SENATE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE
DEBRA BOWEN, CHAIRWOMAN

Tuesday, June 19, 2001
3:00 p.m. -- Room 112

INFORMATIONAL HEARING

The Administration's Memorandum of Understanding
with Southern California Edison

Hearing 1: An Overview of Terms & Ratepayer Impacts
 

BACKGROUND

California’s attempt to deregulate its electricity marketplace hasn’t worked out as the Legislature, ratepayers, business groups, utility companies, environmentalists, and others associated with the 1996 deregulation effort envisioned.

At the time the market was restructured, the Legislature and all of the various parties who worked to craft the market believed deregulation would lower electric rates by at least 20%, provide more reliable electric service, be profitable for utility stockholders, and improve California’s environment as old, dirty, inefficient power plants were replaced by new, clean, more efficient power plants.

Not only have those benefits failed to materialize, but retail electric rates have increased by approximately 40%, electric service is less reliable, utility shareholders have seen the value of their investments decline, and air quality management districts throughout the state are waiving or modifying their air emission regulations to permit more air pollution. The most telling number is the wholesale cost of electricity, excluding the regulated cost of transmission, distribution, and utility overhead. In 1999, Californians spent about $7 billion for that electricity. In 2000, that figure nearly quadrupled to about $27 billion. In 2001, some experts project that figure will exceed $50 billion by the end of the year.

One of the fundamental features of the 1996 electric restructuring statute (AB 1890 (Brulte), Chapter 854, Statutes of 1996) was a freeze on electric rates for all customers. The rates were frozen at a level higher than the combined cost of the energy and the costs associated with the transmission & distribution of electricity. The gap that resulted, known as "head room," provided the utilities with revenue to pay down their "stranded costs" – investments that were recoverable in a regulated environment, but would otherwise be difficult to recover in a competitive market. As part of the agreement, the utilities agreed to assume the risk that those costs might not be recovered, though parties disagree as to exactly how much risk the utilities assumed. The utilities were given until March 2002 to recover those costs. The San Diego Gas & Electric Company (SDG&E) recovered all of its stranded costs early and as a consequence, the rate freeze was lifted for its customers on July 1, 1999.

Last May, wholesale prices for electricity began to soar. SDG&E customers, because they were no longer protected by the rate freeze, felt the pain most directly with sharply higher electric bills. Legislation (AB 265 (Davis), Chapter 328, Statutes of 2000) was enacted to moderate the price spikes in SDG&E territory. A rate cap was imposed to protect SDG&E ratepayers from the price spikes, but a "balancing account" was established to require ratepayers to eventually pay off the cost of the higher-priced energy that SDG&E was required to buy on their behalf. The balancing account currently shows that SDG&E’s ratepayers owe approximately $747 million to the utility, but an agreement between SDG&E and the Governor, announced on June 18, 2001, would reduce that figure to $0 if the California Public Utilities Commission (CPUC) approves the agreement.

In Southern California Edison (SCE) and Pacific Gas & Electric (PG&E) territories, both utilities saw their costs to buy energy skyrocket as well. However, because the rate freeze was still in place for those two utilities, they were precluded from passing their increased costs onto their customers. (Both utilities have fought the CPUC over this provision and, having lost their cases at the CPUC and in state courts, are now fighting the case in federal court. These are what are often referred to as the "filed rate doctrine" cases.).

In October, both PG&E and SCE requested CPUC approval to pass through $4 billion in higher wholesale power costs to customers. On January 4, 2001, the CPUC, concerned about the financial condition of the utilities, imposed a temporary 10% rate increase on utility bills in the two utilities’ service areas. Rolling blackouts on January 17 led the Governor to proclaim a State of Emergency. Two days, later the Legislature passed SB 7X (Burton), Chapter 3, Statutes of 2001, which appropriated $400 million from the state’s General Fund to the Department of Water Resources (DWR) for the purchase of electricity for up to twelve days.

Work quickly began on a longer term solution, which led to the enactment of AB 1X (Keeley), Chapter 4, Statutes of 2001. That measure authorized DWR to contract for electricity on behalf of retail customers that the utilities couldn’t otherwise provide (known now as the "net short") and barred DWR from entering into contracts after January 1, 2003. By taking over the net short purchasing requirement, DWR was helping to avoid blackouts (since power generators would only sell energy to a credit worthy entity and neither PG&E nor SCE were deemed to be credit worthy) and slow the financial drain on the two utilities.

On February 16, 2001, Governor Davis announced the framework of a recovery plan for SCE and PG&E that included the purchase of the utility transmission systems and the commencement of serious negotiations. Rolling blackouts hit the state again on March 19 and 20. On March 27, the CPUC approved a $5 billion rate increase, the largest electric rate increase in the history of the state, to cover the vastly higher wholesale cost of electricity. The temporary 10% increase enacted in January was also made permanent. On April 6, PG&E filed for bankruptcy (Case No. 01-30923-SFM, U.S. Bankruptcy Court, Northern District of California). On April 9, Governor Davis announced that he had reached a Memorandum of Understanding (MOU) with SCE, its holding company Edison International (EIX), and DWR. Legislation to enact the MOU was introduced as SB 78XX (Polanco) on May 17.

SCE has not yet filed for bankruptcy but, like PG&E, it has expressed concerns about bankruptcy – either through a voluntary or involuntary filing – since the latter part of last year. EIX has received permission from the Federal Energy Regulatory Commission (FERC) to reorganize itself to protect its other unregulated companies from an SCE bankruptcy. As part of that reorganization, EIX recently announced plans to refinance its corporate debt, much as PG&E did before it filed for bankruptcy.

This analysis will look at both the conceptual framework and the details of the agreement that are contained in the MOU. A subsequent analysis will focus on the statutory implementation.

DESCRIPTION

This MOU is an agreement between SCE and Governor Davis designed to help SCE will return to creditworthiness and fulfill its regulatory obligations to its customers. The MOU also lays out the processes the state will use to ensure that SCE meets the obligations it has to all of its customers.

This MOU provides for the following:

• Payment to SCE of 100% of its unpaid debts to various creditors, estimated at $3.5 billion;
   
• DWR’s purchase of SCE’s transmission system at a price that’s 2.3 times the estimated book value of the system, which amounts to about $2.8 billion;
   
• Legislative authorization of two dedicated rate components to pay for the unpaid debt and the transmission system;
   
• SCE’s agreement to sell the output from the generation plants it owns on a cost-of-service basis through December 31, 2010;
   
• Perpetual conservation easements preserving the existing uses on 21,425 acres of lands surrounding SCE’s hydroelectric projects;
   
• An end to the investigation by the CPUC into whether SCE’s holding company, EIX, has complied with the rules it agreed to when the CPUC permitted its formation;
   
• Statutory establishment of an 11.6% authorized rate of return for SCE through the end of the decade;
   
• An agreement by EIX to refund to SCE $400 million in federal tax refunds and federal loss carrybacks, though there are no specifics provided regarding the use of those funds;
   
• An agreement by SCE and EIX to make at least $3 billion in investments in SCE through 2006;
   
• An agreement by SCE to resume procurement of electricity in 2003, provided the CPUC has developed a mechanism for passing through wholesale energy costs to customers by that time;
   
• Payment by SCE of an unspecified amount representing the costs incurred by DWR in purchasing electricity from January 18, 2001 through April 7, 2001 to replace the electricity that would have been provided by unspecified qualifying facilities (QFs). This amount of money will be added to SCE’s net undercollection, which will in turn be paid for by ratepayers;
   
• An agreement by EIX to sell the output of a specific new electric generation plant (the Sunrise facility) at specified rates for 10 years;
   
• Termination of SCE’s federal "filed rate doctrine" lawsuit against the CPUC and other claims by SCE;

The stated goal of the MOU is to return SCE to investment grade credit status. The MOU is terminable by any party if a number of "Definitive Agreements" and implementing legislation aren’t enacted by August 15, 2001.

COMMENTS

The Big Picture & The Future of The Electric Market In California

Does the MOU Help California Deal with Blackouts and High Prices This Summer?

California faces blackouts of potentially unprecedented duration and frequency this summer, as well as a continuation of historically unprecedented prices (the recent reduced prices on the spot markets and the federal price mitigation measures adopted on June 18, 2001, notwithstanding).

This MOU provides some potential minor blackout avoidance benefits in that it imposes penalties if EIX’s Sunrise power plant, a 320 megawatt (MW) gas-fired facility that will operate as a peaker plant this year, isn’t functional by August 15, 2001. Arguably, this potential benefit is in a sense trumped by the stronger incentive to operate a plant that will be able to charge high peak electricity prices.

Some have argued that an SCE bankruptcy will affect electric supply availability and could increase the likelihood of blackouts in California. However, the evidence in PG&E’s case is that electric supply has not been affected by a bankruptcy given DWR’s role in procuring the net short.

The MOU doesn’t affect the contracts DWR has signed with power generators and marketers – contracts that have helped bring down spot market prices and have provided some price stability in California.

The MOU requires SCE to withdraw its challenge to a CPUC decision which allocates revenues between DWR and SCE. This challenge by SCE, if successful, could jeopardize the issuance of the revenue bonds authorized by SB 31X (Burton), Chapter 9, Statutes of 2001. Resolving this issue could provide some certainty for bond issuers and buyers, except for the fact that PG&E has challenged that same CPUC decision.

The MOU may have some benefit to California’s immediate electricity crisis in that should SCE file for bankruptcy, it may make it more difficult, or more costly, for the state to sell the $12.5 billion in revenue bonds needed to finance the difference between the cost of electricity and the prices actually paid.

How Does the MOU Fit Into the State’s Long-Term Energy Strategy?

The MOU is a strategy for helping SCE to become a financially viable corporation once again and decrease the potential it will file for or be forced into bankruptcy. However, while few people are interested in promoting bankruptcy as a solution to the current situation, many don’t believe bankruptcy is something that should be feared or avoided at all costs.

To what end California’s ratepayers should help SCE avoid bankruptcy is the major public policy question that has yet to be squarely addressed. Clearly, given the events of the past 12 months, a reassessment of the state’s electric service market structure is in order if the state wants to try and ensure that history doesn’t repeat itself.

The electric industry restructuring effort was undertaken in 1996 to improve the reliability of the electric grid and to lower electricity prices, which at the time were 50% above the national average. While the product of that effort was a consensus agreement supported by ratepayers, business groups, utilities, environmentalists, and a number of others, it obviously hasn’t worked as many, if not all, of those parties envisioned.

There is relatively little debate over what Californians expect from its electric industry: reliable, affordable electricity produced in environmentally benign ways. However, there’s plenty of disagreement over how California can or should now go about best achieving those basic goals.

Should the state continue with an industry structure that relies on free markets and federal regulation to provide reliable and affordable electricity? Should the state return to traditional regulated markets, complete with vertically integrated utilities that generate, transmit, and distribute electricity? How does customer choice of electric supplier (i.e. direct access) fit into the picture? How does SCE fit into California’s future electric service structure? Should SCE be simply a poles-and-wires company or should it be required to become more active in the electric generation business, as was the case prior to deregulation?

While significant, necessary work has been done to encourage energy efficiency, streamline the permitting process to bring new energy supply on line, and establish a public power authority, a public debate on the future of California’s electric industry market structure is long overdue. Placing an MOU into statute before deciding what California’s electric industry should look like arguably puts the cart before the horse. A more logical approach would be to articulate what California’s electricity future should look like, then determine whether and how any strategy to help SCE avoid bankruptcy fits into that future.

Specific Issues Associated With The MOU

Payment of the Undercollection

The MOU allows SCE to recover in rates 100% of the costs it has incurred for electricity purchases that haven’t been recoverable from customers because of the rate freeze, less overcollections from the power SCE sold from its retained generation. This cost – known in short as the utility’s "back debt" – is estimated at $3.5 billion. Under this MOU, that $3.5 billion will be recovered from all ratepayers over an unspecified number of years through a non-bypassable dedicated rate component (see below).

The $3.5 billion figure includes charges for electricity sold by power generators and marketers, charges with also include "credit premiums" that were imposed by some power sellers. As has been widely reported, FERC has found a number of the rates charged by power generators and marketers to be "unjust and unreasonable."

However, the MOU doesn’t require those electricity generators and/or marketers to share the high cost of this electricity crisis. Instead, it provides them with full payment of what they say they’re owed. This allows electricity generators and marketers to quickly and completely recover their debts while consumers suffer unprecedented rate increases and electrical supply uncertainty.

Under this agreement, creditors are arguably treated far better than they would be treated in a bankruptcy proceeding, yet nothing is demanded of them in return despite published reports indicating that many electric suppliers have agreed to take less than 100% of the money they feel they’re owed as part of an overall agreement. Imposing such a reduction (which has become known as a "haircut") on the debt of one private company that’s owed to another private company is no doubt complex, especially since the generators and marketers aren’t necessarily direct creditors of SCE. Using PG&E as an example, the vast majority of its debts to unsecured creditors are owed to banks, the now bankrupt Power Exchange (PX), and the California Independent System Operator (ISO). However, this complexity should not excuse power sellers from participating in an equitable solution.

Similarly, by agreeing to pay off 100% of the back debt, the MOU asks very little of SCE or its holding company. There is no "haircut" for the holding company – the $400 million from EIX to SCE in federal tax benefits is already required under their existing tax agreements and the funds don’t provide any clear ratepayer benefit, such as reducing the $3.5 billion undercollection. Additionally, by allowing the entire undercollection to be recovered from ratepayers, the MOU settles SCE’s dispute with the CPUC over whether the rate freeze enacted as part of the original electric restructuring statutes put the utilities or consumers at risk for changes in commodity prices.

On June 18, FERC issued an order stating it will convene a settlement conference on the back debt issue, implying that something less than 100% of the back debt owed by the utilities to the generators and marketers will eventually have to be paid.

Transmission System

The MOU allows the state to purchase SCE’s transmission system for 2.3 times the net book value of those assets as of December 31, 2000, plus $63 million representing the value of tax benefits associated with the transmission system which previously flowed through to ratepayers. This amounts to about $2.8 billion (2.3 multiplied by the book value of $1.2 billion), to which will be added the value of any capital additions made after December 31, 2000, less any further accumulated depreciation.

The factor of 2.3 is a negotiated figure for which a fairness opinion must be obtained. Under the MOU, the state will assume all liabilities related to the transferred assets, including environmental liabilities, with specified exceptions. The state will also enter into an agreement with SCE to operate and maintain the transmission system for not less than three years, for an as-yet negotiated fee. Review of the system pursuant to the California Environmental Quality Act (CEQA) is dispensed with through legislation.

If the sale of the transmission system fails to close within 24 months, then SCE is required to offer to sell DWR its hydroelectric assets, plus rights to the output of SCE’s interests in generating plants after 2010 so the value is equal to that of the transmission system.

The sale of the transmission system is subject to approval by FERC, but regulatory approval is far from certain. Furthermore, even if FERC does approve the sale, no guarantees can be made that FERC won’t attach unfavorable conditions to the sale.

The value of owning only a portion of the investor-owned utilities’ transmission grid is unclear, in part because it dilutes economies of scope and scale and complicates some transmission management issues. Sempra Energy, the parent company of SDG&E, has rejected selling its transmission grid at a price of 2.3 times book value as inadequate and has suggested a reasonable price would be several hundred million dollars more. According to a June 18, 2001 press release issued by Sempra, it has reached an agreement with the Governor to sell the utility’s 1,800-mile transmission system to the state for approximately $1 billion, or 2.3 times book value, plus retirement of $180 million in related debt.

It should be noted that even if the state were to purchase all three of the transmission grids owned by the state’s three investor-owned utilities, it still wouldn’t own 100% of the grid. That’s because as approximately 30%-50% of the total grid is owned and/or operated by the state’s municipal utilities and/or federal transmission authorities.

Should the transmission sale fall through, the back-up transaction in the MOU is the sale of SCE’s hydroelectric plants and an unspecified amount of cost-of-service generation. This transaction isn’t well specified in the MOU. However, the value of additional cost-of-service generation, which would be available after the initial commitment of cost-of-service generation through 2010 lapses, may be low because it’s both a decade away and because the CPUC and/or the Legislature can require the utility to operate cost-of-service generation without the MOU.

Should the sale of the transmission sale not be approved by FERC or fail for other reasons, the imposition of a second dedicated rate component would be triggered (see below).

While the uncertainty about the ability to close the transmission system sale is a concern, as is the high price, state ownership of the transmission system will allow the system to be operated solely for the benefit of ratepayers. Necessary transmission system improvements can be assured and the cost of such improvements can be reduced because of the state’s lower cost of capital. The financial advisors to the Governor estimate that the transmission system acquisition can be paid for without raising transmission rates.

Dedicated Rate Components

The cost of the undercollection and the transmission system will be financed through two legislatively-authorized dedicated rate components (DRC). These DRCs are non-bypassable, meaning all of SCE’s customers would pay for them.

As noted above, the SCE undercollection is placed at $3.5 billion. The book value of the transmission assets is $1.2 billion and the state is required to purchase them for 2.3 times book value, or $2.8 billion. The profit from the sale – $1.6 billion – would be applied to the undercollection (thus reducing the undercollection to $1.9 billion). The first DRC would then be assessed, requiring ratepayers to cover that amount of money ($1.9 billion).

The second DRC would be for $1.6 billion and would only take effect if the transmission assets aren’t sold to the state. The purpose of authorizing a second DRC is to provide a dedicated rate stream to assure lenders that are willing to loan SCE the full $3.5 billion now to cover its undercollection that the money will be paid back, regardless of whether the transmission sale goes through (since it needs CPUC, legislative, and FERC approval).

The effect of the two DRCs is that SCE will get the full $3.5 billion back debt repaid whether or not the transmission asset sale or any back-up transaction is approved. Some have read this portion of the MOU as requiring ratepayers to pay $4.7 billion for the transmission assets ($2.8 billion for the transmission lines, plus $1.9 billion for the balance of the undercollection).

CPUC Regulatory Authority

Many provisions of the MOU preempt the CPUC’s regulatory authority:

• The MOU creates a 60 day review of the net undercollected amount, after which neither the CPUC, the Legislature, nor the courts may review such amount for reasonableness;
   
• It prejudges the CPUC’s investigation into the conduct of EIX by barring the CPUC from considering the primary issue in that case and from imposing any material penalty;
   
• The CPUC is precluded from adopting any rule, regulation, or order which would have a material adverse effect on either SCE or EIX;
   
• The CPUC is precluded from conducting a CEQA review of the transmission system purchase or any backup purchase;
   
• The MOU defers SCE’s General Rate Case from 2002 to 2003;
   
• The MOU statutorily establishes an authorized rate of return of 11.6% through the end of the decade.

The CPUC is an independent regulatory body with the statutory obligation to ensure that rates are fair and reasonable. By preempting the CPUC, the Legislature is substituting its judgement for that of the CPUC. While that is clearly the prerogative of the Legislature, it’s questionable as to whether the Legislature has the benefit of the facts and a detailed knowledge of the issues to make these determinations.

Furthermore, codifying these provisions makes them difficult to change as circumstances may warrant in the future. The Legislature has the responsibility for establishing policy and it has long realized the merit of assigning the responsibilities for implementing those policies to a regulatory agency with the appropriate expertise and processes.

Taking DWR Out of The Electricity Procurement Business

The MOU requires SCE to reassume the obligation to purchase sufficient energy to meet the needs of its customers after 2002. However, DWR has entered into a number of long-term contracts for energy (some contracts are as long as 20 years) and in the last half of 2003 alone, DWR has contracted for nearly 100% of the projected net short. Similarly, in 2004 and 2005, DWR has contracted for about 90% of the projected net short.

It’s unclear what returning procurement responsibility back to SCE means in the context of substantial long-term DWR contracts for power. Does it mean the DWR contracts are assigned to SCE? Also, no law or regulation has changed which relieves SCE of its procurement obligation. The authority for DWR to procure on behalf of the utilities ends at the end of 2002, so regardless of the disposition of the MOU, SCE will have to reassume its duty to buy electricity for the portion of its needs not already procured by DWR in long-term contracts. Given the recent rate increases adopted by the CPUC, the concern over SCE’s financial ability to enter into contracts should be moot as revenues should be sufficient to cover costs on a going-forward basis.

Customer Rates

The financial advisors to the Governor have stated publicly that the MOU, including the transmission sale, can be implemented without raising rates beyond those in effect today. This assertion is backed by a financial analysis prepared by The Blackstone Group L.P and Saber Partners, LLC on April 20, 2001.

That analysis is predicated on a substantial energy efficiency and demand management effort this year and next, an elasticity effect from the recent rate increases, the return to production of 90% of the power produced by QFs, QF prices at between $0.12 per kilowatt hour (kwh) to $0.095/kwh, sale of $12.5 billion in revenue bonds, and various assumptions about contracted energy costs, spot market purchases, and growth in electric consumption.

However, a June 15 article in the New York Times raised some question as to whether the MOU could be implemented within the existing rate structure. Specifically, the article states:

Mr. [John] Bryson’s [SCE’s chief executive officer] point is this: Any resolution, which will almost certainly involve a rate increase above the 35 to 50 percent most Californians began paying last month, will have to be approved by state administrative officials anyway.

Retained Generation

SCE’s retained generation (including hydroelectric, coal, and nuclear) will provide electricity to SCE’s customers on a traditional cost-of-service basis through December 31, 2010. The MOU provides that SCE will be guaranteed through legislation and CPUC implementing decisions to recover its costs of operation of its retained generation from January 1, 2001, notwithstanding any rate freeze to the contrary in AB 1890. The MOU further specifies in great detail which costs would be recoverable by the utility.
 

The MOU also requires adoption of a CPUC implementing decision repealing (after 2003) a specific formula relative to the treatment of nuclear generation revenues, whereby profits from such generation are shared equally between the utility and ratepayers, and appears to then return the nuclear power plants back to cost of service ratemaking.

The MOU specifies what qualifies as "costs" and specifies a rate of return of 11.6%.

Sunrise Power Plant

The MOU provides that generation from the Sunrise Project, jointly owned by EIX and Texaco, will be sold to DWR on a cost of service basis for 10 years. This project will initially provide 320 MW of capacity, rising to 500 MW over two years. That plant will receive a rate of return of 11.6% on equity and all fuel costs will be passed directly through to DWR.

Sunrise will receive a capacity payment of $120/kW-yr for Phase I and $176/kW-yr for Phase II, with a final capacity price based on costs incurred for the project – costs that DWR has no control over. It’s unclear, if this is a baseline generation plant, why it would be receiving capacity payments.

In addition to fixed $3/megawatt hour (MWH) operation & maintenance costs (above the fuel costs, the capacity payment costs, and the 11.6% return), DWR will be responsible for "start up payments" for any start up over 100 in a contract year. Start ups from 101-135 will cost $300 each, 136-150 will cost $5,000 each, and over 150 will cost $14,000 each.

The Phase I capacity charge will be based on a limitation of hours of operation not reflected in the MOU and any increase in usage would cause the capacity payments to rise.

The value of this provision is unclear. While the pricing is on a cost-of-service basis, electricity prices may come down to cost-based levels given the substantial new generation that has been permitted in the state. In any event, the value of this provision of the MOU is limited by the relatively small output of the plant, which amounts to about 2% of SCE’s total peak need.

Uncertain Benefits

Some advertised benefits of the MOU are either already being provided by current law and/or regulation or could be achieved without implementing the MOU.

For example, the MOU provides for SCE’s retained generation to operate under the CPUC’s regulatory authority through 2010. However, SCE’s retained generation is already being operated under the CPUC’s regulatory authority, with the power being sold to SCE customers at either cost-based rates or under a performance-based ratemaking approach. This decision is entirely within the discretion of state government and isn’t subject to SCE’s approval and consent. AB 6X (Dutra), Chapter 2, Statutes of 2001, requires generation owned by public utilities to continue to be subject to regulation by the CPUC and bars the CPUC from authorizing the sale of such assets prior to January 1, 2006. Nothing precludes the Legislature from extending that statute and nothing precludes the CPUC from continuing to exercise its regulatory authority over those assets.

The MOU commits SCE and its parent company to make capital investments into SCE’s regulated businesses of at least $3 billion through 2006. But such investments are a fundamental part of SCE’s obligation to serve and are required under existing law and regulation. Requiring such commitment in the MOU is simply a restatement of SCE’s existing statutory and regulatory obligations.

The MOU calls for the termination of various legal proceedings by SCE against the state, the most prominent of which is SCE’s federal filed rate doctrine case. Estimates of the value of this settlement vary, but these estimates are inherently uncertain and, given the progress of the cases to date, should be relatively low. In particular, the MOU gives SCE 100% of its back debt, which is what SCE is seeking in the filed rate doctrine case. That arguably makes the value of settling the case very small in the eyes of the ratepayers.

Bankruptcy Avoidance and California’s Future Electric Service

Since the end of last year, the financial situations of PG&E and SCE were the subject of many legislative and executive branch discussions that were motivated in part by a desire among some to help the utilities avoid bankruptcy proceedings. Many believed that having one or both of the state’s investor-owned utilities file for or be forced into bankruptcy would impair service reliability and cause a loss of state control.

However, the PG&E bankruptcy experience has dispelled many of those concerns, as bankruptcy hasn’t – to date – affected reliability or resulted in the catastrophic loss of control as some had thought. The CPUC has retained its regulatory authority over PG&E, including jurisdiction over accounting procedures and rate-setting, and the bankruptcy judge has specifically rejected PG&E’s request that the court overturn the CPUC orders. As a consequence, PG&E’s rates have risen only to the extent that the CPUC has judged those rate increases to be fair and reasonable. While the bankruptcy trustee’s suggestion for establishment of a ratepayer committee was rejected by the bankruptcy judge, the Attorney General was invited to represent ratepayers and provided certain privileges to facilitate his participation. Some would argue that the threat of bankruptcy to the general public is not so threatening anymore.

PG&E Template

Some believe this MOU could serve as a template for a similar agreement to extract PG&E from its bankruptcy proceeding. However, under the terms of its bankruptcy filing, PG&E has a period of exclusivity when only it can propose a reorganization plan to the court and the creditors. That period of time runs for 120 days (PG&E filed for bankruptcy on April 6) and it’s not uncommon for courts to extend the period of exclusivity at the request of a bankruptcy debtor.

Furthermore, PG&E’s circumstances are materially different than SCE’s in a number of respects. For example, PG&E has substantially more unpaid debt than SCE. Also, DWR has contracted for substantially less power for PG&E’s customers than it has for SCE’s customers. The issue of the responsibility of PG&E’s parent holding company for PG&E’s debts will be an issue in PG&E’s bankruptcy proceeding, and the MOU’s limitation of any CPUC inquiry into that issue may effect resolution of that issue for PG&E.

Definitive Agreements

Enactment of the MOU is contingent on completion of various "Definitive Agreements." These agreements include the specifics of the power sale contract for the Sunrise power plant, the conservation easements, how SCE will work with the state in pursuing claims against third-party generators, how any proceeds from overcharge claims are divided and applied, details of the backup transaction should the transmission system sale fall through, and details regarding settlement of other claims by SCE.

These agreements have not been completed.

Conservation Easements

The MOU requires SCE to convey to the state perpetual protective conservation easements to 21,425 acres of lands surrounding SCE’s hydroelectric projects.

However, easements are less secure than clear title to the lands and it’s unclear why the state shouldn’t receive title to the lands. Furthermore, the easements also provide no assurance that the lands will be managed in an environmentally sound manner.

Finally, the agreement grandfathers in all existing non-utility uses of the land for five years or the remaining terms of existing contracts (whichever is longer), continues utility uses in perpetuity, and permits the expansion of hydroelectric facilities with approval in perpetuity. Existing logging operations are subject to modification pursuant to a public process developed by the Wildlife Conservation Board. The state may ask SCE to convey a fee interest in specific properties, but any such interest is required to provide an easement back to SCE. No fee ownership request can relate to lands covering existing hydroelectric facilities, related uses, and reasonable expansions.

Noting all of these attached conditions and prohibitions, it’s unclear exactly what the state is getting in connection with these properties that it doesn’t have now.