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Enron Mail |
This is a long one....
EXECUTIVE SUMMARY=20 ? California Senate's MOU Debated in State Assembly ? Coordinating the California Legislature=20 ? CPUC's Rate Setting Authority In Question ? Highlights from the SoCal Investor Conference Call MOU As reported earlier, SB 78XX (the leading SoCal rescue adopted by the CA=20 Senate) has undergone minor amendments by the California Assembly. Three= =20 important revisions on the bill are: ? In regard to commercial rates, the assembly has now left open the=20 definition of large or "industrial users" by eliminating the previous 500= =20 kWh+ usage requirement. This change could enable the Assembly to categoriz= e=20 either smaller or larger consumers into the industrial/commercial user stat= us=20 ? The bill would not become effective unless SB 39XX is signed into law. S= B=20 39XX (authored by Sen. Speier) is regarding the CPUC=01,s authority over= =20 utilities and generators in California; it places certain generation that w= as=20 purchased by Reliant, Dynegy, etc. from the utilities after deregulation=20 under PUC authority. ? The State=01,s purchase of the SoCal Ed. transmission lines has been remo= ved. AB 82XX was also revised by the Assembly with many of the deleted provision= s=20 duplicate in SB 78XX, such as the conservation lands and the option to buy= =20 the transmission lines. Additionally, AB 82XX can not be enacted unless SB= =20 1XX (the windfall profits bill) is signed. The joining of 78XX to SB 39XX= =20 and of 82XX to 1XX is very likely a method by which the Assembly is=20 pressuring the governor to sign these other bills, which otherwise might no= t=20 have been enrolled. However, the joining of these bills makes their passag= e=20 more difficult. The remaining provisions of AB 82XX are as follows: ? Renewables Portfolio ? Direct Access ? Ratepayer Refund Account (changed the name to Ratepayer Benefit Account) ? Balancing Account for SCE procurement of power ? DRC replaced with non-bypassable charge option for MOU. This includes=20 reference to balancing account, recovery of reasonable procurement costs, a= nd=20 the prohibition of reasonableness review on contracts by PUC. Putting the MOU to a Vote The Speaker feels that everything in these bills has been discussed already= ,=20 so nothing is really new. Hertzberg met with advisors Wednesday night (10:0= 0=20 pm) to decide if the Assembly will convene on Friday. It probably has a lot= =20 to do with the ability to get enough members' support of these measures and= =20 willingness to go back to Sacramento. Many are vacationing; some in other= =20 countries. If there is an Assembly session on Friday, he plans to have an= =20 informational hearing on the measure today. If the Assembly=01,s session f= ails=20 to convene Friday, it is unclear what he intends to do. On the other side = of=20 the equation, it is unlikely that Senator Burton will bring the Senate back= =20 into session to approve this bill. The Senate won't even consider it until= =20 it comes back from recess, but the Assembly feels it is their responsibilit= y,=20 thereby putting the onus back on the Senate. Apparently there is really no= =20 coordination between the leadership of the different houses. While SB 78XX and AB 82XX are the most publicized bills, neither bill will = be=20 the actual legislative vehicle for these provisions. The proposed content = of=20 these bills will be amended into other bills which are further along in the= =20 process, thereby eliminating the need to waive a number of rules and hold= =20 numerous hearings. This will speed up the process. Apparently the Speaker'= s=20 office has not yet identified the actual bills that will be used. But they= =20 hope to find bills that are so far along in the legislative process that if= =20 the Assembly passes the bills they will not be able to be amended in the=20 Senate. It does appear that the Assembly does intend to send these through= =20 as two separate bills, though, with the SB 78XX provisions in one bill and= =20 the AB 82XX provisions in another. CPUC, Rate Setting Authority or Rate Setting Minority Recently, the California Assembly has pursued a legislative provision that= =20 would enable lawmakers to abrogate the CPUC=01,s rate-setting authority and= hand=20 over that power to the California legislature. Politically, this gives the= =20 Governor the ability to say, if rates increase automatically, that he did n= ot=20 approve of the rate increase, and there is nothing he can do about it. But= =20 it also gives Wall Street buyers of California=01,s revenue bonds assurance= s=20 that no matter what the need, there will always be enough revenue to back= =20 revenue bonds payments; thus deniability to ratepayers and certainty for=20 bondholders. =20 Were this provision to pass, the CPUC would still retain oversight of rates= =20 for the investor owned utilities. As for DWR, under the draft rate agreeme= nt=20 proposed by the CPUC, it contains a mechanism for the Commission to use in= =20 setting electricity rates that satisfy DWR=01,s =01&revenue requirement.=01= 8 DWR=01,s=20 revenue requirements include bond-related costs, operating costs (such as= =20 power purchase costs), and administrative costs. AB1X provided for=20 energy-related bonds to be sold by the state to support DWR=01,s power=20 purchases. Because power contracts require DWR to pay for power before it= =20 makes bond payments, and DWR must sell power to obtain revenues, the=20 rate-setting mechanism in the rate agreement also applies to DWR=01,s power= =20 purchases not just its bond payments. Note that if the Commission adopts a= =20 rate agreement, it becomes irrevocable.=20 ? -The draft agreement also includes a provision stating that the CPUC will= =20 take the DWR at its word as to its retail revenue requirements. ? The agreement would require that the CPUC set rates meeting DWR=01,s=20 requirements in either 30 or 90 days. The 90-day mechanism applies whenever= =20 DWR submits a revenue requirement. The 30-day mechanism applies when DWR=20 anticipates or actually draws on its reserves.=20 ? The rate agreement includes an enforceable covenant by the CPUC specifyin= g=20 how the Commission will set rates to meet DWR=01,s revenue requirements (wh= ich=20 includes both bond costs and operating costs). =20 If the CPUC=01,s draft rate agreement is approved, there will be no legisla= tive=20 or PUC oversight of any of those costs, and no opportunity for public comme= nt=20 for as long as bonds are outstanding. If a rate agreement can be avoided,= =20 there will be opportunities to review and alter the agreement=01,s demand= =20 management and administrative costs. Either way, power contract costs rema= in=20 an obligation of DWR and cannot be altered except by mutual consent of DWR= =20 and the contractor. SoCal Edison Investor Conference Call The following are notes from the SoCal Edison conference call with holders = of=20 defaulted debt, 24 July 2001, 1:30 PDT: ? In order for California to sell their revenue-bonds with an investment=20 grade rating, two criterion must be met; 1) there must be a rate-supported,= =20 dedicated revenue stream in place and 2) the legislature must have the powe= r=20 to override of the CPUC's rate setting authority and raise rates if=20 necessary. The second criterion, however, faces significant opposition fr= om=20 the California State Constitution. ? Regarding the DWR rate requirement, Craver, the spokesperson for SoCal, = =20 stated that SoCal is evaluating the numbers, particularly on the DWR side. = =20 He stated that if you accept their output of models and numbers, it appears= =20 this requirement would fit within the existing rate structure. However, "w= e=20 need to remember that deregulation started with forecasts that proved to be= =20 wrong". Therefore, this is "risky" in that SoCal is faced with "fixed=20 revenues and floating costs." Unlike DWR, SoCal has no ability to adjust= =20 rates based on costs, making floating natural gas prices a risk. ? Prudential asked, if based on the Hertzberg legislation, the sale of the= =20 transmission assets is now off the table. SoCal responded that this is=20 correct. Prudential asked if SoCal could then anticipate more=20 securitization, i.e., be securitized for all but $500 million with an optio= n=20 to buy the transmission assets at book for 5 years. SoCal responded that i= t=20 was "unclear what the pricing [of the transmission assets] would be, but=20 there would be an option" for the state to purchase the transmission assets= . ? Prudential asked about the status of the remaining (non-legislative)=20 implementing decisions on the MOU and if the legislation (78XX and 82XX)=20 contains them. SoCal responded that there are 3 outstanding issues remaini= ng=20 for implementing the MOU: 1) Ratemaking for the utilities' retained generation: The PUC is holding= =20 hearings on this issue this week. These hearings have slowed the process. = A=20 decision is expected by the end of August. 2) A procurement plan for the utility: This plan is before the PUC. SoCal= =20 suggested the PUC may be waiting to see what passes the legislature before= =20 acting on this point. Regardless, the company needs an "adequate balancing= =20 account with an automatic rate trigger." 3) Clarification on the utility holding company's position regarding 1st= =20 priority: On this front, the PUC asserted its jurisdiction over all three= =20 utilities and their holding companies. The three holding companies have=20 challenged this decision. Commissioner Bilas has written a draft decision = in=20 favor of the challenge; a final decision is expected as soon as Thursday.= =20 This would clarify that the utilities have first call on investment from th= e=20 holding companies, but that the holding companies are not obligated to pay= =20 the debts of the utilities. ? Deutsche Bank asked if, in SoCal's numbers reported to date, it was=20 assuming the charges for ancillary services. SoCal responded that DWR had= =20 confirmed as of 18 January that it would pick up these charges. These=20 charges would otherwise amount to $800 million - $1 billion in additional= =20 revenue requirement for the utility. Based on FERC rulings, SoCal had not= =20 been counting on paying these charges, so they are not reflected in the=20 company's numbers. However, SoCal will be paying grid management and uplif= t=20 charges. They anticipate paying "some portion" of these charges. This cou= ld=20 potentially require an amended URG filing. ? Citigroup asked where Edison stands on the Edison Mission Energy issues. = =20 Edison responded that they are "working on new facilities on the bank side.= "=20 The current facilities expire on October 10th or 11th. Edison indicated it= =20 is in the process of finalizing sales of approximately 1,000MW of=20 non-strategic assets. They are in negotiations with the final bidders exce= pt=20 for Hopewell, which is done. There is no specific timeline on when the dea= ls=20 will be announced, but it is a matter of days to a week. ? Appalucia Management asked if, on SoCal's generation, DWR is assuming a= =20 cost-plus or retail rate. SoCal responded that it uses cost-of-service bas= ed=20 rates. The return on the 12/31/00 rate basis is approximately 4 1/2 cents.= =20 The $72.77 stipulated covers SoCal's generation, its contracted generation,= =20 QF costs (which were quoted as the most significant portion) and=20 uncollectables. This is driven by gas costs for the QFs. Revenue is fixed= =20 at $73.00.
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