IV. Resolution of Limited Rehearing Issues Granted in D.03-08-076
A. Framework for Determination of Cost Responsibility for MDL "New Load"
As a basis for resolving the disputes at issue in the rehearing phase of this proceeding, we first clarify the conceptual framework within which any evidence should be evaluated as a basis for assigning cost responsibility. In D.03-07-028, we concluded that the MDL CRS should be imposed, and that the CRS should extend to "new municipal load" attributable to publicly-owned utilities that formed after February 1, 2001. We granted a limited exception to the CRS, however, applicable to new municipal load attributable to publicly-owned utilities providing "substantial operations" as of February 1, 2001.
The date of February 1, 2001 represents the point in time that DWR officially took over responsibility for procuring the net short position of the IOUs pursuant to AB1X. By adopting that date in D.03-07-028 as a cutoff for establishing eligibility for a CRS exception, we were implicitly assuming that the load forecasts relied on by DWR incorporated recognition of bypass due to new load at least for POUs that were already in existence at that time. We did not extend the exception, however, to "new" publicly-owned utilities (i.e., those formed after February 1, 2001). Our stated reason for this distinction between existing and "new" publicly-owned utilities was "to ensure that a loophole is not created that encourages new publicly-owned utilities to develop solely to take advantage of a disparity in rates associated with DWR and historical utility costs-to the detriment of remaining ratepayers. . . ." (D.03-07-028, p. 61 (slip op.).)
In the Rehearing Decision, however, we concluded that the record appeared inadequate to determine eligibility for the new load exemption adopted in D.03-07-028 based on whether a publicly-owned utility POU was formed before or after February 1, 2001. Accordingly, the Rehearing Decision directed that further proceedings be conducted concerning "whether, or to what extent, there is sufficient factual basis for a CRS allocation based on whether the publicly-owned utility was formed before or after February 1, 2001." Our further scrutiny of the record pursuant to the rehearing, however, has revealed that such an assumption is not supported by the evidence.
1. Avoidance of Cost Shifting
In assessing the relevance and adequacy of the evidentiary record in resolving outstanding issues concerning the MDL CRS, we are guided by the statutory provisions of 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).6 Through AB 117, which was signed into law September 24, 2002, the Legislature enacted Pub. Util. Code § 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 authorizes the Commission to impose a "fair share" of cost responsibility on applicable categories of customer load on whose behalf DWR procured power, including Municipal Departing Load. The determination of the "fair share" amount is left to the Commission's discretion in its exercise of this authority. In determining the "fair share" applicable to the "new load" component of MDL, we are guided by the legislative intent to avoid cost shifting among customers.
Cost shifting refers to the situation where one group of customer load bears DWR costs that were incurred on behalf of a different group of customer load. The relevant criteria relate to underlying load categories rather than to individual customers. Thus, even if an individual customer resided outside of California during the period that DWR was entering into long-term power contracts. If that individual subsequently moves into the service territory of a California IOU as it existed on February 1, 2001, that customer assumes responsibility for a DWR power charge applicable to the load on whose behalf DWR procured power.
A similar principle holds true for future customers that take service from a publicly-owned utility in the form of "new load." A provision to serve both current and future load within the utilities' service territory was incorporated within DWR's sales forecast. DWR entered into long term power commitments to serve future growth due, in part, to what could ultimately become new load of publicly-owned utility. (See, Tr. 2640-41/DWR McDonald.)
To the extent that DWR procured power relying on forecasts on behalf of service territory that included such "new load," customers taking power as part of such "new load" remain responsible for paying a CRS provision to DWR. If such "new load" is not assessed a "fair share" of costs corresponding its responsibility, its share of costs would be shifted to another group of customers. Correspondingly, if the load forecast relied upon by DWR excluded a particular category of MDL customer load, then DWR did not procure power on behalf of the excluded load. If no costs were incurred to serve a particular load category in first place, then there are no costs to be shifted.
As a basis for determining whether, or to what extent, a CRS exception should apply to new load, therefore, the relevant factual question is whether DWR procured costs on behalf of such new load. The answer to that question, in turn, depends on whether, or to what extent, the load forecast utilized by DWR excluded the new load from the forecast.
Thus, the question before us in the context of the rehearing is whether, or to what extent, the load forecasts utilized by DWR (a) distinguished in any way between new load attributable to POUs formed before versus after February 1, 2001, or (b) distinguished based on any other criteria between new load of POUs.
2. Prudence of Forecast Forms No Basis for CRS Exception
Certain parties argue that even if new load was ignored in DWR's procurement, the IOUs should have accounted for new municipal load for both existing and newly formed publicly-owned utilities. These parties argue that that the deciding factor warranting a CRS exception should be whether the IOU had knowledge that the publicly-owned utility was or would be providing retail service during the period covered by the forecast provided to DWR.
These parties call for Commission review of the reasonableness of the load forecasts utilized by DWR as a basis for assigning cost responsibility based on what the IOUs "should have factored" into the load forecasts (SSJID Comments, pp. 1, 6-7). Various parties allege that the IOUs' load forecasts are "disingenuous" or "blunders" (Merced ID Comments, pp. 2, 5). Merced ID cites to a May 11, 2001 letter from DWR to CMUA where DWR states that it would attempt to procure resources for publicly-owned utilities if requested to do so as indicating that DWR took into account publicly-owned utility load by omission. Merced ID believes that neither the IOUs nor DWR reasonably should have ignored new publicly-owned utility load when preparing the 2001 forecasts.
Proponents of the prudence standard argue that if IOUs provided incorrect forecasts, or failed to take into account certain factors they were aware of prior to providing those forecasts, a portion of the DWR burden corresponding to those forecast errors should be borne by utility shareholders.7 NCPA argues that specific time periods need to be ascertained where the utility was aware that a certain amount of load that it previously supplied would soon be supplied by a publicly-owned utility. NCPA uses, as an example, the City of Redding's annexation. In October and November 2000, Redding signed three separate letter agreements provided by PG&E for the preparation of Sales Agreements. Although the Sales Agreements were not complete when DWR began procuring power for the IOUs, NCAP argues that PG&E was aware of both the size and load within that area, as well as the impeding departure of that load form PG&E and should not have included it in its long term forecasting. NCPA refers to a similar example concerning Turlock Irrigation District.
In seeking a Commission review of the managerial prudence of forecasting methodologies underlying the load forecasts provided to DWR as a basis to disallow a portion of the MDL cost responsibility as a "fair share" allocation to utility investors, parties ignore the legal obligations associated with DWR cost recovery. A key component of the MDL CRS is comprised of DWR costs. Under the obligations outlined in AB1X, it is DWR, not the utility, that is the principal seller of power. AB1X assigns roles to the Commission and DWR respectively in establishing the relationship between DWR as power seller and the customers within the service territories of the investor-owned utilities. A key provision of the statute governing DWR cost recovery is Water Code Section 80110, which provides in relevant part:
"The department shall retain title to all power sold by it to the retail end use customers. The department shall be entitled to recover, as a revenue requirement, amounts and at the times necessary to enable it to comply with Section 80134, and shall advise the commission as the department determines to be appropriate."
Water Code Section 80104 further states: "Payment for any sale [of power by DWR] shall be a direct obligation of the retail end use customer to the department."
Thus, the funds for payment of DWR power belong to DWR, and must be collected from retail customers as a direct obligation payable to DWR. The funds to be collected through the MDL CRS are a subset of the total pool of funds attributable to the payment of power purchased by DWR. By law, MDL CRS funds attributable to DWR costs are the property of DWR. The right of DWR to collect those funds is not dependent on findings by this Commission concerning whether the forecasts underlying the DWR procurement were "reasonable." Thus, the DWR payment obligations, including the portion thereof collected through the MDL CRS, cannot be allocated partially to utility investors, or "disallowed" from utility revenues on the basis of an alleged forecasting imprudency. The utility merely collects DWR costs as an intermediary and remits such funds to DWR.
With no legal basis to disallow recovery of DWR costs by seeking to impose a share of such costs on utility investors, any "fair share" associated with procuring power to serve MDL that is not paid for by MDL would be made up from the remaining pool of funds collected from all other customers that are bearing the burden of DWR costs. Failure to allocate a "fair share" of DWR costs to MDL customers would cause a shifting of that share of DWR costs to other retail customers in violation of the statutory provisions of Pub. Util. Code § 366.2(d)(1) prohibiting cost shifting among customers in connection with the recovery of DWR costs.
The reasonableness of the IOUs' or DWR's forecasts and purchasing decisions thus were not a factor in determining the allocation of costs to be collected from MDL, and was not identified in the rehearing order as an issue to be litigated. Rather, the relevant criteria involve what was incorporated in the forecasts upon which DWR relied, upon assuming responsibility for power procurement under AB1X. To the extent that the load forecast relied upon by DWR excluded MDL attributable to any particular criteria, that load did not contribute to burden assumed by DWR in procuring power. Thus, no cost shifting would result by excluding such load from the CRS obligation.
To the extent that any adjustments were made excluding or exempting MDL customers from paying for DWR costs on the basis of what "should have" been the forecast load contracted by DWR, those costs would merely be shifted to other customers. It would not be equitable for those other customers to be charged for costs for which they were not responsible. Thus, failure to impose DWR cost responsibility on MDL would result in impermissible cost shifting in violation of AB 117.
B. Conclusions Relating to "New Load" Exception
1. Overview
For purposes of analyzing the manner in which load forecasts provided to DWR took into account MDL, it is useful to distinguish between categories of publicly-owned utilities, namely those formed before and after February 1, 2001. It is also useful to delineate between two categories of municipal departing load, namely : (1) preexisting or "transferred load" and (2) "new load."
The record shows that neither DWR nor the IOUs incorporated quantifiable adjustments into the load forecasts relied upon by DWR to recognize any bypass attributable to new load for publicly-owned utilities, whether they were existing as of February 1, 2001, or yet to be formed. In comments filed by parties representing Municipalities and Irrigation Districts, we find nothing showing or suggesting that DWR forecasts actually took into account forecasts of new load, or distinguished new load forecasts for existing POUs in contrast to any allowance of new load for POUs that had not yet been formed. Likewise, we find no evidence that the IOUs made quantifiable adjustments to recognize the effects of future new municipal load. Modesto ID argues that the Commission previously found the record sufficient to allocate new load "in keeping with historic trends." (Modesto ID Comments, p. 6.) We disagree. The Commission in its rehearing decision found that the record was not adequate to determine how a new load exemption, if any, should be allocated. The development of such an evidentiary record is the purpose of this rehearing phase.
The only "historic trend" regarding new load locating within the service territory of an IOU but taking service from a publicly-owned utility was essentially zero, since up to that point, virtually all load served by publicly-owned utilities was transferred load. Modesto ID moreover does not provide any methodology for allocating a new load exemption based on "historic trends."
Thus, in view of the lack of record basis showing that load forecasts utilized by DWR incorporated any recognition of bypass due to new load, either for existing or yet-to-be-formed publicly-owned utilities, we find no basis to exempt existing publicly-owned utilities' new load from the MDL CRS, or to utilize the date of formation of the publicly-owned utilities for determining whether or not a CRS exemption should apply. Absent adjustments either by DWR or the IOUs, there is no factual basis to treat new load of existing POUs differently from new load of yet-to-be-formed publicly-owned utilities in assigning a CRS. The rationale for applying the CRS to new load of yet-to-be-formed publicly-owned utilities applies equally to the new load of pre-existing publicly-owned utilities. We likewise find that the record does not support any alternative allocation basis for an exemption of some portion of new municipal load. As previously stated, the our determinations is based on what was contained in the forecasts utilized by DWR in procuring power.
Accordingly, we conclude that the MDL CRS should apply on a uniform basis to new load. D.03-07-028 thus shall be modified to remove the CRS exception for new load attributable to publicly-owned utilities that were formed as of February 1, 2001.
On the other hand, we find that in the case of PG&E, the load forecasts relied upon by DWR did in fact incorporate assumptions concerning the forecasted future bypass of certain existing load to municipalities and irrigation districts that were formed and serving customers as of February 1, 2001. Thus, we conclude that a modification in D.03-07-028 is warranted to grant an exclusion from the MDL CRS for a portion of existing load as of February 1, 2001 attributable to that portion that was identified by PG&E in its Bypass Report as "transferred load," as explained in further detail in Section V below. Granting this exclusion for transferred load is consistent, in principle, with the approach we adopted with respect to the adoption of a CRS exclusion for Customer Generation Departing Load based on adoption of a 3000 MW cap.
2. DWR Did Not Account for Distinctions in New Load Attributable to Either Newly Formed or Existing Publicly-Owned Utilities
As a preliminary basis to develop the record in the rehearing phase, DWR provided a memorandum dated September 26, 2003, describing the sequence of events relating to the sources of the load forecast data upon which it relied in determining the contractual commitments to meet the IOU net short requirements under AB1X. The DWR memorandum was attached to the ALJ ruling dated November 20, 2003, as a framework for parties to file comments on the rehearing issues.
As explained in its memorandum, DWR did not independently consider any form of MDL, including new load growth either for existing or yet-to-be-formed publicly-owned utilities, as a basis for making contractual commitments. DWR did rely on the load forecasts provided by the three IOUs in making its contractual commitments for power.
DWR began procuring power for the PG&E and SCE on January 17, 2001 and for SDG&E on February 7, 2001. As a basis for determining procurement requirements, DWR initially used 10-year forecasts obtained from the California Independent Systems Operator (CAISO) up through February 12, 2001. On February 14, 2001, DWR started to use load forecasts provided by PG&E and Edison. SDG&E provided a forecast about March 4, 2001. DWR states that these forecasts had been prepared by the IOUs during the year 2000.
DWR states that the forecast received from PG&E on February 14, 2001 consisted of three years of data (for 2001-03). DWR independently extended the PG&E forecast to cover a 10-year period by applying data from PG&E's Federal Energy Regulatory Commission (FERC) Report Form 714.
On April 1, 2001, DWR reduced the utility forecasts to reflect anticipated response to higher rates, crisis conservation, and other conservation actions. On May 1, 2001, DWR adopted a new forecast that included adjustments for additional conservation programs, a reduction for forecasted distributed generation, updated direct access estimates, and new load management programs. DWR used these forecasts to develop the estimates of the IOUs' net short in California.
DWR did not know at that time whether any departing load assumptions associated with municipalization, municipal annexation, or customer migration from IOU to municipal service areas were incorporated into the load forecasts supplied by the IOUs. DWR did not observe any adjustment in the IOUs' forecasts to account for municipalization.
3. The IOUs Did Not Adjust for "New Municipal Load" in Forecasts Sent to DWR
a) Load Forecasts Applicable to SCE Service Territory
SCE submitted to DWR forecasts of its net short position covering the periods of two to five years forward, beginning in 2001.8 SCE received no information from DWR suggesting that DWR did not rely on these forecasts in entering into its contractual commitments. DWR did not inform SCE that it was discounting any of the forecasts on its own, or that it had obtained alternative forecasts of future SCE load from other sources.
The first load forecast that SCE provided to DWR was prepared in about March 2000 and submitted in January 2001. At that time, no new publicly-owned utility had been formed in SCE's service territory since the City of Vernon did so in 1936. Growth of existing publicly-owned utilities through annexation (by cities served by their own publicly-owned electric utilities) of unincorporated areas served by SCE since that time was slow,9 even prior to the enactment of AB 1890 and its declaration of the nonbypassability of the Competition Transition Charge ("CTC"). Because the reduction of SCE load growth due to growth of existing municipal utilities had been negligible up to 2001, SCE did not reduce its own load forecasts to account for any subsequent growth of new municipal load occurring within its service territory.10
SCE's load modeling program allows for activities by what are deemed Public Power Utilities ("PPUs"), but that term refers only to what were, prior to industry restructuring, the seven so-called SCE "resale" cities. SCE transmitted power and, in the pre-restructuring years, also sold power in these cities' capacity as "partial requirements customers" of SCE. The term PPU does not include other municipal utilities, such as the City of Los Angeles Department of Water & Power. SCE's econometric load forecast model factors historical SCE trends of retail sales, and would to that extent necessarily include the de minimis annexation of its service territory noted above, but not as a separate "line item" input. In contrast, SCE expressly allowed for customer self-generation. SCE's forecasts submitted to DWR were for utility bundled-customer load only.11
Concurrently with the filing of its opening brief in this matter, CMUA filed a motion to "update Exhibit 80," received into evidence in the original MDL phase of this proceeding, and also requested to amend its Petition to Modify to seek a CRS exclusion applicable to the SCE service territory. Exhibit 80 is a document entitled "History of Condemnations within the SCE Territory by Municipal Utilities." CMUA argues that an updated version of Exhibit 80 will allow the Commission to make a determination that a small amount of annexation-related MDL was excluded from the forecast that SCE provided to DWR, and on that basis, ought to be exempted from the CRS. The information used by CMUA to produce its "updated" version of Exhibit 80 was provided to CMUA by SCE through discovery. CMUA argues that there is no factual dispute concerning the proposed update to Exhibit 80 and that the Commission only needs to consider arguments as to the legal significance to accord this evidence.
As part of the same pleading, CMUA requested to amend its previously filed Petition for Modification to propose that a 10-year total of 1,341,817 kWh of annexation-related MDL in SCE's service territory be exempted from ongoing DWR power charges.
In its reply brief, SCE expressed opposition to CMUA's motion. SCE objects procedurally on the basis that the Motion is untimely, and seeks to introduce materials that are beyond the scope of the current proceeding. SCE also disputes the conceptual merits of CMUA's claim that incorporation of the additional updated data on annexations would justify imposing a CRS exclusion in the SCE territory.
We deny CMUA's motion to admit into the document it has characterized as an "Update to Exhibit 80." Likewise, we deny CMUA's request to amend its Petition for Modification. The motion is procedurally defective in that it seeks to introduce information beyond the defined scope of the proceeding, and to do so after hearings had already concluded. Moreover, no foundation has been laid to indicate what, if any, relevance the historical annexation data in the update had to do with the load forecast that SCE provided to DWR. Even assuming a connection could have been proven between the historic data and SCE's load forecast, SCE calculates that the resulting amount of exemption would only be 28 kW (utilizing SCE's 55% load factor), an amount that SCE argues wouldn't even be enough to cover the costs of administering the exception.
b) Load Forecasts in SDG&E Territory
SDG&E states that during the January-February 2001 timeframe, it provided DWR with a three-year forecast of hourly load for the period 2001 through 2003. Also included with the forecast was hourly historical load data for 1999 and 2000. The forecast was provided to DWR in February 2001 in response to a DWR data request. In late January 2001, SDG&E also provided a ten-year annual forecast of its URG supply, load and net short for the period 2001 through 2010. Both forecasts are derived from the same area forecast performed in the second half of 2000. According to the DWR Memorandum attached to the Ruling, the DWR based its purchasing decisions on SDG&E's forecast after making its own adjustments to the data SDG&E provided.
SDG&E affirms that its forecasts did not attribute any future load growth in its service territory to municipalization because there was no history of any municipal utility serving load. SDG&E argues that it had no basis for including any such growth in its load forecasts. SDG&E has one very small (0.145 MW), longstanding (at least several decades) municipal customer, Escondido Mutual Water Company, SDG&E did not amend its forecast for this load because of its nil effect on SDG&E's load forecast.12
Since 2001, no municipal annexation of existing utility customer load has occurred in the SDG&E service territory. Since 2001, there has been no municipal installation of new facilities in previously undeveloped areas within the SDG&E service territory. SDG&E's load forecasts provided to DWR were based on the assumption that SDG&E would provide for 100% of the bundled load within its service territory. This assumption, to date, continues to be correct.13
SDG&E is aware of no economic or other basis to apportion CRS between existing and newly formed publicly-owned utilities.
c) Load Forecasts for the PG&E Service Territory
In contrast to the forecasts applicable to SCE and SDG&E, the PG&E load forecast provided to DWR did, in fact, include specific and quantifiable amounts of MDL based on PG&E's August 2000 "Bypass Report" (Bypass Report). In its December 2, 2003 comments, PG&E agreed that the 2001-03 sales forecast reflected "a bypass forecast prepared by PG&E Witness Keane in August 2000." The August 2000 Bypass Report included a forecasted loss of MDL through 2004 .
Although the Bypass Report identified Municipal Departing Load bypass, PG&E argues that this involved only "transferred load" not loss of "new load." As such, PG&E claims the bypass forecast would have no effect on the "new load" exemption, because PG&E's forecast assumed all new load within its service territory would be served by PG&E.
PG&E did not include any forecast of new municipal departing load within its sales forecasts, and states that those individuals preparing the forecasts during the time frame in question were generally unaware of efforts by local publicly-owned utilities to serve new load (Tr. 2558, 2560/PG&E Keane). DWR did not make any adjustment to the sales forecasts to account for new MDL. (Tr. 2598/DWR McDonald.)
We separately address issues relating to the treatment of PG&E's "transferred load" in Section V below.
6 Commission authority to adopt and allocate CRS to Municipal Departing Load is also found in AB 1X concerning the obligations to retail end-use customers for DWR costs, and our broad authority to regulate "to do all things...which are necessary and convenient in the exercise of such power and jurisdiction," under Pub. Util. Code § 701. (See discussion, D.02-11-022, pp. 11-13 (slip op.).)
7 See NCPA Comments, pp. 4-5; see also Industry Comments, p. 8.
8 SCE's forecast transmittal e-mails to DWR were subsequently lost in a computer problem.
9 SCE notes that annexation and electric service are different activities, and that growth through annexation, by a city having its own publicly-owned electric utility, of incorporated county land on which are located existing customers served by SCE does not automatically trigger a service cut-over.
10 See SCE Comments on Rehearing Issues, filed December 2, 2003, p. 3.
11 Id., p. 4.
12 SDG&E Comments on Rehearing Issues, filed December 2, 2003, p. 4.
13 See Tr. 15 at 1841 where Mr. Hansen states: "I can tell you that to the extent that DWR relied upon a forecast made by SDG&E, our forecast would show no departing load to municipal service."
