1) ................................ .................. ............ 9, 10,11 5
(1998) ............. 3 6 Booth v. Maryland, 112 F.3d 139 (4th Cir. 1997), cert. denied, 524 U.S. 905 7 Children's Healthcareis a Legal Duty, Inc. v. Deters, 92 F.3d 1412 (6th Cir. 1996) .............. 9 8 Commonwealth of Va. Dep't of Med. Ass't Servs. v. Shenandoah Realty Partners,L.P.
(In re Shenandoah Realty Partners,L.P.), 248 B.R. 505 (W.D. Va. 2000) .............. 17, 18, Cir. 1998) ........................ 17, 18, 10 Confederated Tribes v. White (In re White), 139 F.3d 1268 (9th 11 Elliot v. Hinds, 786 F.2d 298 (7th Cir. 1986) .......................................................................... 6 12 Exparte Young, 209 U .S. 23 (1908) ..................................................................................... passim 13 FirstAm. Title Ins. Co. v. Naegele, 35 F.2d 1072 (9th Cir. 1994) ............................................ 12 14 First Union Nat'l Bank v. MCA Fin. Corp. (In re MCA Fin. Corp.),
15 237 B.R . 338 (Bankr. E.D . M ich. 1999) .................................................................... 17, 18 16 Gardnerv. New Jersey, 329 U.S. 565 (1947) .......................................................................... 19 17 Hankins v. Finnel, 964 F.2d 853 (8th Cir. 1992) ................................................................... 17, 18 18 Hill v. Blind Industry & Services of Maryland, 179 F.3d 754 (9th Cir. 1999) ........................ 17 19 Idaho v. Coeur D'Alene Tribe, 521 U.S. 261 (1997) .............................................................. 11 20 223 Cir. 1981) ........................... 12 Ken/on Prods. & Dev. Co. v. United States, 646 F.2d
(_5h 21 13, 14, 15 22 Lazar v. California,237 F.3d 967 (9th Cir. 2001) ...........................................................
23 M illiken v. Bradley, 433 U .S. 267 (1977) ................................................................................. 8 24 in re M itchell, 209 F.3d 1111 (9th Cir. 2000) .................................................................... 14,16,17 25 Nantucket Investors II v. Cal. Fed. Bank (In re Indian Palms Assocs., Ltd.),
12 26 6 1 F.3d 197 (3d C ir. 1995) ..........................................................................................
27 Papasan v. A llain, 478 U .S. 265 (1986) ............................................................................ 5, 6,7,8 28 Pitts v. Ohio Departmentof Taxation (In re Pitts), 241 B.R. 862 (Bankr. N.D. Ohio 1999) ...... 17 CROSS-APPEII.ANTS' REPI.Y BRIEF AND OPPOSITION TO REQIUEST FPOR !UIDICIAI NOrIcE
-ii -
1 1Seminole Tribe of Floridav. Florida,517 U.S. 44 (1996) ..................................................... 19 2
2 10 Assocs. v. Pryor, 180 F.3d 1326 (1 1th Cir. 1999) ...........................................
3Summit Med.
3 1, 5 4United Mexican States v. Woods, 126 F.3d 1220 (9th Cir. 1997) ..........................................
4 5United States v. Patrin,575 F.2d 708 (9th Cir. 1978) ................................................................. 11 5
6 252 F.3d 316 (4th Cir. 2001) .................. 9, 10 6 Waste Management Holdings, Inc. v. Gilmore, 7 F.3d 1241 (9th Cir. 1999) ................ 14 7 Yakima Indian Nation v. Wash. Dep't of Revenue, 176 8
8 STATUTES 9
9 12 Fed. R . Evid. 201(b) ...............................................................................................
10 10 11 11 12 12 13 13 14 14 15 15 16 16 17 17 18 18 19 19 20 20 2l 21 22 22 23 23 24 24 25 25 26 26 27 27 28 28 CROSS-API'PEL.I.AN IS' REPLY BRIEF AND OPPOSITION TO REQUEST FOR JuI)DICIAL NOTIC-E
- iii -
1 PRELIMINARY STATEMENT 2 In its opening brief, the Commission showed that PG&E's claims against the 3 Commissioners do not fit within the narrow exception to Eleventh Amendment immunity created 4 by Ex parte Young, 209 U.S. 23 (1908). PG&E's opposition brief on appeal ("PG&E Br.")
5 offers no persuasive reason for this Court to reach any different conclusion.
6 1. Actual and Ongoing Violation. PG&E barely defends the Bankruptcy 7 Court's application of the "actual and ongoing violation" requirement of the Young doctrine.
8 Instead, PG&E tries to recast a lawful prepetition action by the Commission (the adoption of the 9 True-up), which the Commission did not take any postpetition action to enforce, into an actual 10 and currently ongoing violation of federal law. The attempt does not succeed.
11 PG&E first claims that "if [the True-up's] implementation or enforcement would 12 violate the automatic stay, [the True-up] necessarily violates federal law." (PG&E Br. at 19.)
13 This is plainly wrong. In order to have availed itself of the Young doctrine, PG&E must have 14 shown an actual and currently ongoing violation of law by the Commissioners at the time PG&E 15 filed its adversaryproceeding, not at some hypothetical future time. Whether "implementation 16 or enforcement" of the True-up in the future, had it ever happened, might then have violated 17 federal law does not mean that the Commission had violated federal law at the time PG&E filed 18 its adversary proceeding. On that critical issue, PG&E has nothing to say.
19 PG&E next claims that a violation of federal law in the past is sufficient to trigger 20 the actual and ongoing violation requirement. Even if this were true, it would not matter in this 21 case because PG&E did not allege any violation of federal law by the Commissioners, either past 22 or present. But PG&E is also wrong on the law. A past violation of federal law is not sufficient 23 for purposes of the Young doctrine. (Comm. Br. at 16-18 & n.8; infra at 4-5.) The Young 24 doctrine does not apply where "federal law has been violated at one time or over a period of time 25 in the past." United Mexican States v. Woods, 126 F.3d 1220, 1223 (9th Cir. 1997).
26 Finally, PG&E suggests that the Commission violated federal law on an actual 27 and ongoing basis merely because the True-up "imposed a duty on PG&E." (PG&E Br.
28 NOTICF CROSS -APPEI.IANI ; RENI Y RRIEF AND OPPOSITION TO REQUIEST FOR JUDICIAl.
- I-
I at 19-20.) PG&E is wrong. PG&E does not cite a single case, and the Commissioners are not 2 aware of any, that found any "imposed" or "unenforced" duty on the plaintiff sufficient to 3 establish an actual and ongoing violation by the defendant state officials. In all the cases, the 4 only question is whether the state officials are engaging in conduct that allegedly violates federal 5 law. Indeed, the cornerstone of the Young doctrine is the fiction that unlawful conduct by state 6 officials is not conduct of the state, and therefore is not shielded by the state's sovereign 7 immunity. Without any such unlawful conduct by state officials, there is no basis for application 8 of Young, regardless of any "imposed" or "unenforced" duties on the plaintiff.
9 Here, PG&E did not allege any unlawful conduct by the Commissioners. PG&E 10 alleged only that the automatic stay, once PG&E filed for bankruptcy, would have prevented 11 certain hypothetical postpetition actions by the Commissioners to "implement or enforce" the 12 True-up. PG&E's allegation that the automatic stay would have prevented certain postpetition 13 actions to enforce the True-up did not make the True-up itself allegedly "illegal" in any sense.
14 Similarly, any supposed "duty" that the True-up imposed upon PG&E did not make the True-up 15 illegal or convert any lawful prepetition actions by the Commission into postpetition actions in 16 violation of the automatic stay. In the end, PG&E merely contends that a lawful prepetition act 17 by the Commission had continuing consequences for PG&E. The Supreme Court has held that 18 Young does not apply in such circumstances. (Infra at 7.)
19 2. Waiver. PG&E contends, for the first time on appeal, that the 20 Commission has waived its sovereign immunity. The Court should reject that argument:
21 First, presumably because most of the acts constituting the alleged waiver had not 22 occurred at the time of the Bankruptcy Court's decision, PG&E did not contend before the 23 Bankruptcy Court that the Commission had waived its sovereign immunity. This appellate Court 24 should not consider any issues that were not considered by the Bankruptcy Court in the first 25 instance. PG&E's proper remedy would have been to bring a motion before the Bankruptcy 26 Court, under Rule 60(b) of the Federal Rules of Civil Procedure as incorporated by Federal Rule 27 of Bankruptcy Procedure 9024, for example, respecting any claims that the Commission has 28 waived its sovereign immunity. Second, there is no support in the record for any waiver by the CROSS-APPE1LAiI'S" REPLY BRIEF AND OPPOSITION TO REQLIF.ST FOR JIJI)ICIAI. NO(ICI-
I Commission. PG&E seeks instead to base its waiver argument on over 70 new documents that 2 PG&E hopes to introduce by way of request for judicial notice. The Court should deny PG&E's 3 request for judicial notice, because it would introduce disputed issues of fact that have not been 4 developed nor considered by a trial court. Third, this Court should not undertake the highly fact 5 sensitive waiver inquiry without the benefit of consideration by the Bankruptcy Court in the first 6 instance, and without the benefit of a full factual record, developed in the context of adversarial 7 litigation before a trial court. And finally, PG&E's argument that the Commission waived its 8 sovereign immunity is incorrect on the merits.
9 STATEMENT OF FACTS 10 PG&E claims that the Commission has been "all over the lot" on whether the II Accounting True-up creates a "defense" to PG&E's Rate Case. (PG&E Br. at 16 n. 16.) The 12 Commission has maintained, from the beginning, that the question of what effect (if any) the 13 True-up has on the Rate Case is a question to be decided in the Rate Case. PG&E acknowledges 14 that the validity of the True-up is not an issue in this adversary proceeding. (PG&E Br. at 16).
15 ARGUMENT 16 THE ELEVENTH AMENDMENT BARS THIS PROCEEDING 17 PG&E claims that it brought this adversary proceeding to prevent the 18 Commission from asserting a "defense" to the Rate Case. (PG&E Br. at 16.) If that is true, then 19 this proceeding cannot proceed in light of the Eleventh Amendment. See Booth v. Maryland, 20 112 F.3d 139, 143 (4th Cir. 1997) ("[Elnjoining a state from asserting a particular defense in 21 some future federal action would be precisely the sort of inroad on state sovereignty that the 22 Eleventh Amendment forbids."), cert. denied, 524 U.S. 905 (1998).
23 As the Commission pointed out in its opening brief, the Court need not determine 24 whether the Commission or the Commissioners are entitled to assert sovereign immunity because 25 PG&E's appeal can be easily disposed of on its merits. (Comm. Br. at 12-13.)
26 27 28 CROSS-APPELI.ANTS' REP! Y BRIEF AND OPPOSITION TO REQUEST FOR JUI)ICIAI] NO1iCI-3
I A. The Bankruptcy Court Incorrectly Determined that PG&E's Claims Against the Individual Commissioners 2 Could Proceed Under the Doctrine of Ex Parte Young 3 1. PG&E Did Not Seek Prospective Relief to Remedy Any Alleged Actual and Ongoing Violation of Federal Law by the Commissioners 4
In its opening brief, the Commissioners showed that the Bankruptcy Court did not 5
of federal law" requirement of Ex parte Young 6 properly apply the "actual and ongoing violation 7 and improperly permitted this action to proceed against the Commissioners. (Comm. Br.
8 at 16-18.) Rather than defend the Bankruptcy Court's application of Young, PG&E tries to 9 "reinvent" the adoption of the Accounting True-up--which PG&E acknowledges was a lawful and currently "ongoing" violation of 10 prepetition action by the Commission-into an "actual" 11 federal law. PG&E fails.
12 PG&E first claims that "if [the True-up's] implementation or enforcement would 13 violate the automatic stay, [the True-up] necessarily violates federal law." (PG&E Br. at 19.)
But that conclusion does not follow at all. PG&E's allegation that the automatic stay might have 14 amount to an allegation that the True-up was 15 suspended enforcement of the True-up does not itself "illegal" by reason of the automatic stay. After all, the fact that the automatic stay may 16 entity for breach of contract hardly means 17 operate to suspend a plaintiff's fight to sue a bankrupt 18 that underlying state contract law is "illegal" by reason of the stay. Furthermore, the Young 19 doctrine is not predicated on any "illegality" of a law in the abstract, but on the specific conduct 20 of state officials taken to enforce the law. Whether some hypothetical "implementation or 21 enforcement" of the True-up by the Commission in the future might then have violated federal 22 law says nothing about whether the Commission had violated federal law at the time PG&Efiled its adversary proceeding.
23 24 PG&E next claims that the Eleventh Amendment "permits plaintiffs to bring an 25 action to redress an ongoing and prospective violation of rights caused by defendants' pre 26 litigation C conduct." (PG&E Br. at 20.) Although PG&E cannot bring itself to state the
,7 proposition openly, apparently PG&E is suggesting that a past violation of rights can suffice to establish a presently ongoing violation for purposes of the Young doctrine. First of all, in the 28 TI-'
CROSqS-APPELI.ANTS' REPLY BRIEF AND OPPOSITION TO REQli-'b T FOR JiII)ICIAI. NC);
4
I proceeding below PG&E did not allege even a past violation of rights by the Commissioners, so 2 whether or not a past violation is sufficient is irrelevant. As explained, PG&E did not contend 3 (and could not possibly have contended) that the prepetition True-up was unlawful under the 4 automatic stay, which is effective only postpetition. (Comm. Br. at 18-19.) PG&E is also wrong 5 on the law. A past violation of federal law is not a currently ongoing violation of law for 6 purposes of Young. (Comm. Br. at 14.) In the words of the Ninth Circuit, the Young doctrine 7 does not apply where "federal law has been violated at one time or over a period of time in the 8 past." United Mexican States v. Woods, 126 F.3d 1220, 1223 (9th Cir. 1997); accord Papasanv.
9 Attain, 478 U.S. 265, 277-78 (1986) ("Young has been focused on cases in which a violation of 10 federal law by a state official is ongoing as opposed to cases in which federal law has been 11 violated at one time or over a period of time in the past. ... ").
12 Finally, PG&E suggests that the Commissioners are violating federal law on an 13 actual and ongoing basis merely because the True-up "imposed a duty on PG&E." (PG&E Br.
14 at 19-20.) According to PG&E, a "pending but unenforced duty" imposed upon PG&E is 15 sufficient to trigger Young. (PG&E Br. at 21.) But PG&E does not explain how any "duty" 16 imposed upon PG&E would be inconsistent with automatic stay, which generally bars an "action 17 or proceeding" against the debtor or an "act" to exercise control over the debtor's estate.
18 (Comm. Br. at 3443.) PG&E is wrong in any event. PG&E does not cite any authority, and 19 there is none, that an "imposed" or "unenforced" duty on the plaintiff is sufficient to establish an 20 actual and ongoing violation by the defendant state officials. The sole question is always 21 whether the state officials are engaging in conduct that allegedly violates federal law. As the 22 Commissioners have shown, the entire Young doctrine is predicated on the fiction that illegal 23 acts by state officials are not actions of the State, and therefore not protected by the State's 24 sovereign immunity. (Comm. Br. at 17-18.) In the absence of any such illegal conduct, the 25 actions by the state officials are fully protected by sovereign immunity, and there is thus no basis 26 to permit the officials to be sued in federal court. For this reason, any "duty" that may have been 27 imposed on PG&E is completely irrelevant for purposes of Young. The critical inquiry is 28
('ROSý-APPE-IANTIS REPLY BRIEF AND OPPOSITION ro RFQI[JFST FOR IiII)ICIAI NOTICF I whether the Commission had taken any actual conduct that amounted to an ongoing violation of 2 federal law.
3 In the Bankruptcy Court, PG&E did not allege any such unlawful conduct. At have 4 most, PG&E alleged that the automatic stay, once PG&E filed for bankruptcy, would or 5 prevented certain hypothetical postpetition actions by the Commissioners to "implement certain 6 enforce" the True-up. But just because the automatic stay might have prevented convert any 7 postpetition actions to enforce the True-up did not make the True-up "illegal" or of the 8 lawful prepetition actions by the Commission into postpetition actions in violation PG&E did not 9 automatic stay. Similarly, just because the True-up imposed some "duty" upon engaged in a 10 make the True-up illegal or create a basis for finding that the Commission had a litigant cannot 11 continuing violation of the automatic stay. As the Supreme Court has indicated, act in the past 12 come within Young by alleging merely (as PG&E does here) that a State official's 13 has continuing consequences for the plaintiff. (Infra at 7, discussing Papasan.)
14 The two "well-established examples" that PG&E relies on have no application continued confinement 15 here. PG&E mentions habeas cases, which challenge a prison warden's 20.) There, the 16 of a prisoner by reason of an allegedly unlawful conviction. (PG&E Br. at imprisoning a human 17 alleged ongoing violation is the warden's affirmative and ongoing act of example relied 18 being. Similarly, an employee discharged in violation of federal law (the other
[because] as long as the 19 upon by PG&E) can assert that the discharge "is a continuing violation acts in what is claimed to 20 state official keeps him out of his allegedly tenured position the official 298, 302 21 be derogation of [plaintiff s] constitutional rights." Elliot v. Hinds, 786 F.2d allege, and could not 22 (7th Cir. 1986) (cited by PG&E at 20). Here, in contrast, PG&E did not current parallel 23 have alleged, that the automatic stay imposed on the Commissioners any failure to take that 24 obligation to take some affirmative step, and that that the Commissioners' 25 affirmative step therefore constituted an ongoing violation of federal law.
to support 26 The two cases that PG&E cites in a footnote (at 20 n. 19) not only fail of federal law by the 27 its theory, they show that PG&E did not allege any ongoing violation against State officials. The first 28 Commissioners here. In Papasan,plaintiffs asserted two claims JEST FOR ILIO)lAID NOTICE CROSS -API'PEI.ANTS' REPLY BRIEF AND OPPOSITION TO REQU 1 claim rested on allegations that in the past, Mississippi officials had improvidently disposed of 2 federal trust lands to be used to support public schools, and that as a result, schoolchildren had 3 been deprived of adequate current school funding in violation of federal trust law. Plaintiffs 4 sought an injunction requiring Mississippi officials to meet an alleged continuing obligation to 5 provide adequate funding. The Supreme Court held that this claim was barred by the Eleventh 6 Amendment and did not fit within the Young exception. The Court explained:
7 We have.., described certain types of cases that formally meet the Young requirements of a state official acting inconsistently with federal law but that 8 stretch that case too far and would upset the balance of federal and state interests that it embodies. Young's applicability has been tailored to conform as precisely 9 as possible to those specific situations in which it is necessary to permit the federal courts to vindicate federal rights and hold state officials responsible to the 10 supreme authority of the United States. Consequently, Young has been focused on cases in which a violation of federal law by a state official is ongoing as 11 opposed to cases in which federal law has been violated at one time or over a period of time in the past, as well as on cases in which the relief against the state 12 official directly ends the violation of federal law ....
13 Papasan,478 U.S. at 277-78 (internal quotations and citations omitted).
14 Based on these principles, the Court held that the Papasanplaintiffs' first claim, 15 although formally based on an alleged "continuing obligation on the part of the trustee" officials, 16 was really an action alleging "ongoing liability for past breach of trust," and therefore fell 17 outside Young. Id. at 280 (emphasis added).
18 Papasanthus demonstrates that a litigant cannot come within Young by alleging 19 merely (as PG&E does here) that a State official's act in the past has continuing consequences 20 for the plaintiff. What counts is whether the State official is actually committing a continuing and 21 violation of federal law. This is why PG&E's insistence that the True-up imposed current 22 future obligations on PG&E is, for purposes of Young, completely beside the point. PG&E 23 brought no claim in this action that the Commissioners acted unlawfully when they promulgated 24 the True-up, and PG&E did not coherently claim that the True-up "violated" federal law. PG&E law, and 25 claimed only that "implementation" or enforcement of the Order was stayed by federal ongoing 26 that claim cannot be cast as an accusation that the Commissioners were engaged in an 27 violation of federal law.
28 (ROSS -APPEI-I.ANIS' REPILY BRIFF ANDOPPOS!IION TORFQ-UFS'r FOR Jt II)ICIAI. NOTICF 7
I Papasansustained plaintiffs' second claim against Eleventh Amendment attack.
2 In that claim, plaintiffs alleged that the defendant Mississippi officials were currently distributing 3 the income from certain lands and trusts unequally among Mississippi school districts, to the 4 detriment of schools in certain counties. This claim, the Supreme Court held, focused on "the 5 present disparity in the distribution of the benefits of state-held assets, and not the past actions of 6 the State." 478 U.S. at 282 (emphasis added). PG&E therefore misdescribes this claim when it 7 asserts that the Court upheld a claim challenging disparate funding "due to State's sale of 8 property held in trust years earlier." (PG&E Br. at 20 n. 19.) Rather, the Court upheld the equal 9 protection claim because it challenged current school funding decisions by State officials as an 10 ongoing violation of federal law, and did not focus on the past sales of trust property.
11 PG&E also cites Milliken v. Bradley, 433 U.S. 267 (1977). Milliken, a school 12 desegregation case, does not support PG&E's position any more than Papasandoes. As a matter 13 of substantive federal equal-protection law, if a school district has imposed legally mandated 14 segregation by race, the school district has an affirmative, ongoing obligation to wipe out the 15 vestiges of that discrimination. The Supreme Court held that Young therefo-e permitted a federal 16 court to order Detroit school officials to take prospective measures to remedy their ongoing and 17 continuing violation of their federal duty to desegregate:
18 The decree requires state officials... to eliminate a de jure segregated school system. More precisely, the burden of state officials is that set forth in Swann-to 19 take the necessary steps "to eliminate from the public schools all vestiges of state imposed segregation." The educational components, which the District Court 20 ordered into effect prospectively, are plainly designed to wipe out continuing conditions of inequality ....
21 Milliken, 433 U.S. at 289-90 (emphasis added, internal citations omitted).
22 Contrary to PG&E's suggestion, therefore, Milliken is not a case where a State 23 official merely took some past action that then disadvantaged plaintiffs in the present. The State 24 officials there were engaged, the Supreme Court held, in an ongoing violation of their 25 substantive Constitutional duty to eliminate "continuing conditions of inequality."
26 27 28 CROSS-APPE.IANIS' REPILY BRIEF ANI) OPPOSITION rO RFQUIJRST FOR JUDICIAL NOTIC
- 2. The Bankruptcy Court Incorrectly Determined that There Was a Sufficient 1 "Threat" that the Commissioners Would Take Action to Enforce the True-up 2 As the Commission has shown, the Bankruptcy Court improperly determined that 3 this action could proceed under Young based upon some "threat" that the Commission would 4 implement or enforce the True-up. (Comm. Br. at 20-21.) By that phrase, the Bankruptcy Court 5 did not mean that the Commissioners had actually threatened in any way to take enforcement 6 action arguably barred by the automatic stay. The Bankruptcy Court meant only that in the 7 nature of things, the Commissioners could or might enforce the True-up. That is insufficient.
8 See Comm. Br. at 20-21; Children'sHealthcareis a Legal Duty, Inc. v. Deters,92 F.3d 1412, 9 1415 (6th Cir. 1996) ("Young does not apply when a defendant state official has neither enforced 10 nor threatened to enforce the allegedly unconstitutional state statute.") (citing voluminous II authority); Young, 209 U.S. at 155-56 ("[O]fficers of the state... who threaten and are about to 12 commence proceedings... may be enjoined by a federal court.") (emphasis added).
13 PG&E relies on three cases, none of which is applicable here. First, PG&E cites 14 Agua Caliente Band of CahuillaIndians v. Hardin, 223 F.3d 1041, 1045 (9th Cir. 2000), cert.
15 denied, 121 S. Ct. 1485 (2001). The Commissioners distinguished that case in its opening brief.
16 (Comm. Br. at 21 n.I 1 & n.12.) PG&E does not even attempt to explain in its appeal brief why 17 the Commissioners' treatment of Agua Caliente is wrong. PG&E claims only that Agua Caliente 18 suggests a "pending but unenforced duty" imposed upon PG&E is sufficient to trigger Young.
19 But the case suggests nothing of the sort. As the Commissioners have explained, Young was 20 triggered in Agua Caliente not by any "pending unenforced duty," but because the plaintiffs had 21 alleged an actual and ongoing violation of federal law, in that state officials had issued tax 22 assessments in alleged violation of federal law. Here, PG&E did not allege any similar unlawful 23 actions.
24 The other authority cited by PG&E is equally wide of the mark. In Waste 25 Management Holdings, Inc. v. Gilmore, 252 F.3d 316 (4th Cir. 2001), there was no issue raised 26 concerning whether a "threat" of enforcement was sufficient under Young. And, in any event, 27 the content of the state statute at issue was allegedly itself contrary to federal law, just as in Agua 28 NOlICI CROSS -APPELLANTS' REPLY BRIFF AND OPPOSITION TO RI-QlIJS I FOR JUD'ICIAl.
I Caliente, whereas here PG&E did not make, and could not make, any similar allegation against 2 the content of the True-up.
3 The final case relied upon by PG&E is in Summit Med. Assocs. v. Pryor, 4 180 F.3d 1326 (1 th Cir. 1999). That case is distinguishable on several grounds. First, in 5 Summit the state officials had affirmatively expressed, in writing, their intent to enforce the 6 statute against those violating it, and there was no question given the circumstances that the 7 officials would carry through on that threat. See id. at 1339. The narrow issue in Summit was 8 not whether a "threat" of enforcement was sufficient, because there clearly was such a threat, but 9 whether Young required the state official to threaten to enforce the statute against the specific 10 plaintiffs in the case. Here, the Commission did not express any intention to enforce the 11 True-up. (Comm. Br. at 19 n.10 & at 21 n. 12.) Second, in Summit the content of a state statute 12 was itself allegedly contrary to federal law, as was true in Agua Caliente and Waste 13 Management, but as is not true here. Third, the statutes at issue in Summit were criminal 14 statutes, enacted in connection with abortion protests, which imposed severe penalties (up to ten 15 years in jail) for a violation. See id. at 1339-40.
16 3. The Young Doctrine Does Not Apply Because the Relief Requested by PG&E Would Drastically Interfere with 17 California's "Special Sovereignty Interest" in Using its 18 Police Power to Manage the Statewide Energy Crisis 19 PG&E understates the relief that this proceeding seeks. As explained in the Commission's opening brief, the sweeping relief that PG&E seeks would upset the entire balance 20 between competing interests that California has struck as a centerpiece of the statewide utility 21 is asking the Court to displace 22 deregulation. (Comm. Br. at 22-24.) In a very real sense, PG&E 23 the State's central judgments on this deregulation in favor of PG&E's own. The affront to 24 California's sovereignty is not just that the relief PG&E seeks "implicates" a core area of state implicates that core area of 25 sovereignty, the regulation of public utilities, but that the relief against California itself. Under 26 sovereignty so intrusively that PG&E's action is effectively 27 these circumstances, the relief PG&E requests in this proceeding would infringe upon California's "special sovereign interest" in a way comparable to the infringement at issue in 28 CROS',-APPEI .I.ANTS' REPLY BRIEF AND OPPOSIT ION TO REQIJE5S I iFOR H IDICIAI. NOTICE I()
1 Idaho v. Coeur D'Alene Tribe, 521 U.S. 261, 270 (1997). See id. at 281-283, 289, 296 2 (O'Connor, J., concurring) (Young inapplicable where "it simply cannot be said that the suit is 3 not a suit against the state"); Agua Caliente, 223 F.3d at 1045-1048; ANR Pipeline Co. v.
4 LaFaver, 150 F.3d 1178, 1194 (10th Cir. 1998).
5 B. The Court Should Reject PG&E's Argument, Raised for the First Time on Appeal And Unsupported in the Appellate Record, 6 . That the Commission Waived Its Sovereign Immunity in This Proceeding 7 PG&E contends that the Commission has waived its sovereign immunity. The 8 Court should reject that argument for several independent reasons:
9 First, PG&E did not raise any waiver contention in the Bankruptcy Court. Most 10 of the acts constituting the alleged waiver had not occurred at the time of the Bankruptcy Court's 11 decision. As we show below, this appellate Court should not consider any issues that the 12 Bankruptcy Court did not first consider. Second, there is no support in the record for any waiver 13 by the Commission. Knowing this, PG&E seeks to base its waiver argument on over 70 new 14 documents, totaling a thousand or so pages, that PG&E seeks to introduce by way of request for 15 judicial notice. As we show below, PG&E's request for judicial notice should be denied. Third, 16 this appellate Court should not undertake the highly fact-sensitive inquiry into whether the 17 Commission waived its sovereign immunity without the benefit of consideration by the 18 Bankruptcy Court, and without the benefit of a fully developed factual record. And finally, on 19 the merits PG&E's argument that the Commission waived its sovereign immunity is incorrect.
20 1. The Court Should Not Consider PG&E's Waiver Argument Because It Was Raised For the First Time On Appeal 21 "As a general rule, a federal appellate court does not consider an issue not passed 22 708, 712 (9th Cir. 1978) (internal quotations 23 upon below." United States v. Patrin, 575 F.2d omitted). Although there are exceptions to this rule, none is applicable here.' PG&E should 24 25 1 An appellate court may consider an issue raised for the first time on appeal where the new the factual record 26 issue "is purely one of law and either does not affect or rely upon developed by the parties or the pertinent record has been fully developed." Id. (citations 27 omitted). As PG&E's newly raised waiver argument is highly fact-sensitive, and no factual record has been developed at all, that exception cannot apply. An appellate court, if the it "has first come to light 28 interests of justice so demand, also may consider a new issue where (continued on next page)
CROSS -A'PEI.LAN"S' REPLY BRIEF AND OPPOSITION TO REQL 1S1 FO(R JUD11)ICIAL. NOTICE
- II -
have that the 1 have brought a motion before the Bankruptcy Court respecting any claims it may bankruptcy 2 Commission has waived its sovereign immunity. PG&E does not dispute that its claims 3 case is still pending, and, therefore the Bankruptcy Court still has jurisdiction to hear any 4 to waiver.
5 2. PG&E's Request for Judicial Notice Should be Denied Because It Would Create New Disputed Issues of Fact That Should Not 6 Be Resolved by this Appellate Court in the First Instance 7 The appellate courts generally deny requests for judicial notice that are designed See FirstAm. Title Ins.
8 to support issues or legal theories that were not raised in the court below.
9 Co. v. Naegele, 35 F.2d 1072 at **3 ( 9 1h Cir. 1994) (unpublished opinion).
10 Here, PG&E has brought just the sort of request for judicial notice that appellate that was not 11 courts will deny: a request to introduce facts to support a new legal theory the record on appeal.
12 considered by the court below, and otherwise has absolutely no support in Assocs., Lid.), 61 F.3d 197, 13 See id.; Nantucket Investors 1I v. Cal. Fed. Bank (In re Indian Palms "unfair to a party to do 14 205 (3d Cir. 1995) (appellate court should not take judicial notice where 15 Kemlon Prods. & Dev. Co. v.
so" and would "undermine the trial court's factfinding authority");
16 United States, 646 F.2d 223, 224 (5th Cir. 1981).
"not subject 17 In addition, a court should take judicial notice only of facts which are at 205. Here, while 18 to reasonable dispute." Fed. R. Evid. 201(b); see Nantucket, 61 F.3d be subject to dispute, the waiver 19 perhaps the fact that a certain proof of claim was filed might not the face of the proof of 20 inquiry requires consideration of facts and circumstances beyond just the "aggregate set of 21 claim. As we show immediately below, the critical inquiry is whether 22 facts of PG&E's claims in this operative facts" of the proof of claim is the same set of aggregate the same. and would be 23 proceeding. The Commission disputes that these aggregate facts are The practical effect 24 entitled to develop and submit its own evidence to support that contention.
25 law..." Id. (emphasis 26 dunng the pendency of the appeal because of a recent change in the any "recent change in the law." Although added). PG&E does not claim that there has been developments, the exception does not 27 PG&E claims that there have been some new factual cover new factual developments.
28 28 FOR JUDICIAL NOfIXIT CROSS-AI'P._AN I SAREPLY BRIFF AND OPPOSITION TO REQUEST
- 1I -
I of granting PG&E's request for judicial notice, therefore, would be to invite a dispute over 2 contested facts that the parties have not had any opportunity to develop, and that the Bankruptcy 3 Court has not considered in the first instance. The function of an appellate court is not as a trier 4 of fact, let alone a trier of facts that are not part of the record on appeal and have not been 5 developed by the parties.
6 3. This Appellate Court Should Refrain From Undertaking in the First Instance the Highly Fact-Sensitive Inquiry Into 7 Whether the Commission Waived Its Sovereign Immunity 8 PG&E has identified a number of purported proofs of claim filed by state 9 agencies, only one of which was filed by the Commission. These proofs of claim have nothing 10 to do with PG&E's claims against the Commission in the proceeding below, namely 11 "implementation or enforcement" of the True-up. PG&E suggests that because these claims 12 have been filed, the Commission has waived its sovereign immunity against any claim that 13 PG&E might bring. But filing a proof of claim will not "waive" sovereign immunity with 14 respect to any claim that the debtor might assert against the state. To the contrary, "when a state 15 files a proof of claim against a debtor, it waives its Eleventh Amendment ii; munity with respect 16 to the adjudication of that claim." Lazar v. California (In re Lazar), 237 F.3d 967, 977 (9th Cir.
17 2001) (emphasis added). Moreover, a proof of claim filed by one state agency does not 18 automatically "waive" the sovereign immunity of another state agency. See id. at 979 n. 13.
19 The inquiry into whether a state agency has "waived" its sovereign immunity is 20 highly fact-sensitive. As the Ninth Circuit has held, when a state files a proof of claim in a 21 bankruptcy, "the state waives its Eleventh Amendment immunity with regard to the bankruptcy 22 estate's claims that arise from the same transaction or occurrence as the state's claim." Id.
23 at 979. In order to determine whether a claim arises from the same "transaction or occurrence, 24 the Court must apply the highly fact-sensitive "logical relationship" test:
25 A logical relationship exists when the [plaintiff's claim] arises from the same aggregate set of operative facts as the initial [proof of] claim, in that the same 26 operative facts serve as the basis of both claims or the aggregate core of facts upon which the claim rests activates additional legal rights otherwise dormant in 27 the defendant.
28 Id. (citations omitted).
(ROSS.APPFII ANTS' REPI Y BRIFF ANDOPPOSITION TO REQIIFST FOR JIU)I( IAI NOTIC(F
-13
I The "logical relationship" test does not even end there. Since PG&E is arguing 2 that the Commission has "waived" its sovereign immunity primarily because other state agencies 3 have filed proofs of claim, the Court must also consider the relevant state laws concerning which 4 state agencies are authorized to submit which proofs of claim. See id. at 978 n. 11,979 n.13.
5 Here, PG&E has not provided any information that would assist the Court in 6 applying the "logical relationship" test to determine whether the proofs of claim it has identified 7 arise out of the same "transaction or occurrence" as PG&E's claims against the Commission in 8 this proceeding. PG&E has simply listed a number of proofs of claim that state agencies have 9 purportedly filed, without anything more than vague descriptions of what those proofs of claim 10 are for. The proofs of claim on their face describe what they seek in only the most general terms.
11 PG&E has not provided any information on the state laws concerning which agencies may file 12 which proofs of claim. Apparently, PG&E leaves it to the Court to perform, all by itself, the 13 enormous task of reading through a thousand pages of proofs of claim, and researching the state 14 law on filing proofs of claim, to determine whether any of the more than 70 claims submitted by 15 more than 20 state agencies "arise[ I from the same aggregate set of operative facts" as PG&E's 16 claims against the Commission in this proceeding. The Commission respectfully submits that 17 this fact-sensitive inquiry should not be entertained for the first time on appeal, without the 18 benefit of consideration by the Bankruptcy Court in the first instance, and especially because 19 there is no factual record concerning these proofs of claim.
20 4. Even on the Merits, the Commission Did Not "Waive" Its Sovereign Immunity In Connection With the Claims Asserted By PG&E In This Proceeding 21 22 In any event, PG&E's waiver claim has no merit. In the Ninth Circuit, "the test 23 for determining whether a State has waived its sovereign immunity is a stringent one." In re 24 Mitchell, 209 F.3d 1111, 1117 (9th Cir. 2000) (quotations omitted). A state "must unequivocally is (quotations omitted). "The state's consent...
25 express its consent to federal jurisdiction." Id.
26 effective only where stated by the most express language." Yakirna Indian Nation v. Wash.
the Cir. 1999). Under this "stringent" standard, 27 Dep't of Revenue, 176 F.3d 1241, 1245 (9th 28 actions by the Commission in the bankruptcy case, which were primarily directed at asserting its CROSS-APPE.I. ANTS' REPL Y BRIEF AND OPPOSITION TO REQUEST FOR JUDICIAL NOTICE 1 sovereign immunity, cannot possibly amount to the "unequivocal" expression of consent that is 2 required for a waiver. PG&E's contention to the contrary is further belied by the Commission's 3 Proof of Claim, which states unequivocally that its filing shall not be deemed or construed as a 4 waiver of, among other things, the Commission's rights under the Eleventh Amendment or 5 related principles of sovereign immunity.
6 . (a) The Commission Has Not "Waived" Its Sovereign 7 Immunity Through the Filing of any Proofs of Claim As explained above, the state "waives" its Eleventh Amendment immunity only 8
with regard to the debtor's claims "that arise from the same transaction or occurrence as the 9
state's claim." Lazar, 237 F.3d at 979.
10 The proofs of claim that PG&E has identified will not meet this test. They clearly 11 have nothing to do with the claim that PG&E asserts in this proceeding, against implementation 12 or enforcement of the True-up. See RJN Ex. 18 (permits and certifications); RJN Ex. 22 (clean 13 up and closure costs for hazardous waste facility); RJN Ex. 25 (loan for improvements to certain 14 facilities); RJN Exs. 26, 40, 72 (corporate taxes); RJN Ex. 27 (unpaid taxes); RJN Exs. 28-38 15 (utility relocation costs); RJN Ex. 39 (costs for prison installation); RJN Exs. 41-43 (lease 16 easements); RJN Exs. 44-54 (costs incurred in fighting fires); (RJN Exs. 58-60 (remediation 17 costs at certain sites); RJN Exs. 61, 64-66 (fees for two timber harvest plants, costs for fish 18 stocking program, and sea water monitoring services); RJN Ex. 62 (remediation costs at nuclear 19 plant); RJN Ex. 63 (fees for commercial coaches); RJN Exs. 67-71 (environmental clean-up 20 costs); RJN Ex.73 (clean-up costs). The only claims that are even conceivably connected, 21 however vaguely, to implementation or enforcement of the True-up are those few claims filed in 22 connection with the general electricity crisis. But even those proofs of claim hardly arise from 23 the same "transaction or occurrence" as implementation or enforcement of the True-up, unless 24 the Court were to stretch the test beyond recognition to include anything connected in some 25 general way to California's power crisis.
26 In addition, virtually all of the state agencies that filed the proofs of claim clearly 27 have nothing to do with PG&E's assault on the Commission's regulatory authority at issue in 28 CROSS -APPELLANTS' R Y KRIEF BI ANDiOpP*OSI TO RFQUES ITFOR JIUDICIAL NOTICL
)ION
I this proceeding. See RJN Ex. 18 (Department of Justice); RJN Exs. 26, 40, 72 (Franchise Tax 2 Board); RJN Ex. 27 (Board of Equalization); RJN Exs. 28-38 (Department of Transportation);
3 RJN Ex. 39 (Department of Corrections); RJN Exs. 41-43 (Department of General Services);
4 RJN Exs. 44-54 (Department of Forestry and Fire Protection); RJN Ex. 57 (Regents of the 5 University of California); RJN Exs. 58-60 (Department of Toxic Substances Control); RJN Exs.
6 61, 64-66 (Department of Fish and Game); RJN Ex. 63 (Department of Housing and Community 7 Development); RJN Exs. 67-71 (Water Quality Control Boards); RJN Ex. 73 (Water Resources 8 Control Board).
9 As for the lone proof of claim submitted by the Commission, it does not have 10 anything to do with "implementation or enforcement" of the True-up. See RJN Ex. 56 (claims in 11 respect of California Environmental Quality Act, user fees, WomenlMinorityfDisabled/Veteran 12 Business Enterprise Programs and miscellaneous items).
13 (b) The Commission Has Not Waived Its Sovereign Immunity 14 Through Any "Participation" in PG&E's Bankruptcy Case PG&E also claims that the Commission has waived its sovereign immunity 15 because state agencies have "participated" in the main bankruptcy case. (PG&E Br. at 41.) This 16 claim is without merit. In order to present its argument, PG&E again relies on stacks of 17 materials that are not part of the record on appeal, and which PG&E seeks to introduce by 18 judicial notice. As explained above, that request should be denied, and the Court should refrain 19 from considering the waiver argument in the first instance.
20 Even taking those materials on face value, PG&E's claim to "participation" is 21 rhetonc at best. According to PG&E, state agencies have "flex[ed] their regulatory muscle" 22 (PG&E Br. at 41), "assert[ed] their regulatory authority over PG&E" (at 42), "attended a 23 deposition" (at 42), and "become one of the most active critics of PG&E's Reorganization Plan."
24 (PG&E Br. at 42.) What PG&E does not claim, however, is that the Commission has 25 "participated" in this adversaryproceeding, other than to resist PG&E's efforts to strip the 26 Commission of its sovereign regulatory authority, and to assert its sovereign immunity.
27 28 CROSS-APPELLANTS' REPLY BRIEF AND OPPOSITION TO REQUiESI IJI) I( AL NOTICE MR I()
1 PG&E recognizes, as it must, that the Commission has asserted its Eleventh 2 Amendment immunity in the Bankruptcy Court at every step. (PG&E Br. at 47.) This is 3 completely inconsistent with PG&E's contention that the Commission has "unequivocally 4 express[ed] its consent to federal jurisdiction." Mitchell, 209 F.2d at 1117.
5 PG&E relies heavily on Hill v. Blind Indus. & Servs. of Maryland, 179 F.3d 754 6 (9th Cir. 1999). That case is distinguishable. First, the state agency in Hill participated in 7 extensive pre-trial activities and discovery in the same action that the plaintiff had brought 8 against it, right up until the eve of trial, and therefore subjected itself to jurisdiction over the 9 claims in that case. Here, by stark contrast, the Commission has done nothing in this proceeding 10 other than to move to dismiss the action on the grounds of sovereign immunity, among other 11 grounds. Second, the state agency in Hill deliberately waited until the eve of trial to assert its 12 sovereign immunity, in order to improperly "hedge its bet" on the outcome of the trial. See Hill, 13 179 F.3d at 757-57. Here by contrast, and like the state agency found to have retained its 14 sovereign immunity in Mitchell, the Commission "immediately asserted its immunity" to the 15 claims brought by PG&E. See Michell, 209 F.2d at 1118 (distinguishing Hill on this basis).
16 PG&E also relies on Pitts v. Ohio Department of Taxation (In re Pitts),
17 241 B.R. 862 (Bankr. N.D. Ohio 1999). That case, however, refutes rather than supports 18 PG&E's waiver contention. In Pitts, the court held that the state agency had not waived its 19 sovereign immunity in an adversary proceeding brought against the agency because, like the 20 agency in Mitchell, the agency "immediately raised" its sovereign immunity in that proceeding.
21 See id. at 878.
22 The other cases relied upon by PG&E are equally wide of the mark. Although 23 PG&E suggests these cases found a wholesale waiver based upon some general "participation" 24 in a bankruptcy, the cases involve extensive, affirmative efforts by a state agency to collect on a 25 specific debt, or otherwise to further specific pecuniary interests the agency had in the debtors' 26 estate, in a proceeding that the agency then claims cannot bind it because of sovereign 27 28 CROSS -Ai'PEI.LAN IS,' RP.Y BRIEF AND)OPPOSITION TO REQUEST FOR Jý I"DICIAI NOTICF
-17 -
is I immunity.- In these cases, the state agency was not acting as a regulator, as the Commission interest in 2 here, but as a creditor of the estate seeking to collect on a debt or other pecuniary 3 property of the estate. These cases, therefore, merely stand for the general rule, discussed above, its sovereign 4 that when a state agency files a proof of claim in a bankruptcy, it "waives" to no 5 immunity with respect to adjudication of only that claim. Here, PG&E can point the True-up for 6 affirmative actions by the Commission to present any debts or claims concerning has asserted from the 7 adjudication by the Bankruptcy Court. To the contrary, the Commission grounds of sovereign 8 beginning that the entire adversary proceeding cannot proceed on the 9 immunity.
sovereign 10 What is more, the cases cited by PG&E involve only limited waivers of and not the wholesale 11 immunity in connection with the specific debt or proof of claim asserted, 3
immunity on all aspects of PG&E's case that PG&E seeks here.
12 waiver of sovereign in 13 PG&E suggests that the Commission has "invoked the court's jurisdiction Not only is that suggestion 14 order to assert its regulatory interests in PG&E." (PG&E Br. at 46.)
On the f, zts, neither the 15 misleading as a matter of fact, the suggestion is legally irrelevant.
of the Bankruptcy Court 16 Commission nor any other state agency has "invoked" the jurisdiction to use the bankruptcy laws to 17 to assert any regulatory interests. Rather, it was PG&E that sought 18 2 First Union Nat'l Bank v. MCA Fin. Corp. (In re MCA Fin. Corp.), 237 B.R. 338, 341-42 1999) (state agency attempted to collect debtor's physical property and 19 (Bankr. E.D. Mich. to collect the property);
affirmatively sought adjudication in federal court that it had the right defendant at all 853, 858 (8th Cir. 1992) (statetried represented 20 1lHankins v. Finnel, 964 F.2dagreed to indemnify him, and then to use its sovereign immunity stages of the litigation, Tribes v. White (In re White),
promise to indemnify); Confederated to "renege" on its1270-71 21 139 F.3d 1268, (9th Cir. 1998) (tribe affirmatively sought to collect on a debt by of a proof of claim); Commonwealth of Va. Dep't of Med. Ass't 22 practical equivalent Partners, filing the Shenandoah L.P. (In re Shenandoah Realty Partners,L.P.), 248 Servs. v. Realty B.R. 505, 512 (W.D. Va. 2000) filedmotion (stateand of claim and actively litigated that proof of proof practice).
23 claim, including extensive discovery 24 3 See First Union, 237 B.R. at 342 (state waived sovereign immunity only with respect to and interests in that property" the state attempted to collect from estate);
25 "respective964rights F.2d at 858 ("the district court found a waiver only with respect to the narrow Hankins, solely to Confederated Tribes,on139 F.3d at 1270-71 (waiver limited 26 facts of this case"); a debt); Shenandoah, 248 B.R. at 512 (state adjudication of tribe's request to collect waived sovereign immunity only with respect to right to collect on proof of claim it had 27 submitted in the bankruptcy).
28 REQUEST FOR JUDICIAl. NOTICE CROSS -APPI-I IANTfREI'1I'r BRIEF ANOOPPOSITION TO
- 18-
I divest the Commission of its sovereign regulatory authority. That the Commission resisted 2 PG&E's attempt by asserting its sovereign immunity as a state regulator, and by asserting that 3 the Bankruptcy Court has no jurisdiction to permit PG&E to divest the Commission of regulatory 4 authority, is hardly an unequivocal indication of "invoking" the Bankruptcy Court's jurisdiction.
5 If anything, the Commission has done exactly the opposite, and fought at every step efforts by 6 PG&E to manipulate the Bankruptcy Court proceedings in order to oust the Commission of its 7 regulatory jurisdiction. If PG&E were correct that the Commission has waived its sovereign 8 immunity by asserting its sovereign immunity, then the concept of sovereign immunity would be 9 meaningless.
10 The suggestion is also legally irrelevant. Although PG&E bases its contention on 11 cases involving a state agency asserting a claim to property of the debtor's estate, as a creditor 12 would, there is a fundamental difference between a state attempting to collect property from the 13 debtor and a state attempting to retain its regulatory authority over a debtor. Bankruptcy law is 14 primarily concerned with the rights of debtors and creditors to a "res" (the debtor's estate) 15 subject to the bankruptcy court's jurisdiction. When a state seeks to collect money or property state 16 from the debtor, the state assumes the role of creditor, and the courts have thus held that the 17 is not insulated from the bankruptcy court's jurisdiction over that property:
and 18 [H]e who invokes the aid of the bankruptcy court by offering a proof of claim the demanding its allowance must abide by the consequences of that procedure. If into a 19 claimant is a State, the procedure of proof and allowance is not transmitted suit against the State because the court entertains objections to the claim. The the 20 State is seeking something from the debtor. No judgment is sought against State. The whole process of proof allowance, and distribution is, shortly such 21 speaking, an adjudicationof interests claimed in a res. It is none the less because the claim is rejected in toto, reduced in part, given a priority inferior to that claimed, or satisfied in some way other than payment in cash.
22 23 Gardnerv. New Jersey, 329 U.S. 565, 573-74 (1947) (emphasis added).
24 In such circumstances, a bankruptcy court's jurisdiction flows from its over the state 25 jurisdiction over the property of the estate in question, not from any jurisdiction the state is acting in 26 itself. But when a state seeks to retain its regulatory authority over a debtor, the estate, and 27 its public capacity as a sovereign. The state is not claiming against property of state. The statc 28 thus there is no basis for the bankruptcy court to assert jurisdiction over the NOTICE (CROSS-APPELIANI'S"RF.I'IY IKRIFE AND OI'POSII ION TO RFQoES rFOR J DICIAL
- 19 -
1 retains its sovereign rights, and to permit a debtor to push aside those rights would be a gross 2 affront to the state's sovereignty. See Seminole Tribe of Floridav. Florida,517 U.S. 44, 58 3 (1996) (Eleventh Amendment immunity "serves to avoid the indignity of subjecting a State to 4 the coercive process of judicial tribunals at the insistence of private parties.").
5 CONCLUSION 6 For the foregoing reasons, the Commission and the Commissioners respectfully 7 submit that PG&E's claims against the Commission and the Commissioners are barred in their 8 entirety by the Eleventh Amendment and related principles of sovereign immunity.
9 Dated: December 26, 2001 10 Respectfully, 11 GARY M. COHEN 12 AROCLES AGUILAR MICHAEL M. EDSON 13 14 15 MICHAEL M. EDSON 16 CALIFORNIA PUBLIC UTILITIES COMMISSION 505 Van Ness Ave., Room 5138 17 San Francisco, CA 94102 Phone: (415) 703-1086 18
- and 19 ALAN W. KORNBERG 20 WALTER RIEMAN BRIAN S. HERMANN 21 ERIC TWISTE MARC F. SKAPOF 22 PAUL, WEISS, RIFKIND, WHARTON & GARRISON 23 Attorneys for Defendants, Appellees and Cross-Appellants 24 25 26 27 28 I IxI."
('ROSS API.LA- R.IPLY BRIEF AND OPPOSITION 1"0 Ri-QtUESI I:OR JII)I(I AL NO iCF
- 20
I,
.1 1 GARY M. COHEN, SBN 117215 CALIFORNIA PUBLIC UTILITIES COMMISSION L) 2 505 Van Ness Avenue San Francisco, California 94102 * ,
3 Telephone: (415) 703-2015 Facsimile: (415) 703-2262 4
ALAN W. KORNBERG 5 WALTER RIEMAN, SBN 139365 BRIAN S. HERMANN 6 ERIC TWISTE MARC F. SKAPOF 7 PAUL, WEISS, RIFKIND, WHARTON & GARRISON 1285 Avenue of the Americas 8 New York, New York 10019-6064 Telephone: 212-373-3000 9 Facsimile: 212-757-3990 10 Attorneys for Defendants, Appellees and Cross-Appellants 11 UNITED STATES DISTRICT COURT NORTHERN DISTRICT OF CALIFORNIA 12 SAN FRANCISCO DIVISION 13 In re Case No. 01-2490 VRW (Bankruptcy Case No. 01-30923 DM; 14 Adv. Proceeding No. 01-3072 DM)
PACIFIC GAS AND ELECTRIC COMPANY, a California corporation, 15 Chapter II Case Debtor.
16 Federal I.D. No. 94-0742640 PROOF OF SERVICE 17 PACIFIC GAS AND ELECTRIC COMPANY, 18 a California corporation, 19 Plaintiff, Appellant and Cross-Appellee, 20 - against 21 CALIFORNIA PUBLIC UTILITIES COMMISSION, 22 and LORETTA M. LYNCH, HENRY M. DUQUE, RICHARD A. B[LAS. CARL W. WOOD, and 23 GEOFFREY F. BROWN, in their official capacities as Commissioners of the California Public Utilities 24 Commission, 25 Defendants, Appellees and Cross-Appellants.
26 27 28 D)oc4 NY6 II 4l' I
1 PROOF OF SERVICE 2
3 1,MARTHA PEREZ, declare:
4 1. I am not a party to this action, am over 18 years of age, and am employed by the California Public Utilities Commission, 505 Van Ness Avenue, San Francisco, California 5 94102.
hand 6 - 2. On December 26, 2001, I caused to be served via electronic mail and Request For delivery copies of Cross-Appellants' Reply Brief And Opposition To Supplemental on the 7 Judicial Notice By Appellant And Cross-AppelleePacific Gas And Electric_Company following:
8 Jerome B. Falk, Jr.
9 Amy E. Margolin Howard, Rice, Nemerovski, Canady, Falk & Rabkin 10 Three Embarcadero Center, 7 1h Floor San Francisco, California 94111-4065 11 Electronic Mail:
jfalk@hrice.com 12 amargolin @ hrice.com Attorneys for Plaintiff/Appellant/Cross-Appellee 13 Stephen Johnson 14 Office of the United States Trustee 250 Montgomery Street 15 San Francisco, California 94104 Electronic Mail:
16 stephen.johnson2@usdoj.gov Trustee 17 Attorney for the Office of the United States
- 3. On December 26, 2001, 1 also caused to be served via electronic and overnight 18 mail copies of the above-referenced court pleadings on the following:
19 Paul S. Aronzon Michael H. Diamond 20 Milbank, Tweed, Hadley & McCloy 21 601 South Figueroa Street, Suite 3000 Los Angeles, California 90017 Electronic Mail:
22 paronzon @milbank.com mdiamond@milbank.com 23 Attorneys for Intervenors The Official Committee of Unsecured Creditors 24 25 26 27 28 1),
N 14~
1,
1 4. Finally, on December 26, 2001, 1 also caused to be served via overnight mail on the following:
2 copies of the above-referenced court pleadings D. Cameron Baker 3 Deputy City Attorney Office of the San Francisco City Attorney 4 1 Dr. Carlton B. Godlett Place San Francisco, CA 94102-4682 5 Attorneys for Amicus Curiae City and County of San Francisco 6
Steven H. Felderstein 7 Felderstein, Fitzgerald, Willoughby & Pascuzzi, LLP 400 Capital Mall, Suite 1450 8 Sacramento, CA 95814-4434 Attorneys for Amicus Curiae State of California 9
Margarita Padilla, Esq.
10 Deputy Attorney General State of California Department of Justice 11 1515 Clay Street, 2 0 'h Floor Oakland, CA 94612-1413 12 Attorneys for Amicus Curiae State of California 13 I declare under penalty of perjury that the foregoing is true and correct.
14 Executed on December 26, 2001, at San Francisco, California.
15 16 Martha Perez U 17 18 19 20 21 22 23 24 25 26 27 28 I)x"" NY6 II141 I
EXHIBIT C COM/LYN/epg Mailed 1/19/2001 Decision 01-01-046 January 19, 2001 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE 6F CALIFORNIA Application of Southern California Edison Company (E 3338-E) for Authority to Institute a Application 00-11-038 (Filed November 16,2000)
Rate Stabilization Plan with a Rate Increase and End of Rate Freeze Tariffs.
Application 00-11-056 Emergency Application of Pacific Gas and (Filed November 22, 2000)
Electric Company to Adopt a Rate Stabilization Plan. (U 39 E)
Application 00-10-028 Petition of THE UTILITY REFORM NETWORK (Filed October 17, 2000) for Modification of Resolution E-3527.
INTERIM OPINION AFFIRMING THE OBLIGATION TO SERVE AND ISSUING TEMPORARY RESTRAINING ORDER I. Summary In this interim decision, we are issuing a temporary restraining order (TRO) preventing Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) from refusing to provide adequate service to all of their customers. We issue this TRO to maintain the status quo so as to avoid further degradation of provision of electric service and to avoid the irreparable harm to the public health and safety that would be caused by further degradation of service. We affirm that regulated California utilities must serve their customers. This requirement, known as the "obligation to serve" is 88122 A.00-11-038 et al. COM/LYN/epg of the mandated by state law. A utility's obligation to serve is part and parcel entire regulatory scheme under which the Commission regulates and controls utilities under the Public Utilities Act.
A bankruptcy filing or the threat of insolvency has no bearing on this aspect of state law. Even utilities that file for reorganization must serve their if customers.: The public's safety, and the economy's health will be impaired to utilities avoid their obligation to serve. We will take all action necessary enforce this obligation, while regulating and controlling utilities in a manner consistent with state law, and make the following orders:
1I. Background In Decision (D.) 01-01-018, we adopted an immediate, interim surcharge for PG&E and SCE, subject to refund and adjustment.' This surcharge is in effect the for 90 days from the effective date of D.01-01-018. As stated in that decision, to increase is a temporary surcharge to improve the ability of the applicants cannot cover the costs of procuring future energy in wholesale markets that they produce themselves to serve their loads. We determined that this expedited utilities action was necessary to fulfill our statutory obligations to ensure that the hearings can provide adequate service at just and reasonable rates. Emergency for were held in late December 2000 and additional hearings are planned February.
the In D.01-01-018, we state that we do not yet have the facts to evaluate and must utilities' claims of their dire circumstances. We have called for an audit all of the facts await the independent auditors' report. Moreover, we do not have customers eligible for the California Alternative Rates for Energy (CARE) customers, program are exempt from this surcharge. The surcharge applies to all other including direct access customers.
A.00-11-038 et al. COM/LYN/epg related to the parent companies, the utilities, the affiliates, and the flow of funds among these entities. The independent auditors will also consider these questions in their reports. We must consider the overall financial position of the utilities and will do so expeditiously.
Further, in D.01-01-018 we state:
We are very troubled by the utilities' assumption that ratepayers must bear the burden of significant rate increases without the shareholders sharing in the pain. The utilities and their shareholders have received significant financial benefit from restructuring thus far. For example, PG&E and Edison have each received the benefit of over $2 billion in cash proceeds from rate reduction bonds. As reported in the monthly TCBA reports, PG&E has received over $9 billion in headroom and other transition cost revenues and Edison has received over $7 billion in such revenues.
As revealed in cross-examination of PG&E witness Campbell, disbursements from PG&E to the parent company, PG&E Corporation (PG&E Corp.) during the transition period were approximately $9.6 billion. Out of this total, PG&E Corp. issued dividends (both common and preferred stock) of approximately
$1.5 billion. PG&E also repurchased stock in the amount of approximately $2.8 billion and retired approximately $2.8 billion of debt. PG&E recognized that market problems were beginning to occur in June of this year, but decided to declare a third-quarter dividend. PG&E did not consider establishing a contingency fund or retaining cash to cushion its risk, because it believed that "its generally conservative financial profile and financing practices would adequately provide cushion against... a reasonable range of contingencies." (TR: 409.)
Now that such contingencies are outside the reasonable range, the utilities turn to the ratepayers for relief. It is decidedly not business as usual and the utilities need to realize that ratepayers are not the only answer to their dilemma. For example, parties have only just begun to explore the ability of the utilities' holding companies to participate in the solution. While the cash on hand in the holding companies may be insufficient when compared with the going-A.00-11-038 et al. COM/LYN/epg other forward costs of procuring power, we are convinced that 15-16.)
potential solutions should be explored. (Id. mimeo. at pp.
Ill. Discussion market Since mid-June, we have seen prices in the wholesale electricity of the skyrocket to staggering levels as a result of the severe dysfunction several deleterious California wholesale electricity market. As a result, Diego Gas & Electric Company's consequences have occurred. Ratepayers in San double and triple over the (SDG&E) service territory saw their electric bills Stage 1, 2, and 3 summer. PG&E and Edison have defaulted on payments.
and indeed, rolling emergencies have occurred with alarming regularity, 17 and 18, 2001. The blackouts occurred in Northern California on January seeking solutions to the Governor, Legislature, and this agency are actively Regulatory Commission energy crisis confronting us. The Federal Energy electric rates are not just and reasonable, (FERC), despite finding that wholesale a remedy under Section chose to lift price caps, and to refrain from devising 824e(a)),2 while making a 206(a) of the Federal Power Act (16 USC Section and uncertainty of the number of other changes that add to the complexity D.01-01-018, these actions have commercial relationships. As we explained in 2 This statute provides in pertinent part:
its own motion or upon Whenever the Commission, after a hearing had upon demanded, observed, complaint, shall find that any rate, charge, or classification, transmission or sale subject to the charged, or collected by any public utility for any regulation, practice, or contract jurisdiction of the Commission, or that any rule, unreasonable, unduly affecting such rate, charge, or classification is unjust, shall determine the just and reasonable discriminatory or preferential, the Commission or contract to be thereafter rate, charge, classification, rule, regulation, practice, order.
observed and in force, and shall fix the same by A.00-11-038 et al. COM/LYN/epg electricity sellers who left California's utilities and ratepayers prey to wholesale above already immediately quadrupled and quintupled their prices unprecedented levels.
and early January, In the hearings we held on financial issues in December that Edison could not a representative of Edison indicated that in the event available in retail purchase power in excess of the 7 cents per kilowatt-hour to be relieved of its obligation revenues to pay for power, Edison would request to serve. (TR: 755)
Gary Heath, Executive On January 18, we received a declaration from regarding PG&E's assertion to Director of the Electricity Oversight Board (EOB)
Department of Water the Deputy Director Raymond Hart of the California that PG&E stated that Resources (CDWR). Mr. Hart informed Mr. Heath only its own generation and beginning January 20, 2001, PG&E would schedule to serve remaining customer would not purchase additional needed generation Heath verified this assertion with PG&E Vice President Dan Richard at load. Mr.
that PG&E would only serve its 2:15 p.m. on January 18. Mr. Richard confirmed would not schedule the customers through its own generation, and therefore load. Mr. Heath states resources secured by the CDWR for PG&E's remaining to meet its obligations to serve all that PG&E cannot rely on its own generation does not obtain additional the customers in its service territory. If PG&E will be "seriously generation, reliability of service to PG&E customers 1.)
jeopardized." (Declaration of Gary Heath, Attachment Terry Winter, the Also on January 18, we received affidavits from Independent System Operator President and Chief Executive of the California and Ziad Alaywan, Managing Director of the ISO. Mr. Winter declares that (ISO) stated in a 4:15 p.m. telephone call Harold Ray, a senior vice president of Edison, coordinator for all of Edison's that Edison plans to continue to act a scheduling A.00-11-038 et al. COM/LYN/epg non-direct access customers. Mr. Ray stated that there is not an intent to abandon any of its customers. At 4:20 p.m., Mr. Winter had a telephone conversation with Mr. Richard of PG&E and Bruce Worthington, General Counsel of PG&E. Mr. Richard stated that PG&E would not change its scheduling responsibilities at this time and that there was a misunderstanding of the scheduling coordination responsibilities regarding the CDWR's role as a conduit to serve some of PG&E's customers. Mr. Winter then declares that:
"Mr. Richards [sic] advised me that while the company does not intend to change its scheduling coordination role for all its non-direct access customers at this time, the company will continue to review its scheduling coordination responsibilities to its non-direct access customers as the situation unfolds."
(Affidavit of Terry Winter, Attachment 2.)
Mr. Alaywan declares that he participated in two conference calls with personnel from PG&E, Edison, and CDWR, which took place at approximately 8:00 a.m. and 2:00 p.m. on January 18,2001. During the morning call, all participants agreed that PG&E and Edison would continue to act as scheduling coordinators for all their non-direct access customers, even though some customers would be served by generation provided by CDWR. PG&E and Edison agreed to undertake an inter-scheduling coordinator trade with CDWR in accordance with prescribed ISO processes. During the afternoon call, a PG&E director indicated that it no longer wished to act a scheduling coordinator for non-direct access customers served by generation provided by CDWR. The PG&E director stated that "PG&E does not wish to shirk its responsibilities, but stated again that another entity should serve as scheduling coordinator for customers served by CDWR generation." (Affidavit of Ziad Alaywan, Attachment 3.)
A.00-11-038 et al. COM/LYN/epg We also received a declaration, dated January 18, 2001, from Peter Garris, employed by the CDWR as Chief Water and Power Dispatcher. Mr. Garris confirms the 2:00 p.m. January 18 conference call described by Mr. Alaywan.
Mr. Garris specifically states that Claudia Grief, Director of PG&E Scheduling, informed the participants thatPG&E would not be the scheduling coordinator for load that could not be served by its own resources. Mr. Garris also participated in a 4:45 p.m. conference call with Ms. Grief, PG&E Vice President Roy Kuga, other CDWR staff, and individuals from the ISO and Power Exchange. Mr. Garris confirms that during this call, Mr. Kuga indicated that PG&E would not take scheduling coordinator trades from CDWR after Saturday, January 20,2001, for energy acquired by CDWR for PG&E's load that is not served by PG&E's own generation. Mr. Garris states that PG&E lacks sufficient resources to meet its native load without securing energy from other sources; if this is left unresolved, PG&E's customers will experience adverse reliability problems.
IV. Obligation to Serve State law clearly requires utilities to serve their customers, and a threatened bankruptcy filing or threat of insolvency does not change that obligation. Similarly, the financial distress of one utility cannot be used as an excuse by another utility to avoid its obligation to serve. As we stated in D.01-01-018, we have a duty to assure that the utilities are able to continue to procure and deliver power for their customers. This duty applies even if the utilities under our jurisdiction have filed for bankruptcy or are on the brink of petitioning for such relief. Our basic obligation under the Public Utilities Act is A.00-11-038 et al. COM/LYN/epg to assure the people of California adequate service at reasonable rates.
Section 451' provides, in relevant part:
All charges demanded or received by any public utility, or by any two or more public utilities, for any product or commodity furnished or to be furnished or any service rendered or to be rendered shall be just and reasonable. Every unjust or unreasonable charge demanded or received for such product or commodity or service is unlawful. Every public utility shall furnish and maintain such adequate, efficient, just and reasonable service, instrumentalities, equipment and facilities as are necessary to promote the safety, health, comfort and convenience of its patrons, employees, and the public.
We therefore issue this decision to affirm that PG&E and Edison must at just continue to provide reliable, safe, and adequate service to all Californians and reasonable rates, including continuing to enter into and maintain any are current and future low-cost contracts to procure power. Our actions 391(a),
consistent with the Legislature's intent, as stated in §§ 330(g), 330(h) and relevant part of Assembly Bill (AB) 1890 (Stats. 1996, Ch. 854), which provide in part:
330(g): Reliable electric service of utmost importance to the safety, health, and welfare of the state's citizenry and economy.
330(h): It is important that sufficient supplies of electric generation will be available to maintain the reliable service to the citizens and business of the state.
391(a): Electricity is essential to the health, safety, and economic well-being of all California consumers.
3 All statutory references are to the Public Utilities Code, unless otherwise noted.
A.00-11-038 et al. COM/LYN/epg In addition, §§ 761-788 give the Commission broad authority to issue utilities.
orders controlling the equipment, practices and facilities of regulated the "service, or For example, § 761 gives the Commission authority to order Section 761 also methods to be observed, [or] furnished" by California Utilities.
render their services provides that utilities must furnish their commodities, or as a customer according t6 the rules and orders of the Commission, so long makes "proper demand and tender of rates."
In relevant part, § 762 requires that:
Whenever the commission, after a hearing, finds that additions, extensions, repairs, or improvements to, or changes in, the existing property of plant, equipment, apparatus, facilities, or other physical any public utility or of any two or more public utilities ought erected, to reasonably to be made, or that new structures should be the public, promote the security or convenience of its employees or the or in any other way to secure adequate service or facilities, such commission shall make and serve an order directing that be made or additions, extensions, repairs, improvements, or changes such structures be erected in the manner and within the time specified in the order.
Furthermore, § 768 provides, in relevant part:
utility to The commission may, after a hearing, require every public construct, maintain, and operate its line, plant, system, equipment, and apparatus, tracks, and premises in a manner so as to promote safeguard the health and safety of its employees, passengers, customers, and the public.
Section 770 provides, in relevant part:
The commission may, after a hearing:
Ascertain and fix just and reasonable standards, classifications, furnished, regulations, practices, measurements, or service to be water, and imposed, observed, and followed by all electrical, gas, heat corporations.
A.00-11-038 et al. COM/LYN/epg Section 701 gives the Commission power to undertake all necessary actions to properly regulate and supervise California utilities. In Consumers Lobby Against Monopolies v. Public Utilities Commission (1979) 25 Cal.3d 891, 905, the California Supreme Court declared:
The commission is a state agency of constitutional origin with far reaching duties, functions and powers. (Cal. Const., Art. XII §§ 1-6.)
The Constitution confers broad authority on the commission to regulate utilities, including the power to fix rtes, establish rules, hold various types of hearings, award reparation, and establish its own procedures (Id., §§ 2, 4, 6.) ...
Pursuant to this grant of power, the Legislature enacted Public Utilities Code section 701, conferring on the commission expansive authority to 'do all things, whether specifically designated in [the Public Utilities Act] or addition thereto, which are necessary and convenient' in the supervision and regulation of every public utility in California. (Italics added.) the commission's authority has been liberally construed. (Consumers Lobby Against Monopolies at 905.)
The California Supreme Court has further found that "the commission often exercises equitable jurisdiction as an incident to its express duties and authority. For example, the commission may issue injunctions in aid of jurisdiction specifically conferred upon it." (Id. at 907.)
Therefore, under our plenary powers and until this crisis is resolved, we intend to closely monitor and supervise the actions and expenditures of the investor-owned utilities under our regulation to ensure that service is provided.
While we are dismayed that the energy crisis has escalated to the point that such tight control by the State is required, we intend to exercise the required control.
We recognize that hearings are required and will provide for these, as we discuss below. Today we issue a temporary restraining order in order to avoid irreparable harm to public health and safety, to maintain the status quo, and to ensure that PG&E and Edison continue to schedule generation through the ISO A.00-11-038 et al. COM/LYN/epg their to serve all customers with adequate, reliable service, consistent with obligation to serve.
from A TRO serves the purpose of preventing the actions of a party on the need for a causing irreparable harm to another party, pending a hearing and on an preliminary injunction. We are issuing this TRO on our motion were not ex parte basis because we are convinced that if adequate service matter could maintained, great or irreparable harm would result before the preliminary proceed to a hearing. A TRO has the same force and effect as a or denying injunction and remains in effect until an order can be issued granting a preliminary injunction.
hearing We therefore order PG&E and Edison to appear at an evidentiary as to why a scheduled for January 29, 2001 at 10:00 a.m. to show cause preliminary injunction should not be issued.
have We expect the utilities to fully comply with our orders. We utilities of their previously stated that nothing in AB 1890 relieves the existing under their respective obligation to serve all customers in their service territories company decision, tariffs (D.97-09-047, mimeo. at p. 44.). In PG&E's holding capital requirements D.98-04-068, the Commission specifically found that: "The meet the obligation to of PG&E, as determined to be necessary and prudent to manner, shall be given serve or to operate the utility in a prudent and efficient (Id., at 98.) The first priority by PG&E Corporation's Board of Directors."
the continuing Commissions' holding company decision clearly affirms obligation to serve.
V. Unforeseen Emergency Situation and Government Code § 11125.5 and Rule 81 of our Rules of Practice quickly than would be Procedure allow the Commission to take action more meeting agenda. An permitted if advance publication were made on the regular A.00-11-038 et al. COM/LYN/epg that example of such an unforeseen emergency situation are those activities severely impair or threaten to severely impair public health or safety.
As underscored by Governor Gray Davis, who declared a state of on emergency, this is such a situation. If PG&E and Edison were to rely only their their own generation to meet their obligations to serve all customers in service territory, reliability of service would be severely undermined.
Draft decisions are generally subject to a 30-day review and comment period may period (§ 311(g)(1)). However, § 311(g)(2) provides that this 30-day be reduced or waived in an unforeseen emergency situation. We have review and determined that this situation exists and therefore waive the public 77.7(f)(9) and comment period on this draft decision. (See also Rules 77.7(f)(1),
81.)
Findings of Fact on the
- 1. On January 3, 2001, in final oral argument before the Commission Weissmann, proposed decision of ALJ Minkin in this proceeding, attorney Henry Edison representing Edison, stated that if the Commission's decision prevented to meet from obtaining additional financing, it would not be able to buy power of the its customers needs. He requested the Commission relieve Edison of the 7 cents obligation to serve to the extent it cannot purchase power in excess per kilowatt hour available in retail revenues to pay for power.
per kilowatt
- 2. In D.01-01-018, we state that the interim surcharge of I cent the ability of hour, subject to refund and adjustment, is adopted to improve in wholesale PG&E and Edison to cover the costs of procuring future energy markets that they cannot produce themselves to serve their loads.
AB 1890 and
- 3. In D.01-01-018, we find that the utilities understood the risks hand in the electric restructuring imposed. In addition, while the cash on the going-forward holding companies may be insufficient when compared with A.00-11-038 et al. COM/LYN/epg costs of procuring power, we are convinced that other potential solutions should be and are currently being explored.
- 4. The evidence obtained at hearing in this proceeding does not support a finding that PG&E or Edison cannot continue to provide service unless there are substantial rate increases. Instead, we called for an audit and must await the independent auditors' report. Moreover, we do not have all of the facts related to the parent companies, the utilities, the affiliates, and the flow of funds among these entities. The independent auditors will also consider these questions in their reports.
- 5. On January 18, we received a declaration from Gary Heath, Executive Director of the EOB regarding PG&E's assertion to the Deputy Director Raymond Hart of the CDWR.
- 6. Mr. Hart informed Mr. Heath that PG&E stated that beginning January 20, 2001, PG&E would schedule only its own generation and would not purchase additional needed generation to serve remaining customer load. Mr. Heath verified this assertion with PG&E Vice President Dan Richard at 2:15 p.m. on January 18, 2001.
- 7. Mr. Heath states that PG&E cannot rely on its own generation to meet its obligations to serve all the customers in its service territory. If PG&E does not obtain additional generation, reliability of service to PG&E customers will be jeopardized.
- 8. We also received affidavits on January 18, 2001 from Terry Winter, the President and Chief Executive of the ISO and Ziad Alaywan, Managing Director of the ISO.
- 9. Mr. Winter declares that Harold Ray, a senior vice president of Edison, stated in a 4:15 p.m. telephone call on January 18, 2001, that Edison plans to continue to act as scheduling coordinator for all of Edison's non-direct access A.00-11-038 et al. COM/LYN/epg customers. Mr. Ray stated that there is not an intent to abandon any of its customers.
- 10. At 4:20 p.m. on January 18, 2001, Mr. Winter had a telephone conversation with Mr. Richard of PG&E and Bruce Worthington, General Counsel of PG&E.
at Mr. Richard stated that PG&E would not change its scheduling responsibilities this time and that there was a misunderstanding of the scheduling coordination responsibilities regarding the CDWR's role as a conduit to serve some of PG&E's customers.
- 11. Mr. Winter declares that Mr. Richards then advised the ISO that PG&E "will continue to review its scheduling coordination responsibilities to its non direct access customers as the situation unfolds."
- 12. Mr. Alaywan declares that he participated in two conference calls with personnel from PG&E, Edison, and CDWR, which took place at approximately 8:00 a.m. and 2:00 p.m.
- 13. During the morning call, all participants agreed that PG&E and Edison access would continue to act as scheduling coordinators for all their non-direct customers, even though some customers would be served by generation provided by CDWR. PG&E and Edison agreed to undertake an inter-scheduling coordinator trade with CDWR in accordance with prescribed ISO processes.
- 14. During the afternoon call, Mr. Alaywan states that a PG&E director for indicated that PG&E no longer wished to act as a Scheduling Coordinator non-direct access customers served by generation provided by CDWR.
January
- 15. The same participants took part in a 3:00 p.m. conference call on position as 18, 2001, in which Edison now indicated that it was taking the same from PG&E as to scheduling coordinator responsibilities. Mr. Ziad understands indicated conversations with Mr. Winter that PG&E and Edison have currently access that they will serve as scheduling coordinators for all their non-direct A.00-11-038 et al. COM/LYN/epg 2001 customers in accordance with the process agreed to during the January 18, morning call.
the
- 16. The January 18, 2001 declaration of Peter Garris of the CDWR confirms in a 2:00 p.m. phone call described by Mr. Alaywan. Mr. Garris also participated 4:45 p.m. conference call with Ms. Grief Director of PG&E Scheduling, PG&E the ISO and Vice President Roy Kuga, other CDWR staff, and individuals from Power Exchange.
- 17. During this call, Mr. Garris confirms that Mr. Kuga indicated that PG&E would not take scheduling coordinator trades from CDWR after Saturday, is not January 20, 2001, for energy acquired by CDWR for PG&E's load that served by PG&E's own generation.
its native
- 18. Mr. Garris states that PG&E lacks sufficient resources to meet load without securing energy from other sources; if this is left unresolved, PG&E's customers will experience adverse reliability problems.
Conclusions of Law a threatened
- 1. State law clearly requires utilities to serve their customers, and bankruptcy filing or threat of insolvency does not change that obligation.
utilities are
- 2. As we stated in D.01-01-018, we have a duty to assure that the This duty able to continue to procure and deliver power for their customers.
or applies even if the utilities under our jurisdiction have filed for bankruptcy the Public appear to be threatened with insolvency. Our basic duty under service at just Utilities Act is to assure the people of California adequate electric and reasonable rates.
770, PG&E and
- 3. Under Public Utilities Code sections 451, 761, 762, 768, and to all of their Edison have an obligation to provide full and adequate service any current and customers, including continuing to enter into and maintain future low-cost contracts to procure power.
A.00-11-038 et al. COM/LYN/epg well-being of all
- 4. Electricity is essential to the health, safety, and economic California consumers.
- 5. Customers of PG&E and Edison would suffer irreparable harm if the utilities did not maintain adequate service to all customers.
of PG&E and
- 6. In order to ensure full and adequate service to all customers Order preventing Edison, the Commission should issue a Temporary Restraining their customers.
the utilities from refusing to provide adequate service to all of from refusing to This restraining order should specifically prevent the utilities System Operator act as scheduling coordinator with the California Independent to serve all of their non-direct access customers.
from causing
- 7. A TRO serves the purpose of preventing the actions of a party the need for a irreparable harm to another party, pending a hearing on preliminary injunction.
parte basis because
- 8. We are issuing this TRO on our own motion and an ex great or we are convinced that if adequate service were not maintained, to a hearing.
irreparable harm would result before the matter could proceed injunction and
- 9. A TRO has the same force and effect as a preliminary denying a request for a remains in effect until an order can be issued granting or preliminary injunction.
and Edison to
- 10. A hearing should be held expeditiously to require PG&E not be granted.
show cause as to why a preliminary injunction should their obligation to
- 11. Nothing in AB 1890 relieves the existing utilities of respective tariffs.
serve all customers in their service territories under their Rule 81, immediate
- 12. Consistent with Government Code § 11125.5 and failure to serve all non action is required because PG&E and Edison's potential that threatens to direct access customers is an unforeseen emergency situation severely impair public heath and safety.
A.00-11-038 et al. COM/LYN/epg public
- 13. Because this is an unforeseen emergency situation, the 30-day 2 ).
review and comment period is waived, consistent with § 311(g)(
restraining order
- 14. This order should be effective today, so that a temporary may be issued expeditiously.
INTERIM ORDER IT IS ORDERED that:
California Edison
- 1. Pacific Gas and Electric Company (PG&E) and Southern adequate service to all their Company (Edison) shall continue to provide full and customers.
from refusing to provide
- 2. PG&E and Edison are temporarily restrained to act as scheduling adequate service to all customers, including refusing customers with the California coordinators to serve all their non-direct access Independent System Operator.
hearing on January 29,
- 3. PG&E and Edison shall appear for an evidentiary Courtrooms to show cause 2001 at 10:00 AM at the Commission's San Francisco a preliminary injunction and to why the Commission should not proceed to issue actions.
take legal action against PG&E and Edison for their This order is effective today.
Dated January 19, 2001, at San Francisco, California.
LORETTA M. LYNCH President CARL W. WOOD Commissioner Commissioner Richard A. Bilas is necessarily absent.
A.00-11-038 et al. COM/LYN/epg I will file a dissent.
/s/ HENRY M. DUQUE Commissioner A.00-11-038 et al. COM/LYN/epg ATTACHMENT 1 DECLARATION 1, GARY HEATH, declare:
- 1. I am employed by the Electricity Oversight Board as the Executive Director. I have personal knowledge of the facts stated herein except as to matters stated upon information and belief, and as to those matters, I believe them to be true. If called upon to testify, I could and would competently do so.
- 2. Today, I received a telephone at about approximately 2:00 p.m. from Deputy Director Raymond Hart of the California Department of Water Resources.
- 3. Mr. Hart informed me that starting Saturday, January 20,2001, Pacific Gas and Electric Company ("PG&E") told him that it would only schedule its own generation, and would not purchase additional needed generation to serve remaining customer load.
- 4. I verified this information from Mr. Hart by contacting PG&E Vice President Dan Richard, at approximately 2:15 p.m. today. Mr. Richard confirmed that PG&E would only serve its customers through its own generation, and therefore would not schedule the resources secured by the California Department of Water Resources for PG&E's remaining load.
- 5. PG&E cannot rely on its own generation to meet its obligations to serve all the customers in its service territory. PG&E must obtain additional generation; otherwise, reliability of service to PG&E customers will be seriously jeopardized.
I declare under penalty of perjury that the foregoing is true and correct.
Executed this 18f day of January, 2001, at Sacramento, California.
/S/ GARY HEATH Gary Heath (END OF ATTACHMENT 1)
A.00-11-038 et al. COM/LYN/epg ATTACHMENT 2 AFFIDAVIT OF TERRY WINTER I, Terry Winter, declare as follows:
System
- 1. I am the President and Chief Executive of the California Independent and can testify Operator. I have personal knowledge of the matters set forth below thereto if called as a witness.
with
- 2. At approximately 4:15 on January 18, 2001, 1 had a telephone conversation (SCE)
Harold Ray, a senior vice president of Southern California Edison Company for all SCE concerning that company's plans for acting as scheduling coordinator to continue non-direct access customers. Mr. Ray advised me that SCE is planning Mr. Ray to act as scheduling coordinator for all SCE non-direct access customers.
uncertainty as further advised me that any confusion on this point was due to some be allocated to how responsibilities for acting as scheduling coordinator would advised me between the California Department of Water Resources and SCE. He its customers.
that there was no intent on the part of SCE to "abandon" any of Dan Richards,
- 3. At approximately 4:20 on January 18, 2001, 1 had a conversation with Bruce a senior executive of Pacific Gas and Electric Company (PG&E) and plans for acting Worthington, General Counsel of PG&E, concerning that company's Mr. Richards as scheduling coordinator for all PG&E non-direct access customers.
responsibilities advised me that PG&E would not change its scheduling coordinator on this point was at this time. Mr. Richards further advised me that any confusion of PG&E due to a misunderstanding of the scheduling coordination responsibilities Department in light of the Governor's statement regarding the role of the California Mr. Richards of Water Resources as a conduit to serve some of PG&E customers.
scheduling advised me that while the company does not intend to change its time, the company coordination role for all its non-direct access customers at this to its non-direct will continue to review its scheduling coordination responsibilities access customers as the situation unfolds.
Declared under penalty of perjury by:
/S/ TERRY WINTER Terry Winter (END OF ATTACHMENT 2)
A.00-11-038 et al. COM/LYN/epg ATTACHMENT 3 AFFIDAVIT OF ZIAD ALAYWAN I, Ziad Alaywan, declare as follows:
I have personal
- 1. I am a Managing Director at the California Independent System Operator.
as a witness.
knowledge of the matters set forth below and can testify thereto if called from Pacific Gas
- 2. On January 18, 2001, 1 participated in two conference calls with personnel and the and Electric Company (PG&E), Southern California Edison Company (SCE)
California Department of Water Resources (CDWR), which took place at approximately scheduling of 8:00 AM and 2:00 PM. These conference calls related to the mechanics for non-direct access customers of PG&E and SCE.
scheduling
- 3. During the morning call it was agreed that PG&E and SCE would act as although some such customers would coordinators for all their non-direct access customers, SCE would undertake an inter be served by generation provided by CDWR. PG&E and by to be provided scheduling coordinator trade with CDWR to account for the generation trades, which CDWR, in accordance with the ISO process for inter scheduling coordinator into a transaction.
requires confirmation from both scheduling coordinators entering not wish to act as
- 4. During the 2:00 PM call, a PG&E director indicated that PG&E did provided by scheduling coordinator for non-direct access customers served by generation scheduling CDWR. This director stated that another entity should be used to act as asked whether PG&E was coordinator for these customers. The CDWR representative that PG&E does not wish shirking its responsibilities as a utility. The PG&E director stated serve as scheduling to shirk its responsibilities, but stated again that another entity should Since it appeared that the entities coordinator for customers served by CDWR generation.
at 3:00 PM.
on the phone had reached an impasse, we agreed to try speaking again get confirmation of the
- 5. After the 2:00 PM call, I called another PG&E representative to informed the ISO PG&E position. I was told that this person could not help me. I therefore President and Chief Executive Officer, Terry Winter, of the development.
reconvened for a call at
- 6. The group (representatives from PG&E, SCE, CDWR and myself) taking the same 3:00 PM. During this call, the SCE representative indicated that it was light of issues that position as PG&E as to scheduling coordination responsibilities, in underscheduling.
needed to be resolved, including for example the $100 penalty for time PG&E and SCE have
- 7. I understand from conversations with Mr. Winter that at this non-direct access indicated that they will serve as scheduling coordinators for all their 8:00 AM call this morning.
customers in accordance with the process agreed to during the Declared under penalty of perjury by:
/s/ ZIAD ALAYWAN Ziad Alaywan (END OF ATTACHMENT 3)
A.00-11-038 et al. COM/LYN/epg ATTACHMENT 4 DECLARATION I, PETER GARRIS, declare:
("CDWR") as
- 1. I am employed by the California Department of Water Resources facts stated Chief Water and Power Dispatcher. I have personal knowledge of the and as to those matters, I herein except as to matters stated upon information and belief, competently do so.
believe them to be true. If called upon to testify, I could and would meeting with
- 2. At approximately 2:00 p.m. today, I participated in a teleconference California representatives from Pacific Gas and Electric Company ("PG&E"), Southern and the Edison Company, the California Independent System Operator ("ISO")
Director of California Power Exchange ("PX"). During this meeting, Claudia Grief, PG&E Scheduling, informed us that PG&E would not be taking "scheduling as of Friday, coordinator to scheduling coordinator trades" from CDWR to PG&E, 20,2001. She also January 19,2001, for energy that would flow on Saturday, January for load that could not informed us that PG&E would not be the scheduling coordinator be served by its own resources.
with
- 3. At approximately 4:45 p.m., I participated in a teleconference meeting by other PG&E Vice President Roy Kuga and Ms. Grief. The meeting was attended Mr. Kuga CDWR staff, and individuals from the ISO and the PX. During this meeting, coordinator indicated that PG&E would not take "scheduling coordinator to scheduling by CDWR for trades" from CDWR after Saturday, January 20, 2001, for energy acquired PG&E's load that is not being served by PG&E's own generation.
- 4. PG&E lacks sufficient generating resources to meet its native load without deficiency is securing energy from other sources, including CDWR. If the resource unresolved, this will result in adverse reliability problems for PG&E customers.
I declare under penalty of perjury that the foregoing is true and correct.
Executed this 18"' day of January, 2001, at Sacramento, California.
/s/ PETER GARRIS Peter Garris (END OF ATTACHMENT 4)
A.00-11-038 et al D.01-01-046 Commissioner Duque, dissenting:
These are clearly stressful times. The Commission, and each Commissioner, now wishes to do whatever we can to reduce the rolling blackouts that Californians are that adopts a facing. Nevertheless, I cannot support today's decision of the majority Temporary Restraining Order (TRO) against SCE and PG&E.
A careful review of each of the affidavits attached to today's order of the majority belies the need for the issuance of a TRO. The affidavits document an understandable confusion on the part of SCE and PG&E concerning the new role of the California Department of Water Resources in buying power. More importantly, the affidavits show an underlying commitment by SCE and PG&E to honor their obligation-to-serve the part Californians. In particular, consider attachment 2, point 2 "there is no intent on consider attachment 3, point 7 of SCE to 'abandon' any of its customers." Furthermore,
"... at this time, PG&E and SCE have indicated that they will serve as scheduling coordinators for all their non-direct access customers.. ." The affidavits demonstrate If that there is no threat by either utility to deny their obligation-to-serve Californians.
there were such a threat by utilities to abrogate their obligation to serve, I would however, does support the order of the majority. The evidence before the Commission, not justify the issuance of a TRO.
It is also wise to ask what the adoption of this order will accomplish. The nothing to that obligation-to-serve is already clear in California law, and the TRO adds obligation. Moreover, the order may simply poison the atmosphere between even more difficult in government and the utilities, thereby making communications potential risks and this time of crisis. Thus, the order of the majority is unwise, with costs exceeding any benefits.
Finally, in the few minutes before this meeting, I called Gordon Smith, the CEO I
of PG&E. He stated that PG&E has no intention to abrogate its obligation-to-serve.
These verbal also called John Bryson, the Chairman of SCE, who said the same thing.
that there is commitments only confirm my reading of the affidavits and my conclusion no need for today's order.
For these reasons, I respectfully dissent from today's order of the majority.
/s/ HENRY M. DUOUE Henry M. Duque January 19, 2001 San Francisco, California
EXHIBIT D lip UNITED STATES OF AMERICA "BEFORETHE FEDERAL ENERGY REGULATORY COMMISSION Pacific Gas and ElectricCompany, PG&E Corporation Docket Nos. EC02-3 1-000 On Behalf of its Subsidiaries EL02-36-000 Electric Generation LLC, CP02-38-000 ETrans LLC and GTrans LLC MOTION FOR
SUMMARY
DISPOSITION, OR IN THE ALTERNATIVE, PROTEST AND REQUEST FOR CONSOLIDATION AND HEARING, OF THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Pursuant to Rules 211, 212, and 217 of the Rules of Practice and Procedure ("Rules") of the Federal Energy Regulatory Commission ("FERC"), the Public Utilities Commission of the State of California ("CPIC"), hereby protests the filing made in the above-referenced dockets, and moves for the summary disposition of the application ("the section 203 application"). In the alternative, if the application is not summarily rejected, the CPUC requests that the application be consolidated with related filings discussed below, and set for consolidated hearing. The CPUC is a constitutionally-established agency charged with the responsibility for regulating natural gas and electric corporations within the State of California. In addition, the CPUC has a statutory mandate to represent the interests of natural gas and electric consumers throughout California in proceedings before the Commission. The CPUC previously filed a Notice of Intervention in these proceedings on December 14, 2001.
112655
I. THE SECTION 203 APPLICATION On November 30, 2001, Pacific Gas and Electric Company ("PG&E") and PG&E Corporation ("Parent") on behalf of its subsidiaries, Electric Generation LLC ("Gen"), ETrans LLC ("ETrans") and GTrans LLC ("GTrans") (collectively, "PG&E" or the "Applicants") filed an application with the FERC, pursuant to Section 203 of the Federal Power Act ("FPA") and related declaratory orders under Sections 201 and 305 of the FPA and Section 12 of the Natural Gas Act ("NGA") for authorization of a disposition of jurisdictional facilities (for convenience the application will be referred to herein as "the Section 203 Application"). Applicants state that this filing has been filed in connection with PG&E's proposed "Plan of Reorganization under Chapter I of the Bankruptcy Code for Pacific Gas and Electric Company" ("Plan") jointly filed by PG&E and its Parent with the Bankruptcy Court on September 20, 2001. Applicants request approval for various transactions in connection with a proposed reorganization of PG&E that would result in the corporate unbundling of certain of PG&E's operations and spin-off of PG&E (as a retail gas and electric distribution company) from the Parent. PG&E states in its application that it does not expect to seek approval of the Transaction by the CPUC.
Specifically, PG&E is seeking FERC approval in the instant application for:
"* Transfer of transmission-related assets and wholesale and transmission contracts to Gen, the GenSub LLCs and ETrans and for the Spin-Off of a Reorganized PG&E from its Parent pursuant to FPA Section 203.
"* Assignment of the beneficial interest in the Nuclear Decommissioning Trust associated with PG&E's Diablo Canyon Power Plant Nuclear Decommissioning Trust associated with PG&E's Diablo Canyon to Diablo Canyon LLC.
"* A declaratory order that the GenSubs LLCs, will not be deemed "public utilities" under Section 201 (3) of the FPA, 16 U.S.C. § 824(3) (2000).
"* A ruling that the declaration of a dividend to effectuate the transfer of Gen, the GenSub LLCs, ETrans and GTrans from PG&E to its Parent, distribution of a stock dividend by PG&E to its Parent, and the Parent's subsequent distribution to its shareholders of its shares of common stock of Reorganized PG&E, do not 2
violate the prohibitions set forth in Section 305(a) of the FPA, or Section 12 of the NGA.
"* Confidential treatment to unredacted files that contain privileged or propriety material.
"* Concurrent approvals with the FERC under Sections 8, 204 and 205 of the FPA, and Section 7 of the NGA, to implement specific aspects of the Bankruptcy Plan.
"* A Final Order Approving PG&E's Application by the end of July 2002.
On December 12, 2001, the FERC issued its "Notice of Filing," setting until January 30, 2002, for the filing of interventions and protests in these dockets. The filing of the Section 203 Application is one part of a complex series of filings ("November 30 Filings") made by PG&E before the FERC as part of the implementation of PG&E's Plan. These filings are voluminous in nature-by PG&E's estimate, 20,000 pages.
The Plan was jointly filed by PG&E and the Parent with the Bankruptcy Court on September 20, 2001. PG&E's Plan involves a complex disaggregation of various businesses within PG&E and the spin-off of its distribution business to a Reorganized PG&E, which will be a separate company that will no longer be affiliated with the remainder of the disaggregated businesses. In effect, the current vertically-integrated PG&E will become a distribution company only and its generation, electric transmission and gas storage and transmission operations will be unbundled into separate companies that remain affiliated with one another under the Parent, but unaffiliated with Reorganized PG&E.
Under this Plan, only Reorganized PG&E will be subject to CPUC regulation. Indeed, as the CPUC has recently stated in its November 27, 2001 bankruptcy filing in response to PG&E's proposed disclosure statement:
Through its Plan and Disclosure Statement PG&E seeks to affect a regulatory jailbreak unprecedented in scope in bankruptcy annals.
Under the guise of section 1123(a)(5) of the Bankruptcy Code and through a misapplication of the debtor protection provisions of chapter 11, PG&E seeks sweeping preemptive relief primarily in 3
the form of no fewer than fifteen affirmative declaratory and injunctive rulings, each designed to permanently dislocate various state and local laws and regulations affecting PG&E's operation of its public utility. (Fn omitted). PG&E's Plan is concerned only secondarily with adjusting debtor-creditor relations and restoring its utility operations to financial health. To be sure, if those were PG&E's primary concerns, then it would have proposed a much more straightforward reorganization strategy. PG&E has as its own agenda an escape from CPUC and State regulation.'
II. THE STATUS OF THE BANKRUPTCY PROCEEDINGS Pursuant to an order of the Bankruptcy court, on December 19, 2001, PG&E filed its First Amended Disclosure Statement For First Amended Plan Of Reorganization ("Am. Discl. St."),
describing the extent to which the Plan relies on preemption of state law and regulation. The CPUC filed its brief on preemption with the Bankruptcy Court on January 8, 2002, and the CPUC's brief on preemption was attached as Exhibit B to the "Joint Parties' Motion To Dismiss Applications, Or In The Alternative To Hold Applications In Abeyance And For Extension Of Time To Intervene, Protest, And Comment, And For Expedited Action And Shortened Response Time" ("Joint Motion") filed on January 22, 2002 in Docket Nos. ER02-455-000 et. al.
PG&E's Am. Discl. St. makes an extraordinarily broad claim of preemption, touching on fundamental aspects of century-old utility law regulation. PG&E asserts that:
[t]he preemptive effect of the [proposed] Confirmation Order extends to all statutes, rules, orders and decisions of the CPUC otherwise applicable to the Restructuring Transactions and the implementation of the Plan. In the Proponents' view, the Confirmation Order supersedes any statute, rule, order or decision that the CPUC might interpret to otherwise apply to the Restructuring Transactions and the implementation of the Plan whether specified here or not.
See p. 3 of "California Public Utilities Commission's Objection to Proposed Disclosure Statement for Plan of Reorganization Under Chapter 11 of the Bankruptcy Code for Pacific Gas and Electric Company Proposed by Pacific Gas and Electric Company and PG&E Corporation," filed November 27, 2001, In re Pacific Gas and Electric Company, United States Bankruptcy Court Northern District of California, San Francisco Division, Case No. 01 30923 DM.
4
Am. Disci. St. at 129.
Specifically, PG&E asserts preemption of, among others, the following statutes, rules, decisions and regulations, which form the foundation of any state public utility code:
" Public Utilities Code §377: As amended in January 2001, § 377 requires the CPUC to "regulate the facilities for the generation of electricity owned by any public utility.., until the owner of those facilities has applied to the commission to dispose of those facilities and has been authorized by the commission under Section 851 to undertake that disposal" and provides that "no facility for the generation of electricity owned by a public utility may be disposed of prior to January 1, 2006. The commission shall ensure that public utility generation assets remain dedicated to service for the benefit of California ratepayers."
" Public Utilities Code §451: Like § 205 of the FPA, requires utility rates to be just and reasonable, and provides that "Every public utility shall furnish and maintain such adequate, efficient, just, and reasonable service, instrumentalities, equipment, and facilities.., as are necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public."
" Public Utilities Code §453: Provides in relevant part that "No public utility shall, as to rates, charges, service, facilities, or in any other respect, make or grant any preference or advantage to any corporation or person or subject any corporation or person to any prejudice or disadvantage."
" Public Utilities Code §701: Provides that: "The commission may supervise and regulate every public utility in the State and may do all things, whether specifically designated in this part or in addition thereto, which are necessary and convenient in the exercise of such power and jurisdiction."
" Public Utilities Code §701.5: Provides for CPUC regulation of certain public utility financing arrangements.
" Public Utilities Code §702: Provides that "Every public utility shall obey and comply with every order, decision, direction, or rule made or prescribed by the commission in the matters specified in this part, or any other matter in any way relating to or affecting its business as a public utility, and shall do everything necessary or proper to secure compliance therewith by all of its officers, agents, and employees."
"* Public Utilities Code §728: Similar to § 206 of the FPA, provides that "Whenever the commission, after a hearing, finds that the rates or classifications, demanded, observed, charged, or collected by any public utility for or in connection with any service, product, or commodity, or the rules, practices, or contracts affecting such rates or classifications are insufficient, unlawful, unjust, unreasonable, discriminatory, or preferential, the commission shall determine and fix, by order, the just, reasonable, or sufficient rates, classifications, rules, practices, or contracts to be thereafter observed and in force."
- Public Utilities Code §761: Along with §§ 762 and 768, provides for basic health, safety and reliability regulation of public utilities. The CPUC may order construction or modification of facilities or equipment, and changes to rules or services, in order to address "unjust, unreasonable, unsafe, improper, inadequate, or insufficient" utility rules, practices, equipment, appliances, facilities or service. Pub. Util. Code §§ 761, 762, 768. The 5
Commission may order changes in a utility's facilities to promote the security or convenience of employees or the public. Pub. Util. Code § 762. It may fix the utility's rules, practices, and service to promote safety, reliability, and other goals. Pub. Util. Code § 761. It may direct a utility to use particular safety devices (Pub. Util. Code § 768). The Commission may fix standards and services to be furnished by utilities. Pub. Util. Code § 770.
"* Public Utilities Code §816-830: These sections govern the issuance by a public utility of debt or equity securities, among other things requiring the approval of the CPUC prior to the issuance.
" Public Utilities Code §851: Similar to § 203 of the FPA, provides that CPUC approval is required for any public utility to "sell, lease, assign, mortgage, or otherwise dispose of or encumber" its property, including certificates of public convenience and necessity.
" CPUC Resolution L-244: Issued in 1994, this CPUC decision prohibits PG&E from "taking any action that would alter the jurisdictional status of PG&E or any division of PG&E or of the rates, services or facilities of PG&E's natural gas transmission system or storage system without first obtaining the Commission's approval."
As the CPUC's President Lynch has stated to the Bankruptcy Court, these laws and regulations "establish the fundamental relationship between the State of California and its regulated public utilities," including the "the utilities' basic obligation to provide electric and gas service to every California customer on a fair and non-discriminatory basis." See e Order Instituting Investigation Into the Power Outage et al., D.99-09-028, 1999 Cal. PUC LEXIS 635,
- 8-26 (1999). As discussed in the Joint Motion, the CPUC, the State of California representing other state agencies, and others have objected that PG&E's unlawful misuse of the Bankruptcy Code renders the Plan unconfirmable on its face. That is, under existing law, the Bankruptcy Court cannot lawfully approve the Plan as proposed. In particular, the Ninth Circuit has held in Baker & Drake Inc. v. Public Service Commission of Nevada, 35 F.3d 1348 (9th Cir. 1994), that the Bankruptcy Code does not preempt state statutes or regulations intended to protect the public safety and welfare. According to the Ninth Circuit, state statutes may be preempted by the Bankruptcy Code only if, at a minimum, they are directed narrowly and solely at economic regulation, and if certain other factors apply. The provisions of the Public Utilities Code that PG&E seeks to preempt protect the public safety and welfare, and accordingly preemption 6
(" cannot occur. That is true even if enforcement of the challenged provisions of state law would make a bankruptcy reorganization more difficult, or even impossible.
In addition, the CPUC has developed and is prepared to file in short order an Alternative Plan of Reorganization ("Alternative Plan"). Unlike the PG&E Plan, the Alternative Plan does not require disassembling the nation's largest public utility, and does not require either the Bankruptcy Court or FERC to reject the application of century-old state regulatory statutes critical to health, safety, and welfare of thirty million citizens. The Bankruptcy Court provided the CPUC until February 13, 2002 to provide the Bankruptcy Court with a term sheet demonstrating that the CPUC's proposed Alternative Plan is feasible. Upon review of the term sheet, the Bankruptcy Court will rule on whether the CPUC will be permitted to file the Alternative Plan.
A hearing on the preemption issues was held on January 25, 2002. The Bankruptcy Court has taken the matter under submission.
III. OVERVIEW OF PLEADING The CPUC moves to dismiss the Section 203 Application, and protests each of the requested authorizations at issue in the section 203 application. Dismissal is sought on the grounds that, inter alia: (1) the Section 203 Application is premature; (2) the transactions for which authorization is sought in the Section 203 Application and the related November 30 Filings contravene the public interest or otherwise violate the law, among other things violating fundamental provisions of state law and creating significant regulatory gaps; (3) PG&E has failed to comply with applicable FERC regulations, including 18 C.F.R. 33.2(e)(3); (4) serious environmental issues are implicated by the transfer of PG&E's hydroelectric facilities to non-7
-* regulated limited liability companies;2 (5) FERC cannot lawfully authorize the requested assignment of the Nuclear Decommissioning Trusts; and (6) the proposed Transactions violate
§ 305 of the FPA In the event that dismissal is not granted, the CPUC moves to consolidate the November 30 Filings, and that the consolidated proceedings be set for hearing. As the various dockets commenced by means of the November 30 Filings constitute interrelated parts of a single Plan, consolidation is warranted. In addition, significant issues having been raised in the instant pleading and the CPUC's contemporaneously filed pleadings in each docket, in the event that the proceedings are not simply dismissed hearings are necessary to fully evaluate whether PG&E's proposals are in the public interest and are otherwise lawful.
IV. MOTION FOR
SUMMARY
DISPOSITION The CPUC submits that the section 203 application must be summarily rejected in its entirety. First, the CPUC renews the arguments made in the Joint Motion for dismissing the Gen application as premature, or alternatively, holding this proceeding in abeyance, and incorporates 3
the Joint Motion herein by this reference.
Second, the Section 203 Application must be summarily dismissed on the merits, because the transactions detailed in the Plan, which are proposed to be implemented in part through the 2PG&E owns the largest private system of hydroelectric facilities in the nation. Consisting of 250 dams and diversions, 99 reservoirs with 2.3 million acre-feet of storage capacity and 200,000 acre-feet of consumptive water rights, and 68 powerhouses with 3,896 megawatts of generation capacity, the system controls Sierra and other rivers from Mt. Shasta to the Kings River Basin near Bakersfield. In addition, it includes 140,000 acres of associated lands.
3PG&E argues, in effect, that although its plan currently seeks to violate state law in numerous ways, it will become lawful if the Bankruptcy Court confirms the plan, including PG&E's request for a declaration that all applicable state law is preempted. This argument, if accepted, merely demonstrates why this application should be dismissed as premature. PG&E's own timetable does not contemplate execution of the plan for at least another eleven months.
And even if the Bankruptcy Court does ultimately confirm the plan, its legality still will be subject to years of appeals. At the present time, it is indisputable that the object of this application is unlawful, and unless and until the Bankruptcy Court states otherwise, and the judgment of the Bankruptcy Court is affirmed, PG&E's claims concerning the legality of this application are hypothetical and speculative at best.
8
(
- Section 203 Application, are contrary to the public interest, as expressed in both state and federal law and regulation. The purpose of the transactions at issue here is, inter alia, to allow PG&E to transfer its generation, electric transmission, and natural gas transportation assets to affiliates of PG&E Corporation, currently PG&E's parent. As to the electric generation assets, the proposed transactions directly violate both California statutory law and clearly expressed federal policy.
Both the California Legislature and FERC have recognized that the particular circumstances that obtain in California's energy markets at this time strongly dictate against a utility divesting itself of all of its own generation assets, as this application seeks authorization to do. As to the natural gas transportation assets, the proposed transactions similarly violate state law. In addition, the PG&E Plan violates numerous other state laws, both substantive and procedural. Moreover, the federal statutes under which these transactions are proposed demonstrate a keen respect for state regulation of public utilities, and cannot be utilized in the manner proposed herein.
In January 2001, the California State Legislature enacted Assembly Bill (AB) X1 6, which prohibits California's investor-owned utilities, including PG&E, from disposing of generation facilities that they own before January 1, 2006, providing in relevant part:
"Notwithstanding any other provision of law, no facility for the generation of electricity owned by a public utility may be disposed of prior to January 1, 2006." Cal. Pub. Util. Code § 377.
The application at issue here seeks FERC approval of transactions for the purpose of violating that statute, and numerous others. Accordingly, the object of the transactions that PG&E asks FERC to authorize in this proceeding is patently unlawful. Moreover, PG&E concedes that it has not and will not seek any authorizations from the CPUC. A partial list of the statutes that its plan violates is set forth above, including Cal. Pub. Util. Code § 851 (similar to FPA § 203, requiring CPUC approval for any disposition of utility property). Not mentioned in the PG&E 9
plan, though equally critical, is the attempted circumvention of the California Environmental Quality Act ("CEQA") Cal. Pub. Res. Code § 21000, et. seq., which is triggered under CPUC § 851 reviews. California has a strong interest in ensuring compliance with CEQA in order to weigh the potential environmental impacts of a proposed utility transaction and by doing so, ensure that the State protects its environment and inhabitants from unnecessary harm. PG&E's preemption claim attacks California's basic power to protect the public against the danger that a utility will fail to carry out its duties, or the danger that a utility transaction will have an adverse impact on the environment.
FERC has previously reached a conclusion similar to that reached by the California Legislature last January. In an order dated December 15, 2000, FERC noted that utility retained generation was an important factor in mitigating wholesale power costs, and thus in ensuring utilities' ability to provide required services. San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,294 (2000) at 62,001 (As a result of the order, "the IOUs will be able to provide power from their own resources to serve their own load .... The best way to mitigate cost exposure is for the IOUs to cease selling and repurchasing what they already produce"). FERC thus ordered PG&E to utilize its retained generation to serve its native load. Id. PG&E's Plan, in contrast, would effectively reverse this aspect of the December 15 Order, and leave the nation's largest utility virtually devoid of generating facilities.
Similarly, well-established California law and regulations prohibit the changes in status sought in Docket Nos. CP02-38-000 et al. for PG&E's natural gas transportation facilities in the absence of CPUC approval. 4 CPUC Resolution L-244, issued in 1994, prohibits PG&E from "4Decisions of the CPUC have the force of state law. Dyke Water Co. v. Public Utilities Corn. (1961) 56 Cal.2d 105, 123 (CPUC rule "had the force and effect of a statute"); Colich & Sons, et al. v. Pacific Bell (1988) 198 Cal.App.3d 1225, 1232, citing Dollar-A-Day Rent-A-Car System, Inc., v. Pacific Tel. & Tel. Co. (1972) 26 Cal.App.3d 454, 457.
10
"taking any action that would alter the jurisdictional status of PG&E or any division of PG&E or of the rates, services or facilities of PG&E's natural gas transmission system or storage system without first obtaining the Commission's approval." Resolution L-244 was premised on the CPUC's concern that such an action by PG&E "may engender significant adverse impacts on California citizens," including "the possibility that the Commission will be unable to ensure the provision of gas to homes, schools, and hospitals in the case of a supply or capacity crisis" and "the possibility that the pricing of gas service for captive customers will undermine the universal availability of affordable gas service for California citizens." PG&E has neither sought nor obtained CPUC approval for such a change.
PG&E acknowledges that the Plan violates state law. The Section 203 Application states, for instance, that:
"If the Debtor were not subject to the jurisdiction of the Bankruptcy Court, under the Public Utilities Code the approval of the CPUC would be required to transfer the generation assets from the Debtor to Gen and its subsidiaries or affiliates and to otherwise effect the Restructuring Transactions. In addition, Section 377 of the California Public Utilities Code states that the Debtor is required to retain its remaining generation assets through 2005.
Am. Discl. St. at 100.
The relief PG&E demands not only violates state law and FERC's December 15 Order, but would undermine Congressional intent to preserve the traditional police power of the states to the greatest extent Constitutionally permissible. Courts have repeatedly recognized the important role of state regulation of public utilities, and that federal law was meant to supplement and not to supplant state regulation of those utilities. The FPA and NGA were enacted to fill in gaps not covered by state regulation, not as a mechanism for avoiding state regulation of public utilities. In enacting Part H of the Federal Power Act, Congress did not purport to exercise all of the authority it might have exercised under the Commerce Clause, 11
because its intention was to preserve, not override, state regulatory jurisdiction. Conn. Light &
Power Co. v. Federal Power Comm'n, 324 U.S. 515, 529-30 (1945). To implement this intent, the "limitations established on [federal commission] jurisdiction ... were designed to coordinate precisely with those [the Attleboro line] constitutionally imposed on the states." United States v.
Public Utils. Comm'n of California, 345 U.S. 295, 311 (1953) ("U.S. v. CPUC"); Conn. Light &
Power, 324 U.S. at 525 ("Progress of the [FPA] bill through various stages shows constant purpose to protect rather than to supervise authority of the states."); Panhandle E. Pipe Line Co.
- v. Pub. Serv. Comm'n, 332 U.S. 507, 517-518 (1947) (NGA "was drawn with meticulous regard for the continued exercise of state power, not to handicap or dilute it in any way."); FPC v.
Southern California Edison Co., 376 U.S. 205, 213 (1964) ("The premise was that constitutional limitations upon state regulatory power made federal regulation essential if major aspects of interstate transmission and sale were not to go unregulated").
Both the FPA and the NGA are replete with provisions that demonstrate the Congressional concern that federal regulation not be used as a mechanism to avoid state regulation of public utilities. Section 201 of the FPA, for instance, is the basic provision providing for federal regulation of electricity. Section 201(a) provides that "the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate commerce is necessary in the public interest, such Federal regulation, however, to extend only to those matters which are not subject to regulation by the States." Section 201 thus explicitly provides for the continued exercise of traditional regulatory authority by the States. 5 See Conn.
Light & Power, 324 U.S. at 529-30.
FPA Sections 19 and 20 contain similar provisions. See also Section 204(f).
12
Similarly in enacting the NGA, Congress created a dual regulatory scheme which "carefully divided up regulatory power over the natural gas industry." Northwest Central Pipeline Corp. v. State Corp. Comm'n, 489 U.S. 493, 510 (1989). Congress "prescribe[d] not only the intended reach of the [federal power]," but also "specifie[d] the areas in to which this power was not to extend." Id.; Kentucky West Virginia Gas Co. v. Pennsylvania Public Utility Commission, 650 F. Supp. 659, 667 (M.D.Pa 1996). For instance, in § 1(b) Congress specifically stated that federal regulation "shall not apply.. . to the local distribution of natural gas." Northwest Central, 489 U.S. at 511 (Congress places express jurisdictional limits on federal powers in § 1(b) of NGA). Under Section 1(c), known as the Hinshaw Amendment, Congress similarly fenced off from federal regulation "any person engaged in the transportation in interstate commerce or the sale in interstate commerce for resale of natural gas received by such person from another person within or at the boundary of a state if all the ... gas... is ultimately consumed within such State." Congress expressly "declared [such regulation] to be
,6 matters of primarily of local concern and subject to regulation by the several States."
In the same vein is § 32 of the Public Utility Holding Company Act ("PUHCA"), enacted as part of the Energy Policy Act of 1992, 15 U.S.C. § Sec. 79z-5a(c). This section of the Energy Policy Act provides that:
If a rate or charge for, or in connection with, the construction of a facility, or for electric energy produced by a facility (other than any portion of a rate or charge which represents recovery of the cost of a wholesale rate or charge) was in effect under the laws of any State as of October 24, 1992, in order for the facility to be considered an eligible facility, every State commission having jurisdiction over any such rate or charge must make a specific 6 PG&E has continuously been a Hinshaw pipeline since 1954 and subject to CPUC regulation. PG&E is a local distribution company of natural gas regulated by the CPUC. See Cal. P.U. Code §§ 451,454, 785.5. PG&E's sales are sales for ultimate consumption by California consumers. As such, PG&E's sales and rates are exclusively regulated by the CPUC. See also the CPUC's contemporaneous filing in Docket Nos. CP02-39-000 et al.
13
( *determination that allowing such facility to be an eligible facility:
(1) ill benefit consumers, (2) is in the public interest, and (3) does not violate State law.
Section Sec. 79z-5a(c) not only contemplates recognition of state interests, but enshrines in federal law the principle that the state must affirmatively give its consent in order for a utility to effectuate a change in status of the kind sought here of any rate-based electric generating facility. 7 Here, of course, not only has PG&E not sought such consent, it seeks to transfer its generating facilities out of state regulation over the objection of its state regulator, and in the face of state law prohibiting the transaction.
Bankruptcy law in the Ninth Circuit, moreover, does not countenance the flouting of state law inherent in PG&E's Plan. The Ninth Circuit has held in Baker & Drake Inc. v. Public Service Commission of Nevada 35 F.3d 1348 (9 th Cir. 1994), that the Bankruptcy Code does not preempt state statutes or regulations intended to protect the public safety and welfare. According to the Ninth Circuit, state statutes may be preempted by the Bankruptcy Code only if, at a minimum, they are directed narrowly and solely at economic regulation, and if certain other factors apply. As discussed above, the provisions of the Public Utilities Code that PG&E seeks to preempt protect the public safety and welfare, and form the foundation of any system of public utility regulation. See also Northeast Utilities Service Company v. FERC, 993 F.2d 937, 945-46 (1st Cir. 1993) ("there is no evidence that the state regulators would have approved a plan to allow PSNH to emerge from bankruptcy that included only the first 'stand alone' step"); In re Nitec Paper Corp., 43 B.R. 492 (S.D.N.Y. 1984) ("a reorganization must be formulated within the bounds of existing state and federal law").
7 In apparent recognition of this fact, PG&E does not seek EWG status for the GenSub LLCs.
14
In sum, state law prohibits implementation of some of the transactions proposed in the Section 203 Application (and the related November 30 Filings) outright, and requires CPUC approval for others (which PG&E has not sought and says it will not seek). Federal public utility law recognizes the-continued importance and vitality of state regulation, and requires FERC to consider the expressed interest of the state in any determination that it makes. Federal bankruptcy law similarly forbids debtors and courts from overriding the state's expressed interest. Finally, FERC itself is on record as determining that PG&E's retained generation must be used to serve native load. These factors lead ineluctably to the conclusion that the transactions proposed PG&E's Section 203 Application are not in the public interest, and the Application should be dismissed.
V. ALTERNATIVE MOTION TO CONSOLIDATE NOVEMBER 30 FILINGS FOR HEARING The CPUC seeks dismissal of the Section 203 Application as set forth above, and seeks dismissal, on various grounds set forth in pleadings filed contemporaneously with the instant pleading, of each of the proceedings arising from the November 30 Filings. If the Section 203 Application is not dismissed, it and any of the other proceedings arising from the November 30 8
Filings which are not summarily dismissed should be consolidated and set for hearing.
The November 30 filings are interrelated pieces of a single coordinated program, intended to implement PG&E's Plan. No single docket among the November 30 Filings can be evaluated in isolation, any more than the various aspects PG&E's Plan could be evaluated singly.
8The dockets as to which dismissal, or in the alternative, consolidation and hearing, are sought are: ER02-455-000 (ETtrans); ER02-456-000 (Gen); CP02-39-000, CP02-40-000, CP02-41-000, CP02-42-000 (GTrans et al.); EC02 31-000, EL02-36, CP02-38-000 (Section 203); ES02-17 (Section 204); Project Nos.77-116, 96-031, 137-031, 175 018, 178-015, 233-082, 606-020, 619-095, 803-055, 1061-056, 1121-058, 1333-037, 1354-029, 1403-042, 1962 039, 1988-030, 2105-087, 2106-039, 2107-012, 2130-030, 2155-022, 2310-120, 2467-016, 2661-016, 2687-022, 2735-071, 233-081L1354-005, 2107-010, 2661-012, 2687-014, 2118-006, 2281-005,2479-003,2678-001, 2781 004, 2784-001,4851-004, 5536-001, 5828-003, 7009-004, and 10821-002 (Section 8).
15
( ! For instance, to fully evaluate the ETrans application in Docket No. ER02-455-000 consideration must also be given to the transfer of transmission assets and contracts proposed in the Section 203 Application. The contracts for which approval is sought in the ETrans Application flow from the dispositions proposed in the Section 203 Application. Similarly, the PSA proposed in the Gen Application cannot be fully evaluated without consideration of issues raised in the instant proceeding, since it is by means of this proceeding that PG&E proposes to transfer certain jurisdictional facilities necessary to support the PSA. Moreover, it is in this proceeding that the issue of whether PG&E's proposed transactions provide adequate compensation to PG&E will be raised.
Likewise, while the Section 8 Applications address only the requested approval to transfer hydroelectric project licenses, the Section 203 Application contains the associated request to transfer to Gen and its subsidiaries certain hydroelectric assets. That application additionally requests a disclaimer by the FERC of any jurisdiction under the FPA over the LLCs which are to hold the hydroelectric FERC licenses. Section 203 Application at 82-83. The Section 204 and 305 Applications request approval regarding the issuance of securities and the assumption of liability by Gen in connection with the transfer.
These applications will require coordinated review and scrutiny to adequately evaluate the difficult legal issues they raise and in order to ultimately determine whether PG&E's filings are in the public interest. Indeed, PG&E asks for "concurrent approvals" of its various November 30 Filings. Accordingly, the November 30 Filings should be consolidated. See Northeast Utilities Service Company v. FERC, 993 F.2d 937, 945-46 (1 st Cir. 1993) ("like the state regulators who approved the two-step plan, the Commission evaluated the plan as a whole").
16
( *FERC precedent supports setting related dockets of similar magnitude for consolidated hearing. See Northeast Utilities Company, 50 FERC ¶ 61,266 (1990) (establishing consolidated hearing procedures for several related proceedings proposed to implement a bankruptcy Plan of Reorganization for Public Service of New Hampshire). The CPUC has raised serious issues regarding whether, for instance, the contracts filed in the ETrans and Gen applications may be considered just and reasonable. Moreover, FERC's policy is to set § 203 proceedings for hearing if issues are raised by a state commission regarding the effect of the proposed transaction on state regulation. See e Ohio Edison Company, 95 FERC ¶ 61,178 (2001) (hearing not necessary because Ohio Commission had jurisdiction over the transaction and did not raise concerns about the effect on regulation); Merger Policy Statement, 77 FERC ¶ 61,263 (1996); Revised Filing Requirements Under Part 33 of the Commission's Regulations, 93 FERC 91 61,164 (2000). As set forth above, PG&E contends that the preemptive force of the Bankruptcy Code deprives the CPUC of the authority it would otherwise have over the transactions proposed in the November 30 Filings. And, as discussed in detail below, the Section 203 Application has serious detrimental impacts on both state and federal regulation, creating a significant regulatory gap with respect to, inter alia, PG&E's generation facilities. Accordingly, although the CPUC disputes PG&E's contention as to the preemptive force of the Bankruptcy Code, the CPUC does seek significant relief herein. Consequently, the November 30 Filings should be set for a consolidated hearing with attendant discovery opportunity and procedures consistent with Northeast Utilities Company. 50 FERC ¶ 61,266 (1990).
VI. THE AUTHORIZATIONS SOUGHT IN SECTION IV OF THE APPLICATION CONTRAVENE THE PUBLIC INTEREST The transactions proposed in the Section 203 Application raise serious concerns with respect to each of the three factors traditionally considered by FERC in a § 203 proceeding, 17
(. producing detrimental effects on competition and rates, and creating substantial regulatory gaps.
San Diego Gas & Electric Co. 79 FERC [ 61,372 (1997) ("SDG&E"). In addition, other factors relevant in this matter to any public interest determination weigh heavily against approval of the authorizations sought by PG&E. 18 C.F.R. 2.26(b). The Section 203 Application proposes that PG&E divest itself of its most valuable assets for a fraction of their value, while retaining billions of dollars worth of liabilities. Moreover, adequate protection of the public interest requires that the environmental implications of the proposed transactions be fully considered.
Finally, approval of the Section 203 Applications is inconsistent with the prompt emergence from Bankruptcy of PG&E. As in the SDG&E case, FERC must act in partnership with the state to assure that the public interest is fully protected. Each of these issues is discussed in greater detail below.
A. The Standard of Review FERC analyzes proposed dispositions under § 203 to determine whether they are "consistent with the public interest." Section 203 provides in relevant part:
(a) Authorizations No public utility shall sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $50,000, or by any means whatsoever.., merge or consolidate such facilities or any part thereof with those of any other person.., without first having secured an order of the Commission authorizing it to do so. Upon application for such approval the Commission shall give reasonable notice in writing to the Governor and State commission of each of the States in which the physical property affected, or any part thereof, is situated, and to such other persons as it may deem advisable. After notice and opportunity for hearing, if the Commission finds that the proposed disposition, consolidation, acquisition, or control will be consistent with the public interest, it shall approve the same.
18
(b) Orders of Commission The Commission may grant any application for an order under this section in whole or in part and upon such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest of facilities subject to the jurisdiction of the Commission. The Commission may from time to time for good cause shown make such orders supplemental to any order made under this section as it may find necessary or appropriate.
FERC primarily examines three factors in analyzing whether a proposed transaction is consistent with the public interest: (1) the effect on competition, (2) the effect on rates, and (3) the effect on regulation. FERC "may also consider other factors" in determining whether a proposed transaction is in the public interest. 18 C.F.R. 2.26(b).
FERC's discussion of these factors in the SDG&E/Enova-Pacific Enterprises merger proceeding is instructive. See San Diego Gas & Electric Co. 79 FERC ¶ 61,372 (1997)
("SDG&E"). In the SDG&E case, the holding companies of two of California's largest public utilities (SDG&E and Southern California Gas Co.) proposed to merge. FERC expressly referenced the CPUC's authority in considering each public interest factor. Under the first factor, "effect on competition" FERC looked at both vertical and horizontal market power.
FERC stated that "vertical mergers raise three types of general competitive concerns: (1) denying rival firms access to inputs or raising their input costs; (2) increased anticompetitive coordination; and (3) regulatory evasion." FERC concluded that the merger could have impacts on competition, and further concluded that most of the mitigation measures it thought necessary were within the CPUC's jurisdiction. Thus FERC conditioned its approval of the merger on the adoption by the CPUC of certain mitigation measures. Id. at 62,565. As to horizontal market power, FERC noted that consolidation of retail gas services of SDG&E and SoCalGas due to the merger could reduce competition, but held that "the California Commission, which also has 19
jurisdiction over this transaction, can adequately address this issue and has not requested our assistance in this regard."
Under the second fact, "effect on rates," FERC noted that the only issue appeared to relate to retail rates, a matter "more appropriately addressed by the California Commission." Id.
at 62,566.
Under the third factor, "effect on regulation," FERC's Merger Policy Statement discusses concerns relating to (1) creation of a regulatory gap as a consequence of a corporate realignment, or (2) shifts of regulatory authority between FERC and state commissions or the Securities and Exchange Commission (SEC). FERC found it dispositive in the SDG&E proceeding that "the California Commission has not raised concerns regarding impairment of its regulatory authority and will be able to approve or disapprove the merger. Therefore, regulatory authority would not be impaired by virtue of the proposed disposition of facilities." Id. at 62,566-67.
In the instant case, the CPUC's otherwise applicable authority to review the transactions proposed in the Section 203 Application and the related November 30 Filings has been challenged by the applicant, PG&E, which seeks to preclude the exercise of the CPUC's authority. Accordingly, the CPUC must seek the assistance of FERC. Under the circumstances, FERC cannot assume that the CPUC will be free to exercise its otherwise applicable authority to review the transactions and address effects on competition, rates, and regulation. Accordingly, FERC's review of the proposed transactions must be particularly searching.
In addition to providing a full and fair evaluation of whether PG&E's proposals are in the public interest under the FPA, FERC can, and should, help to ensure that all of the public interest considerations at issue here are fully evaluated. Section 203(b) empowers FERC to issue orders authorizing disposition of jurisdictional property "upon such terms and conditions as it finds 20
necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest." In this matter, FERC should expressly condition any approvals it may issue herein on similar approval by the CPUC of transactions within the CPUC's jurisdiction pursuant to the California Public Utilities Code.
Finally, in addition to the three traditional factors addressed in any § 203 proceeding, FERC should in this matter consider several other factors which bear on whether the transactions proposed herein are in the public interest. Those factors are:
(1) the failure of consideration embodied in these transactions; (2) the environmental impacts of the proposed transactions; and (3) whether approval of this Application is consistent with PG&E's prompt emergence from bankruptcy.
B. Effect on Competition The proposed transactions raise both vertical and horizontal market power issues. While arguing to the contrary, PG&E implicitly acknowledges as much-it places in a footnote the disclosure that its horizontal and vertical competitive screen analyses submitted with the Section 203 Application attribute 7,100 MW of generation facilities not to Gen, the proposed holder of those facilities in PG&E's brave new world, but to Reorganized PG&E. PG&E seeks to justify this treatment by asserting that the market power of Gen will be mitigated by the Purchase and Sales Agreement ("PSA") at issue in ER02-456-000. But, as PG&E surely realizes, the PSA is for twelve years, while the loss to PG&E of its hydroelectric and nuclear generating facilities under the Plan is forever. PG&E's competitive market screen analyses are invalid on their face, and cannot support PG&E's claims that the transactions will not have a detrimental effect on competition. 9 9The CPUC will address the competitive market screen analyses in greater detail in discovery and testimony should this matter be set for hearing. See also the CPUC's contemporaneous filing in Docket No. ER02-456-000 (Gen).
21
As one of the largest holders of natural gas transportation assets, electric generation assets, and electric transmission assets in the western United States, PG&E's corporate parent will be in a prime position to exercise market power both vertically and horizontally. In the upstream delivered gas market, as in the SDG&E case, PG&E/GTrans would control access to the natural gas necessary for gas-fired generating companies which will compete with PG&E/Gen, and will have access to potentially sensitive market information regarding those competing generators' costs and fuel usage. SDG&E, 97 FERC at 62,562. And Gen, which will control 7, 100 MW of generation (roughly 40% of the generation in the oft-constrained PG&E service territory), will clearly have market power in the California wholesale electric markets.
See the CPUC's contemporaneous pleading in ER02-456 for a more detailed discussion of Gen's market power.
In addition, FERC has previously addressed this issue, and held that the sale and purchase of PG&E's generation in the wholesale market had a detrimental effect on competition.
Accordingly, FERC ordered PG&E to use its retained generation resources-the same resources that it will "spin off' to its corporate parent in the proposed transactions-to serve its native load. San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,294 (2000) at 62,001 (As a result of the order, "the IOUs will be able to provide power from their own resources to serve their own load .... The best way to mitigate cost exposure is for the IOUs to cease selling and repurchasing what they already produce").
C. Effect on Rates The Merger Policy Statement explains that the protection of wholesale ratepayers and transmission customers is FERC's primary, but not sole, concern regarding the effects of a section 203 proposal on rates. Merger Policy Statement, at 30,123. Section 2.26 of FERC's regulations provides, under Effect on Rates, that "[alpplicants should propose mechanisms to 22
protect customers from costs due to the [transaction]." The PG&E Plan will, by design, have a significant impact on both wholesale and retail electric rates. For instance, under the PSA proposed in Docket No. ER02-456-000, Gen will charge unjust and unreasonable wholesale rates to Reorganized PG&E, which proposes to pass the rates through to its retail ratepayers pursuant to the filed rate doctrine. Reorganized PG&E will be stuck with a long-term contract at above market rates. See the CPUC's contemporaneous pleading in ER02-456-000, incorporated herein by this reference, for a more detailed discussion of this issue. Retail ratepayers will be stuck paying passed-through wholesale rates approaching double the otherwise applicable retail rate for the same energy from the same power plants.
-The "stable" rates which PG&E promotes as a virtue of its plan may have serious long term effects on California ratepayers and the California economy. These "stable" rates will result in overall retail rates over the next decade that rival those of the early 1990s, which engendered industrial users to begin the push for electric restructuring. Along with the above market CDWR contracts against which the PSA is "benchmarked," these "stable" rates will threaten the state with recession as large users leave the state or decline to enter it. The "stable" above-market rates of the PSA thus threaten residential ratepayers with the prospect of paying an ever-increasing share of the "sunk" costs of the PSA.
Accepting as true for the purposes of argument PG&E's contention that its current wholesale customers will be protected from the costs of the transactions, Reorganized PG&E itself will be a new wholesale customer as a result of the transactions, and the purported cost protection provided to existing wholesale customers is noticeably not provided to Reorganized PG&E. To the contrary, Reorganized PG&E will be subject to the overpriced PSA, and as discussed in greater detail in the CPUC's contemporaneous pleading in Docket No. ER02-455 23
(ETrans), Reorganized PG&E will be saddled with the worst of PG&E's existing transmission contracts, while profitable contracts are transferred to ETrans. In addition, the high rates which Reorganized PG&E is committed to pay under the PSA detrimentally affect its ability to resume serving its "net short" load, and increases the likelihood of further retail rate increases in order for Reorganized PG&E to do so.
D. Effect on Regulation PG&E's Plan and its implementation by means of the Section 203 Application would create very significant "regulatory gap[s] as a result of a corporate realignment," as well as "shifts of regulatory authority between the Commission and state commissions." Merger Policy Statement, at 30,124-25. Generally, federal regulation has primarily if not solely concerned wholesale rates, leaving the remaining bulk of regulation to the states. Gen. Motors Corp. v.
Tracy, 519 U.S. 278, 290-92 (1997). The most significant of the regulatory gaps which would result if PG&E's Plan were accepted include: (1) the proposed creation of a new interstate pipeline with contractual obligations to customers and vendors, but which eliminates the obligation to serve California retail customers, and eliminates health, safety and welfare regulation over these facilities; 10 (2) the creation of new entities owning 7,100 MW of California generation facilities which would be entirely unregulated, either by the FERC or by the CPUC, and the attendant elimination of health, safety, and welfare regulation over these facilities; (3) the elimination of regulation and oversight over PG&E's Nuclear Decommissioning Trust Funds, resulting in the potential for underfunding in one or more of the trusts, and compromising the safety of PG&E's nuclear facilities."I 10 See the CPUC's contemporaneous pleading in Docket Nos. CP02-39-000 et al., incorporated herein by this reference, for a detailed discussion of this issue.
See discussion, infra.
24
FERC has consistently held that the elimination of state regulation which proceeds from a proposed transaction constitutes a regulatory gap affecting the public interest. Merger Policy Statement, 77 FERC ¶ 61,263 (1996) ("commenters generally argue that it is important for the Commission to contirnte to look at the effect of a merger on the effectiveness of state and Federal regulation"); Enron Corporation, 78 FERC ¶ 61,179 (1997) (because "state and federal jurisdiction will remain static" pursuant to transaction, deferring action until after Oregon Commission has acted unnecessary); Niagara Mohawk Power Corporation, 89 FERC ¶ 61,124 (finding that "the proposed transaction will not adversely affect state regulation"); Niagara Mohawk Holdings, Inc., 95 FERC ¶61,381 (2001) ("we are also concerned with the effect on state regulation where a state does not have authority to act on a merger and has raised concerns about the effect on its regulation of the merged entity").
As the gas and nuclear issues are discussed extensively elsewhere (see footnotes 10 and 11), this section will focus on the regulatory gap with respect to PG&E's generating facilities.
PG&E asserts that as a result of the proposed transactions the GenSub LLCs will not be public utilities under either state or federal law, and will thereby entirely unregulated. PG&E's claim that the GenSub LLCs will not be public utilities under federal law is addressed further infra.
PG&E's contention that the GenSub LLCs will not be public utilities under state law apparently depends on the contention that by means of the proposed transactions the generating facilities which will be used in the same manner that they have traditionally been used, if PG&E is to be believed, and to serve the same customers with the same energy-will no longer be dedicated to public use.'2 Currently, PG&E's generating facilities are subject to the full range of state rate, 12 See Cal. Pub. Util. Code § 216; Richfield Oil Corp. v. Public Utilities Commission (1960) 54 Cal.2d 419, 426-31.
25
health, safety, welfare and reliability regulation. All safety and reliability regulation over the PG&E generating facilities would thus be lost if PG&E's Plan is implemented.
Furthermore, while Gen itself will be a public utility under federal law, under PG&E's Plan PG&E Gen would not be a public utility under state law. Accordingly there will be no regulatory body with health, safety, and welfare jurisdiction over the generating facilities. And while FERC would have a measure of regulatory authority over Gen's rates, the transformation from a vertical entity making retail sales to wholesale seller also entails a regulatory gap. The CPUC performs cost of service ratemaking, which FERC has held to be valuable in the December 15 order, while FERC generally does not.
-Finally, although the CPUC would retain jurisdiction over the distribution facilities and retail rates of the resulting Reorganized PG&E, by wholly separating generation from load (promoted as another virtue of its Plan by PG&E), the Plan and this Section 203 Application would seriously undermine PG&E's ability to reliably serve its load, and wholly undermine the CPUC's ability to ensure that PG&E do so, at least in the short term.
E. The Failure of Consideration PG&E's Section 203 Application is both incomplete for its failure to comply with Section 33.2(e)(3) of FERC's regulations, 18 C.F.R. § 33.2(e)(3), and, substantively, is not in the public interest because PG&E proposes to strip itself of its most valuable assets for insufficient consideration, to the detriment of both the resulting Reorganized PG&E and its ratepayers.
Section 33.2(e)(3) of FERC's regulations requires an applicant to discuss in a § 203 application "the consideration for the transaction." PG&E contends that "because this Transaction is not a sale of assets but rather a reorganization, the concept of consideration is not applicable." Application at 20. But PG&E provides no support for this contention, and FERC's regulations make no such exception. To the contrary, prior case law addressing transactions 26
related to bankruptcy reorganization have expressly addressed the consideration issue. See El Paso Electric Company, 68 FERC 61,181 (1994) at 61,893, 61,918. While PG&E has provided an Exhibit describing "the various financial transactions" associated with is Plan, PG&E fails to provide a narrative discussion of the transactions or their implications. For instance nowhere in PG&E's several thousand page filing does PG&E provide a single number indicating the value 3
of the cash and notes to be provided to Reorganized PG&E as a result of the transactions.'
PG&E's application is thus incomplete, and may be rejected on this basis alone.
An examination of the application reveals that the Section 203 Application and related Bankruptcy Court filings proposes transactions that fail to provide consideration to PG&E that can be considered in the public interest. The table below estimate the value of the assets to be transferred out of the PG&E utility under the Plan. No market valuation of the electric or gas transmission facilities have been made in Commission filings, but applying discounted cash flow valuation techniques and the plan's assumptions regarding net revenues to be derived from these assets, we obtain the following estimates:
13 PG&E states that Gen will provide Reorganized PG&E with $2.4 billion in exchange for transfer of the generating facilities, and numbers for the amounts to be provided by GTrans and ETrans are provided separately, but no total figure is provided.
27
Comparison of Estimated Values of Transferred Assets and Consideration to PG&E
($ billion)
Type of Asset Net Book Market Value Amount Returned to Loss to Utility Value Estimate Utility by Mortgaging Assets 14 Hydro Generation 0.59 2.8 - 4.116 Nuclear Generation 0.0 1.417 All Gen 0.59'5 4.2-5.5 2.4 1.8-3.1 Electric Trans 1.518 2.519 1.05 1.45 Gas Trans 1.720 1.519 0.9 0.6 TOTALS 3.79 8.2-9.5 4.35 3.85-5.15 As these figures demonstrate, PG&E proposes to divest itself of its gas transportation, electric transmission, and electric generating facilities for amounts that approximate the book value of the facilities. Although the corporate parent proposes to capitalize the new entities based on the market value of the facilities, and charge market-based rates to Reorganized PG&E under the PSA, the proposed consideration to PG&E for the facilities approximates half of their 14PG&E Amended Disclosure Statement, Exhibit E., 12/19/01.
"1PG&E I0-Q dated August 2, 2001 p. 25; value as of June 30, 2001.
16 Market value of 2.8 fixed by settlement agreement between PG&E, TURN, and other parties in A.99-09-053.
Market value of 4.1 estimated by PG&E in A.00-1 1-056, the rate stabilization proceeding.
17 Based on an average price per kW for the recent sales of the Nine Mile Point Unit 2, Indian Point Unit 2, and Millstone Units 2 and 3.
18 PG&E FERC Form 1, Vol. 1, 2000.
19 "Market values" for electric and gas transmission are estimated using discounted cash flow analysis over 25 years of service at an assumed discount rate of 8%. Net income estimates from Attachment C of the 8-K issued with the Plan. Note that the value of the gas transmission assets derived from this method suggests that the value to investors is approximately the net book value of the assets.
20 A.97-12-020 and PG&E FERC Form 1, Vol. 2,2000.
28
market value, and results in a staggering loss to Reorganized PG&, on the order of $4 to $5 billion dollars.
Even this calculation, however, understates the loss to Reorganized PG&E. In addition to the gas transportation, electric transmission, and electric generating facilities, PG&E proposes to transfer to its parent tens of thousands of acres of watershed and forest land associated with its hydroelectric facilities which are not encompassed within the FERC-licensed projects (the "non project hydro land"). This non-project hydro land is located primarily in the growing foothill regions of the Sierra Nevada, and will be subject to intense pressure for development (raising serious environmental concerns, as addressed in the CPUC's contemporaneous filing in the Section 8 applications, P-77-116 et al.). They are extremely valuable. Yet, apparently, Reorganized PG&E will receive nothing for the loss these lands, which will, in addition, be freed from CPUC regulation.
In addition, PG&E proposes to transfer its existing proprietary telecommunications network to ETrans or a subsidiary of ETrans called "Telco." See Application at 21; Exhibit I at 1-4. The proposed transfer includes "related controls and intellectual property rights... used to transport voice and data information." Id. These assets probably include existing wire and fiber optic cables, rights of way, and wireless licenses. Such assets all hold the potential to become highly valuable on the open market; the licenses in particular my prove to be highly lucrative, as the radio band they use has recently been made commercially viable for cellular telephone service. PG&E's belief in the commercial value of its telecommunications assets is demonstrated eg. in Pacific Gas & Electric Company, 90 FERC ¶ 61,314 (2000). Moreover, after the separation some of the telecommunications assets will then be leased back to Reorganized PG&E in whole or in part for profits at ratepayer expense.
29
On the other side of the ledger, the Section 203 Application proposes that Reorganized PG&E retain liabilities which logically would be transferred to ETrans. Reorganized PG&E is slated to hold the lion's share of PG&E's Existing Transmission Contracts ("ETCs"), and the ETCs assigned to Reorganized PG&E will be the most underperforming of the lot - including WAPA Contract 2948A, which PG&E has elsewhere alleged will cost PG&E on the order of
$1.8 billion before its 2004 termination. 2 1 The ETC allocation proposed in the Section 203 application, and the related "Back-to-Back agreement" proposed in Docket No. ER02-455-000 simply facilitate PG&E Corp.'s culling of the transmission wheat from the chaff, with the chaff falling to Reorganized PG&E while ETrans makes off with the wheat.
Ratepayers have funded, through the ongoing recovery in rates, depreciation, etc, under the benefits of monopoly regulation, the acquisition and construction of all of these assets. It fundamentally contravenes the public interest for PG&E to transfer these assets to its to-be unregulated corporate parent without assuring that ratepayers receive fair value in return, whether the transaction is proposed in the context of a Bankruptcy reorganization plan or in any other context. This Plan most assuredly does not provide ratepayers, or Reorganized PG&E, with fair consideration, and the Plan must be rejected as contrary to the public interest.
F. NEPA Review is Required for the November 30 Filings Adequate protection of the public interest requires FERC to conduct environmental review of the proposed hydroelectric project license transfers, and the related transfers proposed 22 herein, under the National Environmental Policy Act ("NEPA") 42 U.S.C. Section 4332(2)(C).
2t See letter dated March 27, 2001 to the FERC in Pacific Gas and Electric Company, FERC Docket EROI-1639 000, in which PG&E sought to amend, inter alia, Contract No. 2948A.
22 Environmental issues are discussed in greater detail in the CPUC's "Motion To Dismiss, Or In The Alternative, Protest, Request For Consolidation And Request For Hearing Of The Public Utilities Commission Of The State Of California", Project Nos.77-116 et al. ("the Section 8 protest"), filed contemporaneously, protesting PG&E's Section 8 Applications which seek the transfer of PG&E's twenty six hydroelectric project FERC licenses to newly 30
Although FERC regulations typically exclude from NEPA review applications under Sections 8, 203, 204, and 205 (18 C.F.R. Section 380.4(a)(15)& (16)), NEPA review is specifically warranted here by special circumstances recognized under 18 C.F.R. § 380.4(b)(2), and 40 C.F.R. § 1508.4.
Underlying the CPUC's contention that FERC should undertake NEPA review related to PG&E's Section 8 Applications is a Draft Environmental Impact Report (DEIR) prepared by the CPUC pursuant to the California Environmental Quality Act, Cal. Pub. Res. Code Sections 21000 et seq., in conjunction with PG&E's 1998 application before the CPUC to sell all of its hydroelectric assets and associated lands. While the DEIR reaches conclusions specific to transfer scenarios involving the hydroelectric projects, the CPUC's Section 8 protest notes the relationship between the Section 8 and Section 203, 204 and 205 applications which similarly warrant NEPA consideration.
The transactions contemplated in connection with the Section 203, 204, 205,and 8 applications at issue here are not typical or simple ownership transfers. Instead, the changes in ownership contemplated by, or inextricably intertwined with, these applications are massive, and it is reasonably foreseeable that these proposed transactions will have significant environmental consequences.
The separate applications in the November 30 Filings deal with separate but interrelated transactions, all of which are portions of a single overarching Plan of Reorganization. FERC is required to address them together in assessing the need for NEPA review. CEQ regulations provide that in preparing an EIS, all connected actions should be considered in one document.
40 C.F.R. § 1508.25. Actions are considered connected if they "cannot or will not proceed formed individual Limited Liability Company's ("LLCs"), and the subsequent lease of project properties to the newly formed LLCs' parent company, GEN. The CPUC incorporates the Section 8 protest herein by this reference.
31
unless other actions are taken previously or simultaneously" or are "independent parts of a larger action and depend on the larger action for their justification." Id. Under this standard, that PG&E's Section 8 applications, and indeed all of the November 30 Filings, are all connected for the purpose of NEPA review is beyond dispute. CEQ regulations further provide that in determining the significance of an action, "significance cannot be avoided by... breaking [an action] down into small component parts." 40 C.F.R. Section 1508.27(b)(7). See also Blue Mountains Biodiversity Proiect v. Blackwood, 161, F.3d 1208 (9th Cir. 1998) (Forest service was required to prepare single EIS that addressed cumulative effects of five salvage logging projects proposed for same watershed.)
In view of the above-stated considerations, the transfers proposed by PG&E in its Section 203 Application warrant and must be considered in the context of NEPA evaluation by the FERC.
G. Emergence From Bankruptcy PG&E contends that its prompt emergence from bankruptcy is in the public interest.
With this the CPUC agrees. This principle does not, however, support PG&E's request for hasty approval of the Section 203 Application. The Section 203 Application will not facilitate PG&E's prompt emergence from bankruptcy, since it attempts to implement a plan that, even if confirmed by the Bankruptcy Court, will inevitably be but the first step in lengthy litigation. To the contrary, the most likely means to PG&E's prompt emergence from bankruptcy, and restoration to creditworthiness, is embodied in the CPUC's proposed Alternative Plan. As discussed above, the CPUC will provide additional information to the Bankruptcy Court regarding the Alternative Plan on February 13, 2002, after which the Bankruptcy Court will determine whether to permit the filing of the Alternative Plan.
32
(.....Whileemergence from bankruptcy is clearly in the public interest, PG&E's Plan is not.
The Plan is simply too costly, in every sense of the word. It is too costly to PG&E's ratepayers, who will pay close to double the otherwise applicable rates under the PSA for the same energy from the same plants. See the CPUC's contemporaneous pleading in ER02-456-000 (Gen). It is too costly to Reorganized PG&E, stripped of its most valuable assets but saddled with liabilities its parent no longer wants. See the CPUC's contemporaneous pleading in ER02-455-000 (ETrans). It is too costly to the State of California, which would be stripped of basic tools necessary to protect the public health safety and welfare of its citizens (andlotentially bereft of funds necessary to ensure the safe decommissioning of two nuclear power facilities).
Haste in these proceedings, then, will not facilitate PG&E's prompt emergence from bankruptcy. For that, PG&E will be required to work with the state, rather than continuing to work against it.
VII. THE REQUEST FOR AUTHORIZATION TO TRANSFER NUCLEAR DECOMMISSIONING TRUST FUNDS MAY NOT LAWFULLY BE APPROVED BY FERC PG&E's request that FERC authorize the assignment of 100% of its beneficial interest in those portions of the CPUC Qualified and Nonqualified Nuclear Decommissioning Trusts (the "Trusts") "associated with" the Diablo Canyon Power Plant ("DCPP") to Diablo Canyon LLC cannot lawfully be approved by FERC. FERC should reject this request for the following reasons, each of which is discussed more fully below: (1) FERC does not have jurisdiction over these Trusts and accordingly cannot authorize their assignment; (2) to the extent that there is any FERC jurisdiction over the Trusts, the proposed assignment cannot be accomplished without approval of the CPUC; (3) to the extent that there is any FERC jurisdiction over the Trusts, it would be unjust and unreasonable to the California ratepayers who have funded these Trusts to authorize their assignment to a holding company that has no explicit obligation to those 33
( ratepayers and that could loot or exploit the Trusts' assets to its own advantage, and to the ratepayers' disadvantage; and (4) to the extent that there is any FERC jurisdiction over the Trusts, the Trusts provide funds for the eventual decommissioning of other PG&E assets specifically, Humboldt Bay Nuclear Unit No. 3 ("HB-3")--which will be retained by PG&E, as well as for the eventual decommissioning of DCPP; thus, on purely practical grounds, the proposed assignment will create serious difficulties and potential inequities in terms of allocating the Trusts' assets as between the needs of DCPP and those other assets.
A. FERC Lacks Jurisdiction to Authorize Any Assignment of PG&E's Interests in the Trusts Because the Trusts are not FERC-jurisdictional agreements, FERC has no authority to approve the transfer proposed by PG&E. PG&E asserts that the Trusts "consist of both CPUC jurisdictional and FERC jurisdictional trusts." However, PG&E provides no support for this assertion, either by reference to the Trusts themselves or in any other manner. To the contrary, PG&E apparently acknowledges the lack of FERC jurisdiction over the proposed transfer, stating that "[t]o the extent the Commisison may deem the transfer of such beneficial interest to be jurisdictional, Applicants are seeking Commission approval .... ." Application at 73. The Trusts were developed in a vertically integrated environment in which PG&E's nuclear facilities provided energy at retail to California consumers, under CPUC regulation. The Trusts themselves provide that they were established pursuant to the regulatory authority of the CPUC and the Nuclear Regulatory Commission ("NRC"). See also Cal. Pub. Util. Code §§ 8321 8330 (California Nuclear Decommissioning Act of 1985). The Trusts are not "facilities subject to the jurisdiction of the Commission" to which § 203 has any application. Cf. Enova Corp. and Pacific Enterprises, 79 FERC ¶ 61,107 (1997) at p. 61,489; Conoco, Inc. v. FERC, 90 F.3d 536 34
(D.C. Cir. 1996). Rather, any disposition of the Trusts must be pursuant to CPUC order, and to the extent applicable, NRC order.
PG&E claims that FERC authorization of the assignment of PG&E's beneficial interests in the portions of the Trusts associated with DCPP is "an essential element of the Transaction because it is necessary to permit Diablo Canyon LLC to become the owner of DCPP under the AEA [Atomic Energy Act, 42 USC § 2011 et §q.] and the NRC's implementing regulations ...
"Application at 74. PG&E is correct, of course, that the assignment of the DCPP portion (whatever that is) of PG&E's interests in the Trusts may be necessary under the Atomic Energy Act and NRC regulations to effectuate the transfer of DCPP to Diablo Canyon LLC, but FERC certainly does not have the authority to enforce the Atomic Energy Act or the NRC's regulations.
Nor does FERC have authority to "authorize" the assignment of PG&E's interests in the DCPP portion of these trusts to Diablo Canyon LLC or to any other entity.
This is true regardless of any order the Bankruptcy Court may or may not issue. In a footnote, PG&E indicates that it will ask the Bankruptcy Court to "compel" the CPUC to approve the transfer or to "deem" the approval to have been granted by the CPUC. Application at 74, n.57. However, the funds contained in the Trust are not subject to creditors' claims (except, of course, for claims relating to decommissioning activities for which a proper Disbursement Certificate is submitted to the Trustee)23 and are therefore outside the purview of the Bankruptcy Court. The Bankruptcy Court therefore has no authority to "break" the contact as part of its approval of a reorganization plan. See In re Nitec Paper Corp. 43 B.R. 492 (S.D.N.Y. 1984) (district court reversed order of Bankruptcy Court permitting the debtor to assign a contract in violation of both state and federal law). In any event, even if the Bankruptcy 23 See discussion infra.
35
(. Court may or indeed does issue an order of the type contemplated by the PG&E footnote, such an order would in no way increase FERC's jurisdiction, or change the non-jurisdictional status of the Master Trust Agreements. Accordingly, this portion of the Section 203 Application must be dismissed for lack of jurisdiction.
B. No Transfer of the Trusts May Be Accomplished Without the Approval of the CPUC The Master Trust Agreements that govern the management of the Trusts are contracts between the CPUC, PG&E and the Trustee, Mellon Bank, N.A. The Master Trust Agreements are, by their terms, irrevocable and not transferable. Section 2.07 of the Master Trust Agreement for the Qualified Decommissioning Trust (the larger of the two in terms of asset value) provides as follows:
"The interest of the Company [PG&E] in the Master Trust is not transferable by the company, whether voluntarily or involuntarily, nor subject to the claims of the creditors of the Company, provided, however, that any creditor of the Company as to which a Disbursement Certificate has been properly completed and submitted to the Trustee may assert a claim directly against the Master Trust in an amount not to exceed the amount specified on such Disbursement Certificate.
Nothing herein shall be construed to prohibit a transfer of the Company's interest in the Master Trust upon sale of all or part of the Company's ownership interest in any Plant or Plant's; provided, however, that any such transfer shall be subiect to the prior approval of the CPUC."
Section 2.06 of the Master Trust Agreement for the Qualified Decommissioning Trust sets forth identical language.
This Master Trust Agreements thus explicitly deny PG&E the authority to transfer its interest in the Trusts either voluntarily or involuntarily. The only exception is in connection with a sale of PG&E's ownership interest in the plant. However, in such a case, the Master Trust Agreement specifically provides that "any such transfer shall be subject to the prior approval of the CPUC." Thus, PG&E's effort via the Section 203 filing to request FERC to assign its interests in the Trusts to Diablo Canyon LLC, without first seeking the approval of the CPUC on 36
its face violates the terms of its contractual agreement and is accordingly a void and unlawful act.
Ultimately, PG&E's request that FERC "authorize" its assignment of its DCPP-related interests in the Trusts to Diablo Canyon LLCF is an idle and futile exercise. The one leading authority cited in section V of its Application, which deals with this issue, Niagara Mohawk Power Corp., 89 FERC ¶ 61,124 (1999) in no way supports PG&E's "authorization" request with respect to assignment of PG&E's DCPP-related interests in the Master Trust Agreements.
Indeed, if anything, the Niagara Mohawk decision undermines the basis for PG&E's request.
In Niagara Mohawk, the co-tenants of the proposed transferee of a majority interest in the Nine Mile Point II power plant protested the proposed transfer based on concerns that the proposed transferor might have insufficient funds to meet its portion of eventual decommissioning expenses, and complained in this regard that the transferor failed to seek FERC approval for the transfer of nuclear decommissioning funds. In its decision, the Commission found that there was no need to separately address whether such authorization was needed in that case, and noted that the financial ability of the proposed transferee to fund nuclear decommissioning was a matter to be addressed in an NRC proceeding. Moreover, in Niagara Mohawk, the Commission explicitly recognized that the proposed transaction was "subject to review by the New York State Commission, and no state commission has argued that the proposed transaction would impair state regulation." See 89 FERC, at 61,347. Thus, PG&E's citation to this Commission decision attempts to turn the plain language of the decision inside out. PG&E is attempting to use a finding that holds that the specific authorization of the transfer of decommissioning funds is a matter, not requiring specific FERC approval, for other agencies 37
(the NRC and presumably also the state) to decide into a pretext for de facto preemption of the state's clear contractual right to make that policy judgment.
C. Assignment of the Trusts' Assets Would Not Be in the Public Interest PG&E contends, without any evidentiary support or analysis, that the assignment of its beneficial interests in the portions of the Trusts associated with DCPP "is consistent with the public interest and is in the public interest." Application at 74. In fact, the opposite is closer to the truth. For instance, the U.S. General Accounting office has just released a report (GAO-02 048, January 2002) finding that the NRC has been approving licensing transfers and related decommissioning efforts even though new owners and operators are unable to assure regulators that the money for decommissioning will be there when reactors are ready for burial.
The specific question of whether the transfer of a nuclear decommissioning fund would be in the public interest, was examined in detail by the CPUC several years ago in a case, A.97 12-039, involving the application of San Diego Gas and Electric Company (SDG&E) for authority to sell its share of the San Onofre Nuclear Generating Station ("SONGS"). There, even SDG&E's partner in SONGS, Southern California Edison Co. ("Edison") expressed concern regarding the proposed transfer, questioning how ratepayers can be assured of protection if the decommissioning trust fund is dissipated by the new, non-utility owner after the transfer. (See RT of October 21, 1999 hearing in CPUC Docket A-97-12-039, at 22.) That question, an answer to which is not even suggested by PG&E in its voluminous Section 203 filing, is as cogent today in the context of the transfer that PG&E is requesting the Commission to authorize as it was 21/2 years ago in that SONGS proceeding. On November 5, 1999, SDG&E withdrew its request to divest its interest in SONGS. See In the Matter of the Application of San Diego Gas & Electric Company (U-902-E) for Authority to Sell Electrical Generation Facilities et al., D.00-10-054, 2000 Cal. PUC LEXIS 760 (2000).
38
( -, It should also be noted that California's decommissioning law is stricter than required by the NRC. Pursuant to the California Nuclear Facility Decommissioning Act of 1985 (Pub. Util.
Code sections 8321 through 8330), California's nuclear power plants generally have considerably more money in the decommissioning trust funds than in most other states, which typically comply only with NRC rules. Under this law, not only must more money be put into such funds (the maximum contribution allowed pursuant to section 468A of the U.S. Internal Revenue Code, and applicable regulations adopted pursuant thereto), but also California has the oversight authority to make sure that the decommissioning work gets done in a timely fashion.
Under CPUC oversight, to date, PG&E has been a good steward of the Trusts.
However, there is absolutely no guarantee that a Diablo Canyon LLC or some other entity that is not regulated by the CPUC would maintain that stewardship, and yet, the transfer of PG&E's "beneficial interest" in the portions of the Trusts associated with DCPP will effectively put much of the Trusts assets in the hands of such a less reliable and less trustworthy entity, over which, in PG&E's view, neither FERC nor the CPUC would have regulatory authority. Such an unregulated entity would have the incentive to delay performing the decommissioning as long as possible, in order to make as much money for itself, using ratepayer provided funds. It would not be in the public interest, and it would be unjust and unreasonable to PG&E's ratepayers, who have footed the bill for the eventual decommissioning of DCPP, to allow such a situation to arise.
D. The Impracticality of Assigning the Trusts' Assets Based on information contained in the most recent annual report (for calendar year 2000) from PG&E's Nuclear Facilities Decommissioning Master Trust Committee ("NFDMTC"), there is currently a total of some $1.462 billion of assets in the Trusts. It is important to note, however, that the Trusts are intended to cover decommissioning costs for the shut down of both 39
HB-3 and the DCPP units. By their terms, the Trust documents do not allocate any given amount of the funds controlled by the Trusts to either plant.
PG&E attempts to sweep this serious problem under the rug by blithely asserting in a footnote (at App. 73 n.56) that all of the funds in the Trusts associated with HB-3will be "segregated" from the DCPP components of the Trusts as part of the larger transaction that PG&E is requesting the Commission to approve. Unfortunately, nothing in PG&E's Section 203 filing indicates how this "segregation" will take place. Nor does PG&E explain how such a "segregation" is consistent with, or permitted by, the Trust documents.
Even if it is both lawful and achievable to so segregate the Trust funds, given the unpredictable nature of decommissioning activities, it would be unreasonable and impractical to attempt to allocate the Trusts into separate HB-3 and DCPP components without a detailed study of the likely scope of the decommissioning effort required for each facility. Such a study would be a lengthy, complicated and expensive endeavor. However, without a proper allocation of Trust assets to HB-3 and DCPP based on a prudent and thorough analysis of the likely costs of decommissioning for both facilities, there is a significant likelihood that one or the other of the facilities would have too little funds to properly complete decommissioning, thereby resulting, especially in the case of HB-3, in an unnecessary, unjust and unreasonable adverse impact on PG&E's ratepayers, and potential health safety and welfare concerns for California citizens.
Thus, assuming arguendo that FERC had the authority to divide the corpus of the Trusts and to assign some share of the Trusts' assets that would be allocated to DCPP to Diablo Canyon LLC (which, as we point out above, FERC clearly does not have the authority to do), it would be improper, imprudent and impractical for the Commission to do so absent the results of a detailed study which has not yet even been commenced.
40
VIII. THE PLAN VIOLATES SECTION 305 OF THE FEDERAL POWER ACT The Spin-Off transactions proposed in the instant application (the "Spin-Off") violate § 305 of the FPA.24 Accordingly, FERC cannot lawfully approve the Spin-Off, and the application should be summarily rejected. Section 305(a) provides:
It shall be unlawful for any officer or director of any public utility to receive for his own benefit, directly or indirectly, any money or thing of value in respect of the negotiation, hypothecation, or sale by such public utility of any security issued or to be issued by such public utility, or to share in any of the proceeds thereof, or to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.
The last clause of § 305(a) prohibits the payments of dividends by public utilities (and § 12 prohibits such dividends by natural gas companies) from any funds properly included in a capital account. There are two elements to the unlawful act: (1) payment of dividends; and (2) from funds properly included in a capital account. PG&E concedes that the Spin-Off satisfies both elements, and thus that its proposal violates sections 305 and 12. PG&E concedes that the Spin-Off includes the payment of dividends. See Application at 75 ("These dividends consist of
- ."). PG&E further concedes that the proposed dividends "must necessarily be deemed to be from a capital account." Application at 80.
Despite conceding that its proposal violates these strictures of the FPA, PG&E argues that FERC should not enforce the law against PG&E because the Congress did not mean what it said. Such a position cannot be countenanced. A federal agency does not have the luxury of ignoring the plain language of a federal statute. Circuit City Stores Inc. v. Adams, 532 U.S. 105 (2001). The "plain" in "plain meaning" means that a court looks to the actual language used in a 24 In addition, to the extent that PG&E is or becomes a natural gas company as a result of its applications in CP02 39-000 et al, thus making section 12 applicable to the Spin-Off, the Spin-Off violates section 12 for the same reasons as set forth in the text. As PG&E acknowledges, § 305 of the FPA and § 12 of the NGA are virtually identical. See Inexco Oil Co., 17 FERC 161,310 at 61,610 (1981). See also the CPUC's contemporaneous filing in Docket Nos. CP02-39-000 et al.
41
statute, not to the circumstances that gave rise to that language. CBS Inc. v. Primetime 24 Joint Venture, 245 F. 3d 1217 (11th Cir. 2001) If the meaning of the rule is perfectly plain from its language, that ends the inquiry. United States v. Alvarez-Sanchez, 511 U.S. 350, 356 (1994)
("When interpreting a statute, we look first and foremost to its text"); see also United States v.
Ron Pair Enterprises, Inc.,489 U.S. 235, 241-243 (1989; United States v. Bost, 87 F. 3d 1333, 1335 (D.C. Cir. 1996); Harbor Gateway Commercial Property Owners' Association v. United States EPA, 167 F. 3d 602, 606 (D.C. Cir. 1999).
PG&E argues, for instance, that the "intent" of § 305 was to prevent the failure to clearly identify the sources from which dividends were paid, and to prevent the payments of "excessive" dividends by holding companies on the securities of their operating companies. Application at
- 79. Whatever the merits of these assertions, what is clear is that that is not what the statute says.
Both sections 305 and section 12 of the NGA are clear and unambiguous on their face. The Congress prohibited the payment of dividends from funds properly included in any capital account. It is neither necessary nor permissible for courts, or in this case, FERC, to look behind the plain language of such a statute to discern a purportedly more relaxed "intent." The Supreme Court has made it clear that "given [a] straightforward statutory command, there is no reason to resort to legislative history." United States v. Gonzales, 520 U.S. 1,6 (1997); accord Circuit City Stores Inc. v. Adams, 532 U.S. 105 (2001); CBS Inc. v. Primetime 24 Joint Venture, 245 F. 3d 1217 (11th Cir. 2001); Pair, supra, 489 U.S. at 241 ("where, as here, the statute's language is plain, 'the sole function of the courts is to enforce it according to its terms"'). Where there exists "straightforward language [the court] cannot read the lack of specific legislative history confirming one possible application of a single provision in an enormous statutory structure to signify Congressional intent to exclude such an application." Blue Cross and Blue Shield of 42
Alabama v. Weitz, 913 F.2d 1544, 1549 (11th Cir. 1990). The reason is that "it is ultimately the provisions of our laws rather than the principal concerns of our legislators by which we are governed." Oncale v. Sundowner Offshore Servs., Inc., 523 U.S. 75, 79 (1998).
Here, the statutory language is unambiguous, and PG&E does not contend otherwise.
The statute prohibits public utilities from paying "any" dividends from funds (not solely cash dividends) properly included in capital accounts. This ends the inquiry. While the legislative history discussed in the application provides examples of abuses which § 305 may have been intended to address, that legislative history is entirely consistent with enforcement of the plain language of the statute, and can by no means "signify Congressional intent to exclude" enforcement of the plain language of the statute. Blue Cross and Blue Shield of Alabama v.
Weitz, 913 F.2d 1544, 1549 (11th Cir. 1990).
Prior FERC case law is of no assistance to PG&E. To the extent that such cases in fact decline to enforce the plain meaning of § 305 against filing utilities, they are wrongly decided, and should not be followed here. The CPUC is aware of no court case which has affirmed a FERC decision declining to enforce § 305. Even on their face, however, the cases cited by PG&E are distinguishable on their facts.
In Citizens Util. Co., 84 FERC ¶ 61,158 (1998) FERC approved a proposal to separate Citizens' communications business from its utility business. A stock dividend was involved.
Importantly, no intervenor challenged either the proposed transaction or the method by which Citizens proposed to accomplish the transaction. 25 Citizens' asserted that: (1) it was not proposing to make a dividend from funds properly included in a capital account; (2) it had 25 The Vermont Department of Public Service filed a protest "urg[ing] the Commission not to approve the transaction unless it is clear that utility ratepayers would not be disadvantaged," but did "not object to the spin-off per se." Id.
43
"accumulated sufficient undistributed earnings in its Proprietary Capital accounts, to support the proposed distribution;" and (3) "the proposed separation does not involve any of the financial abuses that section 305(a) was intended to prevent, i.e., misleading shareholders or raiding the company's earnings for the benefit of a holding company." FERC examined the legislative history of § 305, and concluded that none of the problems that reportedly led to the enactment of
§ 305 were present in that case.
Here, by contrast, none of the critical factual predicates which Citizens established are present. To the contrary, the problems which FERC concluded in Citizens had led to the enactment of § 305 are clearly present here. PG&E concedes that its proposed dividend is from a capital account. Application at 80. PG&E further concedes that it has "no retained earnings from which to 'pay' a dividend." Application at 80. Furthermore, this case does involve "raiding" the company's assets for the benefit of the holding company. PG&E's Plan of Reorganization, of which its corporate parent PG&E Corporation is a co-sponsor, and which would be implemented in part by the proposed Spin-Off, proposes to transfer critical utility assets to the holding company for a fraction of their value. See discussion, supra. Unlike Citizens, in which there was "nothing to indicate, and Vermont DPS has not alleged, that any dividends paid will be excessive," in this matter it is clear beyond dispute that the proposed "dividend" will far exceeds the value which Reorganized PG&E will receive in return, and are excessive as a matter of law. See also Delmarva Power & Light, 91 FERC 1 61,043 (2000). In Delmarva, FERC approved a similar transaction, but expressly limited its approval to "the circumstances of this case." Id. No party protested the application or even sought to intervene.
FERC found that the proposed dividend was not excessive.
44
Nor is Public Service of New Mexico, 93 FERC 61,213 (2000) of any help to PG&E. In PSNM, "a corporate separation [was] being performed to comply with a requirement of state law." No party protested the application. Here, by contrast, PG&E proposes the Spin-Off in direct defiance of, among other things: (1) state law prohibiting the disposition of utility-owned generation assets prior to 2006; (2) long-standing CPUC regulation (which has the force of law) prohibiting PG&E from taking action which would alter the jurisdictional status of its natural gas transmission and storage systems; and (3) state law requiring CPUC approval in the public interest of any proposed disposition of utility assets.
In what is apparently the only prior case in which the applicants' proposed interpretation of § 305 was challenged by intervenors, FERC refused to grant the application as proposed. In Niagara Mohawk Holdings, Inc., 95 FERC 61, 381 (2001) rejected applicants proposal which would not have "limit[ed] dividend payments to just the balance of retained earnings that will be transferred to capital accounts." Id. FERC's concern was premised on its conclusion that "dividends could exceed the balance in the retained earnings account." Id. FERC conditionally approved the proposal, but required applicants to make a compliance filing limiting the payment of dividends to the amount of retained earnings. Id. In PG&E's case there are no retained earnings at all.
IX. THE REQUEST FOR DISCLAIMER OF JURISDICTION OVER THE GENERATION LLCS SHOULD BE DENIED, AS THEY DO NOT QUALIFY FOR PASSIVE INVESTOR STATUS PG&E's attempt to avoid FERC public utility status under § 201 for the GenSub LLCs must be denied. As structured by PG&E, the relationship between Gen and the GenSub LLCs, fits no fact pattern under which FERC has disclaimed jurisdiction. Here, it is proposed that the GenSub LLCs own the hydro facilities, and hold the licenses. It is proposed that Gen "lease" the facilities-from subsidiaries Gen controls-and operate the facilities. PG&E cites no case where 45
FERC disclaimed jurisdiction under § 201 of the FPA of a wholly owned subsidiary acting as a "passiveinvestor/lessor that holds (1) Part I licenses for Projects, and (2) holds title to the generation facilities. FERC has disclaimed jurisdiction in cases where an LLC was created solely for the purpose of holding property, but not where the LLC held both the property and Part I licenses.
A request for disclaimer of FERC jurisdiction over entities taking title to jurisdictional facilities by way of sale and leaseback transaction was addressed in Pacific Power and Light Company. 3 FERC ¶ 61,119 (1978).16 In Pacific Power, the Commission established a two-step analysis for determining whether holding a financial interest in jurisdictional facilities constitutes ownership resulting in public utility status under the FPA. See Allegheny Energy Supply Company, LLC, 97 FERC ¶ 61,377 (2001); City of Vidalia, 52 FERC P61,199 (1990). Under that analysis, FERC must determine first whether the purported "passive participants" will operate the facilities. Second, FERC must be assured that a "passive participant" is not in the business of producing or selling electric power. In Pacific Power, FERC concluded that because the passive participant held mere equitable or legal title to the subject electric facilities and were clearly removed from the actual operation of the facilities and the sale of power, the passive participants were not public utilities for the purpose of § 201(e) of the FPA. See Pacific Power, at 61,377.
PG&E's GenSub LLCs fail both prongs of the Pacific Power test. First, each of the GenSub LLCs is to be controlled entirely by Gen. As to each of the GenSub LLCs, Gen is the "sole member" of the LLC. PG&E concedes that Gen will be a public utility under federal law.
26 There, the Commission granted a request for waiver of jurisdiction over financial institutions which took title to facilities as part of a leveraged lease transaction. The Commission found that the titleholders: (1) would not operate or control the operation of the jurisdictional facilities and (2) were not otherwise engaged in the business of selling or producing electric power, and that their principal place of business activity was other than that of a public utility.
46
The GenSub LLCs are no more than sham paper entities, entirely controlled by a public utility.
Effectively, Gen is the GenSub LLCs. Moreover, the lease agreements between Gen and each of the GenSub LLCs contain a "savings provisions" entitling the GenSub LLCs to take action at any time to assure compliance with FERC license conditions. Application at 83.27 Thus, it cannot be said that the purportedly passive participant is sufficiently remote from the operation or control of the facilities to meet the Pacific Power standard.
PG&E fails the second prong of the Pacific Power test as well, as the GenSub LLCs cannot be said to be "not in the business of producing or selling electric power." PG&E's reliance on Green Mountain Power Corp., 53 FERC ¶ 61,035 (1990) is misplaced. In Green Mcuntain, the "passive investor" was IBM. IBM was not in charge of operating or controlling the facilities and was not in the business of selling or producing power. See Pacific Power, 3 FERC at 61,337. Unlike IBM, which has a large and well known business unrelated to electric generation, the GenSub LLCs have no other business and no other purpose. Nor are the GenSub LLCs a bank which happens to have an ownership interest in a power plant. Moreover, the GenSub LLCs relationship to the facilities is not limited to "mere equitable or legal title to the subject electric facilities" nor are the GenSub LLC's "clearly removed from the actual operation of the facilities and the sale of power," since the GenSub LLCs will also hold the FPA Part I licenses. Gulf States Util. Co., 54 FERC ¶ 61,826 (1991), also relied on by PG&E, is similarly distinguishable on its facts.
Because the proposal fails both prongs of the Pacific Power test, PG&E's request for a disclaimer of jurisdiction over the GenSub LLCs should be denied. However, if FERC were to 27 Moreover, PG&E takes an inconsistent position in the Section 8 Applications, asserting that the lease agreements proposed therein should be approved because the "savings provision" gives the licensee sufficient control over operations to qualify as a licensee. See, e.g., Sec. 8 App. for P-2687 at 10.
47
disclaim jurisdiction over the LLCs, it should require that Gen be made a co-licensee of each applicable project.2S X. CONCLUSION For the foregoing reasons, the CPUC submits that the Section 203 Application should be summarily rejected in its entirety. The proposal is inconsistent with the public interest.
Moreover, even if the proposals could be considered in the public interest, critical portions of the proposed transactions-such as the proposed dividend discussed above-simply violate federal law, rendering the entire proposal infirm. Finally, if the Section 203 Application is not dismissed, PG&E's package of November 30 Filings intended to implement (or such of the proceedings which survive dismissal) should be consolidated and set for hearing.
Respectfully submitted, GARY COHEN AROCLES AGUILAR SEAN GALLAGHER IDA M. PASSAMONTI PAM NATALONI TODD 0. EDMISTER LARRY CHASET MICHAEL EDSON By: ,
SEAN GLAER Staff Counsel Attorneys for the Public Utilities Commission of the State of California 505 Van Ness Ave., Rm. 5124 San Francisco, CA 94102 January 29, 2002 Phone: (415) 703-2059 28 See the CPUC's contemporaneously filed pleading in the Section 8 proceeding, P-77-116 et al. That FERC require the LLCs and Gen to be co-licensees is consistent with City of Vidali, 52 FERC ¶ 61,199 (1990) and Oglethorpe Power Corp., 77 FERC ¶ 61,334 (1996), where both the "passive investors" and the lessees were co licensees.
48
CERTIFICATE OF SERVICE I hereby certify that I have this day caused the foregoing document to be served upon all known.parties in this proceeding by mailing by first-class mail a copy thereof properly addressed to each such party.
Dated at San Francisco, California, this 29th day of January, 2002.
Sean Gallagher/
EXHIBIT E UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Pacific Gas and Electric Company, Docket No. ES02-17-000 PG&E Corporation On Behalf of its Subsidiaries Electric Generation LLC, ETrans LLC and GTrans LLC MOTION TO DISMISS, OR, IN THE ALTERNATIVE, PROTEST AND REQUEST FOR HEARING, AND COMMENTS OF THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Pursuant to Rules 211, 212 and 217 of the Rules of Practice and Procedure ("Rules") of the Federal Energy Regulatory Commission ("FERC"), the Public Utilities Commission of the State of California ("CPUC") hereby moves to dismiss the application for lack of jurisdiction. In the alternative, if the application is not dismissed, the CPUC protests the filing made in the above-referenced docket, provides comments, and requests that FERC set the matter for hearing.
The CPUC is a constitutionally-established agency charged with the responsibility for regulating natural gas and electric corporations within the State of California. In addition, the CPUC has a statutory mandate to represent the interests of natural gas and electric consumers throughout California in proceedings before the Commission. The CPUC previously filed a Notice of Intervention in these proceedings on December 14, 2001.
110577
I. THE SECTION 204 APPLICATION On November 30, 2001, Pacific Gas and Electric Company ("PG&E") and PG&E Corporation ("Parent"), on behalf of its subsidiaries, ETrans LLC ("ETrans") and Electric Generation LLC ("Gen") (collectively, the "Applicants"), tendered a filing in the above referenced docket, seeking authorization under Section 204 of the Federal Power Act ("FPA") to issue a variety of securities and assume a variety of liabilities, and for a waiver of the Commission's competitive bidding and placement regulations. PG&E is a debtor pursuant to Title 11 of the U.S. Code. Applicants state that this filing has been filed in connection with PG&E's proposed "Plan of Reorganization under Chapter 11 of the Bankruptcy Code for Pacific Gas and Electric Company" ("Plan") jointly filed by PG&E and its Parent with the Bankruptcy Court on September 20, 2001. PG&E states in its application that it does not expect to seek approval of the Transaction by the CPUC.
On December 12, 2001, the FERC issued its "Notice of Filing," setting until January 30, 2002, for the filing of interventions and protests in these dockets. The filing of the Section 204 Application is one part of a complex series of filings ("November 30 Filings") made by PG&E before the FERC as part of the implementation of PG&E's Plan. These filings are voluminous in nature-by PG&E's estimate, 20,000 pages.
The Plan was jointly filed by PG&E and its Parent with the Bankruptcy Court on September 20, 2001. PG&E's Plan involves a complex disaggregation of various businesses within PG&E and the spin-off of its distribution business to a Reorganized PG&E, which will be a separate company that will no longer be affiliated with the remainder of the disaggregated businesses. In effect, the current vertically-integrated PG&E will become a distribution company only and its generation, electric transmission and gas storage and transmission operations will be 2
unbundled into separate companies that remain affiliated with one another under the Parent, but unaffiliated with Reorganized PG&E.
Under this Plan, only Reorganized PG&E will be subject to CPUC regulation. Indeed, as the CPUC has recently stated in its November 27, 2001 bankruptcy filing in response to PG&E's proposed disclosure statement:
Through its Plan and Disclosure Statement PG&E seeks to affect a regulatory jailbreak unprecedented in scope in bankruptcy annals.
Under the guise of section 11 23(a)(5) of the Bankruptcy Code and through a misapplication of the debtor protection provisions of chapter 11, PG&E seeks sweeping preemptive relief primarily in the form of no fewer than fifteen affirmative declaratory and injunctive rulings, each designed to permanently dislocate various state and local laws and regulations affecting PG&E's operation of its public utility. (Fn omitted). PG&E's Plan is concerned only secondarily with adjusting debtor-creditor relations and restoring its utility operations to financial health. To be sure, if those were PG&E's primary concerns, then it would have proposed a much more straightforward reorganization strategy. PG&E has as its own agenda an escape from CPUC and State regulation.1 II. THE STATUS OF THE BANKRUPTCY PROCEEDINGS The status of the PG&E bankruptcy proceeding is discussed in the CPUC's contemporaneously filed pleading in Docket Nos. EC02-31-000 et al., and incorporated herein by this reference.
III. FERC LACKS JURISDICTION TO APPROVE THE APPLICATION, AND THEREFORE SHOULD DISMISS THE APPLICATION.
Pursuant to section 204(f) of the FPA, FERC lacks jurisdiction to authorize the issue of securities or the assumption of liabilities by a public utility where the utility's security issues are SSee p. 3 of "California Public Utilities Commission's Objection to Proposed Disclosure Statement for Plan of Reorganization Under Chapter I I of the Bankruptcy Code for Pacific Gas and Electric Company Proposed by Pacific Gas and Electric Company and PG&E Corporation," filed November 27, 2001, In re Pacific Gas and Electric Company, United States Bankruptcy Court Northern District of California, San Francisco Division, Case No. 0 1-30923 DM.
3
regulated by a state commission. 16 U.S.C. § 824c(o; Kansas City Power & Light Co., 53 FERC
¶61,097, at p. 61,280 n.54. Here, applicant PG&E is a public utility organized and operating under the laws of the State of California. Applicants ETrans and Gen also will be public utilities under state law, once they commence operations. 2 Section 818 of the California Public Utilities Code vests in the California Public Utilities Commission authority to regulate Applicants' security issues, providing:
No public utility may issue stocks and stock certificates, or other evidence of interest or ownership, or bonds, notes, or other evidences of indebtedness payable at periods of more than 12 months after the date thereof unless, in addition to the other requirements of law it shall first have secured from the commission an order authorizing the issue, stating the amount thereof and the purposes to which the issue or the proceeds thereof are to be applied, and that, in the opinion of the commission, the money, property, or labor to be procured or paid for by the issue is reasonably required for the purposes specified in the order, and that, except as otherwise permitted in the order in the case of bonds, notes, or other evidences of indebtedness, such purposes are not, in whole or in part, reasonably chargeable to operating expenses or to income.
FERC, accordingly, lacks jurisdiction over this application, and must dismiss the proceeding.
The CPUC hereby moves for such dismissal.
In a footnote in its application ("App."), PG&E acknowledges this jurisdictional barrier, but argues that section 204(f) does not apply here because it has asked the bankruptcy court to declare preempted any and all state laws that might impede PG&E's reorganization plan. App. at 2 See Cal. Pub. Util. Code §§ 216, 217, 218.
4
6 n.9. 3 This argument lacks merit for at least two reasons.
First, unless and until the bankruptcy court grants PG&E's request regarding preemption, there is valid, enforceable state law regulating PG&E's security issues, and under section 204(f),
FERC simply lacks jurisdiction to grant or consider PG&E's application at this time.
Second, even if the bankruptcy court were to determine that there is an irreconcilable conflict between the Bankruptcy Act and state law, and accordingly declares state law preempted, such a declaration would have no effect on the Federal Power Act. It is axiomatic that the FPA was designed to supplement, not to supplant, state law, and reflects a clear Congressional preference for state regulation of utilities. See, e.g., Connecticut Light & Power Co. v. FPC,324 U.S. 515, 525-26 (1945). Section 204(f) embodies an explicit expression of Congressional intent that this Commission not act to regulate utility security issues where state law governing them exists. That the bankruptcy court might determine that there is a conflict between the Bankruptcy Act and state law - such that for the purposes of its bankruptcy jurisdiction state law is unenforceable - can have no bearing on the express statement of Congress in the Federal Power Act that public utilities seeking to issue securities must obtain permission from state commissions to do so, where the state has enacted legislation giving those commission authority to so regulate.
This Commission is governed by, and obtains its authority from, the Federal Power Act.
not the Bankruptcy Act or the bankruptcy court. Where Congress has spoken, FERC cannot 3 We note that Section 34.3(g) of the Commission's regulations requires an applicant for the issuance of securities to provide a statement as to whether or not any application with respect to the transaction or any part thereof is required to be filed with any State regulatory body. In Section G of its application (App. at 22-23), PG&E has blatantly misstated the relevant facts.
As noted above, Section 818 of the California Public Utilities Code unquestionably requires CPUC approval of the transaction. However, in note 9, PG&E waves off this indubitable fact of State jurisdiction over the transaction in question by a bald assertion that the Bankruptcy Court will rule in its favor on the very complex preemption issues that are currently before it.
5
ignore the mandate. Bankruptcy courts themselves recognize this important distinction. In In re:
Cajun Elec. Power Coop., 230 B.R. 715 (M.D. La. 1999), for example, part of the debtor's reorganization was to obtain Exempt Wholesale Generator ("EWG") status for some of its generation. Indeed, the bankruptcy court referred to this feature of the plan as "a strong condition precedent" to its consummation. Id. at 746. Normally, to acquire EWG status for certain facilities, the Public Utility Holding Company Act ("PUHCA"), 15 U.S.C. § 79z-5a, requires an applicant to obtain certain certifications from relevant state commissions. The debtor argued that because obtaining EWG status was a central feature of its reorganization plan, federal bankruptcy law should trump other federal law, and no state commission certification should be required.
230 B.R. at 746. The bankruptcy court disagreed, holding that where Congress, in PUHCA, had expressly conditioned obtaining EWG status on also obtaining state commission certifications, the debtor had to seek and obtain such certifications, even if that meant that its plan might not be feasible (if the state commission withheld its certification). Id. at 746-47.
Exactly the same reasoning applies here. Regardless of what the bankruptcy court says about state law in PG&E's proceedings there, this Commission cannot ignore the jurisdictional requirement of section 204(f).
IV. THE APPLICATION SHOULD BE DENIED ON THE MERITS.
If FERC declines to dismiss for lack of jurisdiction, it should deny the application on its merits. Under section 204, FERC can approve the application only if it determines that the securities issue or liability assumption: "(a) is for some lawful object, within the corporate purposes of the applicant and compatible with the public interest, which is necessary or appropriate for or consistent with the proper performance by the applicant of service as a public utility and which will not impair its ability to perform that service, and (b) is reasonably 6
necessary or appropriate for such purposes." 16 U.S.C. 824c(a). Here, PG&E's application fails virtually every prong of this standard: It is not for a lawful object, it is not compatible with the public interest, it will impair PG&E's ability to serve as a public utility, and the entire underlying transaction is neither necessary nor appropriate for the purposes to which PG&E points.
The purpose of the transactions at issue here is, inter alia, to allow PG&E to transfer its generation assets to an affiliate of PG&E Corporation, currently PG&E's parent. App. at 22. In January 2001, the California State Legislature enacted Assembly Bill (AB) X1 6, which prohibits California's investor-owned utilities, including PG&E, from disposing of generation facilities that they own before January 1, 2006, providing in relevant part: "Notwithstanding any other provision of law, no facility for the generation of electricity owned by a public utility may be disposed of prior to January 1, 2006." Cal. Pub. Util. Code § 377. The application at issue here seeks to have this Commission approve the issue of securities and assumption of liabilities for the purpose of violating that statute. Accordingly, the object of the transactions that PG&E asks FERC to authorize in this proceeding is patently unlawful, and the application must be denied.4 PG&E argues that the transactions will not impair its ability to perform its function as a public utility, because separation of generation, transmission and distribution businesses "has been approved by FERC because it furthers objectives related to competition." App. at 24.
However, the decisions cited in PG&E's application do not stand for the sort of radical unbundling of ETrans and Gen that PG&E seeks to accomplish through the November 30 4 PG&E argues, in effect, that although its plan currently seeks to violate state law in numerous ways, it will become lawlt the Bankruptcy Court confirms the plan, including PG&E's request for a declaration that all applicable state law is preem, App. at 23. This argument, if accepted, merely demonstrates why this application should be dismissed as premature. PG, own timetable does not contemplate execution of the plan for at least another eleven months. App. at 30. And even if the Bankruptcy Court does ultimately confirm the plan, its legality still will be subject to years of appeals. At the present tinik is indisputable that the object of this application is unlawful, and unless and until the Bankruptcy Court states otherwise, 8 the judgment of the Bankruptcy Court is affirmed, PG&E's claims concerning the legality of this application are hypotheti and speculative at best.
7
Filings. FERC has stated, e.g., that "we ... encourage utilities to explore whether corporate unbundling or other restructuring mechanisms may be appropriate in particularcircumstances."
See id. at 24 n.55 (emphasis added) (quoting Order 888). This does not say, and does not mean that all unbundling of utility assets will either "further objectives related to competition" or be in the public interest.
Applicants suggest that divestiture of generation and transmission assets from the utility is "encouraged by the Commission." App. at 24. Applicants point to an application by Southwest Gas Corp. 43 FERC ¶ 61,257 ("Southwest") (App. at 24 n.55) as evidence of the Commission's interest in such divestiture. Contrary to Applicants' suggestion, however, the Southwest decision had to do with regulatory jurisdiction, not with the wisdom of asset divestiture. A careful review of the Commission's decision in the Southwest case shows that it bears no resemblance to the present case. For example, in its Southwest decision, the Commission stated: "Reorganization would remove the possibility of dual regulatory authority over Southwest and would enhance the operation and delivery of services for the benefit" of its customers. (Emphasis added.) 43 FERC, at 61,709. Note that Applicants in this case make no claim, and can make no claim, of enhanced service as a result of its proposed divestiture. Thus, Applicants' reliance on the Southwest decision is misplaced.
The Applicants also point to this Commission's Order No. 888 as support for the Applicants' assertion that utility asset divestiture is encouraged by the Commission. In fact, Order No. 888 does not encourage such actions by utilities, but, instead, discusses the desirability of achieving functional unbundling of wholesale services in order to "implement non discriminatory open access transmission." FERC Stats. and Regs., at 3 1,654. Functional unbundling refers to the creation of separate tariffs for wholesale generation, transmission, and 8
ancillary services; the separation of transmission employees from those involved in wholesale power merchant functions; and the use of the same information system as its transmission customers use when buying or selling power.
In Order No. 888, the Commission said that other mechanisms, such as divestiture, "may be appropriate in particular circumstances." Id., at 31,656. However, Applicants in this case have not identified why these particular circumstances requires the "intrusive and potentially more costly mechanism" of divestiture. Id., at 31,655. Contrary to the implication urged by Applicants, in Order No. 888, the Commission stated "that corporate unbundling should not now be required." (Emphasis added.) Id.
As both the California Legislature and FERC have recognized, the particular circumstances that obtain in California's energy markets at this time strongly dictate against a utility divesting itself of all of its own generation assets, as this application seeks authorization to do. The California Legislature recognized as much when it enacted ABXI 6, prohibiting utilities from disposing of their remaining generation. FERC reached the same conclusion, when in an order dated December 15, 2000, it noted that utility retained generation was an important measure to be taken in mitigating wholesale power costs, and thus in ensuring utilities' ability to provide required services. San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,294 (2000) at 62,001 (As a result of the order, "the IOUs will be able to provide power from their own resources to serve their own load ... The best way to mitigate cost exposure is for the IOUs to cease selling and repurchasing what they already produce").
Moreover, the financial data submitted by applicants to support their contention that these transactions will leave them financially sound is wholly inadequate. It is not a coincidence that the vast majority of electric utilities are integrated, using the utility's own generation, 9
transmission and distribution assets. Such vertical integration has been found to yield beneficial economies in the provision of electric services. These are often referred to as economies of scope or economies of diversification.5 Sources of such economies are usually from the sharing of centralized functions such as management, planning, engineering, information technology, and general and administrative overhead. Section 854 of the California Public Utilities Code recognizes such economies and, in the case of the merger of utilities, requires that such economies be identified and quantified so that ratepayers might share in the savings engendered by the merger.
The quantification of the scope economies lost due to the divestiture of assets, especially assets that were designed and developed especially to work together efficiently to deliver services to a specific customer base, is difficult to analyze prior to the actual separation. Applicants have not submitted any cost studies or estimates covering the independent operation of the assets to be divested, if such studies or estimates have even been made. However, the Applicants propose to have the reorganized post-bankruptcy PG&E enter into a contract with Gen for the purchase of electric generation over the next twelve years. The price called for in this contract is 4.6 cents per kWh for the first year, and 5.1 cents per kWh on average for subsequent years. 6 Applicants estimate 33,000 GWh output for this contract in 2003. PG&E projects a total income from this contract of $1,471.5 million for the first year. However, the cost of producing the energy for this contract is only 2.5 cents per kWh, according to Applicants' own figures. See the CPUC's contemporaneous pleading in Docket Nos. EC02-3 1-000 et al. This represents an excess of nearly $700 million that Gen will receive over its costs for the first year. Assuming that See for instance William G. Shepherd, The Economics of Industrial Organization, Prentice Hall, fourth ed., 1997, p. 152:
Michael A. Crew and Paul R. Kleindorfer, The Economics of Public Utility Regulation, MIT Press, 1986, pp. 22-25.
6 PG&E Disclosure Statement for the First Amended Plan of Reorganization, p. 106.
10
ratepayers will pay 5.1 cents per kWh for years 2004 -2013, Gen will receive a surplus approximating $768 million per year or $8.3 billion for the first 11 years of the contract. This surplus represents a gigantic windfall to Gen at the expense of PG&E and its ratepayers.
Much of this difference between the average costs now experienced by the still-intact utility is undoubtedly due to market power that will be exercised by Gen; however, market power may not explain a price differential of 89%. It is likely that a portion of this difference is due to increased average cost, due mainly in turn to a loss of scope economies when the assets are divested by the utility. It is also true that some of this difference could be due to increased transaction costs engendered by the Plan, including the additional legal costs of obtaining authorizations from several overseeing and regulatory bodies. However, these transaction costs should be one-time and not reflected in out-years. Nevertheless, such costs are a measure of the inefficiency of the Plan and, combined with the additional market power and loss of scope economies, contribute to the conclusions that (1) the transfer of assets from the utility to Gen works against the public interest, and (2) there can be no basis for the Commission to find that the proposed transaction will leave the reorganized post-bankruptcy PG&E financially sound.
Applicants state that the reorganized utility and new companies Gen and ETrans "will be on a sound financial footing after the reorganization," and point to Exhibits C-2, D-2, and E-2 for proof of this assertion. However, these tables are very assumption laden, as Applicants acknowledge in Attachment 2 to the application. For example, p. 6 of Attachment 2 addresses expected operating expenses for Gen following execution of the Plan. Item 2.b states: "Normal expenses are based on the Company's historic level of spending prior to the passage of
[California Assembly Bill] 1890." However, this assumption ignores the loss of scope economy and the additional transaction costs (discussed above) due to the transfer of assets required by II
Applicants' Plan. Note that on page 6 of Attachment 2, Applicants provide only a definition of M&O and A&G expenses and do not provide the assumptions on which these numbers and projections are based in Exhibit D-2. Thus, even if these numbers are based upon an assumption of "normalcy" or linear projection from before the California restructuring legislation was passed, such assumptions ignore certain realities regarding costs resulting from the divestiture of assets from the utility.
Applicants state that "the Plan will improve the ability of Applicants to access capital markets. . ." App. at 25. Given the flaws indicated here regarding Applicants' projections of costs, it is impossible for Applicants to make such a claim. If profits are affected significantly, Applicants access to capital markets may be seriously flawed. In fact, given such flaws, it is likely that the alternate plan offered by the CPUC would provide more access to capital markets than the Plan proposed by the Applicant.
Of interest in this regard is the debt to equity ratio projected by the Applicants in Exhibit C-2. The second table entitled "Projected Balance Sheet of Reorganized PG&E" indicates that the projected debt to equity ratio is 56:44 at the end of 2002. It was reported recently at Bloomberg.com that "An energy company's debt should not outweigh its equity, if the business holds an investment grade credit rating . . ." according to Moody's analysts.7 "The sensitivity and volatility of the power markets and the financial markets as a result of what has happened in the sector have made us more sensitive and made us take a second look." Id. This suggests, contrary to the Applicants' assertions, that the Plan advanced by the Applicants would not leave the reorganized utility with significant access to capital.
"7"Moody's Says Energy Company Leverage should be Less than 50%," Terence Flanagan, Bloomberg, December 20, 2001.
12
PG&E next claims, "Each of the Applicants will continue to be subject to regulation with respect to its rates, financing, and disposition of facilities, either by the CPUC ... or by this Commission." This statement is far from true. Under PG&E's plan, Gen will not own any generation facilities itself; individual LLC subsidiaries of Gen will. PG&E has specifically requested that this Commission find that the individual LLCs will not be public utilities subject to FERC's jurisdiction. This request suggests that if one of the LLCs wants to dispose of the facility it owns, it, along with Gen, will argue that that disposition is not subject either to section 203 of the FPA, or to section 851 of the California Public Utilities Code. Furthermore, three of the hydropower facilities that these applications propose to transfer (namely, the Hamilton, Lime Saddle, and Coal Canyon facilities) currently are subject only to CPUC regulation, and do not possess FERC licenses. If these transactions are approved, the three facilities in question will be subject to no regulation whatsoever.
V. THE AUTHORIZATIONS REQUESTED IN THE APPLICATION CONTRAVENE THE PUBLIC INTEREST Finally, these transactions are patently not in the public interest. The transactions proposed in Applicants' Section 204 Application will produce detrimental effects on competition and rates, and will create substantial regulatory gaps. San Diego Gas & Electric Co. 79 FERC ¶ 61,372 (1997) ("SDG&E"). In addition, other factors relevant in this matter to any public interest determination weigh heavily against approval of the authorizations sought by PG&E. 18 C.F.R. 2.26(b). In its related Section 203 Application, PG&E proposes to divest itself of its most valuable assets for a fraction of their value, while retaining billions of dollars worth of liabilities.
Moreover, adequate protection of the public interest requires that the environmental implications 8 See pages 6-7 of the Executive Summary of the Draft Environmental Impact Report, which is attached to the CPUC's contemporaneously filed pleading in Project No.77-116, et al.
13
of the proposed transactions be fully considered. Finally, approval of this Section 204 Application and the related November 30 Filings would be inconsistent with the prompt emergence from Bankruptcy of PG&E. As in the SDG&E case, FERC must act in partnership with the state to assure that the public interest is fully protected. Each of these issues is discussed in greater detail in section VI of the CPUC's contemporaneously filed pleading in EC02-3 1-000 et al., the substance of which is incorporated herein by this reference.
VI. APPLICANTS' REQUEST FOR A WAIVER FROM THE COMPETITIVE BIDDING REQUIREMENTS SHOULD BE DENIED Finally, Applicants have requested an exemption from the competitive bidding requirements imposed by 18 C.F.R. § 34.2. Section 34.2 of the Commission's regulations requires that securities authorized under Section 204 of the FPA be issued through either a competitive bid or a negotiated placement. Competitive bids require at least two "prospective dealers, purchasers or underwriters," while negotiated offers require at least three such agents.
Applicants request waiver of these requirements.9 However, such an exemption is unnecessary and is not sufficiently justified by Applicants.
Applicants assert that if they are required to put the securities that are the subject of this application out to competitive bid, they will lose control of the timing of these offerings, causing potential buyers to require a risk premium to be added to the price. This is exacerbated by the structural complexity of the transactions proposed by the Applicants' Plan. See App. at 10. The Applicants want to be authorized to choose the method and specific underwriters appropriate to the "market conditions and other factors so as to maximize their access to capital markets and minimize their cost of funds." App. at 11.
9 Applicants refer only to "competitive bid requirements," without specific reference to the negotiated offers option. We assume that the Applicants consider both to be competitive and are asking for exemption from both.
14
However, Applicants have ignored that the purpose of Section 34.2 is to encourage the use of financial markets and competition to attempt to get the best price and terms for the utility.
To suggest that a private deal would yield a lower price and superior terms than a competitive process has not been supported by Applicants. Generally, financial markets are considered highly efficient, as long as entry is not impaired. It is not necessary to seek out "a small number of sophisticated investors" (App. at 12), as the financial market already relies on such sophistication and information, as well as on that provided by a large number of other analysts, to determine the correct and efficient price of an asset. This correct and efficient price is the price that will satisfy Section 34.2(3)(i) and (ii).
Moreover, the Applicants also do not explain why the timing of the offerings would result in a higher risk premium demanded by lenders. Other factors, such as the unrecognized additional costs to implement the Plan identified in this filing, may increase the risk in the eyes of the market, but the timing of the offering should not be one of them.
If there are underwriters familiar "with Applicants' financial situation and the energy industry.. ." (p. 11), they will come forward in the competitive process. If the Plan is "structurally complex," it is safer to rely on the discipline of the market to anticipate and discount problems than to expect management that has, with all due respect, an uneven record at best, to do a better job. We are left with the Applicants' unsubstantiated claim that they will make sure that the fees, commissions and expenses are comparable to market-determined costs (App. at 12).
The Commission should accordingly deny Applicants' request for an exemption from the competitive bidding requirements imposed by 18 C.F.R. § 34.2.
15
VII. CONCLUSION For all of the foregoing reasons, the application filed herein should be dismissed for lack of jurisdiction or, in the alternative, denied on the merits.
Dated: January 29, 2002 Respectfully submitted, GARY M. COHEN AROCLES AGUILAR MICHAEL M. EDSON LAURENCE G. CHASET By: /s/ MICHAEL M. EDSON MICHAEL M. EDSON Attorneys for the Public Utilities Commission of the State of California 505 Van Ness Ave., Room 5035 San Francisco, CA 94102 Phone: (415) 703-1697 16
EXHIBIT F UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Electric Generation LLC Docket No. ER02-456-000 MOTION FOR
SUMMARY
DISPOSITION, OR IN THE ALTERNATIVE, PROTEST AND REQUEST FOR CONSOLIDATION AND HEARING, OF THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Pursuant to Rules 211, 212, and 217 of the Rules of Practice and Procedure
("Rules") of the Federal Energy Regulatory Commission ("FERC"), the Public Utilities Commission of the State of California ("CPUC"), hereby protests the filing made in the above-referenced docket, and moves for the summary disposition of the application ("the Gen application"). In the alternative, if the Gen application is not summarily rejected, the CPUC requests that the proceeding be consolidated with PG&E's related November 30 Filings and set for hearing. The CPUC is a constitutionally-established agency charged with the responsibility for regulating natural gas and electric corporations within the State of California. In addition, the CPUC has a statutory mandate to represent the interests of natural gas and electric consumers throughout California in proceedings before the Commission. The CPUC previously filed a Notice of Intervention in this proceeding on December 14, 2001.
I. THE GEN APPLICATION On November 30, 2001, Electric Generation LLC ("Gen") filed an application with the FERC pursuant to Section 205 of the Federal Power Act, and Part 35 of FERC's 114610
regulations, an application for acceptance of a power sales agreement and interim code of conduct and grant of various waivers. Gen is currently a subsidiary of Pacific Gas &
Electric Company (PG&E). The filing of this application is one part of a complex series of filings ("November 30 Filings") made by PG&E before the FERC as part of the implementation of PG&E's proposed "Plan of Reorganization under Chapter 11 of the Bankruptcy Code for Pacific Gas and Electric Company" ("Plan") jointly filed by PG&E and its Parent with the Bankruptcy Court on September 20, 2001.
As detailed elsewhere,1 PG&E's Plan proposes to transfer PG&E's electric generation, electric transmission, and natural gas transportation facilities to PG&E's Parent, PG&E Corporation, leaving a Reorganized PG&E to emerge from bankruptcy as an underfunded distribution-only utility possessing only assets and liabilities not desired by the corporate parent. Included is a proposal to transfer all of PG&E's hydroelectric and nuclear generation facilities to Gen, and then to transfer Gen to the corporate Parent by means of an unlawful stock dividend in violation of § 305 of the FPA.2 Should the various proposed transactions culminating in the proposed "Spin-Off' be approved, PG&E proposes that Gen enter into a proposed Purchase & Sale Agreement ("PSA")
with Reorganized PG&E which is the subject of the instant proceeding. Under the PSA Gen proposes to sell all of the output of the (former) PG&E generation facilities to Reorganized PG&E for an eleven year period at an unjust and unreasonable price, approaching double the rates PG&E would receive for the output of the facilities in the absence of the proposed transactions, and justified only by the need to service the
' See CPUC pleadings filed contemporaneously in Docket Nos. EC02-3 1-000 et al., ER02-456-000, ES02-17-000, CP02-39-000 et al. and P 77-116 et al.
2 See CPUC pleading filed contemporaneously in Docket Nos. EC02-3 1-000.
2
unnecessary debt which Gen proposes to incur upon receipt of the facilities (the PSA output). 3 includes a twelfth year for approximately half of the facilities' Under this Plan, only Reorganized PG&E would be subject to CPUC regulation.
Indeed, as the CPUC has recently stated in its November 27, 2001 bankruptcy filing in response to PG&E's proposed disclosure statement:
Through its Plan and Disclosure Statement PG&E seeks to affect a regulatory jailbreak unprecedented in scope in bankruptcy annals. Under the guise of section 1123(a)(5) of the Bankruptcy Code and through a misapplication of the debtor protection provisions of chapter 11, PG&E seeks sweeping preemptive relief primarily in the form of no fewer than fifteen affirmative declaratory and injunctive rulings, each designed to permanently dislocate various state and local laws and regulations affecting PG&E's operation of its public utility. (Fn omitted). PG&E's Plan is concerned only secondarily with adjusting debtor-creditor relations and restoring its utility operations to financial health. To be sure, if those were PG&E's primary concerns, then it would have proposed a much more straightforward reorganization strategy. PG&E has as its4 own agenda an escape from CPUC and State regulation.
On December 13, 2001, the FERC issued its "Notice of Filing," setting until January 30, 2002, for the filing of interventions and protests in this docket. On January 22, 2002, the CPUC on behalf of Joint Parties including the California Electricity Oversight Board, the People of the State of California, and the California Resources Agency filed a Joint Motion seeking to have the November 30 Filings dismissed, or in the alternative, held in abeyance pending certain rulings of the Bankruptcy Court ("Joint 3 See "Joint Parties' Motion to Dismiss et al." filed January 22, 2002, setting forth the outlines of the CPUC's proposed Alternative Plan for PG&E to emerge from bankruptcy without dismantling the utility.
4 See p. 3 of "California Public Utilities Commission's Objection to Proposed Disclosure Statement for Plan of Reorganization Under Chapter I I of the Bankruptcy Code for Pacific Gas and Electric Company Proposed by Pacific Gas and Electric Company and PG&E Corporation," filed November 27, 200 1, In re Pacific Gas and Electric Company, United States Bankruptcy Court Northern District of California, San Francisco Division, Case No. 0 1-30923 DM.
3
Motion"). The Joint Motion requested that FERC issue a ruling granting the motion by January 25, 2002.
I. THE STATUS OF THE BANKRUPTCY PROCEEDINGS The status of the PG&E bankruptcy proceeding is discussed in the CPUC's contemporaneously filed pleading in Docket Nos. EC02-3 1-000 et al., and incorporated herein by this reference.
III. PROTEST AND MOTION FOR
SUMMARY
DISPOSITION, OR IN THE ALTERNATIVE, TO SET THE PROCEEDING FOR HEARING The CPUC protests the Gen application and each of the authorizations and approvals requested. The CPUC's preliminary review of the Gen application discloses strong indications that the pricing, terms and conditions of the PSA are not just and reasonable, as discussed further below. The CPUC accordingly requests that the Gen application be dismissed. In addition, with additional time and formal discovery rights, the CPUC is likely to be able to identify additional issues not expressly discussed below.
Accordingly, if the Gen application is not dismissed, FERC should set this matter for hearing without limiting parties to any other issues which may be raised. In addition, FERC should consolidate PG&E's November 30 Filings for hearing.
A. The Gen Application Should be Dismissed The CPUC renews the arguments made in the Joint Motion for dismissing the Gen application as premature, or alternatively, holding this proceeding in abeyance, and incorporates the Joint Motion herein by this reference. In addition, the Gen application should be dismissed pursuant to § 35.3(a) of FERC's regulations. Section 35.3(a) requires that rate schedules be tendered no more than 120 days prior to the date on which service is to commence. In the instant proceeding, PG&E has tendered the PSA as a rate 4
schedule thirteen months prior to the earliest date on which it anticipates service may commence. While FERC has on occasion waived the 120 day requirement, good cause for waiver is not present in this matter. To the contrary, and as set forth in greater detail in the Joint Motion, the Gen application is premature and should be dismissed in order to avoid the expenditure of very substantial resources both by the parties and FERC, all of which may be rendered moot by rulings of the Bankruptcy Court expected in fairly short order.
Moreover, the substantive issues raised below support summary rejection of the Gen application. PG&E has wholly failed to meet the standards applicable to power sales agreements between affiliates. Under the circumstances here, the applicable standards must be applied with extraordinary scrutiny. The PSA was not reached at arm's-length by entities with competing interests, but rather were developed by the same counsel working simultaneously for all the (affiliated!) parties, one of which is essentially non existent. PG&E concedes that the PSA was developed, on behalf of both the "buyer" and "seller" by a single "Team [which] developed the price, terms and conditions of the PSA." Ex Gen-l (Kuga Testimony) at 11.
Finally, the PSA proposed in this docket is part and parcel of a coordinated set of applications which in whole and in part are contrary to the public interest as expressed in both state and federal law. For the reasons set forth in greater detail in the CPUC's contemporaneous pleading in Docket Nos. EC02-3 1-000 et al., the Gen application must be dismissed on this basis as well.
5
B. The Rates in the Proposed PSA Are Unjust and Unreasonable to Reorganized PG&E and its Retail Customers Who Will Foot the Bill The heart of the Gen application is PG&E's contention that the rates in the proposed PSA are just and reasonable to Reorganized PG&E on the basis of a "benchmark" analysis conducted by witness Meehan. As set forth in detail below, PG&E's "benchmark" analysis misses the mark. First, the rates in the proposed PSA must properly be evaluated not against other long-term power transactions, but rather against the rates which PG&E would receive in the absence of the proposed Spin-Off and related transactions. That is, the proposed PSA rates must be compared against the CPUC's rates for Utility Retained Generation. Second, even if it is appropriate to measure the proposed PSA against "comparable" wholesale transactions, PG&E's benchmark analysis fails to establish that the proposed PSA rates are just and reasonable.
Third, PG&E fails to provide a cogent analysis of its market power. Consequently, PG&E fails to establish that the price and non-price terms and conditions of the PSA are just and reasonable, and that the PSA is not fatally tainted by self-dealing.
- 1. The Proposed PSA Rates Must be Evaluated in Comparison with Otherwise Applicable Rates Under PG&E's proposal, Gen will sell the output of the electric generation facilities currently owned and operated by PG&E to Reorganized PG&E, which would in turn resell the facilities' output to its retail customers. In the absence of the transactions proposed in PG&E's Plan, PG&E would retain the electric generation assets which it proposes to transfer to Gen and the GenSub LLCs, and would continue selling the output 6
5 of the generation facilities directly to its retail customers. Under either scenario PG&E's retail customers will receive the same energy and Ancillary Services from the same facilities. Thus, the appropriate comparator against which to measure the PSA is the utility-retained generation ("URG") component of PG&E's retail rates.
Under current California law and CPUC policy, such rates are determined on a traditional cost-of-service basis. See e.g. Application of San Diego Gas & Electric Company et al., D.01-12-015, 2001 Cal. PUC LEXIS 1072, *7 ("We intend to apply cost based ratemaking to all of SDG&E's retained generation assets... which we believe is consistent with ABXI 6"); Application of Southern California Edison Company et al.,
D.01-01-061, 2001 Cal. PUC LEXIS 30 ("PG&E, SDG&E and Edison shall establish a cost-based rate for URG"). The CPUC has expressly rejected PG&E's request to set its URG revenue requirement based on market valuation rather than cost-of-service.
Application of Southern California Edison Company et al., D.01-10-067, 2001 Cal. PUC LEXIS 959 ("We determine that market valuation does not apply to setting a prospective revenue requirement for PG&E's URG assets").
PG&E's witness Meehan states that the levelized price over the twelve-year period of the PSA is approximately $52.29/MWh. Application at 4. Elsewhere PG&E asserts that the average price under the contract over the life of the contract is approximately 5.1 cents/kWh ($5 1/MWh). Application at 3. That the contract costs are unjust and unreasonable as to Reorganized PG&E (and to its retail ratepayers) is confirmed by PG&E's own numbers. In its Plan, PG&E projects revenues under the discussed in greater detail in the Joint M otion and in the CPUC's contemporaneously-filed pleading in Docket Nos. EC02-3 1-000 et al., the CPUC has formulated an Alternative Plan under which PG&E would be able to emerge from bankruptcy without disposing of its electric generation assets.
7
contract of approximately $1.5 billion annually. For calendar year 2003, PG&E projects revenues under the contract of $1,471,500,000. See Exhibit A hereto (Ex C. to Plan, at 10). Based solely on the numbers presented by PG&E in its Plan, PG&E's revenue requirement based on traditional cost-of-service principles would be approximately
$790.4 million for 2003-about half of PG&E's projected revenues. This translates to an illustrative rate of approximately 2.5 cents/kwh.6 This calculation proceeds as follows: PG&E's Plan projects total operating expenses for Gen in 2003, including depreciation, of $759.7 million. From this figure is subtracted "other income" of $88.9 million, leaving net operating expenses of $670.8 million. To this is added a rate of return and taxes of $119.6 million, calculated utilizing PG&E's projected 2003 net plant shown in the Plan of Reorganization for the nuclear and hydro assets of $913.8 million and PG&E's rate of return grossed up for income tax authorized by the CPUC of 13.09%.7 This results in an illustrative cost-of-service revenue requirement for Gen, using PG&E's own figures, of $790.4 million for 2003.
The illustrative cost-of-service revenue requirement of $790.4 million is 53.7% of the proposed revenues PG&E would receive under the PSA in 2003 of $1,471.5 million.
PG&E asserts that rates under the PSA in 2003 would be approximately 4.6 cents/kWh.
Since, as PG&E asserts, revenues of $1,471.5 million equates to 4.6 cents/kWh on 6 This pleading does not purport to determine the rate which the CPUC would actually set for PG&E's URG for any particular customer or class of customers, but simply utilizes figures provided by PG&E to provide, for illustrative purposes, a rough calculation of a cost-of-service rate based on such figures.
7 PG&E's Plan shows higher figures for return, interest expense, and taxes, totaling $800.8 million, because the figures reflect and are being used to support the borrowing of over $2 billion to help pay off creditor claims. The $119.6 million in the calculation above includes interest expense on the net plant of $913.6 million, as it is based on a 13.09% weighted average rate of return that includes interest and taxes. See PG&E work papers submitted in CPUC Docket No. A.00- 11-038, Scenario 1.
8
average, the cost-of-service revenue requirement is approximately 2.5 cents/kWh on average (.537 x 4.6 cents/kWh) for 2003. 8 While a rate of 2.5 cents/kWh is low compared to recent prices for gas-fired generation, the rate reflects the resource mix utilized for the PSA and PG&E's actual costs-not including the cost of unnecessarily borrowing over $2 billion. PG&E's hydroelectric resources are highly depreciated. PG&E's nuclear and hydro pumped storage resources have been subject to accelerated depreciation during the transition period established under California's deregulation law. Ratepayers have paid several billion dollars of accelerated depreciation through California's Competitive Transition Charge, and would be losing a good portion of what they paid for under PG&E's Plan of Reorganization. See also the proposed decision addressing PG&E's revenue requirement for utility-retained generation ("the URG PD") recently issued by a CPUC ALJ (a 9
proposed decision has a status somewhat analogous to a While these figures may be subject to some refinement, this illustration demonstrates that the PSA is grossly overpriced. If the PSA were approved as proposed, PG&E's ratepayers would make some $700 million in excess payments to Gen over and above the otherwise applicable rate for the same energy from the same facilities in 2003.
Over the life of the PSA, the overpayments approximate $8 billion.
aA recent report issued by the consumer group TURN estimates the "Expected Price Under Regulation" at approximately 2.5 cents/kWh in 2003, and 2.9 cents over the term of the PSA. See "Highway Robbery:
Unmasking the PG&E Bankruptcy Plan's Financial Impact on California Consumers," available at http://www.turn.orn/turnarticles/PG&E report.pdf.
9 California law generally requires the CPUC's proposed decisions to be released for comment prior to a Commission vote. See Cal. Pub. Util. Code § 31 I(d), (g). The URG PD is available from the CPUC's web site, at http://www.cpuc.ca.gov/published/comment decision/ 12655.htm. An alternate proposed decision of Commissioner Lynch is available at http://www.cpuc.ca.gov/published/Ayenda decision/ 12659.htm.
9
- 2. PG&E's Benchmark Analysis is Invalid Assuming arguendo that the benchmark analysis utilized by FERC in connection with previous affiliate transactions is applicable, PG&E's benchmark analysis, supported by the testimony of witness Meehan, is invalid for a number of reasons, discussed below.
FERC has articulated standards pursuant to which it will accept power sales contracts between affiliates in a series of three orders over the past ten years. Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991) ("Edga"); Ocean State Power IL, 59 FERC $61,360 (1992), reh'g denied, 69 FERC ¶ 61,146 (1994)
("Ocean State"); Ameren Energy Mktg. Co., 96 FERC ¶ 61,306 (2001) ("Ameren"). In E FERC stated that such arrangements will be permitted if two conditions are satisfied. First, FERC requires a showing that there exists no potential abuse of self dealing or reciprocal dealing. Second, if there has been a showing of no potential abuse of self-dealing or reciprocal dealing, FERC has found that market-based rates may be acceptable if the seller can also demonstrate that it lacks market power (or has adequately mitigated its market power), under familiar principles. Edgar, 55 FERC at 62,167.
As PG&E recognizes, the potential for self-dealing is present here, where the seller under the proposed PSA is essentially non-existent, and the terms and conditions of the PSA were developed by a single entity acting on behalf of both the putative seller and buyer. The risk of self-dealing is at its height in this transaction, in which the buyer under the proposed PSA would, if PG&E's Plan is confirmed, be stripped of all of its most valuable assets and the affiliate relationship then terminated.
FERC has articulated three means by which lack of self-dealing or reciprocal dealing may be shown, to ensure that an affiliated "buyer has chosen the lowest cost supplier from among the options presented, taking into account both price and nonprice 10
terms (i.e., that it has not preferred its affiliate without justification"). Edgar, 55 FERC at 62,168. PG&E has chosen to present "benchmark evidence" of market value, i.e.
evidence of other relevant power sales agreements between non-affiliates, which it claims demonstrates that the PSA is not unreasonable. See Application at 14 ff. Under the Edgar line of cases, the benchmark sales must be: (1) transactions in the relevant market; and (2) should be contemporaneous with; and (3) involve service that is comparable to, the instant transactions. In addition, FERC requires that the benchmark analysis examine nonprice as well as price terms, and assumptions used in comparing the various projects should be explained with respect to both price and nonprice terms. Finally, the applicant must demonstrate that the benchmark evidence was not distorted by exercise of market power by the seller or its affiliates. Ocean State, 59 FERC at 62,333. FERC has observed that it must "take into account the evolving nature of our analyses of market based affiliate transactions," including changes to the national generation market. Ocean State, 59 FERC at 62,332.
PG&E contends that the relevant market is "the market for firm, long-term baseload and peaking capacity and energy for a duration of approximately 10-15 years with a start date expected near January 2003," and that the relevant region must be limited to suppliers which can deliver energy to PG&E. Application at 17. PG&E contends that the relevant "contemporaneous" period is May 2000 through November 2001. Application at 18. By so attempting to confine the analysis, PG&E contends that the appropriate benchmark sales are nine long-term contracts entered into by the California Department of Water Resources ("DWR") during 2001.
11
PG&E's Reliance on DWR Contracts In confining its benchmark comparison to the DWR contracts, PG&E has sought to define as the relevant period precisely the same period in which the California wholesale electricity markets exhibited extreme dysfunction. PG&E has previously characterized this as a period of "massive market failure and upheaval in the regulatory regime that has led to billions of dollars in overcharges since May 2000.1° Similarly, PG&E has attempted to confine its benchmark comparison to DWR contracts, the negotiation of which PG&E has previously contended were subject to the exercise of market power, and as to which PG&E has contended FERC ought to order refunds."I As PG&E stated in its Request for Rehearing of FERC's July 25, 2001 order (San Diego Gas
& Electric Company, et al., 97 FERC 61,275 (2001), filed in Docket No. ELOO-95 on August 24, 2001, at 12:
the DWR bilaterals... have drawn the most attention.
These transactions are not bilateral purchases in the conventional sense with a willing buyer and a willing seller. Rather, they reflect the state stepping into the shoes of insolvent utilities as the default buyer of power in order to backstop the ISO's efforts at maintaining reliability in a dysfunctional market."
PG&E's reliance on the DWR contracts for its benchmark analysis is fatal. The DWR contracts were negotiated and executed during a period of extreme exercise of market power, as FERC has acknowledged on repeated occasions. FERC has expressly recognized that the exercise of market power in the spot markets extended to the forward
'0See PG&E's Request for Rehearing of FERC's July 25, 2001 order (San Diego Gas & Electric Company, et al., 97 FERC 61,275 (2001), filed in Docket No. ELOO-95 on August 24, 2001, at 19.
"1FERC has not found any specific DWR contracts to be "just and reasonable." See, e.g., GWF Energy, 97 FERC 61,297 (200 1), slip op. at pp. 3-4.
12
2 markets during the time period to which PG&E seeks to confine the analysis. 1 Thus, the DWR contracts cannot be relied on to be a benchmark of market value in a competitive market, and cannot be relied on to demonstrate that the PSA reflects a competitive market value.13 The Relevant Market In Ocean State FERC indicated that a benchmark analysis should consider as the geographic market suppliers that can supply the relevant product to the buyer. Ocean State, 59 FERC at 62,333. However, FERC also expressly stated that its analysis and holding in Ocean State were confined to the facts of that proceeding. Ocean State, 59 FERC at 62,338 n. 117. In this proceeding, it is inappropriate to consider only a geographic market centered on PG&E's service territory. First, as discussed above, an analytic limitation to contracts in PG&E's California service territory focuses the analysis on an environment of acknowledged market power.
Second, a broader geographic market is appropriate in this case due to the nature of the PSA. The PSA is a long-term agreement with a delayed implementation date.
Developed in 2001, it is proposed that the PSA run from January 2003 through 2014.
The market for such contracts is decidedly national, not regional. That is, a seller need not be physically located in California in 2001 in order to provide power under a 12 year contract commencing in 2003. Because of the long duration and delayed implementation date, a seller would have sufficient time to build new facilities to satisfy all but the 12 San Diego Gas & Electric Company, et al., 93 FERC ¶61,121 (2000) at 61,358 ("higher spot prices in turn affect the prices in forward markets"); San Diego Gas & Electric Company, et al., 95 FERC ¶ 61,418 (2001), at 62,556 (expanded spot market mitigation plan "will, over time, impact bilateral and forward markets as well"); see also AEP Power Marketing, Inc., 97 FERC ¶ 61,219 (2001).
"1Only a competitive market value is relevant to a section 205 just and reasonable analysis, as "tihe prevailing price in the marketplace cannot be the final measure of 'just and reasonable' rates mandated by the Act." FPC v. Texaco, 417 U.S. 380, 397 (1974).
13
earliest segments of the twelve year period. Certainly long-term capital markets are national, as are long-term natural gas markets.
That the long term market for electric generation is essentially national rather than regional is confirmed by an examination of regional pricing for forward electricity contracts. During the height of the California crisis western forward prices were substantially higher than forward contracts at other national trading hubs-as much as an order of magnitude higher. Since FERC's summer 2001 orders restored a measure of stability to western markets, however, forward contract prices at various regional hubs have tended to converge. For instance, as of December 12, 2001 (when the notice was issued in this proceeding) the simple average of reported futures prices for calendar year 2002 were $30.66 for the California-Oregon border ("COB"), $34.25 for PJM, and
$30.80 for Cinergy.14 Longer term prices should show similar convergence-a point which the CPUC will develop should this proceeding be set for hearing. As the relevant market for products similar to the PSA is a national rather than regional market, and PG&E analyzes only a corrupted regional market, PG&E's benchmark analysis fails to satisfy the "relevant market" prong of the benchmark analysis.
Contemporaneousness PG&E's benchmark analysis similarly fails to satisfy the "contemporaneous" prong articulated in FERC's prior cases. PG&E examined only contracts "entered into between May 2000 and the date of this Application." Application at 18. Witness Meehan's benchmark analysis focuses on nine contracts entered into between February and August 2001 as his "comparison group." Application at 21-22. As discussed above, 14 See www.enerfax.com. By late January 2002, prices in all three markets had declined.
14
this is precisely the period in which all energy transactions in the California markets were tainted with market power. It is patently unreasonable to consider only such contracts.
Moreover, this period is not contemporaneous with the period in which the PSA was developed. PG&E filed its Plan with the Bankruptcy Court on September 20, 2001. It filed the instant application on November 30, 2001. The key event in this scenario is the order issued by FERC on June 19, 2001, which quickly restored a semblance of stability to the California markets. All of the contracts in witness Meehan's "comparison group" no later than June 22, 2001.15 were either executed or had an executed letter of intent That is to say, the negotiation of all of the comparison group contracts took place in the market power period. By the fall of 2001 when the PSA was developed, forward contract prices in California had already begun to converge with forward prices in regional markets across the country, at prices well below the prices in the PSA. PG&E has thus failed to examine any contemporaneous contracts in its benchmark analysis.
In Ocean State FERC approved a benchmark analysis which considered as the relevant period late 1987 into 1989, "reflecting the period during which the purchasers made their decisions to contract with Ocean State II." Ocean State, 59 FERC at 62,334.
PG&E provides no similar justification for the period it has chosen. Certainly PG&E makes no claim that that the roughly eighteen month period it has selected for examination represents the only, or even the most relevant, time period in which buyers seeking energy for the 2003-2014 period would have, or did, engage in negotiations.
The CPUC has no principled objection to a "contemporaneous" period of roughly eighteen months. But PG&E has disingenuously selected the precise 18 months in which 1SSee California State Auditor, "California Energy Markets: Pressures Have Eased, But Cost Risks Remain," 193-195, Table 10. The report is available at http://www.bsa.ca..ov/bsa/pdfs/2001009.pdf 15
the California market was at its most dysfunctional. Were there no long-term power contracts entered into in the western United States in the first quarter of 2000? In the last quarter of 1999? Or, for that matter, in the truly contemporaneous period-third and fourth quarter 2001? The "contemporaneous" period selected by PG&E is invalid on its face, particularly when coupled with the limited geographical market also selected by PG&E. Rather, FERC must acknowledge changing market conditions. Any valid benchmark analysis must, if not be limited to, certainly include an examination of contracts executed during a period of relative market stability. Such a period could include, for instance portions of 1999 and 2000, and the latter third of 2001. Evidence as to whether and to what extent buyers sought long-term contracts for period comparable to the PSA during these periods can be presented at hearing.
Comparability As PG&E observes, FERC has held that benchmark evidence must encompass "4similarservices when compared to the instant transaction." Edgar, 55 FERC at 62,129; Ocean State at 62,333. PG&E's benchmark analysis fails this requirement as well. In the instant case, the PSA provides for capacity and energy from approximately 7,100 MW of hydroelectric and nuclear power plants. The size of the PSA alone disqualifies each of the purported "comparison group" contracts from consideration as comparable. Witness Meehan admits that he must treat each of the comparison group contracts as "infinitely scalable" in order to make a comparison. Application at 27; Ex Gen-2 (Meehan Testimony) at 16.
In Ocean State the applicant provided comparison evidence relating to 33 projects. FERC confined its analysis to the ten projects which were "comparable to 16
Ocean State II with respect to size and technology." Ocean State, 59 FERC at 62,334.
Similarly, in Edgar, FERC rejected a benchmark showing in part due to the applicant's failure to evaluate the proposed rates against truly comparable projects. Edgar, 55 FERC at 62,169 ("Boston Edison's comparison of projects [against a 306 MW combined-cycle generating unit] includes projects as small as 0.7 MW and powered by wind, wood, waste, peat and hydropower"). Here, of course, the facilities proposed to support the PSA are exclusively hydroelectric and nuclear generating plants. The "comparison group" contracts, to the extent that they have any specific source of generation attached to them, are exclusively natural gas-fired units. The PSA is for some 7,100 MW. Only one of the comparison group contracts is within the same order of magnitude. The 16 nor technology to the PSA.
comparison group contracts are comparable in neither size Price The foregoing establishes that PG&E's benchmark analysis fails to establish the absence of self-dealing in the development of the PSA. As such, the PSA may not be accepted. E , 55 FERC at 62,170. Moreover, the proposed rates in the PSA are simply too high to be considered just and reasonable. For instance, the capacity charges in the first year of the PSA amount to $170.75/kW-year. Ex Gen-1 (Kuga Testimony) at
- 6. Specifically, the capacity charges are $20.50/kW-mo for the peak months of July and August, $15.25/kW-mo for June, September, and October, and $12/kW-mo for November through May. The capacity payment is paid on a portfolio of 7,100 MW of capacity. Id. at 5. Thus the capacity payments alone under the PSA, in the first year, 16 PG&E declines to provide benchmark evidence regarding "buy-back" agreements executed in recent years in connection with sales of nuclear facilities in New York, or with fairly large hydroelectric portfolios elsewhere in the U.S.
17
amount to over $1.2 billion, and escalate to nearly $1.5 billion in year eleven. Ex.
Gen- l-1.
FERC recently addressed another power sales agreement between affiliates in Ameren Energy Mktg. Co., 96 FERC ¶ 61,306 (2001) ("Ameren"). The contract is for a minimum of 350 MW of capacity and energy per hour from June 2001 through May 2002. In the affiliate contract at issue in Ameren, the maximum capacity charge is
$4/kW-mo. The minimum capacity charge in PG&E's PSA exceeds that by 300 per cent.
The CPUC will address additional specific price terms in the PSA in testimony 7
should this matter be set for hearing.'
Non-Price Terms and Conditions The CPUC will address specific non-price terms and conditions in the proposed PSA in testimony should this matter be set for hearing, and expects to raise issues relating to water risk, availability, and dispatchability, among others.
At this juncture, however, one point should be made. The value of PG&E's Plan to Gen exceeds simply the revenues that Gen would receive under the PSA. Under the Plan, Gen will receive not only $52.29/MWh for twelve years, but in addition, Gen will receive virtually all of PG&E's electric generation assets for a fraction of their value.
Gen will effectively pay reorganized PG&E $2.4 billion for PG&E's hydroelectric and nuclear assets. Application at 2 (upon receiving the generating facilities from PG&E "Gen will then transfer cash and notes to PG&E amounting to $2.4 billion").
17Witness Kuga's testimony at Ex Gen-l-33 and 44 is inconsistent with the chart at Ex Gen-l-3 as to Diablo Canyon availability. The testimony says that Diablo Canyon reliability figures are based on the most recent five years, while the chart includes lengthy 1994 outages. According to the chart, the average Diablo Canyon refueling outages over the last five years are less than the 42 days asserted in the testimony.
For the years 1996-2001 the average is 38.8 days. For the years 1997-2001 the average is 37.2 days.
18
As we have shown elsewhere (see the CPUC's contemporaneous pleading in Docket Nos. EC02-3 1-000 et al.), Gen thus proposes to acquire the hydro and nuclear assets for less than PG&E has previously proposed as the market value for the hydro facilities alone. The market value of the hydro facilities was set at $2.8 billion in a settlement agreement proposed by PG&E, TURN, and other parties in CPUC Docket No.
A.99-09-053, but which was not approved by the CPUC. PG&E subsequently proposed a market value of $4.1 billion for the hydroelectric facilities alone in CPUC Docket No.
A.00- 11-056.
These facts demonstrate that the PSA cannot appropriately be considered in isolation. Any substantive evaluation of the PSA must consider related issues including the value to Gen of obtaining the PG&E generating facilities for a fraction of their PG&E-proposed market value.
- 3. PG&E's Market Power Analysis is Woefully Insufficient The Edgar line of cases requires an applicant in an affiliate sales case to make two separate market power showings. First, PG&E must demonstrate that "the benchmark evidence was not distorted by exercise of market power by the seller or its affiliates."
Ocean State, 59 FERC at 62,333. In this regard, FERC is concerned that, "If the seller or any of its affiliates has exercised market power and thus kept prices high in the relevant market, the benchmark evidence would be skewed in favor of the seller and thereby allow the affiliated buyers to give an undue preference to the sellers." Ocean State, 59 FERC at 62,337. In this proceeding, FERC must address not only whether PG&E has exercised market power and thus skewed the benchmark evidence, but rather whether any party exercised market power in connection with the benchmark evidence. That is, a proper market analysis in this proceeding must consider whether the benchmark evidence was 19
skewed by the exercise of market power. As discussed above, there is no doubt that it was. Accordingly, the benchmark evidence is invalid, and cannot be used to support the PSA. Moreover, the issue of whether PG&E in fact exercised market power to the detriment of DWR's contracting options or decisions is an issue of fact which should (if the application is not rejected outright) be set for hearing, where the testimony submitted by PG&E on this subject may be subject to discovery and examination. For instance, PG&E's utilization of its generation resources may have affected the size of the "net short" position which DWR was attempting to cover through its contracting, and consequently the pricing and terms of the DWR contracts.
Second, if there has been a showing of no potential abuse of self-dealing or reciprocal dealing, FERC has found that market-based rates may be acceptable if the seller can also demonstrate that it lacks market power (or has adequately mitigated its market power), under familiar principles. Edgar, 55 FERC at 62,167. As PG&E requests acceptance of the PSA as market-based rate, 18 PG&E must satisfy this standard (although, set out above, PG&E has not demonstrated the lack of abuse of self-dealing).
PG&E currently possesses in excess of, and Gen proposes to acquire, 7,100 MW of generation. PG&E's contention that a supplier of such magnitude in frequently constrained Northern California does not have market power fails the straight face test.
Indeed, PG&E has been among the loudest voices arguing that suppliers with much smaller portfolios have both possessed and abused market power. See e.g. "Late Motion to Intervene and Protest of Pacific Gas & Electric Company and Southern California Edison Co." in Docket No. ER99-1722-004, filed April 3, 2001, at 7 ("because the "IS Application at 14 n. 13.
20
premises on which Williams based its market power analysis are no longer valid, and because of the clear evidence that Williams can exercise market power in the WSCC, the Commission's review should lead to a suspension of Williams' market-based rate authority") and "Testimony of James Wilson for PG&E" in Docket No. ELOO-95-000 at 10-16 and Figures 1, 2 and 5 (unrebutted testimony demonstrating that conditions in the California marketplace have permitted the exercise of market power, bidding without adequate competition by pivotal suppliers, and existence of Cournot pricing conditions during potentially 4000 hours0.0463 days <br />1.111 hours <br />0.00661 weeks <br />0.00152 months <br /> in 2001).
Whether measured by the now-disregarded hub-and-spoke methodology or the Supply Margin Assessment ("SMA") screen established in AEP Power Marketing, Inc.,
97 FERC ¶ 61,219 (2001) ("AEP"), PG&E indisputably possesses market power. At best, PG&E's showing-i.e. that it is a net purchaser rather than a net seller of electricity, and that its generation resources are currently required both by state and federal regulation to be devoted to native load--demonstrates that under current circumstances it has little incentive to exercise the market power it possesses. Application at 34-35. All this of course, will change should PG&E's Plan be implemented. Gen would become a stand-alone merchant seller with the largest single generation portfolio in California, and one of the largest generation portfolios in the country. Moreover, although the Gen application is a new market-based rate application submitted after the announcement of the SMA screen in AEP, PG&E has failed to perform an SMA analysis. Nor has PG&E submitted a hub-and-spoke analysis.
In sum, there can be no question that a supplier with a generation portfolio of the magnitude at issue here in Northern California possesses market power.
21
- 4. In Light of the Inadequacies of PG&E's Showing, and the Unique Aspects of the Proposed PSA, Only Cost-based Rates May be Accepted as Just and Reasonable PG&E's Gen application wholly fails to satisfy the applicable standards necessary to support the rates in the proposed PSA, or any market-based rates. Due to the unique nature of both the proposed transaction and the magnitude of the generation portfolio supporting it, it is unlikely that PG&E could make a showing that satisfies the benchmark standards and effectively rebuts the presumption of self-dealing which must be drawn from the facts at issue here. Consequently, if this application is not dismissed outright, it should be set for hearing to determine lawful cost-based rates.
PG&E has asserted that other suppliers in California should be subject to cost based ratemaking. For instance, in PG&E's Request for Rehearing of FERC's July 25, 2001 order (filed August 24, 2001), PG&E asserted that "cost of service rates [are] the only legally appropriate baseline given the fact that the California wholesale markets have been found to be unable to yield just and reasonable rates in all hours." Id. at 2.
Similarly, PG&E's Rehearing Request states that, "As PG&E has previously stated in these dockets, absent a properly functioning market sellers should be permitted to collect no more than their cost of service, which would include a reasonable return on equity."
PG&E is entitled to no more. As the example set out above illustrates, a lawful cost-of-service rate for the portfolio supporting the PSA is on the order of 2.5 cents/kWh for 2003-roughly half of the rate proposed by PG&E.
- 5. At a Minimum, the November 30 Filings Should be Consolidated and Set for Hearing PG&E's request to accept the PSA without a hearing must be denied. The CPUC has identified a multitude of legal and factual issues, and is prepared to address additional 22
issues at hearing. Moreover, the PSA cannot be evaluated or accepted in isolation. Any hearing must consolidate all of the November 30 Filings for a full consideration of the issues (should the applications not simply be rejected outright). FERC precedent supports setting related dockets of similar magnitude for hearing. See Northeast Utilities Company, 50 FERC ¶ 61,266 (1990) (establishing consolidated hearing procedures for several related proceedings proposed to implement a bankruptcy Plan of Reorganization for Public Service of New Hampshire). While PG&E has submitted testimony with its application, which it asserts supports acceptance, that testimony has not either been subject to discovery or tested by cross-examination.
C. PG&E Acknowledges that the True Justification for the Rates Proposed in the PSA is to Service the Debt to be Incurred by Gen Under the Plan Further evidence that the rates proposed in the PSA are justified neither by truly comparable benchmark sales in a competitive environment, nor by any other measure of just and reasonable pricing, is provided in statements in the Application which reveal the true justification for the proposed rates. For instance, at 41-42 the Gen application states that "it would not be possible for Gen to assume this substantial portion of Exit Financing Debt without the PSA." That is, the rates in the PSA were determined by reference solely to the amount of financing which PG&E anticipates that Gen will incur after taking possession of the generating assets, and by the cash flow necessary to support that debt.
If PG&E thought it could raise additional debt, the rates in the PSA would have been higher. If it had to finance the true market value of the facilities, the rates under the PSA would have to be substantially higher.
In fact, neither the income stream under the PSA nor the PSA itself are necessary for PG&E to emerge from bankruptcy. See eg Application at 42. Nor will PG&E's 23
Plan provide, as PG&E asserts, a quick route out of bankruptcy. The legal infirmities of PG&E's Plan are so extensive (and PG&E apparently so determined to press on with its Plan despite its legal infirmities) that years of litigation over the plan are almost inevitable. Rather, as discussed in the Joint Motion, the CPUC has formulated an Alternative Plan, to be outlined in greater detail to the Bankruptcy Court on February 13, which would enable PG&E to promptly emerge from bankruptcy with a minimum of litigation, without dismantling the company, and without the need to charge PG&E ratepayers the egregious rates proposed in the PSA.
IV. CONCLUSION For the foregoing reasons, the CPUC requests that the application be dismissed.
In the alternative, the CPUC protests the Gen application, requests consolidation of the November 30 Filings, and requests that FERC set the consolidated proceedings for hearing.
Respectfully submitted, GARY COHEN AROCLES AGUILAR SEAN GALLAGHER By:
SEAN GALL/GHER Staff Counsel Attorneys for the Public Utilities Commission of the State of California 505 Van Ness Ave., Rm. 5124 San Francisco, CA 94102 January 29, 2002 Phone: (415) 703-2059 24
EXHIBIT A en (SMiIIions) 12131102 12131103 1211104 12/31105 NCOME STAEME-NT 1471.5 1488.8 1504.9 Total Operating Revenues 95.7 89.5 93.8 Opet Expenses:
ofg Total Cost of Energy NAME. 10 ERROR! UNKNOWN DOCUMENT PROPERTY
EXHIBIT G DECLARATION OF DAVID R. EFFROSS I, David R. Effross, declare as follows:
- 1. I am employed as a Public Utilities Regulatory Analyst by the California Public Utilities Commission ("CPUC"). In that capacity, I am responsible, among other things, for analyzing the technical and financial aspects of filings made by electric generation and transmission companies in order to determine whether those filings are sound, just and reasonable.
- 2. My educational background is as follows. I received an A.B. degree in Politics from Princeton University in 1987. I went on to study business management at the Sloan School of Management at the Massachusetts Institute of Technology, and received a Master of Science in Management degree in 1989. In 1994, I received a Mastbre Specialis6 en Politique et Gestion de l'Energie from the Ecole Nationale Sup~rieure du P~trole et des Moteurs ("ENSPM") of the Institut Frangais du P~trole ("IFP") in Reuil-Malmaison, France. I also hold a Master of Science degree in Energy Management and Policy, which I received in 1994 from the Center for Energy and the Environment of the University of Pennsylvania.
- 3. Prior to coming to the CPUC, I worked as an energy analyst for PWI Energy, an energy services company in Philadelphia, Pennsylvania.
- 4. I have thoroughly reviewed the filing made by Pacific Gas and Electric Company ("PG&E") in Nuclear Regulatory Commission Dockets 50-275 and 50-323, in which PG&E seeks approval for a license transfer for its Diablo Canyon Power Plant ("DCPP") Units 1 and 2 to a new generating company named I
Electric Generation LLC ("Gen") and, in turn, to a new, wholly owned subsidiary of Gen named Diablo Canyon LLC ("Diablo").
- 5. The license for DCPP should not be transferred to Gen, because Gen's finances are highly questionable. It is uncertain that Gen will have the resources to carry out the critical plant maintenance and public safety-related functions that will enable DCPP to continue to meet the Commission's rigorous regulatory requirements.
- 6. As part of the Reorganization Plan it has submitted in connection with its bankruptcy filing, PG&E would divest most of its generation assets, including DCPP, to Gen, and would then enter into a Purchase & Sale Agreement
("PSA") to buy back the power output of DCPP for the next twelve years. This PSA has been submitted to the Federal Energy Regulatory Commission ("FERC")
for approval. However, the rates proposed in the PSA are unjust and unreasonable, and FERC should accordingly not approve it.
- 7. Assuming that FERC properly determines that Gen should only be allowed to collect cost-based rates for DCPP, there will simply not be enough money coming in to Diablo both to operate the plant properly, and to service the debt to be incurred under the bankruptcy reorganization Plan. Under such circumstances, Gen and Diablo will be in no position to satisfy the requirement of the NRC's regulations that a non-utility applicant (such as Gen would be) must have reasonable assurance of obtaining the funds necessary to cover the plant's estimated operating costs.
2
- 8. Under the PSA, Gen proposes to sell all of the output of the (former)
PG&E generation facilities, including DCPP, to Reorganized PG&E for an eleven year period at an unjust and unreasonable price, approaching double the rates PG&E would receive for the output of the facilities in the absence of the proposed transactions, and justified only by the need to service the unnecessary debt which Gen proposes to incur upon receipt of the facilities (the PSA includes a twelfth year for approximately half of the facilities' output).
- 9. The purported financial viability of Gen and Diablo depends wholly on FERC approval of the PSA. However, PG&E has wholly failed to meet FERC's standards applicable to power sales agreements between affiliates. Under the circumstances here, the applicable standards must be applied with extraordinary scrutiny. The PSA was not reached at arm's-length by entities with competing interests, but rather was developed by the same counsel working simultaneously for all the (affiliated!) parties, one of which is essentially non existent.
- 10. At the heart of PG&E's application to FERC that seeks approval of the PSA is the contention that the rates in the proposed PSA are just and reasonable to Reorganized PG&E on the basis of a "benchmark" analysis conducted by PG&E's witness Meehan.
- 11. However, this "benchmark" analysis misses the mark. First, the rates in the proposed PSA must properly be evaluated not against other long-term power transactions, but rather against the rates which PG&E would receive for the 3
power output of DCPP and the other PG&E generation assets in the absence of the proposed Spin-Off. That is, the proposed PSA rates must be compared against the CPUC's rates for Utility Retained Generation. Second, even if it is appropriate to measure the proposed PSA against "comparable" wholesale transactions, PG&E's benchmark analysis fails to establish that the proposed PSA rates are just and reasonable. Third, PG&E fails to provide a cogent analysis of its market power.
Consequently, PG&E fails to establish that the price and non-price terms and conditions of the PSA are just and reasonable, and that the PSA is not fatally tainted by self-dealing.
- 12. Under PG&E's proposal, Gen will sell the output of the electric generation facilities currently owned and operated by PG&E to Reorganized PG&E, which would in turn resell the facilities' output to its retail customers.
However, in the absence of the transactions proposed in PG&E's Plan, PG&E would retain the electric generation assets that it proposes to transfer to Gen and to the subsidiaries of Gen, including, in this. case, to Diablo Canyon LLC, and would continue selling the output of these facilities directly to its retail customers. Under either scenario, PG&E's retail customers will receive the same energy and Ancillary Services from the same facilities. Thus, the appropriate comparator against which to measure the PSA is the utility-retained generation ("URG")
component of PG&E's retail rates. Under current California law and CPUC policy, such rates are determined on a traditional cost-of-service basis. The CPUC has expressly rejected PG&E's request to set its URG revenue requirement based 4
on market valuation rather than cost-of-service.
- 13. PG&E's witness Meehan states that the levelized price over the twelve-year period of the PSA is approximately $52.29/MWh. Elsewhere, PG&E asserts that the average price under the contract over the life of the contract is approximately 5.1 cents/kWh ($5 1/MWh). That the contract costs are unjust and unreasonable as to Reorganized PG&E (and to its retail ratepayers) is confirmed by PG&E's own numbers. In its Plan, PG&E projects revenues under the contract of approximately $1.5 billion annually. For calendar year 2003, PG&E projects revenues under the contract of $1,471,500,000. Based solely on the numbers presented by PG&E in its Plan, PG&E's revenue requirement based on traditional cost-of-service principles would be approximately $790.4 million for 2003-about half of PG&E's projected revenues. This translates to an illustrative rate of approximately 2.5 cents/kWh.
- 14. This calculation proceeds as follows: PG&E's Plan projects total operating expenses for Gen in 2003, including depreciation, of $759.7 million.
From this figure is subtracted "other income" of $88.9 million, leaving net operating expenses of $670.8 million. To this is added a rate of return and taxes of
$119.6 million, calculated utilizing PG&E's projected 2003 net plant shown in the Plan of Reorganization for the nuclear and hydro assets of $913.8 million and PG&E's rate of return grossed up for income tax authorized by the CPUC of 13.09%. This results in an illustrative cost-of-service revenue requirement for Gen, using PG&E's own figures, of $790.4 million for 2003.
5
- 15. The illustrative cost-of-service revenue requirement of $790.4 million is 53.7% of the proposed revenues PG&E would receive under the PSA in 2003 of $1,471.5 million. PG&E asserts that rates under the PSA in 2003 would be approximately 4.6 cents/kWh. Since, as PG&E asserts, revenues of $1,471.5 million equates to 4.6 cents/kWh on average, the cost-of-service revenue requirement is approximately 2.5 cents/kWh on average (.537 x 4.6 cents/kWh) for 2003.
- 16. While a rate of 2.5 cents/kWh is low compared to recent prices for gas-fired generation, the rate reflects the resource mix utilized for the PSA and PG&E's actual costs-not including the cost of unnecessarily borrowing over $2 billion. Moreover, PG&E's hydroelectric resources are highly depreciated, and PG&E's nuclear and hydro pumped storage resources, including DCPP, have been subject to accelerated depreciation during the transition period established under AB 1890, California's electric utility restructuring law. Ratepayers have paid several billion dollars of accelerated depreciation through California's Competitive Transition Charge, and would be losing a good portion of what they paid for under PG&E's Plan of Reorganization.
- 17. While these figures may be subject to some refinement, this illustration demonstrates that the PSA is grossly overpriced. If the PSA were approved as proposed, PG&E's ratepayers would make some $700 million in excess payments to Gen over and above the otherwise applicable rate for the same energy from the same facilities in 2003. Over the life of the PSA, the 6
overpayments approximate $8 billion.
- 18. PG&E's benchmark analysis, supported by the testimony of its witness Meehan, is invalid for a number of reasons. First, FERC requires a showing that there exists no potential abuse of self-dealing or reciprocal dealing.
Second, if there has been a showing of no potential abuse of self-dealing or reciprocal dealing, FERC has found that market-based rates may be acceptable if the seller can also demonstrate that it lacks market power (or has adequately mitigated its market power).
- 19. As PG&E recognizes, the potential for self-dealing is present here, where the seller under the proposed PSA is essentially non-existent, and the terms and conditions of the PSA were developed by a single entity acting on behalf of both the putative seller and buyer. The risk of self-dealing is at its height in this transaction, in which the buyer under the proposed PSA would, if PG&E's Plan is confirmed, be stripped of all of its most valuable assets and the affiliate relationship then terminated.
- 20. In its unsuccessful attempt to demonstrate a lack of market power, PG&E contends that the relevant market is "the market for firm, long-term baseload and peaking capacity and energy for a duration of approximately 10-15 years with a start date expected near January 2003," and that the relevant region must be limited to suppliers which can deliver energy to PG&E. PG&E also contends that the relevant "contemporaneous" period is May 2000 through November 2001. By so attempting to confine the analysis, PG&E contends that 7
the appropriate benchmark sales are nine long-term contracts entered into by the California Department of Water Resources ("DWR") during 2001.
- 21. In confining its benchmark comparison to the DWR contracts, PG&E has sought to define as the relevant period precisely the same period in which the California wholesale electricity markets exhibited extreme dysfunction.
PG&E itself has previously characterized this as a period of "massive market failure and upheaval in the regulatory regime that has led to billions of dollars in overcharges since May 2000." Similarly, PG&E has attempted to confine its benchmark comparison to DWR contracts, the negotiation of which PG&E has previously contended were subject to the exercise of market power, and as to which PG&E has contended FERC ought to order refunds.
- 22. PG&E's reliance on the DWR contracts for its benchmark analysis is fatal. The DWR contracts were negotiated and executed during a period of extreme exercise of market power, as FERC has acknowledged on repeated occasions. FERC has expressly recognized that the exercise of market power in the spot markets extended to the forward markets during the time period to which PG&E seeks to confine the analysis. Thus, the DWR contracts cannot be relied on to be a benchmark of market value in a competitive market, and cannot be relied on to demonstrate that the PSA reflects a competitive market value.
- 23. However, in connection with the PG&E bankruptcy reorganization Plan, it is inappropriate to consider only a geographic market centered on PG&E's service territory. First, as discussed above, an analytic limitation to contracts in 8
PG&E's California service territory focuses the analysis on an environment of acknowledged market power. Second, a broader geographic market is appropriate to consider in this case due to the nature of the PSA. The PSA is a long-term agreement with a delayed implementation date. Developed in 2001, it is proposed that the PSA run from January 2003 through 2014. The market for such contracts is decidedly national, not regional. That is, a seller need not be physically located in California in 2001 in order to provide power under a 12-year contract commencing in 2003. Because of the long duration and delayed implementation date, a seller would have sufficient time to build new facilities to satisfy all but the earliest segments of the twelve year period.
- 24. That the long-term market for electric generation is essentially national rather than regional is confirmed by an examination of regional pricing for forward electricity contracts. During the height of the recent California energy crisis, western forward prices were substantially higher than forward contracts at other national trading hubs-as much as an order of magnitude higher. Since FERC's summer 2001 orders restored a measure of stability to western markets, however, forward contract prices at various regional hubs have tended to converge. For instance, as of December 12, 2001 (when the notice was issued in this proceeding) the simple average of reported futures prices for calendar year 2002 were $30.66 for the California-Oregon border ("COB"), $34.25 for PJM, and
$30.80 for CINergy. Longer-term prices should show similar convergence. As the relevant market for products similar to the PSA is a national rather than 9
regional market, and PG&E analyzes only a corrupted regional market, PG&E's benchmark analysis fails to satisfy the "relevant market" criterion on which a proper benchmark analysis must be based.
- 25. PG&E's benchmark analysis similarly fails to satisfy the "contemporaneous" criterion on which a proper benchmark analysis must be based. PG&E examined only contracts "entered into between May 2000 and the date of this Application." Meehan's analysis focuses on nine contracts entered into between February and August 2001 as his "comparison group." As noted above, this is precisely the period in which all energy transactions in the California markets were tainted with market power. It is patently unreasonable to consider only such contracts. Moreover, this period is not contemporaneous with the period in which the PSA was developed. PG&E filed its Plan with the Bankruptcy Court on September 20, 2001; however, the key event in this scenario is the order issued by FERC on June 19, 2001, which quickly restored a semblance of stability to the California markets. All of the contracts in witness Meehan's "comparison group" were either executed or had an executed letter of intent no later than June 22, 2001. That is to say, the negotiation of all of the comparison group contracts took place in the market power period. By the fall of 2001 when the PSA was developed, forward contract prices in California had already begun to converge with forward prices in regional markets across the country, at prices well below the prices in the PSA. PG&E has thus failed to examine any contemporaneous contracts in its benchmark analysis.
10
- 26. PG&E provides no justification for the period it has chosen.
Certainly, PG&E makes no claim that that the roughly eighteen month period it has selected for examination represents the only, or even the most relevant, time period in which buyers seeking energy for the 2003-2014 period would have, or did, engage in negotiations.
- 27. The CPUC has no principled objection to a "contemporaneous" period of roughly eighteen months. But PG&E has disingenuously selected the precise 18 months in which the California market was at its most dysfunctional.
The "contemporaneous" period selected by PG&E is invalid on its face, particularly when coupled with the limited geographical market also selected by PG&E. Any valid benchmark analysis must, if not be limited to, certainly include an examination of contracts executed during a period of relative market stability.
Such a period could include, for instance portions of 1999 and 2000, and the latter third of 2001.
- 28. Benchmark evidence must also encompass "similar services."
However, PG&E's benchmark analysis fails this requirement as well. The proposed PSA provides for capacity and energy from approximately 7,100 MW of hydroelectric and nuclear power plants. The size of the PSA alone disqualifies each of the purported "comparison group" contracts from consideration as comparable. Meehan admits that he must treat each of the comparison grout) contracts as "infinitely scalable" in order to make a comparison. Here, the facilities proposed to support the PSA are exclusively hydroelectric and nuclear 11
generating plants. However, the "comparison group" contracts, to the extent that they have any specific source of generation attached to them, are exclusively natural gas-fired units. The PSA is for some 7,100 MW. Only one of the comparison group contracts is within the same order of magnitude. The comparison group contracts are comparable in neither size nor technology to the PSA.
- 29. Moreover, the proposed rates in the PSA are simply too high to be considered just and reasonable. For instance, the capacity charges in the first year of the PSA amount to $170.75/kW-year. Specifically, the capacity charges are
$20.50/kW-mo for the peak months of July and August, $15.25/kW-mo for June, September, and October, and $12/kW-mo for November through May. The capacity payment is paid on a portfolio of 7,100 MW of capacity. Thus the capacity payments alone under the PSA, in the first year, amount to over $1.2 billion, and escalate to nearly $1.5 billion in year eleven.
- 30. The value of PG&E's Plan to Gen exceeds the revenues that Gen would receive under the PSA. Under the Plan, Gen will receive not only
$52.29/MWh for twelve years, but in addition, Gen will receive virtually all of PG&E's electric generation assets for a fraction of their value. Gen will effectively pay reorganized PG&E $2.4 billion for PG&E's hydroelectric assets and DCPP. Gen thus proposes to acquire the hydro and nuclear assets for less than PG&E has previously proposed as the market value for the hydro facilities alone.
It follows from this that the PSA cannot appropriately be considered in isolation.
12
Any substantive evaluation of the PSA must also consider related issues, including the value to Gen of obtaining the PG&E generating facilities for a fraction of their PG&E-proposed market value.
- 31. An applicant in an affiliate sales case such as this one must make two separate market power showings. First, PG&E must demonstrate that the benchmark evidence was not distorted by exercise of market power by the seller or its affiliates. However, PG&E must also show whether any party exercised market power in connection with the benchmark evidence. That is, a proper market analysis must consider whether the benchmark evidence was skewed by the exercise of market power. As discussed above, there is no doubt that it was.
Accordingly, the benchmark evidence is invalid, and cannot be used to support the PSA. Second, if there has been a showing of no potential abuse of self-dealing or reciprocal dealing, FERC has found that market-based rates may be acceptable if the seller can also demonstrate that it lacks market power (or has adequately mitigated its market power). Since PG&E requests acceptance of the PSA as market-based rate, PG&E must satisfy this standard (although, as is noted above, PG&E has not demonstrated the lack of abuse of self-dealing).
- 32. PG&E currently possesses in excess of, and Gen proposes to acquire, 7,100 MW of generation. PG&E's contention that a supplier of such magnitude in frequently constrained Northern California does not have market power fails the straight face test. Indeed, PG&E has been among the loudest voices arguing that suppliers with much smaller portfolios have both possessed 13
and abused market power.
- 33. PG&E indisputably possesses market power. At best, PG&E's showing -- i.e. that it is a net purchaser rather than a net seller of electricity, and that its generation resources are currently required both by state and federal regulation to be devoted to native load -- demonstrates that under current circumstances it has little incentive to exercise the market power it possesses. All this, of course, will change should PG&E's Plan be implemented. Gen would become a stand-alone merchant seller with the largest single generation portfolio in California, and one of the largest generation portfolios in the country. In sum, there can be no question that a supplier with a generation portfolio of the magnitude at issue here in Northern California possesses market power.
- 34. PG&E has wholly failed to satisfy the applicable standards necessary to support the rates in the proposed PSA, or any market-based rates. Due to the unique nature of both the proposed transaction and the magnitude of the generation portfolio supporting it, it is unlikely that PG&E could make a showing that satisfies the benchmark standards or effectively rebut the presumption of self dealing which must be drawn from the facts at issue here.
- 35. PG&E has itself, however, asserted that other suppliers in California should be subject to cost-based ratemaking. For instance, in one FERC proceeding, PG&E has asserted that "cost of service rates [are] the only legally appropriate baseline given the fact that the California wholesale markets have been found to be unable to yield just and reasonable rates in all hours." Similarly, 14
PG&E has stated that, "As PG&E has previously stated in these dockets, absent a properly functioning market sellers should be permitted to collect no more than their cost of service, which would include a reasonable return on equity."
- 36. PG&E is entitled to no more than it has asserted other suppliers to be entitled to. As the above example illustrates, a lawful cost-of-service rate for the portfolio supporting the PSA is on the order of 2.5 cents/kWh for 2003 -- roughly half of the rate proposed by PG&E.
- 37. The rates in the PSA were determined by reference solely to the amount of financing which PG&E anticipates that Gen will incur after taking possession of the generating assets, including DCPP, and by the cash flow necessary to support that debt. If PG&E thought it could raise additional debt, the rates in the PSA would have been higher. If it had to finance the true market value of the facilities, the rates under the PSA would have to be substantially higher.
- 38. In fact, neither the income stream under the PSA nor the PSA itself is necessary for PG&E to emerge from bankruptcy. Nor will PG&E's Plan provide, as PG&E asserts, a quick route out of bankruptcy. Rather, the CPUC has formulated an Alternative Plan, to be outlined in greater detail to the Bankruptcy Court on February 13, 2002, which would enable PG&E to promptly emerge from bankruptcy with a minimum of litigation, without dismantling the company, and without the need to charge PG&E ratepayers the egregious rates proposed in the PSA.
- 39. For all the foregoing reasons, Gen cannot by any stretch of the 15
imagination be deemed to satisfy the financial responsibility requirement of the NRC's regulations. Moreover, there is a reasonable alternative plan, sponsored by the CPUC, under which PG&E will continue to operate DCPP under cost-of service rates, that does provide reasonable assurance of more than adequate funding for all of DCPP's plant operational and maintenance-related needs, thereby assuring protection of public health and safety. For all these reasons relating to the lack of financial responsibility of the proposed transferee of DCPP, the NRC should reject PG&E's request for a license transfer.,._
I declare under penalty of perjury that the foregoing is true and cqfrect to the best of my knowledge.
Executed this 5th day of February, 2002, at SanFy Cisco, CaAO~ia 16
EXHIBIT H Ne wterror attacks on U.S. predicted documents, diagrams and com Nuclear reactor seen puters In Mghanistan. showing as possible target al-Qalda's apparent Interest in producing a nuclear weapon or By Thomas Frank in possibly attacking a nuclear NEWSDAY reactor or other major facility, The CIA said in a report WASHINGTON ----' Officials Wednesday that it had found stepped up warnings "rudimentary diagrams of nu Thursday of a potential new clear weapons inside a sus terrorist attack on the United pected al-Qaida safehouse In States, possibly against a nu Kabul." The threat of terrorists clear power plant or water fa using chemical, biological, radi cility, or involving nuclear ological and nuclear "appears weapons. to be rising particularly since The warnings came as De the Sept. J I attacks," the CIA fense Secretary Donald Rums added.:
feld said attacks against the nation. "could ý-grow vastly An FBI bulletin Wednesday more deadly" tihan the Sept. said that al-Qaida members ap 11 hiJackligs that killed more parently were studying water than 3,000. supply systems and sewage The new, concerns were spurred by the discovery of Please see Attack, NEWS-9 HILLERY SMITH GMRRISON - Associated Prs DEFENSE Secretary Donald Rumsfeld, accompanied by Gen. Tommy Franks, issues terror-warning Thursday.
during a news conferencein Washington.
I WI A I I I RI I Bay10Area.1xINEWS-2 i
Landers ....... LN]NG-2 Partly cloudy, cool Legals ........... CLASS-4 High: mid 50s. Lottery .......... NEWS-2 Low: lower 40s Movies .......... PREVIEW Obits.......C.1YSIDE-4 s dear Yesterday Opinion....CITYSIDE'5 deal High: Alameda, 55 Scores ........ SPORTS-7 Low: Berkeley, 38 Weather. LMNG-8
'ityside
Attackx'rFBI alerted police Jan. 1/6of possibleattacks Continued from N Homeland Security Plants Someoein 'the United Ladrecy linkedStatsto spokesman Gordon Johndroe:
Someone ,'indirectly ited S s aetIse pcfclycvrr*
said he believed it was the Blrat Osama bin Laden showed an alert issued specifically cover,*.
apparent..'interest in'the design such facilities, although fourn.,
of dams" the FBI added, relying general alerts have been made information; from, that per- since October, most recently on Con's computer. Jan.2.
And Son ommid the Nuclear Regulatory Reports of new threats came Nportedly warned after President Cenatisbon' r103ndc war e Tuesday In hisBush's warning State of the tIhe nation's 103 nuclear power union plants,butan of ap FBI Official at- address about more ter C butied an BIodcialtsaidsaidthe rorist attacks. Bush said U.S.
tme officials found "diagrams I~relied on "dated informa-ce of nu Non (that] is- uncorroborated." clar power plants and publk he FBI has said the water facilities, detailed instruc h0 disescrib ck th e pSaidtheinfrmatitons an edal-Qaida urpoperative w aon o rted a t- weapons, survain gnc chemical s frmaking surveillance e m ap ta maps of e American cities ho has not been credible and thorough in the descriptions of pa st.~ a Source said.
America landmarks In But the Office of Homeland world." and throughout the Se -uritysaid Thursday that the FBI Director Robert Mueller FBý I hadalered lcal olienf said Jaii. 16 of possible attacks on "still Thursday that the nation 1!4 in a high state of alert and ene sgy fac'lnffe, reservoirs dai and will anc ns uclek6ra storage sites dno- f-efo1om;im for highly en .
Distributed by the Los An ridtled uranium, the key ingre ticIt in nuclear weapons. geles Service.
News Times-Washington Post Strike threat looms at refineries BAY MIY NEWS ee and the oll Industry are taking MARTINEZ place at the national level
- As a strike In deadline that would affect oil re Nashville, Tenn.
fineries nationwide approaches, Negotiations are also taking union representatives held a place at the local level, where.
news conference in Martinez the unions say the refineries Thursday to announce should increase the national sitions if a contract doesn't their po baseline offerings to the 2,500*'
get signed. union refinery workers in the Negotiations between unions Bay Area due to the high cost ol region.
living in the
EXHIBIT I DIABLO CANYON INDEPENDENT SAFETY COMMITTEE ELEVENTH ANNUAL REPORT ON THE SAFETY OF PLANT OPERATIONS DIABLO CANYON NUCLEAR POWER July 1, 2000 - June 30, 2001 Volume I - MAIN REPORT Philip R. Clark, Chair*
E. Gail de Planque, Vice-Chair*
A. David Rossin 2000 - June 30, 2001
- for the period July 1, Approved: October 17, 2001 on this report.
The DCISC invites questions and conmentS the DCISC at the following:
Contact The Diablo Canyon Independent Safety Committee 857 Cas St., Suite D Monterey, CA 93940 (California Only)
Telephone: 1-800-439-4688 E-Mail: dcsafety,*dcisc.org World Wide Web: www.dcisc.org
PREFACE of the Diablo Canyon This report covers the activities for the period July 1, Independent Safety Committee (DCISC) report 2000 through June 30, 2001. This is the eleventh annual of the DCISC; the first report covered the six-month period The report is presented in January 1, 1990 - June 30, 1990.
two volumes.
and history regarding Volume I includes a brief introduction held the DCISC (Section 1.0), a summary of the public meetings (Section 2.0), a review and during the reporting period Commission (NRC) assessments evaluation of Nuclear Regulatory Member and Consultant (Section 3.0), Committee and issues public input topic summaries (Section 4.0),
investigation Gas and Electric (Section 5.0), and a follow-up of Pacific 6.0). A (Section (PG&E) actions on DCISC recommendations and recommendations (Section summary of the DCISC conclusions 8.0) conclude the report. The 7.0) and PG&E's response (Section also appear throughout the main conclusions and recommendations of the subject involved.
body of the report with a discussion These appear in boldface type.
among other things, full reports by Volume II contains, meeting notices and agendas, Committee Members/Consultants, of documents received by the PG&E organization charts, a list Power Plant operations for DCISC, a summary of Diablo Canyon a of plant tours by the DCISC, the reporting period, a record and correspondence with glossary of terms, and communications members of the public.
and comments on this report.
The DCISC invites questions Contact the DCISC at the following:
Committee The Diablo Canyon Independent Safety 857 Cass St., Suite D Monterey, CA 93940 Telephone: 1-800-439-4688 E-mail: dcsafety@dcisc.org World Wide Web: www.dcisc.org P-I
Committee Diablo Canyon Independent Safety Annual Report on the Power Plant Operations Safety of Diablo Canyon Nuclear July 1, 2000 - June 30, 2001 EXECUTIVE
SUMMARY
Safety Committee (DCISC) was The Diablo Canyon Independent 24, 1988 settlement agreement established as part of the June proceedings for the Diablo Canyon which arose out of the rate was Power Plant (DCPP). The original settlement agreement Public Utilities Commission terminated by the California electricity markets (CPUC) in its decision to open the state the 1, 1998; however, under to competition on January on Decision 97-05-088, issued provisions of the Commission's continue to function and fulfill May 21, 1997, the DCISC will under the terms of the its responsibilities as established on April 6, Following PG&E's filing 1988 settlement agreement. and Bankruptcy Court for protection 2001, in the United States Code as 11 of the U.S. Bankruptcy reorganization under Chapter has in California, the DCISC a result of the energy situation of as provided under the terms continued to receive funding the 1997 Decision.
provided for a three-member The original settlement agreement and for the purpose of reviewing Independent Safety Committee One operations of Diablo Canyon.
assessing the safety of California, the member each is appointed by the Governor of and the Chairperson of the Attorney General of California The Committee Energy Commission, respectively.
California were Mr. Philip R. Clark, retired Members during this period and Operating Officer of GPU President and Chief Executive by the Chair of the California Nuclear Corporation (appointed consultant and E. Gail de Planque, Energy Commission); Dr.
U.S. Nuclear Regulatory Commission former Commissioner of the Rossin, General; and Dr. A. David (appointed by the Attorney Secretary for Nuclear Energy, consultant and former Assistant Mr.
by the Governor).
U.S. Department of Energy (appointed Dr. de this reporting period, and Clark served as Chair during Planque served as Vice-Chair.
1989 with the appointments of The DCISC was formed in late and formal review activities Committee Members and began ES-I
meetings on January 1, 1990. The Committee regularly performs the following activities:
"* Three sets of public meetings each year in the vicinity of the plant
"* One tour of the Diablo Canyon Nuclear Power Plant with members of the public each year
"* Numerous fact-finding visits by individual Committee Members and Consultants to assess issues, review plant programs and activities, and interview PG&E personnel
"* Visits by the DCISC Members and legal counsel to offices of their appointing officials (California Attorney General, California Energy Commission, and The Governor) to update them on DCISC activities
"* Use of several regular part-time technical consultants to perform assessments and reviews
"* Use of legal counsel to advise the Committee on its activities
"* Use of expert consultants, as needed, to investigate, assess, and review special issues such as seismology, pipe cracking, radiological effects, probabilistic risk assessment, and quality assurance The DCISC issues a report for each reporting year, which runs from July 1 to June 30. The report is approved by the Committee Members at the Fall public meeting following the end of the reporting period. The first interim report and subsequent ten annual reports covered the following periods:
January 1, 1990 - June 30, 1990 July 1, 1990 - June 30, 1991 July 1, 1991 - June 30, 1992 July 1, 1992 - June 30, 1993 July 1, 1993 - June 30, 1994 July 1, 1994 - June 30, 1995 July 1, 1995 - June 30, 1996 July 1, 1996 - June 30, 1997 July 1, 1997 - June 30, 1998 July 1, 1998 - June 30, 1999 July 1, 1999 - June 20, 2000 ES-2
report covers the period July 1, 2000 This eleventh annual June 30, 2001.
of the plant were held in the vicinity Three public meetings period.
Obispo, California during this reporting in San Luis items were covered:
The following significant events
"* DCPP performance and operational plans and results
"* Refueling outage overviews, indicators
"* Review of DCPP performance program
"* Human error performance improvement Committee (NSOC) and President's
"* Nuclear Safety Oversight Nuclear Advisory Committee (PNAC) activities
"* Public comments outages
"* Plans for and results of refueling including the employee
"* Safety conscious work environment, concerns program and performance
"* Steam generator inspections
"* DCPP Self-Assessment Program Specifications
"* Transition to Improved Technical
"* DCPP Training Program
& Results
"* Integrated Assessment Process Outages
"* Radiation Exposure During Refueling the California Energy Crisis
"* Implications for DCPP from
"* Five Year Business Plan Plans
"* On-Site Spent Fuel Storage
0 Plant-wide Safety Conscious Culture Survey
"* Removal of Post-Accident Sample System
"* On-Line Maintenance Many other items were reviewed in 9 fact-finding visits, inspections and tours at DCPP by individual Committee Members and consultants. The DCISC Chair visited the California Energy Commission office and the Vice-Chair visited the Attorney General's office to provide updates on DCISC activities. In addition, the full Committee toured the plant with 15 members of the public on February 7, 2001. The third Committee Member contacted the Governor's Staff and provided a copy of the previous year's Annual Report for their review.
The DCISC concludes that PG&E operated DCPP safely during the period.
Based on its activities, the DCISC has the following specific conclusions from the major review topics examined during the current reporting period (references to sections of this report are shown in parentheses):
- 1. PG&E appears to be taking positive steps in reviving neglected portions of its Aging Management Program with new leadership, augmented management support, and several new initiatives (the latter due in large part to aging related failures of plant components). The DCISC has had concerns about the program in the last several reporting periods and is pleased to see progress towards improvement. A major element of DCPP aging management is the system long-term planning process in which system engineers are responsible for monitoring, measuring and planning for aging-related effects.
The DCISC will continue to follow PG&E's progress with aging management, including review of the Generation Vulnerability Identification Team report and the Passive Device Aging Management Investigation Team report.
(4.1.3)
- 2. The DCPP Maintenance Program appears to be functioning satisfactorily and implemented properly to meet NRC Maintenance Rule requirements. The Maintenance organization is functionally aligned to the work scope, and the On-Line Maintenance Program is soundly PRA-based.
activities and on The DCISC will follow up on Maintenance plant the possible effects on safety of lowered/delayed capital spending. (4.2.3) of Operations appeared satisfactory,
- 3. DCPP Conduct Control Room policies and including outage activities; priorities; and preparation and demeanor, and Specifications.
implementation of the Improved Technical area as part of The DCISC will continue to review this its normal activities. (4.3.3) in its emergency
- 4. It appeared that DCPP has performed well improving drills and exercises and has been working on of accurate and understandable its communication to the public. The DCISC radiation release information plans to follow this item. (4.4.3)
The PG&E engineering programs, including Configuration 5.
continue to be Management and Equipment Qualification, for supporting safe operations at DCPP.
satisfactory (4.5.3) performance and work
- 6. Although DCPP has methods to track they do not load of ARs and AEs and System Engineers, work that is not appear to have a method for tracking identify the entire covered by either ARs or AEs nor to they have enough Engineering Workload to determine if getting behind.
resources to perform the work without (4.5.3)
PG&E's engineering The DCISC will continue to monitor performance, including workload management and a review of the new Generation Vulnerability of the results its release in June Identification Team report following 2001.
have taken appropriate actions in
- 7. PG&E appears to events and system response to plant off-normal operating this period and has applied and equipment problems during recurrence. The appropriate corrective actions to prevent as part of its DCISC will continue to review this area normal activities. (4.6.3)
(CAP) appears to have
- 8. The DCPP Corrective Action Program external been improved as a result of self-assessments, CAPs. Measures of evaluations and reviews of other plant were just being developed and program effectiveness ES-5
appeared headed in the right direction. The DCISC will review the CAP in early 2002, following completion of improvement action items and the next self-assessment.
(4.6.3)
- 9. DCPP environmental performance appeared satisfactory, and the DCPP environmental program appeared to meet applicable requirements. The DCISC will continue to review the environmental program as part of its normal activities. (4.7.3)
- 10. Based on satisfactory DCISC and NRC reviews and inspections in the previous reporting period, the DCISC did not review fire protection in the current reporting period. A DCISC review of fire protection is planned for the next period. (4.8.3)
- 11. The Human Performance Program is doing an adequate job of error trending, evaluating the data, and working toward increasing performance and enhancing safety. Human error continues to be the largest cause of problems, and, although the numbers of human errors are small, the trends are not yet showing sustained improvement. The DCISC will continue to actively review human performance at DCPP. (4.9.3)
- 12. The DCPP Employee Assistance Program appears to be well utilized, and is carrying out its responsibilities appropriately. The DCISC will review this area as part of its normal activities. (4.9.3)
- 13. Operator fitness continues to be an issue of concern, which the DCISC will continue to track. Indicators point to a growing problem with operator fitness, and it was not apparent that DCPP had measures in place to deal with the problem. (4.9.3)
- 14. PG&E appears to be handling fuel or fuel-related problems appropriately. The DCPP Unit 1 core has been reliable and clean; however, Unit 2 has experienced a small amount of fuel damage due to baffle jetting and debris or a fuel defect. The assembly was removed, repaired and returned to the reactor. It appears PG&E will maintain its 19-21 month fuel cycle or move to an 18-month cycle. (4.10.3)
The DCISC will continue to follow on-going problems such as expansion of spent fuel storage, spent fuel pool ES-6
fuel problems or poison (Boraflex), and any fuel-related issues that arise.
and review functions and
- 15. Nuclear safety oversight at functioning satisfactorily organizations appear to be to have the very beneficial DCPP. It also appears to be since each committee covers joint PNAC/NSOC meetings, INPO The results of the 2001 much of the same agenda. The DCISC will appear to be favorable.
evaluation and NSOC meetings to observe continue to monitor the PNAC issues. (4.11.3) their review of plant safety there was constructive and The DCISC observed that although there were the NSOC meetings, helpful dialogue during processes.
limited challenges to existing thinking and (4.11.3)
Assessment Report is a
- 16. It appears that the Integrated overall use to assess the positive tool for management's all of the of the plant. It combines performance on the plant from the various reports information will useful document. The DCISC performance into one very Integrated Assessment Report.
continue to review the (4.11.3) the IRlO and 2R10 outages
- 17. It appears that PG&E managed in the best outages at DCPP very effectively to achieve DCISC will except cost and schedule.
all measures refueling performance of each continue to review the outage. (4.12.3) were made of DCPP overtime
- 18. Although no specific reviews any problems. The activities, there did not appear to be problems.
remain sensitive to overtime DCISC will (4.13.3) concludes that the quality
- 19. As in past years, the DCISC program have been effective program and self-assessment weaknesses of the activities in identifying strengths and effective corrective action.
at DCPP and bringing about is doing a good job in It appears that the NQS group to problems and bringing them monitoring the top quality The DCISC will continue the attention of line management. normal as part of its to review DCPP quality programs activities. (4.14.3) program for controlling The DCPP radiation protection 20.
radiation doses inside and outside the plant appears effective overall. DCPP had experienced unusually high radiation dose rates during Outage IR9 but had effectively reduced those levels in three subsequent outages. The DCISC will closely follow radiation protection during future outages. (4.15.3)
- 21. Overall, PG&E's risk assessment and risk management programs appear to be effective in supporting safe plant operation. The PRA Group has become pro-active and effective in supporting station decisions with risk-based analyses. The DCISC will continue to review risk management activities as part of its normal activities.
(4.16.3)
- 22. PG&E's actions to improve its safety conscious work environment appear satisfactory. A cultural survey concluded that the safety culture was satisfactory and about average for the industry; however, some employees are reluctant to bring concerns to management. PG&E has an action plan to address these findings, and the DCISC will monitor these actions. (4.17.3)
- 23. PG&E's Steam Generator (SG) program appears effective.
PG&E now expects that the DCPP steam generators will last the currently-licensed life of the plant, if the NRC approves the PG&E License Amendment Requests for Alternate Repair Criteria; however, economic considerations may call for early steam generator replacement. The DCISC will continue to closely monitor DCPP steam generator performance. (4.18.3)
- 24. PG&E appears to have taken appropriate action in addressing system and equipment performance issues; however as noted in several instances, the DCISC believes additional work is needed and has provided recommendations accordingly. The DCISC will continue to review this area as part of its normal activities.
(4.19.3)
- 25. The DCPP training and development programs appeared satisfactory, and the DCISC will continue to monitor them. (4.20.3)
- 26. It appears that the Five-Year Business Plan is helpful in aligning the department and plant goals and objectives.
Also, the hierarchy of DCPP performance plans represented ES-8
of disseminating management an effective method organization. Nuclear safety expectations to the whole The DCISC will follow up was appropriately addressed. are how effectively the plans periodically to assess being implemented. (4.21.3) above, followed in the Conclusions In addition to items being the following areas:
the DCISC has concerns in of problems, to be the largest cause
- 1. Human error continues are small, the human errors and, although the numbers of DCISC sustained improvement. The trends are not yet showing at DCPP.
review human performance will continue to actively appear operators continue to age, and fitness levels
followed.
of bankruptcy need to be
- 3. The potential impacts that confirms the general experience
- 4. A recent study for NRC an adverse and stress can have periods of rapid change and on the performance of organizations. DCPP has effect changes, including to undergo major continues processes rather than functions.
reorganization focusing on major understandably stressed by In addition, employees are filing for changes underway in the industry and the PG&E steps these and has been taking bankruptcy. DCPP recognizes affect safe, reliable operation; to assure that they don't adverse continue to look for any however, the DCISC will effects.
(references to are the following DCISC recommendations shown in parentheses):
sections of this report are a
It is recommended that DCPP develop and implement R01-1 and monitor the entire method to identify assure that the necessary Engineering Work Load to support safe is performed to effectively work in ensuring and to help operation of the plant are available.
engineering resources adequate (4.5.3) cause of events is human R01-2 Because the predominant more closely error, it is recommended that DCPP Action and Human coordinate the Corrective utilize training in human Performance Programs and ES-9
characteristics and skills (e.g., interviewing skills, human error characteristics) for personnel preparing root cause analyses and corrective actions. (4.9.3)
R01-3 It is recommended that PG&E continue to augment its programs for operator health and aging to consider such areas as operator "aging management", physical fitness, and mental alertness on shift to further improve operator human performance. (4.9.3)
R01-4 It is recommended that PG&E management raise its expectations of the Nuclear Safety Oversight Committee internal and external members to take a more aggressive stance in challenging problem solving and the status quo. Additionally, PG&E should consider adding independent external members (not just from STARS plants) . (4.11.3)
R01-5 It is recommended that NSOC take a more active role in determining the scope of the biennial audit of NQS to give the audit more independence. The DCISC had made a similar recommendation in the previous Annual Report and requests that PG&E reconsider its response of having NSOC only review the audit plan.
(4.14.3)
R01-6 It is recommended that PG&E take the initiative in dealing with staffing issues by developing a long term staffing plan. (4.17.3)
R01-7 It is recommended that PG&E take actions necessary to improve the employees' perception of the Employee Concerns Program. (4.17.3)
R01-8 It is recommended that PG&E apply the normally used Corrective Action Program, Human Performance Program, and System Long Term Plan Program (and possibly others) to Security Services and develop an implementation plan. (4.19.3)
R01-9 It is recommended that PG&E develop a plan for how System Health Reports and Long Term Plans should be utilized by Operations and Maintenance. (4.19.3)
The DCISC will follow these concerns and recommendations during the next reporting period.
received at the public Public input and questions were and by telephone, meetings, during the public plant tour, the public spoke at DCISC letter or E-mail. Eight members of following has responded to or is public meetings. The DCISC (see Section 7.0, concerns and requests their questions, Public Contacts).
Public Input and Exhibit G, ES-il
Diablo Canyon Independent Safety Committee ANNUAL REPORT ON THE SAFETY OF OPERATIONS DIABLO CANYON NUCLEAR POWER PLANT July 1, 2000 - June 30, 2001 Table of Contents Volume I - MAIN REPORT Page Section P-1 Preface ES-I Executive Summary i
Table of Contents 1-1 1.0 Introduction Committee 1-2 i.I Formation of the Independent Safety 1-2 1.2 Appointment of Committee Members 1-6 1.3 Documents Provided to the DCISC Tours and 1-6 1.4 Committee Member Site Inspection Fact-finding Meetings Philip 1-7 1.4.1 Inspections and Visits By Mr.
R. Clark E. Gail 1-7 1.4.2 Inspections and Visits By Dr.
de Planque A. 1-8 1.4.3 Inspections and Visits by Dr.
David Rossin 1-8 1.4.4 Inspection of DCPP by DCISC Members and Members of the Public on February 7, 2001 1-10 1.4.5 Visits by DCISC Members to California State Agencies i
2.0 DCISC Public Meetings 2-1 2.1 September 14 & 15, 2000 Public Meetings 2-1 2.2 February 7 & 8, 2001 Public Meetings 2-1 2.3 June 20 & 21, 2001 Public Meetings 2-1 3.0 NRC Assessments and Issues 3-1 3.1 Summary of Licensee Event Reports 3-1 3.1.1 Discussion 3-1 3.1.2 Voluntary LERs 3-8 3.1.3 Reactor Trips Reported in LERs 3-9 3.1.4 LER Trends 3-10 3.1.5 DCISC Evaluation and Conclusions 3-10 3.2 NRC Inspection Reports 3-11 3.2.1 Discussion 3-11 3.2.2 DCISC Evaluation and Conclusions 3-13 3.3 NRC Enforcement Actions 3-14 3.3.1 Discussion 3-14 3.3.2 DCISC Evaluation and Conclusions 3-16 3.4 NRC Plant Performance Program Results 3-16 3.5 NRC Review of DCPP Safety with PG&E Bankruptcy 3-23 3.6 DCISC Evaluation 3-23 4.0 Summary of Major DCISC Review Topics 4-1 4.1 Aging Management 4-2 4.1.1 Overview and Previous Activities 4-2 4.1.2 Current Period Activities 4-3 ii
4-6 4.1.3 Conclusions 4-7 4.2 Conduct of Maintenance 4-7 4.2.1 Overview and Previous Activities 4-7 4.2.2 Current Period Activities 4-12 4.2.3 Conclusions 4-13 4.3 Conduct of Operations 4-13 4.3.1 Overview and Previous Activities 4-14 4.3.2 Current Period Activities 4-17 4.3.3 Conclusions 4-18 4.4 Emergency Preparedness 4-18 4.6.1 Overview and Previous Activities 4-19 4.6.2 Current Period Activities 4-22 4.6.3 Conclusions 4-23 4.5 Engineering Program 4-23 4.5.1 Overview and Previous Activities 4-23 4.5.2 Current Period Activities 4-26 4.5.3 Conclusions and Recommendations 4-27 Action 4.6 Event/Problem Analysis and Corrective 4-27 4.6.1 Overview and Previous Activities 4-28 4.6.2 Current Period Activities 4-32 4.6.3 Conclusions and Recommendations 4-34 4.7 Environmental 4-34 4.7.1 Overview and Previous Activities iii
4.7.2 Current Period Activities 4-34 4.7.3 Conclusions 4-35 4.8 Fire Protection 4-36 4.8.1 Overview and Previous Activities 4-36 4.8.2 Current Period Activities 4-37 4.8.3 Conclusions 4-37 4.9 Human Performance 4-38 4.9.1 Overview and Previous Activities 4-38 4.9.2 Current Period Activities 4-39 4.9.3 Conclusions and Recommendations 4-45 4.10 Nuclear Fuel Performance/Fuel Cycles/Storage 4-46 4.10.1 Overview and Previous Activities 4-46 4.10.2 Current Period Activities 4-48 4.10.3 Conclusions 4-51 4.11 Nuclear Safety Oversight and Review 4-52 4.11.1 Overview and Previous Activities 4-52 4.11.2 Current Period Activities 4-54 4.11.3 Conclusions and Recommendations 4-62 4.12 Outage Management 4-64 4.12.1 Overview and Previous Activities 4-64 4.12.2 Current Period Activities 4-65 4.12.3 Conclusions 4-71 4.13 Overtime Control 4-72 4.13.1 Overview and Previous Activities 4-72 iv
4-72 4.13.2 Current Period Activities 4-73 4.13.3 Conclusions 4-74 4.14 Quality Programs 4-74 4.14.1 Overview and Previous Activities 4-75 4.14.2 Current Period Activities 4-80 4.14.3 Conclusions and Recommendations 4-81 4.15 Radiation Protection 4-81 4.15.1 Overview and Previous Activities 4-82 4.15.2 Current Period Activities 4-86 4.15.3 Conclusions 4-87 4.16 Risk Assessment and Management 4-87 4.16.1 Overview and Previous Activities 4-88 4.16.2 Current period Activities 4-90 4.16.3 Conclusions 4-91 Environment 4.17 Safety Conscious Work 4-91 4.17.1 Overview and Previous Activities 4-93 4.17.2 Current Period Activities 4-98 4.17.3 Conclusions and Recommendations 4-100 4.18 Steam Generator Performance 4-100 4.18.1 Overview and Previous Activities 4-101 4.18.2 Current Period Activities 4-102 4.18.3 Conclusions V
4.19 System and Equipment Performance/Problems 4-103 4.19.1 Overview and Previous Activities 4-103 4.19.2 Current Period Activities 4-104 4.19.3 Conclusions and Recommendations 4-112 4.20 Training and Development Programs 4-114 4.20.1 Overview and Previous Activities 4-114 4.20.2 Current Period Activities 4-115 4.20.3 Conclusions 4-116 4.21 Strategic and Business Plans 4-117 4.21.1 Overview and Previous Activities 4-117 4.21.2 Current Period Activities 4-118 4.21.3 Conclusions 4-121 5-1 5.0 DCISC Performance Measures DCISC Open Items List 6-1 6.0 7.0 Public Input 7-1 8-1 8.0 PG&E Actions on Previous DCISC Report Recommenda tions 9-1 9.0 Conclusions and Recommendations 9-1 9.1 Conclusions 9-6 9.2 Concerns 9-6 9.3 Recommendations 10-1 10.0 PG&E Response vi
Volume II - EXHIBITS Page Exhibits A-1 A. Documents Received By the DCISC Agendas and Reports B-I B. DCISC Public Meeting Notices, 2000 Public B.1-1 B.1 Notice of September 14 & 15, Meetings 2000 Public B.2-1 B.2 Agenda for September 14 & 15, Meetings 2000 Public B.3-1 B.3 Minutes of September 14 & 15, Meetings 2001 Public Meetings B.4-1 B.4 Notice of February 7 & 8, 2001 Public Meetings B.5-1 B.5 Agenda for February 7 & 8, 2001 Public Meetings B.6-1 B.6 Minutes of February 7 & 8, 2001 Public Meetings B.7-1 B.7 Notice of June 20 & 21, 2001 Public Meetings B.8-1 B.8 Agenda for June 20 & 21, 2001 Public Meetings B.9-1 B.9 Minutes of June 20 & 21, List B.10-1 B.10 Typical DCISC Service Mailing C-1 C. Diablo Canyon Operations C-I 1.0 PG&E/DCPP Organization C-I 2.0 Summary of Diablo Canyon Operations C-I 2.1 Summary of Unit 1 and Unit 2 Operations Indicators C-I 2.2 Unit 1 and Unit 2 Performance C-i 2.2.1 Capacity Factor C-2 2.2.2 Refueling Outages C-4 2.2.3 Collective Radiation Dose vii
2.2.4 Industrial Safety Lost Time C-4 Accident Rate 2.2.5 Unplanned Reactor Trips C-5 2.2.6 Unplanned Safety System Actuations C-5 2.2.7 Secondary Chemistry Index (SCI) C-5 2.2.8 Fuel Reliability C-6 2.3 Employee Concerns Program Statistics C-7 2.4 Fitness for Duty C-9 D. DCISC Reports on Fact-finding Meetings D-1 D.1 Report on Fact Finding Meeting at DCPP D. 1-1 on July 6-7, 2000 1.0 Summary D. 1-1 2.0 Introduction D. 1-1 3.0 Discussion D. 1-2 3.1 Corrective Actions from September 22, D. 1-2 1999 Reactor Trip 3.2 Human Performance D.1-4 3.3 System Health Indicators and Long-Term D. 1-8 Plans 3.4 Environmental Performance for 1999 and D. 1-10 First Half of 2000 3.5 Organization Development Program D. 1-12 3.6 Turbine Blade Cracking D. 1-14 3.7 DCISC Performance Indicators D. 1-15 3.8 INPO SOERs 98-1 and 98-2 D.1-15 3.9 May 15, 2000 Fire and Unusual Event D.1-16 viii
System Review D.1-18 3.10 Control Room Ventilation Director D.1-19 3.11 Meeting with Medical Facility D.1-21 4.0 Conclusions D.1-23 5.0 Recommendations D.1-23 6.0 References at DCPP D.2-1 D.2 Report on Fact Finding Meeting on October 25-26, 2000 D.2-1 1.0 Summary D.2-2 2.0 Introduction D.2-2 3.0 Discussion D.2-2 3.1 Observe Outage iR10 Daily Meeting D.2-3 3.2 Tour Outage Work Control Center D.2-3 3.3 Outage 1R10 Overview and Outage Safety Plan D.2-5 3.4 Meeting with Manager of Operations Services D.2-6 3.5 Meeting with NRC Resident Inspector Plant D.2-6 3.6 Meeting with Vice President and Manager D.2-6 3.7 Meeting with Manager of Engineering Services D.2-7 3.8 Meeting with Manager of Maintenance Services D.2-7 3.9 Outage IR10 Main Turbine Work D.2-8 3.10 Tour of Containment Manager D.2-8 3.11 Observe Control Room Shift Turnover ix
3.12 Driving Tour of DCPP Site and Intake D.2-9 Facility 3.13 Low Level Liquid & Solid Radwaste D.2-9 Handling Systems 3.14 Reactor Pressure Vessel Integrity D.2-10 3.15 Aging Management D.2-11 3.16 Radiation Protection Overview D.2-13 3.17 Meeting with Human Resources Director D.2-14 3.18 Meeting with Manager of Nuclear D.2-15 Quality & Licensing 4.0 Conclusions D.2-15 5.0 Recommendations D.2-16 6.0 References D.2-17 D.3 Report on Fact Finding Meeting at DCPP D.3-1 on November 14-15, 2000 1.0 Summary D.3-1 2.0 Introduction D.3-1 3.0 Discussion D.3-2 3.1 Joint NSOC & PNAC Meetings D.3-2 3.2 Intake Structure Inspection & Results D.3-7 3.3 Outage IR10 RP Results D.3-9 3.4 Corrective Actions on 9/22/99 Unit 1 D.3-10 Reactor Trip 3.5 V.C. Summer Piping Concerns D.3-11 (NRC IN 2000-17) 3.6 SG Inspection Results D.3-12 3.7 Spent Fuel Storage Status D.3-13 x
D.3-14 3.8 Nuclear Fuel Items D.3-14
- 1. IR10 Nuclear Fuel Performance/
Inspection D.3-15
- 2. Gap Re-opening D.3-15
- 3. Extended Fuel Cycle D.3-16
- 4. Boraflex D.3-16 4.0 Conclusions D.3-17 5.0 Recommendations D.3-17 6.0 References at DCPP D.4-1 D.4 Report on Fact Finding Meeting on December 13, 2000 D.4-1 1.0 Summary D.4-2 2.0 Introduction D.4-2 3.0 Discussion Report D.4-2 3.1 PG&E's Response to the Annual Performance D.4-2 3.2 Management View of Human D.4-4 3.3 Maintenance Human Performance for D.4-6 3.4 Human Performance Measures Engineering (Latent Errors)
D.4-7 3.5 Informal Meeting with Supervisors Physical D.4-8 3.6 Incentives for Increased Enhancement and Fitness, Attention Stress Management D.4-9 3.7 Employee Concerns Program/Differing Professional Opinions Program D.4-10 3.8 New Behavior-Based Safety D.4-11 3.9 Five Year Plan re Operator D.4-12 3.10 Medical Center Visit Fitness xi
3.11 Safety Class on Cardiac Health D.4-13 4.0 Conclusions D.4-14 5.0 Recommendations D.4-16 6.0 References D.4-16 D.5 Report on Fact Finding Meeting at DCPP D.5-1 on December 14, 2000 1.0 Summary D.5-1 2.0 Introduction D.5-1 3.0 Discussion D.5-2 3.1 Transition Program to Prepare for D.5-2 Competition 3.2 Engineering Work Load Performance D.5-3 Indicator Recommendation 3.3 Alternate Source Terms D.5-5 3.4 Joint Utility Venture Status (STARS) D.5-7 3.5 Top Ten Quality Problems D.5-8 3.6 Security System Computer Performance D.5-9 and Long Term Plan 3.7 Self-Assessment Program Update D.5-10 3.8 Asset Team Update D.5-11 4.0 Conclusions D.5-13 5.0 Recommendations D.5-14 D.6 Report on Fact Finding Meeting at DCPP D.6-1 On March 14-16, 2001 1.0 Summary D.6-1 xii
D.6-2 2.0 Introduction D. 6-2 3.0 Discussion Indicators D.6-2 3.1 DCISC Performance Inspector D.6-4 3.2 Meeting with New NRC Resident Risk D.6-5 3.3 NRC Report on Refueling Outage D. 6-6 3.4 On-line Maintenance D.6-9 3.5 Corrective Action Program D.6-12 3.6 Winter Storm Experience/Procedures Performance D.6-13 3.7 Year 2000 Environmental D.6-14 3.8 RCS Hot Leg Flow Measurement Officers D.6-15 3.9 Amount of Time PG&E Corporate Devote to DCPP Review & D.6-16 3.10 Auxiliary Saltwater System Tour with System Engineer Program D.6-17 3.11 Configuration Management Program D.6-19 3.12 Equipment Qualification Outage 1R10 D.6-20 3.13 Reportable Items in D.6-22 3.14 Performance Plans D.6-25 3.15 Control Room Tour Advisor D.6-25 3.16 Observe Shift Technical Training Class Discussion D.6-26 3.17 Observe Brown Bag Management Table Top D.6-27 3.18 Observe Multi-Facility Emergency Exercise D.6-29 4.0 Conclusions D.6-31 5.0 Recommendations xiii
6.0 References D. 6-31 D.7 Report on Fact Finding Meeting at DCPP D. 7-1 on April 18-19, 2001 1.0 Summary D. 7-1 2.0 Introduction D.7-2 3.0 Discussion D.7-2 3.1 DCPP Communications Update D.7-2 3.2 Results of December 2000 Culture D.7-3 Survey 3.3 Results of INPO Evaluation D.7-6 3.4 Tracking Data Concerning the Accredited D.7-6 Training & Instructor Training Programs 3.5 Update on Self-Assessments D.7-8 3.6 Company Status After Declaring D.7-9 Bankruptcy 3.7 Status & Plans for Dry Cask Storage of D.7-10 Spent Fuel 3.8 Probabilistic Risk Assessment Program D.7-11 3.9 Generation Vulnerability Identification D.7-12 Program 3.10 Establishment of Priorities for D.7-13 Operators 3.11 Security Response to QA Security Audit D.7-14 3.12 System Review of Component Cooling D.7-15 Water 3.13 Discussion with Manager, Radiation D.7-16 Protection 3.14 Nuclear Quality Services (NQS) - D.7-17 xiv
Status of Improvements from Last Biennial Audit & NQS Self-Assessment D.7-18 4.0 Conclusions D.7-20 5.0 Recommendations at DCPP D.8-1 D.8 Report on Fact Finding Meeting on May 1-2, 2001 D.8-1 1.0 Summary D.8-1 2.0 Introduction D.8-2 3.0 Discussion D.8-2 3.1 Changes in Radiation Protection Philosophy & Organization D.8-3 3.2 Radiation Protection Preparations for Outage 2R10 D.8-4 3.3 Radiation Control Area Tour Radiological D.8-5 3.4 Emergency Preparedness Processes & Tools Information D.8-6 3.5 Communicating Radiological to the Public D.8-7 3.6 STARS Update D.8-9 3.7 2000 Synergy Comprehensive Cultural Assessment Results D.8-11 3.8 Nuclear Safety Oversight Committee Meeting D.8-18 4.0 Conclusions D.8-19 5.0 Recommendation D.8-19 6.0 References xv
D.9 Report on Fact Finding Meeting at DCPP D. 9-1 on June 19, 2001 1.0 Summary D. 9-1 2.0 Introduction D. 9-1 3.0 Discussion D. 9-2 3.1 Human Performance Update D. 9-2 3.2 Behavioral Observation Based Safety D.9-3 (BOBS) Process Update 3.3 Work Process Review D. 9-5 3.4 Employee Assistance Program Update D. 9-5 3.5 Medical Center Update D. 9-7 4.0 Conclusions D. 9-8 5.0 Recommendations D. 9-8 6.0 References D. 9-8 E. Record of DCISC Tours of DCPP E-1 F. DCISC Open Items List F-1 G. DCISC Public Contacts G-1 G.1 DCISC Telephone/Correspondence Log G.1-1 G.2 DCISC Correspondence G.2-1 H. Past DCISC Recommendations and PG&E Responses H-1 I. DCISC Informational Brochure I-1 J. Glossary of Terms J-1 xvi
1.0 INTRODUCTION
Committee 1.1 Formation of the Independent Safety Canyon Independent Safety The establishment of the Diablo the terms of a Committee ("DCISC") was provided for as one of into by the Division of Ratepayer settlement agreement entered Commission Advocates ("DR-A") of the California Public Utilities of General ('AG") for the State
("CPUC"), the Attorney The Electric Company ("PG&E").
California, and Pacific Gas and 24, 1988, covered the agreement, dated June settlement associated with the two operation and revenue requirements ("Diablo Nuclear Power Plant units of PG&E's Diablo Canyon the commercial for the 30-year period following Canyon") arose out of rate The agreement operation date of each unit. before the CPUC for four proceedings that had been pending hearings and pre-trial years, and which included numerous of trial, the DRA, depositions. Just prior to the commencement and entered into the settlement the AG and PG&E prepared the CPUC for approval.
agreement and submitted it to The agreement provided that:
shall be established "An Independent Safety Committee one each appointed by consisting of three members, California, the Attorney the Governor of the State of of the California Energy General and the Chairperson Commission ("CEC"), respectively, serving staggered three-year terms. The Committee shall review Diablo of assessing the Canyon operations for the purpose any of operations and suggesting safety Neither the recommendations for safe operations. have any nor its members shall Committee operations, and plant responsibility or authority for direct PG&E have no authority to they shall in all The Committee shall conform personnel.
laws, regulations and respects to applicable federal
('NRC) policies."
Nuclear Regulatory Commission that the DCISC shall have the The agreement further provided of operating reports and records right to receive certain have the right to Diablo Canyon, and that the DCISC shall and of the Diablo Canyon site conduct an annual examination as it may to the plant site such other supplementary visits annual report, deem appropriate. The DCISC is to prepare an 1-1
and such interim reports as may be appropriate, which shall include any recommendations of the Committee.
The settlement agreement and its supplemental implementing agreement were referred to the CPUC for review and approval.
Following hearings before a CPUC Administrative Law Judge and the Commission itself, the CPUC, in December, 1988, approved the settlement agreement, finding that it was reasonable and "in the public interest" and that the "Safety Committee will be a useful monitor of safe operation at Diablo Canyon."
As required by the provisions of CPUC decisions and of Assembly Bill 1890 enacted by the California Legislature, which mandate electric utility rate restructuring and deregulation, PG&E filed an application which proposed a rate-making treatment for Diablo Canyon which would price the plant's output at market rates by the end of 2001. On May 21, 1997, the CPUC issued Decision 97-05-088, which found that the DCISC remains a key element of monitoring the safe operation of Diablo Canyon. The Decision ordered that the DCISC remain in existence under the terms and conditions of the settlement agreement (Decision 88 12-083, Appendix C, Attachment A) until further order of the Commission. Following PG&E's filing on April 6, 2001, in the United States Bankruptcy Court for protection and reorganization under Chapter 11 of the U.S. Bankruptcy Code as a result of the energy situation in California, the DCISC has continued to receive funding as provided under the terms of the 1997 Decision.
The first "Interim Report on Safety of Diablo Canyon Operations," covering the period of January 1 through June 30, 1990, was adopted by the DCISC on June 6, 1991, and there have been ten annual reports since then. This eleventh report covers the period July 1, 2000 - June 30, 2001 and was adopted by the DCISC at a public meeting on October 17, 2000.
1.2 Appointment of Committee Members The settlement agreement provided that the Committee members are to be selected from a list of candidates jointly nominated by the President of the CPUC, the Dean of Engineering of the University of California at Berkeley, and the President of PG&E, and that they "shall propose as candidates only persons with knowledge, background and experience in the field of nuclear power facilities." In July, 1989, when CPUC President G. Mitchell Wilk announced a list of nine candidates nominated for appointment to the DCISC, he noted that "an 1-2
could clearly requires members who independent safety committee For this reason, independence.
demonstrate objectivity and PG&E or any other party for none of the nominees has testified Regulatory Commission in any before the PUC or the Nuclear Canyon".
proceeding regarding Diablo 1.2.1 Philip R. Clark Clark was appointed by In August of 1994, Philip R.
Energy Commission to complete the Chairman of the California Committee Member Warren H.
the unfinished term of previous term Owen ending on June 30, 1995 and to a new three-year in 1998 to a new He was appointed beginning on July 1, 1995. 2001.
through June 30, three-year term of July 1, 1998 Executive Officer, and Chief Mr. Clark was President, Chief Corporation. Additionally, he Operating officer of GPU Nuclear GPU Service Corporation and was director of GPU Nuclear, GPU Nuclear Nuclear Experimental Corporation.
Saxton Generating operates the Oyster Creek Nuclear Corporation is Nuclear Station, Unit 1 and Station and Three Mile Island and of Three Mile Island Unit 2 responsible for the shutdown He retired from all Plant.
the Saxton Nuclear Experimental 1995.
these positions on December 31, Degree in Civil Engineering from Mr. Clark earned a Bachelor's he also did Institute of Brooklyn, NY where Polytechnic of Reactor graduate study. He attended the Oak Ridge School Technology in 1953-4.
Reactors, Naval Reactor He worked as Associate Director, as Chief, Reactor Division, US Department of Energy and Power Directorate, Naval Sea Engineering Division, Nuclear In these positions, the Navy.
Systems Command, Department of Rickover and directed a Hyman G.
Mr. Clark reported to Admiral He Nuclear Propulsion Program.
major element of the US Naval field for 45 years.
has worked in the nuclear power included Mr. Clark's activities during this reporting period to Old Dominion Electric Chairman of the Nuclear Advisors Independent Management Advisory Cooperative, and member of the Committee for Connecticut Yankee.
Academy of Mr. Clark is an elected Member of the National Society. He the American Nuclear Engineering and a Fellow of Civilian Service Award in 1972 received the Navy Distinguished and Development Administration and the US Energy Research 1-3
Special Achievement Award in 1976. He served as DCISC Chair July 1, 1996 June 30, 1997, July 1, 1997 - June 30, 1998 and July 1, 2000 - June 30, 2001.
1.2.2 E. Gail de Planque On February 3, 1998 E. Gail de Planque was appointed by the California Attorney General to succeed previous Committee Member Herbert H. Woodson (whose term ended on June 30, 1997) for a new three-year term ending June 30, 2000.
Dr. de Planque received her A.B. degree in Mathematics from Immaculata College, M.S. in Physics from Newark College of Engineering (now NJ Institute of Technology), and Ph.D. in Environmental Health Sciences from New York University. She attended the Program for Senior Managers in Government at Harvard University. Dr. de Planque was an Adjunct Associate Research Professor at New York Medical Center, a Member of the Engineering Science Department Advisory Committee to the Board of Trustees of the New Jersey Institute of Technology, and a Member of the Advisory Committee of the Nuclear Engineering and Engineering Physics Department at Rensselar Polytechnic Institute.
Dr. de Planque began her career in 1967 as a Research Physicist at the U.S. Department of Energy Environmental Measurements Laboratory. Her research centered around the application of basic physics of radiation interactions with matter to problems of radiation protection. Areas of specialty included solid-state dosimetry, radiation transport and shielding, environmental radiation, nuclear facilities monitoring, and problems of reactor and personnel dosimetry.
She became Deputy Director of the Environmental Measurements Lab in 1982 and then Director in 1987, responsible for the guidance, direction and management of the program activities, budget, personnel, and administrative functions of the Laboratory. Concurrently, Dr. de Planque served as Vice President and then President of the American Nuclear Society from 1987 to 1989.
From 1991 to 1995, Dr. de Planque served as a Commissioner of the U.S. Nuclear Regulatory Commission.
Dr. de Planque is a Fellow of the American Nuclear Society; an elected Member of the National Academy of Engineering; Member of the Board on Energy and Environmental Systems of the National Research Council; Member of the National Council on 1-4
President of the Radiation Protection and Measurements; Council; Member of the International Nuclear Societies Member of the Health Physics Association for Women in Science; Physical Society; Member of Society; Member of the American and the Advancement of Science; the American Association for among Nuclear Energy Academy; Secretary of the International numerous national and She has been involved in others. involved with international committees and working groups dosimetry, and measurements.
radiation protection, standards, Board of Current appointments include Northeast Utilities Plc. Board of Directors; Directors; British Nuclear Fuels, TU British Nuclear Fuels, Inc. Board of Directors; Member, Committee; Member, External Electric Operations Review Resource Center for Advisory Committee, Amarillo National various utilities and the United Plutonium; and Consultant for Energy Agency.
Nations International Atomic 1999 Chair for the period July 1, Dr. de Planque served DCISC 1, 2001 Chair for the period July June 30, 2000 and was elected
- June 30, 2002.
1.2.3 A. David Rossin was appointed by In July 2000, Dr. A. David Rossin on the Committee expiring July Governor Gray Davis to a term Professor to succeed previous Committee Member 1, 2002, William E. Kastenberg.
for Nuclear Energy, U.S.
Dr. Rossin was Assistant Secretary of the Department of Energy, and he served as President 1992-1993. He was Visiting American Nuclear Society from at the University of Scientist in Nuclear Engineering and taught graduate California, Berkeley from 1988-1991 as cycle. Dr. Rossin has served courses on the nuclear fuel Analysis Center at the Electric Director of the Nuclear Safety Chair of Power Research Institute and Director of Research and for the Commonwealth Edison the Nuclear Waste Task Force Industry Man of the Company. In 1982 he was voted Electric understanding his efforts to improve public Year . . . for issues." Dr. Rossin's of nuclear, energy and environmental Laboratory involved predictions research at Argonne National He reactor pressure vessel steel.
of embrittlement of nuclear He reactor shielding and safety.
also specialized in nuclear ten Safety Review Committee for served on Argonne's Reactor years and was its Chair for two years.
1-5
Dr. Rossin is President of Rossin and Associates, a consulting company which advises utility companies, trade associations, national laboratories and universities on nuclear and advanced energy technology, non-proliferation, waste management and other electricity related issues. He is a consultant to Lawrence Livermore National Laboratory and Los Alamos National Laboratory.
Dr. Rossin is currently an affiliated scholar at the Center for International Security and Cooperation at Stanford University. His present research is on the people and events which led up to the U.S. policy decisions of 1976-1977 to abandon reprocessing of spent nuclear fuel, its impacts, and the implications for the future. Dr. Rossin is currently writing a book based on this research. With Professor T.
Kenneth Fowler, Dr. Rossin published a book titled "Conversations on Electricity and the Future - Findings of an International Seminar and Lessons from a Year of Surprises" (U.C. Printing Service, June 1991).
Dr. Rossin received his B.S. degree in engineering physics from Cornell University, his M.S. degree in nuclear engineering from the Massachusetts Institute of Technology, an M.B.A. from Northwestern University and his Ph.D. in metallurgy from Case Institute of Technology.
1.3 Documents Provided to the DCISC The settlement agreement provides that the DCISC shall have the right to receive on a regular basis specified operating reports and records of Diablo Canyon, as well as "such other reports pertinent to safety as may be produced in the course of operations and may be requested by the Committee". Hundreds of documents have been provided by PG&E and the Nuclear Regulatory Commission to the DCISC, relating to both historical and current operations. Document lists are shown in Volume II, Exhibit A.
1.4 Committee Member Site Inspection Tours and Fact-finding Meetings The DCISC Members and Consultants visit DCPP regularly to attend fact-finding meetings and tour areas of the plant to inspect systems, equipment or structures which the Committee has under review or has interest. Additionally, the Members and Consultants tour the plant annually with members of the public 1-6
meetings is as described below. A record of these fact-finding Volume II, Exhibits D, and plant tours and contained in Exhibit E.
inspections are presented in Meetings By Mr. Philip Inspections and Fact-finding 1.4.1 R. Clark made two visits to the DCISC Member Philip R. Clark 2001 in
- June 30, DCPP site during the period July 1, 2000 These visits are summarized as addition to the public tour. can be found follows (detailed trip reports for these visits in Volume II of this report):
and DCPP with Consultants Booker December 13-14, 2000 - to meeting to observe PG&E Cass to attend a DCISC fact-finding an report; human performance; responses to the DCISC annual employee fitness, attention informal meeting with supervisors; employee concerns program; enhancement, and stress management; plan; DCPP competition program; DCPP five year safety alternate source work load; transition program; engineering problems; terms; joint utility venture status; top ten quality asset self-assessment program; and security computer system; teams (See Volume II, Exhibits D.4 and D.5) .
attend with Consultant Wardell to March 14-15, 2001 - To DCPP to review NRC outage safety a DCISC fact-finding meeting Auxiliary Saltwater System, report, corrective action program, maintenance, configuration on-line winter storm experience, RCS flow measurement, and management, equipment qualification, Exhibit D.9).
Volume II, environmental performance (See Meetings By Dr. E. Gail 1.4.2 Inspections and Fact-finding de Planque made two visits to DCISC Member E. Gail de Planque These visits are the DCPP site during the reporting period.
trip reports for these visits summarized as follows (detailed this report) can be found in Volume II of Wardell for a fact May 1-2, 2001 - To DCPP with Consultant an NSOC meeting and to review finding meeting to observe preparations, emergency protection, outage radiation survey results (See STARS, and safety culture preparedness, Volume II, Exhibit D.8).
1-7
June 19, 2001 - To DCPP with Consultant Cass to review human performance, behavior-based safety plan, work processes, employee assistance program and an update with the DCPP medical director (See Volume II, Exhibit D.9).
1.4.3 Inspections and Fact-finding Meetings by Dr. A.
David Rossin DCISC Member A. David Rossin made three visits to the DCPP site during the reporting period. These visits are summarized as follows (detailed trip reports for these visits can be found in Volume II of this report).
October 25-25, 2000 - To DCPP with Consultant Wardell for a fact-finding meeting to observe an outage daily meeting; tour the containment and the outage work control center; review the outage safety plan, main turbine work, radioactive waste processing systems, reactor pressure vessel integrity, aging management, and radiation protection. The trip included meetings with the Station Vice-President, Engineering Vice President and managers of Operations, Maintenance, Radiation Protection, Human Resources and Nuclear Quality & Licensing and with the NRC Resident Inspector (Volume II, Exhibit D.2).
November 14-15, 2000 - To DCPP with Consultant Booker for a fact-finding meeting to observe NSOC/PNAC meetings and to discuss intake structure inspection results, reactor trip corrective actions, industry cracked piping concerns, nuclear fuel matters, steam generator inspection results, and spent fuel storage status (See Volume II, Exhibit D.3).
April 18-19, 2001 - To DCPP with Consultant Booker to review DCPP radiological communications, results of safety culture survey, INPO evaluation results, accredited training programs, self-assessments, PG&E bankruptcy status, dry cask storage of spent fuel, probabilistic risk assessment, aging management, operator priorities, QA security audit, Component Cooling System, radiation protection, and the NQS biennial audit (See Volume II, Exhibit D.7).
1.4.4 Tour of DCPP by DCISC Members and Members of the Public on February 7, 2001 The DCISC performs a public tour of Diablo Canyon Power Plant each year with members of the public in conjunction with its January/February Public Meeting. The tour is noticed in 1-8
and members of the public advance in the local newspapers, sign up in advance.
where at the PG&E Community Center, The tour began at 7:30 AM exhibits gathered to tour the plant 15 members of the public Canyon Power Plant video "Diablo and view the Diablo Canyon joined by the three DCISC Members, Today." The public group was introduced The DCISC Members and three DCISC consultants. described the and the Committee consultants, themselves DCISC.
questions about the Committee's function and answered for the trip to the plant, while The group boarded a PG&E bus of group on the history and features PG&E personnel briefed the between the discussions took place Diablo Canyon. Individual representatives.
members of the public and Committee Control site, the group visited the Upon arriving at the plant operator training a discussion of Room Simulator and heard This was observed at the controls.
where an operating crew period.
included a questions and answer was the plant, the group split into two sub-groups, Inside and received a welcome and processed through plant security the The groups then toured briefing from plant personnel.
following areas of the station:
deck, the main turbines
"* Turbine Building main operating and generators and related piping and equipment and additional plant
"* Turbine Building lower decks separator reheaters, equipment, including the moisture condenser, and steam dump valves of area (including discussion
"* Outside transformer recent upgrades) the glass door)
- Control Room (viewed through a
toured the Steam Generator mock-up and heard The group steam performed inspections of presentation of how personnel generator tubes.
and group then viewed the Intake Structure from an overlook The buildup of ocean storms and kelp participated in a discussion problems.
the plant tour concluded at the site overlook above by The to view exterior features which were described buildings the 500 observed and heard described PG&E personnel. The group 1-9
kV switchyard and an account of the September 22, 1999 lightning strike at the switchyard, which caused a reactor trip. This was followed by a drive-by of the 230 kV switchyard, a protected archeological site, and the plant water discharge to the ocean.
During the return to the visitor's center on the bus, members of the public and the Committee Members and Consultants held individual discussions concerning the DCISC, Diablo Canyon and nuclear power.
1.4.5 Visits by DCISC Members to California State Agencies DCISC Chair Mr. Clark and Committee Counsel Wellington had a meeting on December 15, 2000 with Commissioner Laurie of the California Energy Commission. Mr. Clark provided information (a document summarizing DCISC activities and recent DCISC recommendations) to the Commissioner and his staff on the Committee and its activities, and he answered several questions concerning the Committee and its role.
On June 22, 2001, DCISC Vice-Chair Dr. de Planque and Committee Counsel Wellington met with staff attorneys of the California Attorney General's office in Sacramento to provide an update (since the last meeting between representatives of the Committee and the Attorney General's office on June 9, 2000) on the Committee's current activities, future plans and site visits. The staff members were interested in the DCISC activities, the California energy situation, the potential for any impact on DCPP operations due to the bankruptcy declaration by PG&E and issues related to nuclear power in general.
The DCISC has plans to schedule annual meetings between its Members and their appointing entities and with Commissioners or representatives of the California Public Utilities Commission to provide background on and information regarding current activities of the Committee.
1-10
2.0 REPORTS OF DCISC PUBLIC MEETINGS in the vicinity of the The DCISC held three public meetings Diablo Canyon Power Plant. These meetings are listed below.
in this report as described.
Minutes of the meetings are located are located in the DCPP Public Full transcripts of each meeting Polytechnic Document Room in the library at the California Institute in San Luis Obispo, California.
2.1 September 14-15, 2000 Public Meetings Exhibit B.1) was A Notice of Meeting (see Volume II, along with several display published in the local newspapers, to the media and those persons on advertisements, and was mailed Exhibit B.10) . The the Committee's service list (see Volume II, II, Exhibit B.2, and minutes of meeting agenda is shown in Volume II, Exhibit B.3.
the meeting are included in Volume 2.2 February 7-8, 2001 Public Meetings Exhibit B.4) was A Notice of Meeting (see Volume II, along with several display published in the local newspapers, to the media and those persons on advertisements, and was mailed Exhibit B.10) . The the Committee's service list (see Volume II, II, Exhibit B.5, and minutes of meeting agenda is shown in Volume II, Exhibit B.6.
the meeting are included in Volume 2.3 June 20-21, 2001 Public Meetings Exhibit B.7) was A Notice of Meeting (see Volume II, the local newspapers, along with several display published in the media and those persons on advertisements, and was mailed to Exhibit B.10) . The the Committee's service list (see Volume II, II, Exhibit B.8, and minutes of meeting agenda is shown in Volume II, Exhibit B.9.
the meeting are included in Volume 2-1
(NRC) 3.0 NUCLEAR REGULATORY COMMISSION ASSESSMENTS AND ISSUES 3.1 Summary of License Event Reports 3.1.1 Discussion reports required of License Event Reports (LERs) are Regulatory power plant licensee by Nuclear the nuclear when an off-normal event occurs Commission (NRC) regulations These events include at an operating nuclear station.
of or in violation of station operations or conditions outside or NRC regulations.
procedures Technical Specifications (TS),
reported by telephone and by written Events are to be promptly knowledge of the or initial report within 30 days of the event for events, which NRC event. Voluntary LERs are submitted but are not specifically should know about or are significant required by NRC.
time period and corresponding The LERs reported during this corrective action were as follows:
(TS) 3.6.5, Containment Air I. Technical Specification was not met when a containment Temperature Limiting Condition, failed "as-is" and went average air temperature indicator surveillances for during subsequent daily undetected approximately 51A months. (LER 2-2000-003-00).
an unanticipated failure mode The root cause was reported as however, it appears to actually for the temperature indicator; when the indicator was replaced be personnel error because, did not consider an with a new design in 1988, engineering indicator would fail that the "as-is" failure. It was believed be readily noticed. Based on either high or low which would was specified to look that assumption, no routine surveillance for a "fail-as-is" type of failure.
of operators satisfying Immediate corrective action consisted manually calculating specification by the technical temperature air temperature using individual containment replaced, calibrated was readings. The temperature indicator recurrence, the to service. To prevent and returned operators to to direct surveillance procedure was revised average calculate containment observe the instrument actively air temperature on their rounds.
3-1
Containment air temperature is an initial condition used in the design basis accident analysis. The maximum temperature is 120 0 F, and the TS assures that maximum is not exceeded during operation. PG&E analysis of the event concluded that there was no adverse impact on safety because three redundant temperature indicators were operational, containment air coolers were functioning normally, and there had been no temperature anomalies during the period. There was no safety system functional failure, and the event was determined to be of "green" (see Section 3.4 for definition of "green") safety significance, based on the NRC Significance Determination Process. There had been no previous similar events.
- 2. PG&E reported that more than one percent of the tubes in Steam Generator (SG) 1-2 were defective, based on analysis of eddy current testing during outage 1R10. The report is required by Technical Specifications. The majority of tube defects were caused by primary water stress corrosion cracking (PWSCC) and outside diameter stress corrosion cracking (ODSCC) . (LER 1-2000-010-00).
Immediate corrective action included plugging of all defective tubes. PG&E maintains a long-term comprehensive program to minimize SG tube degradation. PG&E analysis of the defects showed that the tubes met the applicable criteria for tube structural integrity at the end of 1R10, and PG&E concluded that there was no safety concern. Similar reports had been made for Unit 1 defective SGs 1-1 and 1-2 tubes following outages 1 & 2R8.
- 3. During 1R10 in Mode 6, Refueling, an engineered safety feature (ESF) actuation signal initiated a trip of the auxiliary electrical power separating Vital Bus F from offsite power. The loss of auxiliary power actuated an undervoltage relay, starting Component Cooling Water Pump 1-1. (LER 1-2000 007-00).
The root cause was determined to be personnel error in that a utility licensed operator mistakenly performed two surveillance tests ("Outage and Pre-Outage Diesel Engine Analysis" and "Vital Bus Undervoltage Relay Calibration")
simultaneously. A contributing cause was a procedure which did not contain adequate precautions to prevent the simultaneous tests.
Immediate corrective action was to halt the tests and review plant conditions to assure the individual tests could proceed 3-2
was revised to include appropriate normally. The procedure precautions.
that all plant equipment Analysis of the event concluded the event did not involve a functioned as designed and that The condition was determined safety system functional failure. Significance "green" (Section 3.4) based on NRC's to be had occurred.
events Determination Process. No similar safety feature actuation occurred when
- 4. An engineered due to an (ASW) Pump 1-2 tripped Auxiliary Saltwater Bus G components initiation of a load-shed signal to 4kV Vital relays to return of undervoltage protective during the service. (LER 1-2000-008-00).
(caused by looseness and The root cause was high resistance adequate reset corrosion) in a test switch that prevented A to the undervoltage relays.
voltage from being applied unfamiliarity with returning contributory cause was operator the relays to service.
ASW flow by aligning it Corrective actions included restoring the failed test switch.
repairing to the Unit 2 ASW system and was issued to Additionally, an Operations incident summary state to returning solid alert operators to issues related determine relays to service. An investigation performed to a generic problem found no whether the switch failure was other problems.
about of spent fuel cooling for The event resulted in loss in the Final Safety a situation analyzed five minutes, the Unit 1 reactor Analysis Report. The event occurred when was the only ESF load running was defueled, and ASW Pump 1-2 that the event was not risk on Vital Bus G. PG&E concluded a safety system functional significant and did not involve failure.
events.
There had been no previous similar was excessive Component
- 5. During Unit 1 outage 1R10, there CCW headers because of valves Cooling Water (CCW) flow between This condition prevented which would not close properly. (LER 1-2000-009 vital headers.
effective separation of the 00).
stops error in that valve travel The root cause was personnel installed during been misadjusted when originally had 3-3
construction. The travel stops allowed the valve discs to rotate past the valve seats.
Immediate corrective actions included properly closing the valves, adjusting the valve travel stops, and verifying the proper adjustments of valve travel stops on similar valves.
Corrective action to prevent recurrence consisted of maintenance verification testing for similar valves to ensure the travel stops are left properly adjusted after maintenance.
PG&E's analysis of the event indicated that the condition was not a safety system functional failure and that it was evaluated to be "green" (Section 3.4) using the NRC Significance Determination Process.
There has been no previous similar events.
- 6. During power operation on Unit 2, Emergency diesel Generators 2-1, 2-2 and 2-3 started, as designed, as a result of loss of power to the startup power system. The loss of power was due to an open disconnect switch separating the startup transformer from the 230 kV system for scheduled maintenance. (LER 1-2000-004-00).
The root cause of the event was personnel error (lack of attention to detail) due to both the operator and verifier failing to verify that the disconnect switch number matched the number on the procedure.
Immediate corrective action included reclosing the switch and securing the diesel generators. To prevent recurrence color coded signs have been installed to designate the switch corresponding to each unit and the operators making the error were coached and counseled on correct self-verification techniques.
PG&E determined that this event had no adverse safety impact and that the event was not a safety system functional failure.
Under the NRC Significance Determination Process, the event screened out "green" (Section 3.4).
There were no similar previous events of operators inadvertently opening these or similar disconnect switches.
- 7. Unit 1 was critical in Mode 2 - Startup following outage lRI0, when the operators manually tripped the reactor due to a failure in the rod control system. The failure was noticed by 3-4
failure in the system.
indicating a an "urgent failure alarm",
(LER 1-2000-011-00).
of was determined to be failure of a portion The root cause inward rod Memory Card that controls the Supervisory Buffer investigation of the Immediate action included initial The motion.
tripping of the reactor and troubleshooting. the problem, and personnel performed card was replaced, faulty before resuming verification testing necessary maintenance startup.
was no of the event concluded that there PG&E analysis systems were in adverse safety impact because in significant and alarm the failure, procedures were place to detect operator action, and systems were place to direct appropriate the reactor, if necessary.
trip in-place to automatically event in 1991, which was the a previous similar There was due to personnel supply fuse believed failure of a rod power the current however, that root cause was different than to error; previous corrective action would not be expected event, and have prevented this event.
46% full power
- Power Operation at
- 8. Unit 1 was in Mode 1 it experienced an undergoing incore flux map testing, when electrical and trip. The trip was due to an intermittent automatic in test equipment attached to the Nuclear short circuit tripped concurrent with a preexisting Instrumentation (NI), considered an the NI. The event was condition associated with and reactor protection system engineered safety feature actuation. (LER 1-2000-012-00).
cause of the trip was the electrical Although the immediate the root cause of the event was short in the test equipment, error, i.e., the decision made to to be personnel determined prior to restoring with testing on the redundant NIs proceed service.
the tripped channel to from the trip, action was to recover Immediate corrective and plan long-term an event investigation, revise the perform actions were to corrections. The long-term to plant issuance of a memo controlling test procedure; an electrical short regarding the possibility of personnel an event case of equipment; providing when using this type and Operations to appropriate Engineering, Maintenance to clarify study similar procedures personnel; and revising prerequisites.
adjustments and test system analysis concluded that the reactor protective been Event and reactor trips have tripped the reactor, properly 3-5
analyzed conditions in the Final Safety Analysis Report as acceptable and expected transients. All engineered safety equipment performed as expected in the shutdown.
PG&E determined that there had been no previous similar events.
- 9. Unit 1 was in Mode 3 - Hot Standby at 0% full power and, Unit 2 was in Mode 1 - Power Operation at 100% full power, when security discovered what appeared to have been an explosive device in the protected area. The device was treated as a credible bomb threat, and a Security Alert was declared, followed by an Unusual Event. About 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> later, the device was determined to be a fake, and the Unusual Event was cancelled.(LER 1-2000-S01-00).
The fake bomb was apparently created as a prank with no malicious intent. The root cause was determined to have been a contractor work-group culture that tolerated unprofessional behavior.
The Security Review Group evaluated the event and determined that all security requirements had been met and that the security contingency plan had been effectively implemented.
Because the bomb was a fake and not the result of criminal, terrorist or malicious intent, the FBI and Sheriff's Office did not pursue prosecution of the perpetrator. PG&E determined that had the bomb been real, it would not have been a threat to vital plant equipment given its location.
- 10. With Unit 1 and Unit 2 both at 100% full power in Mode 1
- Power Operation, a security officer left his rifle unattended in an office in the Turbine Building for approximately 22 minutes. The rifle was retrieved with all ammunition accounted for. (LER 1-2001-S02-00).
The cause was determined to have been personnel error, specifically, inattention to detail. Corrective actions included disciplinary action for the responsible officer, additional rifle racks in several security holding areas, and emphasis on the event by the Manager of Security Services to security officers.
Analysis by security concluded that the response to the event was within the bounds of the capability of the security force.
No previous similar events existed.
3-6
Operation at 100%,
II. Units 1 and 2 were in Mode 1 - Power in a trip circuit for the when a broken wire was discovered Additional Spray Pump (CSP) 2-2 Breaker.
Containment in CSP 1-1 degraded wires inspections discovered additional operators Additionally, during repairs, circuits. (TS) by having Specifications inadvertently violated Technical for greater Bus H inoperable all three power sources to Vital than one hour. (LER 2-2-1-01-00).
was the result of bending The root cause of the degraded wires are opened and closed for when the breaker cubicle doors Operators failed to meet TS Operations and Maintenance access.
procedural guidance.
because of incomplete and inconsistent replaced, and problems found The degraded wire for CSP 2-2 was switchgear cubicles for on other wires in the 4.16 kV vital same way. Corrective actions both units were corrected in the formulated by PG&E at the to prevent recurrence were being up on that plan time of this writing. The DCISC will follow the Open Items List, Exhibit (follow-up items are tracked on F).
Procedures were revised Concerning operator action, Operating and acceptable to clearly indicate necessary precautions training was conducted on the conditions to meet TS. Operator event.
that of the 15 degraded wires PG&E event analysis concluded found, 13 were operable, and two could have not performed redundant equipment could their functions. In these two cases, trip functions. Thus, PG&E have performed the needed breaker low risk significance in this concluded that there was very operator action concluded that event. Analysis of incorrect
,during an accident, would have been a slight the effect resulting in delays in increase in peak Containment pressure operation of Containment fan coolers and CSPs; effective the plant design and however, the increase was well within licensing basis.
degraded wiring existed. One No previous similar events of in which the 230 kV offsite similar event occurred in 1995 its design requirements; power system was unable to meet not been expected to however, corrective actions would have prevent the current event.
100%
- 12. Units 1 and 2 were in Mode 1 - Power Operation at Generators (EDGs) full power, when the Emergency Diesel upon loss of power on the 230 kV startup started as designed power system. The loss of power was due to phase-to-phase 3-7
arcing on the 230 kV lines because of heavy smoke from a fire.
An Unusual Event was declared for an out-of-control fire for greater than 15 minutes. (LER 1-2001-001-00).
The root cause of the event was inadequate administrative controls and DCPP personnel oversight of California Department of Forestry activities during cutting and burning of brush in the transmission line corridor.
Fire crews monitored the fire until it self-extinguished. PG&E developed additional procedural guidance to formalize the administrative control and oversight of future burning activities. The procedures address advance planning and contingencies, improved communications between PG&E and Forestry personnel, and PG&E expectations for burning operations.
A similar event (including declaration of an Unusual Event) occurred in 1991 when a wind shift caused a controlled fire to jump fire lines. PG&E determined that those corrective actions (minimum training requirements for personnel, minimum personnel and equipment, and review and approval) would not have prevented the current event.
3.1.2 Voluntary LERs There was one voluntary LER submitted by PG&E during this period.
- 1. PG&E determined that several non-load-bearing concrete walls in the Turbine Building did not meet design requirements applicable to the Hosgri Seismic Criteria. The walls were required to remain intact for seismic and fire protection of safety related equipment. Additionally, some attached components did not satisfy similar design requirements. The condition was discovered by a PG&E engineer while evaluating the effect of a proposed plant modification. (LER 1-2000-003 00).
The condition was caused by personnel error and an inadequate design process in that the original designers did not consider the potential that quality-related equipment would be mounted on the walls, and the calculations for the Hosgri seismic event did not consider the cumulative effect of the mounted equipment.
Corrective actions included performing calculations to assure that all safety functions were maintained; however, some loss of design margin resulted in the need for reinforcements to 3-8
Administrative controls, including restore the margin.
component list, drawings, procedures and the safety-related were changed to prevent recurrence.
because the walls could PG&E event analysis concluded that have performed their functions, albeit with reduced design impact on safety.
margins, there was no significant adverse event closely when it was The DCISC had begun reviewing this first discovered in October 2000 and believed PG&E had the problems; however, effectively analyzed and corrected problems, other similar engineering design because of had area, the DCISC particularly in the Civil Engineering on a broader basis. PG&E recommended PG&E investigate this recommendation (see Section satisfactorily responded to Recommendation RO0-11).
6.0 and Exhibit G of this report, Reactor Trips Reported in LERs 3.1.3 LERs:
Two reactor trips were reported on Type Cause Root Cause Date Unit Manual Rod control system Faulty 11-5-00 1 failure component Automatic Electrical short Faulty 11-20-00 1 &
in test equipment component personnel error problems during or following these There were no significant trips.
periods the following numbers In the past five DCISC reporting of trips have occurred:
Number of Trips Automatic Manual Reporting Period 4 2 1996/1997 1 1 1997/1998 0 1 1998/1999 2 2 1999/2000 1 1 2000/2001 3-9
3.1.4 LER Trends The following table depicts the LER history for DCPP for the last five DCISC reporting periods:
Time Period Number of LERs Submitted 7/1/96 - 6/30/97 25 (plus 3 voluntary LERs) 7/1/97 - 6/30/98 21 (plus 0 voluntary LERs) 7/1/98 - 6/30/99 15 (plus 0 voluntary LERs) 7/1/99 - 6/30/00 15 (plus 1 voluntary LER) 7/1/00 - 6/30/01 12 (plus 1 voluntary LER)
During the current reporting period, 11 of the 13 (12 required and one voluntary) reported events were reported within the requirement of within 30 or 60 days of event discovery. The eleven events were realized at the actual occurrence of the event, and two events were realized about six months and many years later than occurrence because of their undetectable nature. Of the 13 LERs, 7 were self identified by PG&E and 6 were self-revealing.
The stated root causes of the 13 LERs were as follows:
Number Percent Root Cause of Causes* of Total Personnel error 8 50 Equipment failure/degradation 5 31 Inadequate admin. controls 3 19 Total 16 100
- The 13 LERs resulted from 16 causes 3.1.5 DCISC Evaluation, Conclusions and Recommendations Each Licensee Event Report was investigated by PG&E to determine the plant conditions before and during the event, background and detailed event description, root cause and contributory causes, immediate and preventive corrective action, and previous LERs on identical or similar problems. No one LER was significant enough to seriously affect operational safety. Except for personnel error, no significant cause code trends were observed. LER investigation reports were submitted to all DCISC Members and Consultants for review; PG&E reported on each LER at DCISC public meetings.
3-10
continues to be personnel The largest contributor to LERs five-year LER personnel error error. The table below shows errors have been categorized history. The specific personnel as follows: Percent Number No. Personnel of LERs Errors Personnel Reporting Period Error 25 15 60 1996/1997 81 1997/1998 21 17 15 9* 60 1998/1999 53 15 8 1999/2000 50 13 (16)** 8 2000/2001 occurred 10-15 years
- Two of these personnel errors had previous
- The 16 causes were included for 13 LERs (13.3%) than the previous two The number of LERs is two fewer than in previous years. The periods and significantly less five-year trend shows improvement.
(LERs) has decreased in The number of License Event Reports the major cause the last five years. Personnel error remains and of LERs; however, it is also decreasing in both number DCPP LER investigations appeared percentage of total.
to be generally adequate, and corrective actions appeared appropriate for all LER events.
The DCISC is following PG&E's programs addressing personnel is included in this report in errors, and a description Section 4.9 - Human Performance.
LERs, their causes, and The DCISC will continue to monitor future fact prevent them in PG&E's actions to correct and finding and public meetings.
3.2 NRC Inspection Reports 3.2.1 Discussion at each nuclear power The NRC performs inspections the plant is to determine how well plant. The purpose NRC regulations, operators are implementing and following Specifications, and other requirements, plant Technical regulatory commitments. Generally, better procedures, or with the NRC meets performance results in fewer inspections. review plant safety year to nuclear plant operator twice per 3-11
performance under the NRC Reactor Oversight Process (see Section 3.4 below). These meetings are usually public.
Inspections are performed by the plant Resident NRC Inspectors, inspectors from the NRC Region Office, experts from other NRC organizations, and NRC consultants. The bulk of inspections are routine, announced visits focusing on one or more specific areas of operation such as ALARA, maintenance, chemistry, security, operator examinations, or corrective actions. Special inspections are often made for investigation into previous events affecting plant safety and into special programs, such as NRC Generic Letter 89-10, Testing of Motor-Operated Valves.
Each inspection usually concludes with an exit interview with licensee personnel, followed by a written inspection report.
Inspections can result in the following categories of findings:
"* Unresolved Items are items for which information is not yet available or awaiting licensee response or action.
"* Individual strengths are used to point out good practices and weaknesses for the licensee's attention for improvement and/or to prevent future problems.
"* Deviations are variances from NRC regulations and/or licensee procedures or other requirements or commitments which are not as severe as outright violations.
"* Concerns, typically including more than one individual weakness in a single area, are to alert the licensee to situations which could become violations if not corrected.
"* Non-cited Violations are violations for which NRC credits the licensee for identifying the violation and/or for prompt, effective corrective action completed before or taken during the inspection. These are usually non recurring, non-safety-significant items.
"* Violations of NRC regulations, plant Technical Specifications, and other commitments, procedures, etc.
require a formal response and corrective action. Violations carry four severity levels as described in Section 3.3, NRC Enforcement Actions.
Fewer violations generally mean better performance. Many in the industry think having a significant number of non-cited violations indicates an effective, aggressive regulatory 3-12
its quickly finds and corrects program, meaning the licensee them.
than the NRC finding own problems/violations rather 12
- June 30, 2001, there were During the period July 1, 2000 DCPP. This inspection reports received from the NRC for previous five 22, 23, 20 and 20 in the compares with 36, with NRC periods, respectively. PG&E's regulatory performance Of has been good, and this generally means fewer inspections.
performed by resident or these 12, 8 were routine inspections were special inspections.
regional NRC inspectors, and 4 Routine Inspections
"* Emergency preparedness (covers many
"* Operations, maintenance & engineering subcategories)
"* Radiation Protection and Chemistry Controls
"* Inservice Inspection
"* Project Engineering
"* Safeguards
"* Maintenance Rule
"* 10CFR50.59
"* Heat Exchangers
"* Corrective Action Program Special Inspections
& Loss of Offsite Power
"* Fire in Unit 1 Non-vital 12kV Bus Auxiliary Saltwater System
"* Design Adequacy & Performance of and 4160v AC Systems Normal Heat Removal
"* Three Reactor Trips with Loss of to Offsite Brush Fire
"* Unusual Event on Loss of 230kV Due 3.2.2 DCISC Evaluation and Conclusions no individual items The DCISC noted that there were trends in Nuclear Regulatory or apparent significant new additional Commission (NRC) inspections, which would warrant Personnel errors continue to be recommendations or actions.
reports, and the DCISC identified as problems in inspection Although the DCISC routinely will continue to monitor that. in fact finding on inspection report items follows-up actions on NRC meetings, the DCISC plans no particular in noted below in the discussion inspection reports, except as Actions.
Section 3.3, NRC Enforcement 3-13
3.3 NRC Enforcement Actions 3.3.1 Discussion NRC considers items not in compliance with its regulations or with the licensee's commitments or procedures to be violations. Corrective action is required for all violations. NRC identifies five severity levels for violations.
Level I is the most severe, representing the most significant regulatory concern which usually involves actual or high potential impact on the safety of the public. Level IV violations are more than minor concern and should be corrected so as to prevent a more serious concern. Civil penalties (monetary fines) are usually imposed for Level I and II violations, are considered for Level III, and usually not imposed for Level IV violations. Most low-level violations are reported as Non-cited Violations provided the licensee places the violation into its corrective action program and provided the violation is not willful or repetitive. NRC has increased its scrutiny of corrective action programs. The categorization of violations in this report follows NRC's actual classification in each notice of a violation.
During the period July 1, 2000 - June 30, 2001, NRC cited no Level I, II, III or IV violations and identified 10 non-cited violations. The history of violations for this and the last four DCISC reporting periods is as follows:
DCISC Number of Violation Severity Level Violations Reporting Period Inspections III IV V Non-Cited Total 7/1/96 - 6/30/97 23 - 23 - 19 42 7/1/97 - 6/30/98 28 - 21 - 20 41 7/1/98 - 6/30/99 20 - 7 - 15* 22 7/1/99 - 6/30/00 20 - 2 - 29 31 7/1/00 - 6/30/01 12 - - - 10 10
- One Non-cited violation was Level III PG&E has not received any Level I or II violations since the inception of the DCISC in 1990.
Non-Cited Violations During the period July 1, 2000 - June 30, 2001, NRC reported 10 non-cited violations. These were considered "non-cited" because they satisfied the criteria specified in the NRC Enforcement Policy that either (1) PG&E identified the problem 3-14
cause as a normal part of ite and corrected the root during the NRC inspection Corrective Action Program before or enough to not warrant full visit, (2) the violation was minor they were part of NRC's policy (see violation status, or (3) The non IV violations.
above) to not normally cite Level cited violations were:
review of the Emergency Preparedness
- 1. Inappropriate an individual who had Program due to using as a reviewer error.
responsibility for the program - personnel load center not restrained as required to
- 2. Portable Component with adjacent prevent potential seismic interaction Cooling Water piping - personnel error.
isolation valves
- 3. Safety Injection accumulator discharge 1000 psig Reactor Coolant energized above, rather than below, System pressure - personnel error.
procedures on two
- 4. Personnel failed to follow maintenance wrong component or unit occasions resulting in work on the personnel error.
survey of the upper
- 5. Failure to perform a contamination the internal lifting rig platform prior to a worker entering area - personnel error.
to obtain radiation dose rate
- 6. Four workers failed entering a high radiation area information prior to personnel error.
unit: (i) lifting a
- 7. Two cases of working on the wrong causing an the wrong unit's electrical panel, lead in leakage loss of the Reactor Coolant System inadvertent startup detection system and (ii) operating the wrong unit's loss of the Unit 2 power transfer switch, causing inadvertent startup transformer - personnel errors.
Plan requirements in
- 8. Failure to follow Physical Security error.
warehouse access control - personnel System train separation
- 9. Loss of Component Cooling Water due to leakage of train boundary valves caused by improper valve adjustment - personnel error.
area survey associated
- 10. Failure (i) to perform a radiation and (ii) to tank filter with the replacement of a spent resin materials of radioactive follow a procedure for two incidents control area - personnel being found outside of the radiation error.
3-15
3.3.2 DCISC Evaluation and Conclusions The number of NRC inspections in this period was sharply down from the number of inspections in recent periods.
The number of NRC cited violations has dropped substantially (to zero) from previous periods (see table of five-year inspection violation history in Section 3.3.1). The numbers of non-cited violations decreased significantly this period, likely due to improved regulatory performance at DCPP and to NRC's policy to not cite violations for events which the plant operator identifies and corrects within its Corrective Action Program. DCISC noted no particular trend to the violations.
Approximately half of the non-cited violations were initially identified and reported by PG&E. The remainder were discovered by the NRC inspectors. Many of these were reported by NRC as a means of documenting their review of problems which PG&E had already identified and corrected, were corrected during inspection visits, or were of minor safety significance.
Similarly to the NRC, the DCISC determined that the non-cited violations were minor.
The DCISC heard presentations by PG&E on each violation at public meetings and has reviewed each cited violation and PG&E's response, where applicable. PG&E corrective actions appeared adequate. There were no individual items of significance to warrant DCISC recommendations or actions.
The DCISC considers corrective actions taken on NRC violations generally satisfactory to correct the violations and to prevent recurrence of similar violations. DCISC will follow-up on selected violations to determine the effectiveness of corrective action (tracked on DCISC's Open Items List, Exhibit F).
As in previous periods, personnel error is the largest contributor to Licensee Event Reports and NRC Notices of Violation. The DCISC has and will continue to actively monitor PG&E's programs to reduce human error. (The DCISC review of DCPP Human Performance is in Section 4.9).
3.4 NRC Performance Evaluations The Nuclear Regulatory Commission (NRC) had previously assessed each nuclear power plant licensee about every 18 months on its overall performance in meeting NRC requirements 3-16
Assessment of Licensee Performance using its Systematic to collect data to (SALP). SALP was an integrated effort functional areas:
evaluate the following four Operations Maintenance Engineering Plant Support Radiological Controls, Emergency Plant Support Area included and Fire Protection.
Preparedness, Security, Housekeeping are considered for Verification Safety Assessment and Quality a four main functional areas rather than each as each of the process, performance was somewhat separate area. In NRC's SALP areas.
the above four functional subjectively addressed for highest SALP rating.
DCPP typically received NRC's (NRC) revamped its Nuclear Regulatory Commission The programs for assessment, and enforcement inspection, takes into The new process commercial nuclear power plants. of the nuclear improvements in the performance account improved approaches of years and industry over the past 25 performance at NRC-licensed inspecting and assessing safety plants.
Oversight Process (RROP) monitors The new NRE Revised Reactor broad areas (called strategic licensee performance in three performance areas):
and reducing the
- 1. Reactor Safety (avoiding accidents they occur) consequences of accidents if (protecting plant employees and the
- 2. Radiation Safety public during routine operations) sabotage or
- 3. Safeguards (protecting the plant against other security threats).
performance within each of The process focuses on licensee in the three areas:
"Seven Cornerstones" of safety Radiation Safety Safeguards Reactor SafetyEvents
- Occupational -;Physical
" Initiating Protection
"*Mitigating Systems 0 Public
"*Barrier Integrity
"* Emergency Preparedness of safety, the NRC uses To monitor these Seven Cornerstones safety that generate information about the two processes significance of plant operations:
3-17
- 1. Inspections and
- 2. Performance Indicators Inspection findings will be evaluated according to their potential significance for safety, using the significance determination process, and assigned colors of GREEN, WHITE, YELLOW, or RED.
"* GREEN findings are indicative of issues that, while they may not be desirable, represent very low safety significance.
"* WHITE findings indicate issues that are of low to moderate safety significance.
"* YELLOW findings are issues that are of substantial safety significance.
"* RED findings represent issues that are of high safety significance with a significant reduction in safety margin.
Performance Indicator data will be compared to established criteria for measuring licensee performance in terms of potential safety. Based on prescribed thresholds, the indicators will be classified by color representing varying levels of performance and incremental degradation in safety:
GREEN, WHITE, YELLOW, or RED.
"* GREEN indicators represent performance at a level requiring no additional NRC oversight beyond the baseline inspections.
"* WHITE corresponds to performance that may result in increased NRC oversight at the Resident Inspector or Regional level.
"* YELLOW represents performance that minimally reduces safety margin and requires even more NRC oversight at the NRC Region level.
"* RED indicates performance that represents a significant reduction in safety margin but still provides adequate protection to public health and safety. NRC response at the Agency level could include a public meeting, utility developed performance improvement plan, and/or a special NRC inspection team.
The assessment process integrates performance indicators and 3-18
conclusions inspection so the agency can reach objective will use an The NRC regarding overall plant performance. predictable manner in a systematic, Action Matrix to determine be taken based on a licensee's which regulatory actions should in response to the significance performance. The NRC's actions of issues will be the same for (as represented by the color) findings. As a performance indicators as for inspection the3 NRC will take more licensee's safety performance degrades, which can include increasingly significant action, and in the Action Matrix.
shutting down a plant, as described the new program with the following PG&E had prepared for actions:
of
"* Issued a procedure for collection and submittal for submittal to NRC Performance Indicator (PI) data Procedures for eight Administrative Work
"* Issued detailed guidance for PI data development Process
"* Provided RROP and Significance Determination (SDP) training to plant staff performance reports
- Incorporated PIs into department plan
- Implemented a communications Determination Process reviews of performed Significance P
LERs and NCRs program uses a risk-informed The redesigned NRC inspection plant to inspect within each approach to select areas of the The selection is based on potential risk, past cornerstone.
requirements.
operational experience, and regulatory and the regional office Each calendar quarter, NRC inspectors and inspection plant performance indicators will review offices headquarters findings. Each year, NRC regional and detailed review, to include a more will make a final performance over the 12-month period, assessment of plant and preparation of a six preparation of a performance report, will be sent to each plant month inspection plan. The report and discussed in a public meeting.
on the NRC performed its first inspection under the new RROP in which it found no DCPP Fire Protection Program systems are considered discrepancies. The fire protection in the RROP and were rated "mitigating systems" Cornerstone the highest rating, "Green".
(PPR)
NRC issued its first Midcycle Plant Performance Review any The report did not identify for DCPP in September 1999. warranted additional areas in which DCPP performance core inspection program. This inspection effort beyond the Matrix, a (1) a Plant Issues report contained two sections:
3-19
listing of items summarized from NRC Inspection Reports and other docketed correspondence between the NRC and PG&E from October 1, 1998 and July 16, 1999 and (2) plans for future NRC inspections of DCPP. The Plant Issues Matrix contained the following items:
- Two Level IV violations
- 15 Non-cited violations
- 35 positive areas
- 13 negative areas
- Six strengths The NRC issued its latest Annual Assessment Letter to PG&E on May 29, 2001. The letter included NRC's assessment of DCPP's safety performance for the period ending May 8, 2001 as well as plans for future inspections. The performance results represented an evaluation of NRC's Performance Indicators (PIs) for the most recent quarter and inspection results from April 2, 2000 through March 31, 2001.
The NRC concluded that, "Overall, DCPP operated in a manner that preserved public health and safety and fully met all cornerstone objectives." All inspection findings had been classified as having very low safety significance (Green), and all PIs indicated a level requiring no additional NRC oversight (Green).
The NRC did report that one Unit 2 PI, Scram with Loss of Normal Heat Removal, had been of "low-to-moderate safety significance (White)" for the first three of the four quarters (see PI table below) . This PI had returned to Green in the third quarter of 2000. NRC had conducted a special inspection to evaluate PG&E's corrective action, which was acceptable.
The DCISC concurs with the NRC assessment that there were no significant performance issues; however, both organizations believe human performance can improve and are monitoring PG&E's actions and results.
The NRC Performance Indicators for DCPP through the first quarter 2001 were reported at the June 2001 DCISC Public Meeting as follows:
3-20
Unit 1 Unit 2 Value Value NRC NRC DCPP Threshold Threshold Unit Color Color Threshold Performance Indicator Cornerstone: Mitigating Events 2.8 0 unplanned scrams (automatic & 3 1 3
manual) per 7000 critical hours Green over previous 4 quarters Green 2 2 Unplanned scrams involving 2 2 2
loss of normal heat removal Green*
Per previous 12 quarters Green 0.9 2.5 Unplanned transients per 7000 6 3 6
Critical hours over previous Green 4 quarters Green Cornerstone: Mitigating Systems 1.7% 0.6%
Safety System Unavailability - 2.5% 1.9%
Emergency Power (average of 2.5%
Green Green previous 12 quarters) 0.3% 0.4%
Safety System Unavailability - 1.5% 1.1%
1.5%
Residual Heat Removal System Green average of previous 12 quarters) Green 0.7% 0.6%
Safety System Unavailability - 2.0% 1.5%
2.0%
Auxiliary Feedwater System Green (average of previous 12 quarters) Green 0.5% 0.6%
Safety System Availability - 1.5% 1.1%
High Pressure Safety Injection 1.5%
Green Green (average of previous 12 quarters) 0.0% 0.0%
Safety System Functional Failures 5 1 (over the previous 4 quarters) 5 Green Green Cornerstone: Barrier Integrity 0.0% 1.2%
Reactor Coolant System Specific 50% 1%
50%
Activity (maximum monthly values Green
% of Technical Specifications) Green 4.7% 3.3%
Reactor Coolant System Leak Rate 50% 40%
(maximum monthly values - % of 50%
Green Green Technical Specifications) 3-21
Total Station Value NRC DCPP Threshold Station Cornerstone: Emergency Preparedness Color Threshold Emergency Response Organization (ERO)- 92.6%
Drill/exercise performance - per- 90% 95%
centage of success/opportunities Green for notifications and PARs during drills, exercises, and events over the prior 8 quarters ERO Participation (percentage of key 90.0%
ERO personnel that have participated 80% 90%
In a drill or exercise in the previous Green 8 quarters)
Alert and Notification System Reliability 99.4%
(percentage reliability during the 94% 98%
previous 8 quarters) Green Cornerstone: Occupational Exposure Occupational Exposure Control Effect- 1 iveness (the number of TS high 1 radiation area occurrences, very 2 0 high radiation area occurrences, and Green unintended exposure occurrences in the previous 4 quarters)
Cornerstone: Public Exposure RETS/ODCM Radiological Effluent Occur- 0 rences (occurrences during the previous 1 0 4 quarters) Green Cornerstone: Physical Protection Protected Area Security Equipment Perf- 0.017 ormance Index (unavailability of PA 0.080 134 hrs/mo IDS/CCTV security systems over Green previous 4 quarters)
Personnel Screening Program Performance 0 (prompt reportable events over the 2 previous 4 quarters) Green Fitness-for-Duty (FFD)/Personnel 0 Reliability Program Performance 2 (prompt reportable events over Green previous 4 quarters) 3-22
PG&E Bankruptcy 3.5 NRC Review of DCPP Safety with on April 6, 2001 because of When PG&E declared bankruptcy PG&E advised NRC of its the California energy situation, and that it would not intention to declare bankruptcy or operations. PG&E has kept significantly affect DCPP safety financial status basis of its the NRC informed on a regular and any effects on DCPP.
NRC continued its PG&E's financial situation, Because of weeks inspection periods at six resident inspector integrated 2001 period) through the end of (versus the normally quarterly managers and bi by NRC Region IV as well as increased visits These actions would be calls with DCPP staff.
weekly the public reports to better keep documented in inspection informed.
18, 2001, NRC concluded, In its Inspection Report dated June that you are to date, have confirmed "NRC inspections, and safely and that public health operating these reactors with this DCISC concurs safety is, thus far, assured." The assessment.
3.6 DCISC Evaluation Diablo Canyon operated The NRC concluded that, "Overall, fully a manner that preserved public health and safety and in on its inspection objectives" based met all cornerstone low safety as having very findings being classified requiring no significance and all PIs indicating a level Based on its reviews, the DCISC additional NRC oversight.
concurs with this overall assessment.
be Program (RROP) appears to The NRC Revised Reactor Oversight primarily-subjective objective than the previous more however, Licensee Performance (SALP);
Systematic Assessment of that noted that the setting of performance bands is such it is can occur from current performance significant degradation own thresholds PG&E has set its before drawing NRC action. of performance NRC's as early indicators lower than degradation.
reports on the NRC RROP Performance The DCISC received regular of its Public Meetings. The DCISC Indicators for DCPP at each using PG&E's DCPP safety performance will continue to monitor public at both fact-finding and the NRC Performance Indicators meetings.
3-23