VI. Discussion of Contested Issues

A. Fundamental Issues

We begin our discussion by addressing two fundamental issues: our legal authority to impose cost responsibility surcharges (CRS) on customer generation, as well as the disposition of the settlement agreement.

1. Legal Authority for Imposing Cost
Responsibility Surcharges

Any charges we impose in this decision must be consistent with the law. Various parties representing DL interests generally argue that the Commission lacks jurisdiction over the right to engage in Customer Generation and the charges associated with CG. EPUC/KCC/GAG also claimed that such charges are prohibited by law and contrary to principles of cost causation. Various parties also claimed that explicit State and federal policies encouraging the development of Customer Generation would be frustrated by the imposition of any CRS on DG load.

We conclude that the Commission has the requisite legal authority to authorize and implement cost responsibility surcharges on Customer Generation load. This authority is clearly set forth in Assembly Bill No. 117 ("AB 117"), which clarified the Legislature's intent concerning the implementation of AB 1X, and the recovery of DWR-related costs from retail end-use customers. (AB 117, Stats. 2002, ch. 838).⁶⁷ AB 117, which was signed into law September 24, 2002, the Legislature enacted Public Utilities Code Section 366.2(d)(1) which makes all end-use customers who took bundled service on or after February 1, 2001 responsible for a fair share of costs incurred by DWR. This statutory provision provides:

"It is the intent of the Legislature that each retail end-use customer that has purchased power from an electrical corporation on or after February 1, 2001, should bear a fair share of the [DWR's] electricity purchase costs, as well as electricity purchase contract obligations incurred..that are recoverable from electrical corporation customers in commission-approved rates. It is further the intent of the Legislature to prevent any shifting of recoverable costs between customers." (Pub. Util. Code §366.2, subd.(d)(1).)

Thus, AB 117 gives the Commission the authority for imposing a "fair share" of cost responsibility on customers, including Customer Generation Departing Load, that took utility service on or after February 1, 2001. The determination of what the "fair share" should be is left to the Commission's determination in its exercise of this authority.

However, in addressing the energy problems confronting California which resulted in the enactment of AB 1X, the Legislature also enacted several laws with the legislative objectives to promote investment and construction of renewal energy resources, diversify California's energy resource mix, stabilize California energy supply infrastructure and produce economic and environmental benefits. (See generally, Assembly Bill No. 29, ("AB 29"), Stats. 2001, ch. 8, enacting Public Utilities Code Sections 2827, 2727.4 and 2827.7 (net energy metering for eligible customer-generators program); SB 28X, Stats. 2001, ch. 12, enacting Public Utilities Code Section 353.1, et seq. (distributed energy resources); Senate Bill No. 1038 ("SB 1038"), Stats. 2002, ch. 515, adding Public Utilities Code Section 353.2 and amended Public Utilities Code Section 383.5 (increasing the amount of renewable electricity generated in California); AB 58, Stats. 2002, ch. 836, amending Public Utilities Code Sections 2827 and 2827.7, and added Sections 2827.8 (operation and development of emerging renewable resource technologies and net energy metering); AB 2228, Stats. 2002, ch. 845, enacting Public Utilities Code Section 2827.9 (net energy metering for eligible biogas digester customer-generators).)⁶⁸

In implementing AB 117, we are cognizant that our implementation should not be in conflict with other statutes, including the legislative intent codified in these statutes, that were enacted at the same time and in response to the electricity problems confronting California. It is important that the Commission's determinations regarding its implementation of AB 117 should be in harmony with those other statutes the Legislature enacted in response to the energy problems confronting California. Thus, our interpretation in today's decision reflects our harmonizing of the AB 117 and these statutes.⁶⁹ Accordingly, we have provided for CRS exceptions as specified in today's decision.

For example, Public Utilities Code Section 353.2 provides:

"In establishing rates and fees, the commission may consider energy efficiency and emissions performance to encourage early compliance with air quality standards established by State Air Resources for ultra-clean and low-emission distributed generation." (Pub. Util. Code § 353.2, subd. (b).)

Thus, despite apparent contrary language in AB 117, we have harmonized Public Utilities Code Section 366.2(d) with Public Utilities Code Section 353.2(b) to permit an exception for the payment of CRS for load involving ultra-clean and low-emission distributed generation.

In sum and unless otherwise excepted, Customer Generation load must be held responsible for a fair share, as determined by this Commission, of the DWR revenue requirements. To the extent that customers departed from bundled utility service to be served by Customer Generation after DWR began buying power on January 17, 2001, such customers consumed power that had been purchased by DWR. The DWR costs for which customers bear responsibility include both previously incurred costs as well as an ongoing cost component. We address the more specific applicability of each respective charge in our discussion below.

2. Disposition of the Settlement Agreement

The Settlement Agreement is sponsored by parties representing a range of interests but is not supported by all parties. Certain provisions are opposed by a number of parties, including ORA, SDG&E, and various parties representing Customer Generation interests.

We appreciate the fact that the Settlement reflects a broad range of divergent interests, including those of the utilities (i.e., PG&E and SCE) and of residential customer representatives (i.e., TURN). The interests of commercial and industrial customers who have developed, or are developing, Customer Generation projects are represented in the Settlement by parties such as BOMA, EPUC, and CIPA, among others. The interests of developers of Customer Generation are represented in the Settlement by Clarus Energy Corporation and Real Energy, among others. The interests of the State of California as a large energy consumer are represented by UC/CSU. The CEC, as a joint settling party, also brings its broad perspective on the State's energy future.

In addition, we have also reviewed and considered the objections of those parties that did not join in the Settlement, including AReM/WPTF, CEERT, CPA, CalSEIA, and the Districts. We recognize that these parties disagree with certain aspects of the results reached in the Settlement. As discussed above in detail, we find merit in the objections raised by these parties, particularly with regard to the Settlement's inconsistency with Legislative and Commission policy direction.

As a basis for reviewing the Settlement, we are guided by the Commission's Settlement Rules set forth in the Rules of Practice and Procedure, Article 13.5: "Stipulations and Settlements." Rule 51.1(e) provides that the Commission must find a settlement, whether contested or uncontested, to be "reasonable in light of the whole record, consistent with the law, and in the public interest" before it may approve a settlement. As we explained in D.96-01-011:

"[W]e consider whether the settlement taken as a whole is in the public interest. In so doing, we consider individual elements of the settlement in order to determine whether the settlement generally balances the various interest at stake as well as to assure that each element is consistent with our policy objectives and the law." (Re Southern California Edison Company, [D.96-01-011] 64 Cal. P.U.C.2d 241, 267, quoting Re Natural Gas Procurement and System Reliability Issues [D.94-04-088, p. 8 (slip op.)] (1994) 54 Cal. P.U.C.2d 337, 343.)

Since the Settlement before us is contested, we take note of the approach followed regarding a contested settlement in D.01-12-018. There, we stated that when a contested settlement is presented to us where hearings have been held on the contested issues, we are free to consider such settlements under Rule 51.1(e) or as joint recommendations. Evidentiary hearings were held on the contested issues in this proceeding, although various parties elected to waive or curtail cross-examination. Nonetheless, the underlying testimony was received into evidence, and forms an independent basis against which to evaluate the reasonableness of the Settlement Agreement.

Under Rule 51.1(e), we may reject a settlement if one or more of its elements is not consistent with our policy or the law, without elaborate examination of all the elements and without dealing with each contention of each party. We recognize that considerable time and effort have been expended preparing a settlement such as this one, which is sponsored by a large number of diverse interests. Nevertheless, we cannot abandon our regulatory obligations in favor of a negotiated outcome.

We believe the Settlement Agreement is inconsistent with Legislative direction contained in several bills including SB 28X (Stats. 2001, Ch. 12), AB 970 (Stats. 2000, Ch.329), and SB 1038 (Stats. 2002, Ch. 515), which indicate a policy preference for customer generation in general, as well as clean CG in particular. Further, we believe giving customers preferential access to ultra-clean and low-emission generation serves the public interest in general, and not just the particular interests of the individuals who choose to install customer generation. In fact, as noted above, there are a number of incentive programs in place, overseen by both this Commission and the CEC, to encourage installation of customer generation as in the public interest. Though we appreciate that the Settlement Agreement attempts to balance these objectives, we do not believe it does so in a manner that is consistent with the public interest. We therefore reject the Settlement Agreement as inconsistent with Legislative and Commission policy, as well as contrary to the public interest.

Upon rejection of a settlement, the Commission may take various steps, including the following options, as set forth in Rule 51.7:

1. Hold hearings on the underlying issues, in which case the parties to the stipulation may either withdraw it or offer it as joint testimony,

2. Allow the parties time to renegotiate the settlement,

3. Propose alternative terms to the parties to the settlement which are acceptable to the Commission and allow the parties reasonable time within which to elect to accept such terms or to request other relief.

In this instance, the Settlement Agreement has assisted us considerably in defining the issues and coming to our decision, as we discuss in considerably more detail below. We have also already held hearings on the underlying issues to establish the factual record for our decision-making. The majority of the choices we make in this decision are questions of policy and not fact, however. Thus, on the basis of the entire record before us, we reject the Settlement Agreement. All parties have had the opportunity to comment on our resolution of the contested issues as part of their comments on this decision.

B. Applicability of CRS Components to Customer Generation Departing Load

Since we have chosen to reject the Settlement Agreement, we must deal with the applicability of each of the surcharge categories (DWR bond charges, DWR power charges, SCE's HPC, and tail CTC) to a variety of types of customer generation. In our general discussion above rejecting the Settlement Agreement, we noted the Legislature has expressed a policy preference, as codified in recently enacted statutes (see discussion, infra) for certain types of customer generation, including ultra-clean and low-emission, as well as net metered systems. We also note that several parties to this proceeding refer to our obligation to address valuation of distributed generation benefits and costs both to the overall electric system as well as to individual customers. We intend to address this question more fully in a successor rulemaking to R.99-10-025, as stated in D.03-02-068. On the basis of the policy preferences already articulated by the Legislature, as codified in recently enacted statutes, and by this Commission, however, we believe that there is sufficient policy basis to believe that customer generation confers a positive public benefit. Therefore, and consistent with these legislative policy directives, and in support of our policy preferences, we believe that we should apply CRS components differentially to the following three distinct categories of customer generation:

1. Clean systems with a capacity of under 1 MW (including-net metered systems)

2. Systems with a capacity of more than 1 MW that also meet the criteria established in Public Utilities Code Section 353.2 ("ultra-clean and low-emission distributed generation")

3. All other types of customer generation

We discuss these categories, the reasoning behind them, and the applicability of different CRS components to them, in more detail below. We also address the concept of applying a MW cap on exemptions, above which all CRS component charges will apply. Finally, we address several miscellaneous categories of customer generation that are categorically exempted from any CRS.

1. Clean Customer Generation Systems Under 1 MW

Although the parties to the Settlement Agreement chose not to deal with issues related to net metering due to the difficulty in reaching consensus, we actually believe that this group of customer self-generation represents the category that is simplest to handle. Public Utilities Code Section 2827, which establishes the net metering program, prohibits any requirement for net-metered customers to install a second meter to measure the gross output of self-generation. Thus, by definition, it would be impossible for us to impose CRS charges on the gross output of a net-metered system representing departing load. Also by definition, customers participating in net metering will pay all applicable charges on the net portion of their energy usage just as any other bundled customer does. We agree with CEERT and other parties who argue that the costs of attempting to measure and charge CRS to the gross output of net-metered systems could outweigh any potential benefits (in the form of collections of CRS). Thus, all net-metered departing load shall not be required to pay any cost components of the CRS.

Though one of the eligibility criteria for the net metering program is that the customer generation system be under 1 MW in size, not all CG in this size category is net metered. For example, a number of installations of solar photovoltaics are not net metered. We believe, therefore, that certain other clean customer generation in this size category should be treated similarly regardless of its net metering status. In particular, both the CPUC and the CEC offer financial incentives from various funding sources to encourage installation of clean self-generation. The offering of a financial incentive clearly indicates a policy preference designed to encourage the installation of such systems. We intend to continue offering these types of systems a preference in order to encourage their installation. Therefore, if a system is under 1 MW in size and eligible for participation in either the CPUC's self-generation program or a CEC program, we will also provide an exception from payment of the full fair share for that system, and therefore the departing load it represents, from any requirement to pay any portion of the CRS.⁷⁰

We recognize that the CPUC self-generation incentive program allows eligible systems up to 1.5 MW in size, while only offering financial incentives for the first 1 MW. We do not revise our exceptions to the CRS created in this decision to include 1.5 MW, as suggested by several parties including Clarus Energy. Instead, we continue to believe that a 1 MW size limit is appropriate for exceptions to CRS, because this is the size limit created by the Legislature in Public Utilities Code Section 2827. We maintain this size threshold to be consistent with the net metering program.

We also state our intent to revisit the 1 MW limit for exceptions to the CRS no later than three years from the date of issuance of this decision, in order to take into account any technological advances or economies of scale in customer generation production and sale.

If the CEC or CPUC incentive programs are discontinued in the future, we will reconsider tying continuing exceptions to the CRS to those programs at that time. Although the CPUC's self-generation program is currently set to expire on December 31, 2004, it is possible that we will extend the program, and today's decision neither addresses or prejudges any issues related to this program at this time.

Further, in response to comments, we indicate our desire to revisit and potentially modify the eligibility requirements for our self-generation incentive program in a new distributed generation rulemaking as indicated in D.03-02-068. In particular, we would like to consider increasing the efficiency requirements associated with any systems receiving incentives that generate power through combustion with waste heat recovery. Although we cannot make any revisions to the program in this decision since these issues were not addressed in this proceeding, we signal our intent to examine these issues in our new distributed generation rulemaking.

Also in response to comments, we clarify that the exception to the CRS granted for these types of technologies includes no requirement to pay SCE's HPC, as well as any potential HPC that may be requested or granted in the future for PG&E and/or SDG&E.

Also in comments, PG&E and SCE argue that Public Utilities Code Section 2827(l) requires the Commission to impose DWR costs on net metering customers. They claim that our exception for net metering would be in violation of this statute. We disagree. Public Utilities Code Section 2827 (l) requires that net metering customers pay "nonbypassable" fees, including both bond charges and power charges. By definition, net metering customers do not bypass either the DWR bond charges, or power charges, since they continue to pay these charges based on their net energy consumption. We believe our interpretation in this decision is consistent with these provisions of Public Utilities Code Section 2827 (l).

Finally, we add a requirement that the utilities report to the Energy Division, and the CEC on a quarterly basis, the amount of customer self-generation installed in this category.

2. Ultra-Clean and Low-Emission Systems over 1 MW

Public Utilities Code Section 353.2 gives us explicit authority to consider the emissions and energy efficiency characteristics of customer generation in establishing rates and fees (subsection (b)). This code section also includes a definition of "ultra-clean and low-emission" distributed generation that meets the following criteria:

"(1) Commences initial operation between January 1, 2003, and December 31, 2005.

(2) Produces zero emissions during its operation or produces emissions during its operation that are equal to or less than the 2007 State Air Resources Board emission limits for distributed generation, except that technologies operating by combustion must operate in a combined heat and power application with a 60-percent system efficiency on a higher heating value."

As discussed in the previous section, any system that meets these criteria and is less than 1 MW in size will not be required to pay any CRS charges. For systems over 1 MW in size, however, we believe their scale dictates that they should be responsible for a fair share of the DWR bond charges. While making exception for systems under 1 MW from bond charges will not make a recognizable difference in collection amounts, collections on larger systems will have a noticeable impact. Therefore, we will require that systems meeting the Public Utilities Code Section 353.2 criteria which are over 1 MW in size pay the DWR bond charge.

In order to maintain the Legislature's and our policy for encouraging ultra-clean and low-emission customer generation in the public interest, we will make exception for these systems, so that they are not required to pay other portions of the CRS. In particular, ultra-clean and low-emission CG over 1 MW in size will not pay for DWR ongoing power costs, nor will they pay for SCE's HPC.⁷¹ These systems should also still pay tail CTC,⁷² to the extent that they are not otherwise exempted by Public Utilities Code Section 372 and/or 374.

We adopt the exceptions for this category based on the above policy directives and considerations discussed above, including the importance of encouraging the installation of these types of generation. We agree with CEERT that not requiring this CG to pay most portions of the CRS (except the DWR bond charge and tail CTC, where applicable) will help support meeting the CARB aggressive standards.

We will, however, impose a cap on customer generation systems over 1 MW in size exempted from various portions of the CRS, as discussed in more detail in Section V.B.4 below.

3. Other Customer Generation

This category of customer generation includes any generation defined in this order that is not addressed in Section V.B.1 and V.B.2. This category does not include back-up generation or any diesel-fired customer generation. All generation addressed in this category, and in this decision, must meet best available control technology standards set by local air quality management districts and/or the California Air Resources Board, as applicable.

We will require any other customer generation departing load not discussed in sections V.B.1 and 2 above to pay all CRS components except the DWR ongoing power charges, up to a certain MW limit as discussed in Section V.B.4 below. Though we wish to support the option of customers to install self-generation, we generally wish to encourage more environmental forms of CG, as described above. Therefore, we do not find a policy justification for exempting CG that is not eligible under Public Utilities Code Section 353.2 from historic procurement charges or, under Public Utilities Code Sections 353.2, 372, or 372, from tail CTC. These systems will therefore be required to pay DWR bond charges, historic procurement charges, and tail CTC. The exception for DWR ongoing power charges is discussed in more detail in the following section.

In response to comments, we also wish to define more clearly the HPC that these types of systems should pay. As noted earlier in this decision, any discussion of HPC for PG&E and SDG&E is outside the scope of this decision. However, SCE HPC should be defined as follows (taken from Section 7.1 of the Settlement Agreement, as well as Appendix B):

· Customer generation departing load defined in this section of this decision that took direct access service at the time of the departure will continue to pay the HPC amounts authorized in D.02-07-032, or successor decisions. Any direct access customer that had load departing after March 29, 2002, but prior to the implementation of this decision, will be back-billed to July 27, 2002 at the 2.7 cents per kWh rate and will be responsible for the charges adopted in D.02-07-032, or successor decisions, on a prospective basis.

· The HPC responsibility for customer generation departing load defined in this section of this decision, that was receiving bundled service at the time of the departure, shall be computed on a customer-specific basis using the following methodology:

· The generation revenues received from the customer since May 2000 shall be compared with the procurement costs incurred to serve the customer's recorded kWh usage. The procurement costs prior to January 17, 2001 shall be based on the Schedule PX prices. The procurement costs from January 17, 2001 through August 31, 2001 shall be based on the amounts in SCE's Energy Cost Accounting system as reflected in Schedule PE. The procurement costs for September 2001 forward shall be equal to the generation-related recoverable costs incurred on behalf of bundled service customers and reflected in SCE's Settlement Rate Balancing Account on a cents per kilowatt-hour basis.

· A customer-specific HPC cost responsibility will be determined by multiplying the customer's cumulative undercollection on August 31, 2002, by the ratio of the starting PROACT balance to the cumulative costs in SCE"s PROACT as verified by the Commission's Energy Division.

· The customer's monthly contributions to the PROACT will be calculated by subtracting the customer's monthly generation-related costs from the customer's monthly generation-related revenues.

· The customer's HPC obligation at the time of departure will be the difference between the customer-specific HPC cost responsibility at the beginning of the recovery period designated in the settlement agreement entered into by SCE and the Commission in Federal District Court Case No. 00-12056-RSWL, and the cumulative contributions to Surplus reflected in the PROACT, but never less than zero.

· The customer's HPC obligation will be adjusted by the estimated proportion of energy to be served by customer generation to the amount of energy used prior to departure.

· The customer's HPC obligation, at the customer's election, may be amortized and paid over a two-year period or in a single lump sum.

Also in response to comments, we wish to limit the amount of customer generation granted the exception for DWR ongoing power charges in this section. We are primarily concerned that setting no limit will result in installation of more non-renewable customer generation than renewable generation. Thus, we will limit the amount of installed MW capacity in this category to half of the cap defined in section V.B.4 below. We discuss this provision further in the next section.

4. Applicability and Administration of a MW Cap

We generally find the rationale behind setting a MW cap on the amount of customer generation not required to pay the DWR ongoing power charge portion of the CRS articulated in the Settlement Agreement to be reasonable. It is clear that DWR, when negotiating long-term power contracts, assumed that a certain amount of customer generation departing load would occur every year and therefore did not procure long-term power for that portion of the load. In fact, such an assumption is based on common sense, since utilities have always faced departing load in various forms, including that caused by an economic downturn, improvements in energy efficiency and building codes, as well as installation of self-generation systems. We therefore reject ORA's argument that no link has been established between assumptions of departing load and DWR's contract negotiations as irrelevant.

While we therefore agree with the overall rationale behind setting a cap to mitigate the risk of cost-shifting, we do not believe the assumptions included in the Navigant model utilized by DWR while negotiating long-term contracts could have been sufficiently precise to permit reliance on them to set an annual cap. We also believe that setting an annual cap would create unnecessary administrative complexity and market uncertainty. Therefore, we will simply rely on the DWR/Navigant model assumptions to set one overall cap of 3,000 MW (the approximate cumulative total (rounded) of DWR's annual assumptions over ten years).

We will apply this cap to all CG departing load. As under the Settlement Agreement, we request the assistance of the CEC in certifying systems as eligible under the cap. We will require the utilities to provide data and to cooperate with the CEC in this endeavor. In addition, we will request that the CEC provide an opportunity for public comment on the manner in which it will gather information, procedures for providing ongoing public notice of Customer Generation projects under development, and procedures for granting exempt status.

In response to comments, we also make several modifications and clarifications on our preferences for administration of the cap. First, we will not require systems described in Section V.B.1 above (small clean and net-metered systems) to apply for exemptions under the cap. Such systems should be tracked by the utilities and reported as described in this decision, and should count towards the cap, but should be automatically granted the CRS exceptions to their fair share as described in this decision.

To address concerns raised by the settling parties about potential cost-shifting to non-customer-generators if more systems are installed sooner than anticipated, as well as to mitigate concerns about too much non-renewable customer generation being installed, we add the following requirements:

· Other customer generation described in Section V.B.3 above should have the following limitations

- a cap of 600 MW before the end of 2004

- an additional 500 MW permitted until July 1, 2008

- a final tranche of 400 MW permitted after July 1, 2008

Adding these limitations causes us to reinstate the provisions of the Settlement Agreement that make special set-asides for UC/CSU. When we had an overall cap of 3000 MW, UC/CSU were confident that their projects would qualify for certain exceptions, but staggering our caps reintroduces uncertainty for UC/CSU's particular projects.

In particular, UC/CSU should be granted the following specific allocations:

· 10 MW by the end of 2004

· an additional 80 MW by the end of 2008

· an additional 75 MW after the end of 2008

Although ultra-clean and other types of customer generation will be granted exceptions to different portions of the CRS components, they will be counted under the MW cap on a first-come, first-served basis. Thus, ultra-clean and low-emission CG will receive a preference in terms of the portions of the CRS to be paid relative to other forms of CG, but will not be exempted from an overall cap on the amount of CG exempted from DWR ongoing power costs. Non-renewable CG, however, will be limited to a total of no more than 1500 MW, in these separate tranches, as discussed above.

Finally, once the 3,000 MW cap is reached, or the caps are reached on non-renewable CG, all additional CG departing load installed thereafter will pay all CRS components, including the bond charge, the DWR ongoing power charges, the HPC, and the tail CTC, as applicable.

We also request that the utilities report to the Energy Division and the CEC, and that the CEC track and report publicly, on a quarterly basis, the amount of customer generation installed under the caps identified above. The utilities should assist the CEC in this tracking and reporting. We will watch the progress of customer generation installations closely, and indicate our commitment to revisit the caps within three years or when 1000 MW of customer generation have been installed, whichever occurs first.

5. Other Excepted Customer Generation

We note that the parties to the Settlement Agreement stipulated that certain types of customer generation should be released from the DWR ongoing power charges, including:

· Existing load served by customer generation that departed utility service on or before January 17, 2001

· "Grandfathered" DL that becomes operational on or before January 1, 2003, or that submitted its CEQA application on or before August 29, 2001 and becomes operational on or before January 1, 2004.

We agree that those forms of departing load should be excepted from the DWR ongoing power charges. In addition, the first category should also be excepted from DWR bond charges, since that customer generation had departed before DWR began buying any power.

We also agree with the Settlement Agreement that it is reasonable to conform all of the definitions of departing load customer generation to utility tariffs, including the use of a "physical test" to determine whether new or incremental load requires the use of a utility's transmission or distribution facilities. In addition, because public entities such as joint power authorities fall outside the scope of the tariffs, they should be excluded for purposes of this order.

Finally, we agree with AECA and the Joint Settling Parties that, in accordance with AB 2228, eligible biogas digester customer generation are not required to pay CRS departing load charges.

· A revenue requirement will be derived for the qualifying facility and power purchase agreement portfolio by multiplying the uneconomic portion ($/MWh) times the forecast of MWh in the portfolio. A total "tail" CTC revenue requirement will be derived by adding the uneconomic portion of the qualifying facility and power purchase agreement revenue requirement to the employee-related transition costs and, in the case of SCE, any costs associated with the nuclear incremental cost incentive plan. The total "tail" CTC revenue requirement will be divided by the total applicable load to derive the CTC rate applicable to Departing Load. The total applicable load includes bundled, direct access, and Departing Load customers not otherwise exempted from ongoing CTC pursuant to statute or to this order. · Any other charge established in the direct access phase of R.02-01-011 to recover the cost of above-market utility retained generation assets or power purchase obligations shall not be applied to Departing Load. (definitions taken from the Settlement Agreement, Section 8)