The financial turmoil in the California energy market has begun to subside. Now
is the time to look at the opportunities and challenges in the future. Several
key structural changes including the reorganization of ISOs will dramatically
change the face of the California energy landscape over the course of the next
few years.

The PG&E Plan of Reorganization

In September, PG&E filed its proposed Plan of Reorganization (PG&E/POR) with
the Bankruptcy Court. There are several features of the plan, which if approved,
would have a significant effect on the California energy markets. PG&E (the
vertically integrated regulated utility) would be split into four separate companies:
1. A local gas and electric distribution company (Utility)
2. An electric transmission company (ETrans)
3. A gas transportation business (GTrans)
4. A generating company to supply power to Utility (Gen)

If approved by the Federal Energy Regulatory Commission (FERC), the Securities
and Exchange Commission, and the Nuclear Regulatory Commission, this reorganization
would transfer all assets other than the local gas and electric distribution
facilities to FERC jurisdiction.¹ This highly controversial
move would reduce the jurisdiction of the California Public Utilities Commission
(CPUC) over the assets of the company. Utility will be spun off as a separate
company listed on the New York Stock Exchange while the other three entities
will be wholly-owned affiliates of PG&E Corporation.

The plan anticipates approval by the Bankruptcy Court by June 30, 2002; assuming
it receives FERC and other approvals, PG&E expects to be creditworthy by January
1, 2003.

There are three major consequences if the PG&E/POR is approved as proposed.
First, PG&E would be in the procurement business for the first time since the
collapse of the IOUs’ credit in January, 2001. Second, any or all of the three
new companies that will remain within PG&E Corporation could be easily sold
or spun off. Third, ETrans will commit to joining a western RTO. It retains
the option to remain in the California ISO if the ISO becomes an RTO. However,
the commitment of ETrans to a western RTO not only indicates dissatisfaction
with the insularity and questionable dealings of the California ISO, but signals
a commitment by a major transmission owner to an alternate organization.

The Southern California Edison Settlement of the Filed Rate Doctrine Case With
The California Public Utilities Commission
In early October 2001, Southern California Edison and CPUC settled the filed
rate doctrine action that had been pending in Federal District Court.²
The suit alleged that the CPUC violated the filed rate doctrine, a matter of
federal law, when it refused to permit the utility to pass through the wholesale
cost of power in retail rates. The settlement of the lawsuit, a different form
of bailout of Edison from what was originally proposed, reflects the Governor’s
inability to get any significant legislative support for his original plan based
on his April Memorandum of Understanding with Edison.³

Under the settlement, Edison will also eventually become a creditworthy entity
able to participate in the procurement business. However, the settlement permits
Edison to remain a vertically integrated utility largely regulated by the state,
in contrast to the approach taken by PG&E.

The Suspension of Direct Access and Interest in
Public Power

In September 2001, the CPUC suspended direct access on a prospective basis
and left in limbo the status of agreements (including extensions) entered into
after July 1, 2001.⁴ The suspension had been mandated
in AB1 X, the January 2001 legislation that put CDWR in the power purchasing
business. Because CDWR had entered into $43 billion of contracts that needed
to be supported by a predictable revenue stream, the suspension of direct access
reflects the difficulty CDWR would have in issuing revenue bonds if the customer
base to pay CDWR for power was significantly reduced.

The suspension of direct access has two major consequences. First, it is probable
that there will be proposals to reinstate direct access, conditioned on payment
of an exit fee to CDWR. That exit fee would be subject to exemptions, and jockeying
for those exemptions will be fierce. Second, there is a window to avoid the
high utility and CDWR rates through municipalization.
While municipalization, which involves condemnation, is a costly and time-consuming
process (the last contested one took over 20 years), new real estate developments
provide an opportunity to utilize or even create the various political jurisdictions
that can run utilities. In addition to avoiding high utility and CDWR costs,
such enclaves also provide some insurance against blackouts and price volatility.
Finally, interest in municipalization of existing investor-owned utility systems
may have increased as a result of near-passage in November of a public power
initiative in San Francisco. Undoubtedly this issue will reappear on the San
Francisco ballot and several cities in California are considering similar moves.

The California Department of Water Resources Contracts

In January 2001, the CDWR was given the authority to provide power for the
entire “net short” — the difference between the utilities’ load and the
resources, both owned and under contract, available to serve that load. Pursuant
to that authority, CDWR went on a contracting binge, signing 56 contracts for
as many as 5,895 megawatts for up to 20 years. These contracts were entered
into at the height of the market. There are efforts to renegotiate the contracts.
In probable defiance of state legislation, the CPUC has not agreed to CDWR’s
proposed revenue requirement for its power purchases. The CPUC believes that
despite legislative language to the contrary, it has the ability to review the
CDWR revenue requirement.

The CPUC’s agreement would have the force of a financing order that would provide
the basis for issuing bonds. As a result of this stalemate between the State
and its own PUC, it has been impossible to issue the bonds. If the bonds are
not issued, the CDWR will be in default on most of its contracts. In addition,
the FERC ordered the ISO to bill CDWR, rather than the utilities, for purchases
through the ISO. The FERC decision provides some needed stability to the financial
side of the energy market, while providing CDWR with another reason to try to
exit it.

In addition, many of these contracts are for power that will not be delivered
for several years. In some cases, the power plants to supply such power have
not been built, nor has significant development work started. Accordingly, it
may be possible to renegotiate contracts to reduce CDWR’s portfolio, particularly
in the years beyond 2004, by paying developers their development costs plus
a premium.
There are some sound reasons why counterparties would agree to such negotiations.
First, nearly half of the megawatts (2,495) are with a single developer —
Calpine. Calpine has been the Governor’s favorite generating company. It is
located in California and therefore does not fit the profile of “out-of-state
gougers,” against which the Governor has been riling for the last year and a
half. Moreover, Calpine supported the Governor’s program by contracting for
nearly half of the new supply. This leaves Calpine exposed to a single purchaser
subject to considerable political pressure. Accordingly, there may be some benefits
to Calpine to reduce and diversify its portfolio. In early December, Calpine
confirmed that it is renegotiating its contracts with DWR.

The Possible Creation of A Western Regional Transmission Organization

The California ISO defies most of the trends in the industry towards using
transmission to facilitate regional markets. The California ISO has operational
control only over the transmission systems of the three IOUs (plus a miniscule
amount of municipal transmission), and does not include the large publicly owned
state, federal, and municipal transmission systems. Moreover, it has been under
fire for giving CDWR contracts preferential treatment and giving CDWR personnel
preferential access to its control room.

FERC Order 2000, which strongly encourages the development of RTOs, conflicts
with the protectionist stance of this single state ISO. Although FERC indicated
that it is no longer committed to a single RTO in the West, it is possible that
the creation of PG&E’s ETrans and the increased attention to the questionable
side of some of the ISO’s dealings will encourage a move toward a true western
RTO. In addition, under the Secretary of Energy’s current plan, the majority
of the $300 million, 84-mile upgrade of Path 15 in PG&E’s transmission system
will be owned by the Transmission Agency of Northern California and the Western
Area Power Administration, neither of which has committed its existing assets
to the ISO but whose regional assets may make them more open to joining an RTO.
A western RTO would not only provide an opportunity to reform those aspects
of the California ISO procedures which have done little to ameliorate the energy
crisis, but could also enhance a truly regional market.

Recently FERC removed a cloud lingering over generators in California who were
seeking or selling under market-based pricing. The order denied challenges filed
by the California Electricity Oversight Board and the California Public Utilities
Commission to the market-based pricing authority of AES’s plant at Huntington
Beach. Since the order concludes that sales to the California ISO are not subject
to the new Supply Margin Assessment (SMA) market power screen, it seems likely
that parties seeking to obtain or renew their market-based pricing authority
within California will be able to do so. However, as FERC also recently ordered,
all market-based pricing tariffs must include a provision prohibiting anti-competitive
behavior. Furthermore, the generic exemption for sales to an ISO or RTO is premised
on that organization having a FERC-approved market power monitoring and price
mitigation plan. FERC stated that the California ISO met this criterion, largely
because of orders that FERC issued this year. However, FERC cautioned that the
price mitigation adopted for California and the West expires on September 30,
2002. If no acceptable replacement market mitigation plan has been accepted
by then, FERC presumably would again review the market-based pricing authority
of sellers into the California market.

This order should remove a log jam of applications for market-based pricing,
on which FERC has generally deferred action while issuing highly technical and
inconsistent deficiency orders. It is fair to assume that FERC will now process
these applications in a more routine manner.

Conclusion

While none of these events are firmly in place, and some are purely speculative
(particularly western RTO creation and CDWR contract renegotiation), there is
enough activity to see opportunities in the years ahead. What seems clear is
that the State will attempt as quickly as possible to get out of the procurement
business, which has been nothing but a costly embarrassment.

Footnotes

1 PG&E made the requisite filings at all three agencies on
November 30, 2001.
2 PG&E has a similar action pending which has been refiled in the Northern District
of California.
3 A consumer group’s attempt to obtain a stay of the order approving the settlement
was rejected by the Ninth Circuit, which scheduled a hearing during the first
week of March 2002 on the appeal.
4 The potential retroactive effect of this order has been challenged in court
by direct access supporters. The CPUC may initiate a proceeding in February
2002 to determine what to do with direct access contracts executed after July
1, 2001.