5. Rate of Return on Meter Devices
In deploying SmartMeters throughout its electric distribution system, PG&E must retire the replaced meters, principally older electromechanical meters, many of which could otherwise provide useful service for a number of years. In A.05-06-028, the proceeding that resulted in the initial authorization of Advanced Metering Infrastructure (AMI) deployment for PG&E (D.06-07-027) and A.07-12-009, the proceeding that resulted in authorization of the SmartMeter Upgrade for PG&E (D.09-03-026), PG&E proposed ratemaking for the retired electromechanical meters, by which the original cost of the meters would be deducted from both the electric plant in service balance as well as the depreciation reserve balance. The result of that ratemaking is that, for rate recovery, the undepreciated balance of the electromechanical meters is amortized over the estimated remaining life of electric meters (approximately 18 years for 2011) with the unamortized balance being included as an element of rate base and earning the authorized rate of return. That is, there would be no effect on rate base compared to what would occur if the electromechanical electric meters had continued to be used and useful and were not replaced by SmartMeters. No party expressed opposition to this proposed ratemaking in either A.05-06-028 or A.07-12-009.
In this GRC proceeding, TURN has taken the position that the retired electromechanical meters are no longer used and useful and therefore should be excluded from rate base, resulting in PG&E earning no rate of return on the undepreciated balance as it is amortized over the approximate 18-year timeframe. PG&E served rebuttal testimony opposing TURN's position arguing that the Commission has already decided that there would be no net impact on net plant to be included in rate base on account of these retirements, and TURN's efforts to re-litigate this matter should be rejected.
The Settlement Agreement excluded costs associated with this issue and provided parties with the opportunity to brief the merits of TURN's proposal for Commission consideration and decision, with the understanding that, if PG&E prevailed, the appropriate related costs should be added to the Electric Distribution revenue requirements for 2011. Dates for opening and reply briefs were set by the assigned ALJ. Opening and reply briefs were filed by TURN, PG&E, DRA, SCE and SDG&E. Aglet filed a reply brief only. In general, TURN's position is supported by DRA and Aglet, while it is opposed by PG&E, SCE and SDG&E. In resolving this issue, a number of arguments presented in briefs were considered, as discussed below.
5.1. Addressing the Issue at this Time
In considering this issue, as advocated by TURN, rebutted by PG&E, and briefed by the various parties, the threshold argument that needs to be addressed is whether the ratemaking for meter devices replaced by SmartMeters has already been addressed and decided by the Commission in D.06-07-027 and D.09-03-026, and, therefore, whether it is appropriate for TURN to raise the issue in this proceeding.
PG&E states that it specifically addressed the ratemaking treatment of the electromechanical meters in its Initial AMI application, A.05-06-028. PG&E's ratemaking proposal was as follows:
3. Retirements of Plant
As the AMI meters are deployed, replaced existing meters will be retired at their original cost. The retirement of these non-AMI meters is accomplished through a simple reduction to plant of the original cost installed with an equal and offsetting entry to accumulated depreciation. Therefore, there is no impact to the net book value (plant less accumulated depreciation). Because of the group depreciation accounting used by PG&E, any un-recovered book investment will be recovered over the average life of the depreciation group.27
Contrary to TURN's current position that rate base should be reduced to account for the undepreciated component of the electromechanical meters, PG&E's proposal was that rate base (i.e., net book value) be unaffected by the retirement. PG&E notes that neither TURN nor any other party opposed this aspect of PG&E's Initial AMI application, and that the Commission approved its proposal as follows:28
1. Pacific Gas and Electric Company (PG&E) is authorized to deploy the proposed Advanced Metering Infrastructure (AMI) project as described and modified by this decision.
2. PG&E's electric and gas allocation proposals are approved. PG&E shall file an advice letter in compliance with this decision in not less than 15 days, or more than 30, to implement PG&E's rate proposals to collect the revenue requirement and modify its preliminary statements for the gas and electric departments establishing the gas and electric balancing accounts as adopted in this decision. The advice letter shall be effective upon its approval by the Commission.
PG&E states that it made the same proposal in its SmartMeter Upgrade application, A.07-12-009, and again it was unopposed. PG&E indicates the Commission approved it as follows:29
1. Pacific Gas and Electric Company (PG&E) is authorized to proceed with the proposed SmartMeter Upgrade, subject to the conditions and costs specified in this decision.
2. PG&E's general cost recovery proposal is adopted.
PG&E argues that given that PG&E expressly addressed the issue of the ratemaking treatment to be accorded the electromechanical electric meters in both the Initial AMI and Upgrade Proceedings, and that TURN was an active party to both cases, TURN should not be allowed now to re-litigate those issues in this GRC.
SDG&E made a similar argument in its opening brief.
First, it should be clarified that in D.06-07-027, the Commission did not authorize the deployment of SmartMeters to replace all existing electromechanical electric meters, as is now the case. In D.06-07-027, the Commission indicated:
At that point in time, PG&E's AMI proposal consisted of metering and communications infrastructure as well as the related computerized systems and software. It is often overly-simplified to imply that only meters are involved. In fact, in most instances, PG&E will not replace residential meters with new meters - most of the existing inventory will be retrofitted with communications modules and redeployed.30 (Footnotes omitted.)
Also, in D.09-03-026, the Commission indicated:
In PG&E's original AMI Application, PG&E proposed deployment of electromechanical electric meters for the majority of its residential electric service customers. The remainder of the residential as well as all commercial customers would receive solid state meters. According to PG&E, for deployment to date, this meter mix has worked as intended and, accordingly, has met the objectives of PG&E's original AMI Application. In the current application, PG&E proposes a transition in this mixture to the deployment of solid state meters ubiquitously. PG&E states that the solid state meter will be the platform for the intelligent, integrated metering solution that will enable PG&E to provide a number of new capabilities including a HAN gateway device (enabling price signals, load control and near real time data for residential electric customers) and load limiting disconnect switches . . . 31
Therefore, while PG&E's ratemaking proposal in A.05-06-028 is the same as in A.07-12-009 and the same as what is reflected in its GRC application, it would have been applied to the replacement of fewer electromechanical meters than anticipated in A.07-12-009 with solid state meters that did not have the full capabilities of the SmartMeters eventually authorized by D.09-03-026 in
A.07-12-009.
Also contrary to PG&E's assertion, Ordering Paragraph 2 in D.09-03-026, which adopted PG&E's cost recovery proposal, did not adopt PG&E's ratemaking proposal for meter devices that are replaced by SmartMeters. This particular ratemaking proposal was not included as part of PG&E's general cost recovery proposal that is discussed in Section 12.1 of D.09-03-026 and adopted in Ordering Paragraph 2. The ratemaking proposal at issue was instead an element of PG&E's revenue requirement methodology.32 That methodology was not specifically adopted in an ordering paragraph, however Conclusion of Law 50 of D.09-03-026 states that the use of PG&E's results of operations model for the purposes of calculating the revenue requirements associated with the SmartMeter Upgrade is reasonable,33 and PG&E's proposals with respect to retirements of plant are reflected in that model.
Therefore, while the applicability of the meter retirement proposal is slightly different in A.05-06-028 than in A.07-12-009 and this GRC, it is clear that, (1) in both prior proceedings, PG&E's meter retirement ratemaking proposal was consistent with what is proposed in this GRC proceeding, (2) no party addressed that proposal in the prior proceedings, and (3) in D.09-03-026, the Commission reflected PG&E's meter retirement ratemaking proposal in the ratemaking treatment for the SmartMeter program. However, in recognizing that no party addressed PG&E's proposal in either AMI proceeding and that neither
D.06-07-028 nor D.09-03-026 contains specific discussion of PG&E's ratemaking proposal for retired meters or includes findings, conclusions or ordering paragraphs in which this issue is specifically identified, it is also clear that PG&E's ratemaking proposal for meter retirement was not specifically adopted or litigated in either A.05-06-028 or A.07-12-009. Therefore, TURN's recommendation in this proceeding is not, as characterized by PG&E, a
re-litigation of the issue. We will not speculate as to why parties did not choose to litigate this issue in either of PG&E's AMI proceedings. That fact that they did not do so is, in itself, insufficient reason to preclude the issue from being addressed in this proceeding. What is of more significance is that the issue is important and relevant, and the Commission likely did not fully understand and consider the ramifications of PG&E's proposed ratemaking in those prior proceedings.
That it is the lone disputed issue in this GRC demonstrates the importance and relevance of PG&E's ratemaking proposal for retired meters. There are significant financial consequences associated with TURN's recommendation that results in the exclusion of rate of return costs of approximately $44 million in 2011, $132 million over the three-year GRC cycle, and $418 million over 18 years. Neither the magnitude of the net plant balance for prematurely retired meters, nor the associated rate of return costs were identified in PG&E's prior AMI testimony. It was not until this GRC proceeding that the $341 million net plant balance and the associated $44 million rate of return cost for 2011 were openly discussed. Also, in briefs, parties have made a number of arguments and cited precedential Commission actions that are relevant and significant, but which were never brought up and considered in the prior AMI proceedings. Consequently, there is good reason to believe that PG&E's ratemaking proposal for retired meters was not fully understood and considered by the Commission in the two prior AMI proceedings. The Commission should now fully examine this issue and determine whether the outcome in D.09-03-026 is just or needs to be changed.34
5.2. Facts Not in Dispute
In considering the merits of this issue, we note that a number of relevant facts, as follows, are not in dispute:
· The Commission encouraged the electric utilities, including PG&E, to consider and implement AMI. PG&E responded with an initial AMI proposal in June 2005 (A.05-06-028) and a revised proposal in December 2007 (A.07-12-009).
· In A.07-12-009, the Commission found PG&E's SmartMeter Upgrade proposal to be cost-effective, in that estimated incremental benefits exceeded incremental estimated costs.
· Electromechanical electric meters replaced by SmartMeters are no longer used and useful.
· In both A.05-06-028 and A.07-12-009, PG&E proposed to reduce both the electric plant in service balance and the depreciation reserve balance by the original cost of the electromechanical electric meters that are replaced by SmartMeters. This produces a result that is the same as leaving the retired meters in plant, continuing depreciation over the estimated life of that asset and receiving a rate of return on the undepreciated balance. No party expressed any opposition to PG&E's proposal in either
A.05-06-028 or A.07-12-009.· The undepreciated portion of electromechanical electric meters that will be replaced by SmartMeters is estimated to be
$341 million at the beginning of 2011. Both PG&E and TURN propose to amortize the $341 million balance over the 2011 through 2028 time period (18 years), at $18.9 million per year.· For test year 2011, PG&E's proposal to include the $341 million net plant balance in rate base, and thus in rates, imposes a financial burden on ratepayers of approximately $44 million, when compared to TURN's proposal to exclude that balance from rate base and rate of return cost recovery.
5.3. Commission Precedents
To support their positions, parties have cited a number of relevant Commission decisions regarding cost recovery as it relates to this issue, including the following:
· D.92-08-036 - The Commission adopted a settlement between SCE, SDG&E and DRA which allowed a 48 month amortization of remaining investment in San Onofre Nuclear Generating Station Unit 1 (SONGS 1). After shutdown of SONGS 1, the remaining unamortized investment was allowed to earn a rate of return, which, after taxes, was fixed at the then current authorized embedded cost of debt.35
· D.95-12-063 - Regarding electric industry restructuring, the Commission determined that transition cost recovery for remaining net investment should be at a reduced rate of return. The Commission noted that "Allowing recovery of remaining net investment associated with SONGS 1 plant at the embedded cost of debt was reasonable at the time, given the risks faced by the utilities under the then-current regulatory structure. However, today's decision decreases the risk associated with recovery of remaining net investment (now part of transition costs), due to imposition of a nonbypassable charge on distribution system customers (as described in greater detail below) which decreases utility business risk. We will adopt 90% of the embedded cost of debt as a reasonable rate of return on the equity portion of the net book value to reflect the reduced risk. We will set the return on the debt portion of net book value at the embedded cost of debt."36
· D.97-11-074 - Regarding electric restructuring, the Commission stated, "In allowing the recovery of generation plant-related transition costs, we have, in effect, allowed the utilities to recover costs of plants that may no longer be used and useful in the new competitive marketplace."37
· D.96-01-011 - Consistent with D.95-12-063, the Commission adopted the same recovery of 90% of the embedded cost of debt as a reasonable rate of return on the equity portion of the net book value regarding Incremental Cost Incentive Pricing (ICIP) pricing for SONGS 2 and 3. The Commission noted, "In
D.95-12-063, we propose a general policy for stranded cost recovery. There we decided that while use of a debt-return is appropriate for the debt component of a stranded investment, a return of 90% of the debt return is appropriate for the non-debt (i.e., equity) share of the stranded investment . . . "38· D.83-08-031 - The Commission addressed early retirement of Pacific Telephone and Telegraph Company's (Pacific's) retired equipment, and allowed rate base treatment for those assets affected by the early retirements, except for those retirements caused by the company's affirmative marketing practices designed to enhance sales of the Bell System (referred to as Pacific's migration strategy). The Commission stated "The record in this proceeding indicates that earlier than anticipated retirements are the largest cause of the decline in Pacific's book depreciation reserve as a per cent of plant. Growth fluctuations are a secondary cause. Whether we call this condition a reserve deficiency or a stranded investment does not matter. Whether the problem has been caused by the economic trends of the day, the migration strategy, or, most likely, some combination of the two, does make a difference. The difference lies in how costs are allocated between Pacific's shareholders and ratepayers. That portion not resulting from the migration strategy should be paid by ratepayers."39
· D.84-09-089 - In the context of the liquefied natural gas (LNG) project abandonment the Commission stated, "As set forth in D.83-12-068 as modified by D.84-05-100, our policy of rate recovery for abandoned plants provides for a sharing of costs between ratepayers and shareholders during periods of great uncertainty. Under this policy, if the applicants declared the LNG project abandoned, we would allow them to recover their direct expenditures, but not their AFUDC."40 However, the Commission noted that, even for project abandonments, the Commission had recognized an exception where benefits could be shown to customers, indicating, "A review of the exceptional cases is presented in D.92497 dated December 5, 1980. In these abandoned project cases we allocated the direct feasibility costs to ratepayers and AFUDC costs to shareholders. The costs borne by ratepayers were then amortized over a period of years. We have allowed the utility to rate-base a portion of the unamortized costs only when the residual value or potential benefits were likely to accrue to ratepayers. Otherwise, we considered such treatment as an inappropriate shifting of risk to the ratepayers."41 Additionally, this decision addresses PHFU, an exception to the used and useful principle, stating, "One exception [to "used and useful"] is PHFU. This is primarily land which has been purchased by a utility for use at a later date. We have allowed such property to be included in ratebase only when there is a definite and reasonably imminent plan for its development. Property which fails to meet this test is excluded under the used and useful principle."42
· D.84-05-100 - With respect to the abandonment of PG&E's Montezuma coal project, the Commission took into consideration that the overall abandonment resulted in a net gain, stating, "Also, we will allow PG&E carrying costs of $ 4.3 million. That sum is equal to the AFUDC accumulated for the Montezuma project through December 31, 1981, by which date PG&E had received bids conforming to its instructions and had accepted Sunedco's bid. (D.82-12-121, Findings of Fact 17-19.) We allow the carrying costs because ratepayers derived substantial benefits from the project, in the form of profits from the sale, even though the project never produced electricity. Thus, PG&E is entitled to its carrying costs through the date indicated."43
· D.85-12-108 - Regarding SDG&E's proposal to store power plants that could no longer be operated economically, the Commission determined that as to those plants likely to remain retired, there should be sharing of the burden, stating, "The specific ratemaking treatment for these plants will essentially follow the suggestion of UCAN. The UCAN position is that the undepreciated balance of the prematurely retired plants be amortized over five years with no return earned. The FEA recommended a longer period - nine years or three rate cases. We find that the UCAN has shown that the two rate case periods or about five years provides an appropriate sharing of the burden between the ratepayers and shareholders."44 However, the Commission did provide an exception to the used and useful principle for one unit that might benefit customers, indicating, "We will adopt the company's suggestion for South Bay 3. We find that it is the last to be stored, assume that it is, therefore, the most economical of the stored plants, and because of the uncertain reliability inherent in SDG&E's resource plan we will allow SDG&E to treat it as plant held for future use. Moreover, South Bay 3 is useful as a "yardstick" in bargaining for firm purchased power . . . We believe that both ratepayers and shareholders benefit by retaining the newer more efficient plants in rate base and excluding the older fossil fuel plants."45
· D.85-08-046 - The Commission focused on who should bear the burden of unrecovered costs in the Humboldt Bay plant retirement and, in rejecting PG&E's attempt to bring other power plants that may have operated for longer than intended into consideration, the Commission stated, "With respect to PG&E's equity argument, we observe that plants which have exceeded their estimated useful lives have been fully depreciated. Thus, the shareholder already has recovered his entire investment and a fair return on that investment from the ratepayer. The ratepayer who has paid for the entire plant is entitled to receive any additional benefit from the plant's continued operation. In the case of a premature retirement, the ratepayer typically still pays for all of the plant's direct cost even though the plant did not operate as long as was expected. The shareholder recovers his investment but should not receive any return on the undepreciated plant. This is a fair division of risks and benefits."46
· D.92-12-057 - In the case of the Geysers Unit 15 premature retirement, the Commission relied on the Humboldt Bay plant retirement as a precedent in ruling that PG&E could not offset the shorter life of Unit 15 against other plants having a longer life, using rules of group accounting. The Commission did offer that PG&E could raise the group accounting argument later, if it could make a stronger showing. The Commission also stated, " . . . We once again endorse our longstanding regulatory principle that shareholders should earn a return only on used and useful
plant . . . "47 PG&E was thus authorized a four-year amortization for the remaining net plant cost, with no return on the unamortized balance.· D.07-05-026 - In addressing cost recovery related to divestiture and/or market valuation of generation assets, the Commission stated, "The principal public interest affected by this proceeding is delivery of safe, reliable electric service at reasonable rates. The Settlement Agreement advances this interest because it permits PG&E to recover reasonable costs of complying with legislative and Commission requirements. Allowing PG&E to recover reasonable costs paid by it to comply with Commission and legislative requirement is fair and just."48
· D.94-10-059 - In discussing utility risk, the Commission stated, "Under traditional cost of service ratemaking, shareholders put up the initial capital for generation, transmission, distribution and storage facilities, and are therefore exposed to potential investment losses if the project does not operate at all, or is removed from rate base because it goes out of service prematurely. However, as PG&E and SoCal explain . . . , under applicable PU Code sections, the Commission has the authority to allow utilities to recover close to the full investment costs of abandoned and out-of-service projects. For PG&E, there have been two proceedings relating to prematurely retired plant: Geysers Unit 15 and the Humboldt Bay Nuclear Power Plant. In each case, the Commission allowed PG&E to recover the undepreciated investments over five years with no return. Similarly, the Commission has also allowed SoCal to recover costs for gas transmission, distribution and storage projects that have never become used and useful, but not earn a rate of return on those investments."49
· D.92497 - The Commission stated, "We are concerned with the increasing magnitude of abandoned project costs and the frequency of abandonments, the cost of which we are routinely being asked to place on the ratepayers' shoulders. We are also concerned with the increasing burden being placed on the stockholders who in the past have invested in utility stocks as a reliable income stock with some growth possibilities and with very little risk. Although the costs in this case are small in comparison to some abandonment costs, such as those of Sundesert, this in itself is not sufficient justification for placing the entire burden either on the stockholder or the ratepayer . . . We cannot emphasize too strongly the necessity of examining each case on an individual basis to arrive at an equitable decision."50
5.4. Positions to Deny Rate of Return on Retired Meters
Briefly, TURN's principal position and argument is that the retired meters are no longer used and useful, and the undepreciated or net plant balance should be denied a rate of return on such assets by excluding such balances from rate base.51 TURN cites D.84-09-089 wherein the Commission stated:
Over the years, this Commission has closely adhered to the "used and useful" principle, which requires that utility property be actually in use and providing service in order to be included in the utility's ratebase. We have regularly applied this principle to exclude from ratebase any construction work in progress, and have removed from ratebase plant which has ceased to be used and useful.52
As further support for its position, TURN cites D.85-08-046, regarding PG&E's Humboldt Unit 3, D.85-12-108 regarding SDG&E's Encina Unit 1 and other stored units, and D.92-12-057 regarding Geysers Unit 15. In each case the Commission amortized rate recovery of the net plant balances over either four or five years and excluded any rate of return on the unamortized balances.
In their reply briefs, both DRA and Aglet indicate support for TURN's recommendation.
DRA's principal recommendation is to address this issue after PG&E has completed its SmartMeter deployment, now estimated to be in 2012. DRA also suggests other possibilities such as allowing PG&E to recover the cost of its remaining investment over the 18 years with a market based interest rate or possibly over a lesser number of years at some reasonable short-term interest rate.
Aglet states that PG&E's decision to retire its electromechanical meters before the end of their normal lifetimes has drastically changed the mortality characteristics of the asset group, but PG&E offers no evidence on the changed characteristics (that average asset life is reduced, and the dispersion from average mortality is substantial). According to Aglet, PG&E has not shown that reliance on group depreciation accounting is reasonable or justified.
With respect to public policy arguments, Aglet states that pursuit of new technology is insufficient cause to force customers to pay a rate of return on unused assets. Also, PG&E is asking the Commission to approve a rate of return on two meters for every customer, and approval of such ratemaking would be unfair to customers. For that reason, Aglet asserts PG&E's proposal would be poor public policy.
5.5. Positions Supporting Rate of Return for Retired Meters
PG&E, SCE and SDG&E oppose TURN's recommendation to exclude the net plant balance of the retired meters from rate base. Other than arguing that this issue has already been decided and should not be re-litigated, the utilities presented a number of arguments.
According to the utilities, PG&E's proposal to use group accounting is consistent with the Commission's Standard Practice U-4 (Determination of Straight-Line Remaining Life Depreciation Accruals), financial accounting standards, and standard industry practice. Furthermore, PG&E and SCE assert that D.83-08-031 supports PG&E's proposal. In that decision, Pacific was allowed to reflect early retirements in rate base, for those assets where the early retirement was caused by economic trends (characterized as improvements in the state of the art or technological innovation). PG&E and SCE equate economic trends with the replacement of electric meters with the more advanced SmartMeters.
Both PG&E and SCE indicate that the utilities could have proposed alternative ratemaking for the retired meters to avoid the stranded costs, but the utilities explicitly chose not to do so in the AMI proceedings. Under group accounting utilities could have proposed to significantly reduce the recovery period to match the shortened lives, which would have recovered the investment so that the assets would be fully depreciated by the end of the deployment of the AMI meters. However, according to PG&E and SCE that was not proposed because of the impact it would have on rates. Instead, the utilities proposed to recover the remaining capital costs of the retired electromechanical meters in rate base over what would have been their remaining book lives had they not been replaced.
The utilities also characterize TURN's adjustment as being inconsistent with PG&E's SmartMeter decision, D.09-03-026, wherein the Commission addressed and quantified costs and benefits associated with the program. While TURN's recommendation results in less costs to ratepayers which is a benefit, that benefit was not identified in the SmartMeter proceeding analysis adopted by the Commission.
PG&E also states that TURN's recommendation is inconsistent with the Commission's evaluation of accelerated tax benefits in the SmartMeter Upgrade decision. PG&E argues D.09-03-026 reflected a deferred tax benefit for early retirement of the meters53 and it would make no sense, and would be logically inconsistent, to expect that PG&E would provide a rate base reduction for an accelerated write-off of tax basis associated with retired meters when the underlying costs themselves would not be included in rate base. PG&E also argues that TURN's recommendation is in conflict with the Commission's generic investigation of taxes and ratemaking (OII 24) in that the OII established a matching principle in determining whether tax benefits should accrue to shareholders or ratepayers and found that, to the extent shareholders rather than customers fund a cost, shareholders should benefit.54 Finally, PG&E indicates that, to the extent normalization rules of the Internal Revenue Code were to apply to these accelerated tax write-offs, TURN's proposal could well be in violation of these requirements by inconsistently treating costs and related tax benefits for ratemaking purposes.
The utilities also argue that the "used and useful" principle is not absolute, noting the PHFU exception as well as the uneconomic plant exception related to electric industry restructuring (D.97-11-074). Also noted was the ratemaking treatment for SONGS Unit 1 where the net plant balance of the retired plant was amortized over four years with a reduced rate of return on the unamortized balance (D.92-08-036), and the ratemaking treatment for South Bay Unit 3 where the unit was put into PHFU (D.85-12-108).
PG&E also presents the argument that in past Commission decisions where no rate of return was allowed on unamortized amounts, the Commission was balancing shareholder and ratepayer interests, because there was a net burden caused by the early retirement or abandonment of the plants. That balance was achieved by allowing recovery of the direct costs over a shortened amortization period (shareholder benefit) but with no rate of return on any unamortized balances (ratepayer benefit). PG&E argues that in this instance, there is no net burden caused by the early retirement of the electric meters, rather there is a net benefit in that the Commission, in D.09-03-026, found the SmartMeter program to be cost-effective. Because there is no net burden associated with the SmartMeter program and the early retirement of the electric meters, PG&E asserts that there is no need for the Commission to address the allocation of net burdens using the "used and useful" principle. As support for this position PG&E cites D.84-05-100 regarding the abandonment of the Montezuma coal project which resulted in a net benefit to ratepayers. PG&E was compensated for all costs, including direct costs and accumulated carrying costs, with the remainder going to ratepayers.
PG&E also notes that TURN did not address why PG&E should not receive a rate of return for 18 years, which is inconsistent with prior Commission decisions where no rate of return was allowed but cost recovery was expedited, typically to four or five years.
The utilities also take the position that TURN's proposal should be rejected as a matter of public policy. PG&E indicates that the only reason the electromechanical meters are being taken out of service is that the Commission directed utilities such as PG&E to propose investments in AMI technology as a necessary predicate to demand response programs and other important public policies. So long as PG&E has not recovered its investment in those meters, PG&E will remain burdened by the continuing financing costs. PG&E states that it is only fair that shareholders should continue to recover their reasonable capital costs when property otherwise used and useful is replaced at the behest of the Commission, and for the Commission to adopt a different approach would be poor public policy and would discourage utilities from embracing technological change, even where warranted. SCE likewise states that investors can hardly be expected to fund innovations such as AMI technologies if doing so would result in denial of the expected return on their prior investments.
PG&E also asserts that it would be poor public policy for the Commission to encourage programs with one ratemaking assumption, but then adopt another once the program is implemented. PG&E states that the financial health of the utility and its customers depends on perceptions by investors that they will be treated fairly when they make long-run investments in the State's utilities, and adopting TURN's proposal, in light of the long record of AMI within the state, would diminish those perceptions of fairness and thus harm customers over the long run.
5.6. Discussion
No party argues that the electromechanical meters that are replaced by SmartMeters are used and useful. By PG&E's proposal the old meters are retired and excluded from plant in service and cannot in any way be considered used and useful. Also, there is no issue as to whether or not PG&E and its shareholders should receive rate recovery of the $341 million net plant balance, through depreciation expense or otherwise. Parties agree that PG&E should be allowed to recover that amount. The issue is whether the remaining net plant amounts should earn a rate of return as it is recovered over time.
The Commission has determined that plant which is not used and useful should be excluded from rate base (and therefore excluded from earning a rate of return). However, as a number of parties have noted, the Commission has also made exceptions to this general policy. In doing so, the causes, as well as the burdens and benefits of the plant items in question, have been taken into consideration in determining appropriate ratemaking balances and solutions. The particular circumstance of each situation has been, and must be, evaluated in making these determinations. There are a number of previous Commission decisions that relate to the issue at hand, and to the extent they are relevant to circumstances of this case, they will be used as a guide in resolving the issue.
We will grant rate of return treatment for the retired meters, despite the fact that they are no longer used and useful, due to our consideration of two facts. The first fact is that AMI implementation was encouraged by the Commission, as a means for implementing Commission demand side management policies. The second fact is that AMI implementation for PG&E, in the form of the SmartMeter Upgrade, was found by the Commission to be
cost-effective. This reasoning is elaborated on below.
Costs can be stranded in a number of different ways, but when they become stranded due to Commission desires or actions that fact should be taken into consideration when determining appropriate ratemaking. For example, due to the Commission's implementation of electric restructuring, certain generation assets became stranded. Although no longer used and useful, in D.95-12-063, such assets were afforded rate base treatment as part of the overall electric restructuring ratemaking process. Also, in D.96-01-011, to address potential stranded costs related to SONGS 2 and 3, the Commission adopted the ICIP mechanism, which included the accelerated cost recovery of net plant assets with a rate of return on the unamortized balance. In none of the cases cited did the Commission specifically encourage or require a utility to prematurely retire an asset, or group of assets, that was functioning properly at the time. This is an important circumstance that differentiates the current proceeding from the cited precedents.
In granting rate base recovery for net plant associated with the shutdown of SONGS 1, the Commission stated:55
"In light of the continued dispute over the future cost-effectiveness of operating SONGS 1, and the need to limit uncertainty for resource planning, the settlement agreement, which provides for the shutdown of SONGS 1 after the current fuel cycle and a return on the unamortized investment in SONGS 1 represents a reasonable compromise and should be adopted."
In that proceeding, the Commission's desire to shut down SONGS 1 in order to limit resource planning uncertainty was a stated reason for the Commission to allow rate base recovery of the stranded SONGS 1 assets.
The situation here, where the Commission encouraged deployment of AMI,56 is more similar to the above cases where the Commission granted a return on plant that was not used and useful, rather than that in the cited examples where utilities were denied rate base treatment for plant that was never, or was no longer, used and useful (principally plant or project abandonments). In the cases where return on rate base was denied, the impetus for the non-used and useful status was utility actions rather than Commission desires or actions.
As PG&E asserts, the fact that the SmartMeter program was determined to be cost effective is significant. Because of this determination, there is no net burden on ratepayers due to the early retirement of the electromechanical electric meters. This is opposed to the circumstances in many of the cited decisions where the Commission excluded plant that was not used and useful from rate base. In most of those cases there was a net burden on ratepayers because of the abandonment of a project or the shortened life of the project. In such cases the burden was shared by ratepayers (payment of the undepreciated balance over a shortened time period) and shareholders (no rate of return on the undepreciated balance, but over a shortened amortization period). In D.85-05-100, as cited by PG&E, the abandonment of the Montezuma project was a net benefit to ratepayers. PG&E was compensated for all costs, including direct costs and accumulated carrying costs, with the remainder going to ratepayers. Also in D.84-09-089, the Commission indicated that it has allowed the utility to rate-base a portion of the unamortized costs only when the residual value or potential benefits were likely to accrue to ratepayers.
In considering the cause of the retired meters and the cost-effectiveness of the SmartMeters that replaced them, we are persuaded to grant a rate of return on the unamortized net plant balance of those retired meters. For this particular case, because the Commission encouraged AMI deployment and because the Commission has determined that the SmartMeter program is cost-effective and therefore would not impose a net burden for shareholders and ratepayers to share, it would be fair and reasonable to deviate from the general principle of excluding a rate of return on the net plant balance of assets that are no longer used and useful. This does not imply that it is necessarily fair and reasonable to adopt PG&E's proposal to amortize the net balance over 18 years with full rate of return recovery on the unamortized amounts. It must be remembered that the retired meters are not used and useful and this fact is important in considering the appropriate ratemaking for this issue. Use of Commission precedents, with respect to the length of the amortization period and the magnitude of the rate of return, would result in reduced ratepayer costs, as discussed below.
Our reasoning and actions as discussed above do not alter the fact that ratepayers will be required to pay a substantial amount of money for the amortization of the undepreciated balance of plant that is no longer used and useful, as well as for a return on the unamortized balance of plant that is no longer used and useful. While this is a case where an exception to our general policy of excluding a rate of return on the unamortized balance of such plant is justified, it is also reasonable that this exception be implemented in a manner that is not only fair to shareholders but in a manner that minimizes ratepayer costs.
In the cases discussed above where a utility was either denied a rate of return or granted a rate of return, the amortization period was set at a reduced length of time, generally in the range of four to five years. To our knowledge, TURN's proposal to deny all return on the retired meters while maintaining the 18-year amortization schedule is without precedent. TURN does not cite any prior case in which the Commission denied all return on investment in prematurely retired long-lived assets without substantially shortening the amortization period. Indeed, due to inflation and the time value of money, forcing PG&E to wait 18 years to recover the $341 million balance in the retired meters at a zero percent rate of return would be tantamount to imposing a substantial penalty on PG&E shareholders.
The shortened recovery period minimizes, to an extent, the effect of granting or denying a rate of return. From a shareholder perspective, the shortened period accelerates recovery of funds on which they do not earn a return. From a ratepayer perspective, the shortened period reduces the total amount of return that will be incurred. It is appropriate to apply that same concept to this situation where ratepayers are responsible for a rate of return on the unamortized balance of plant that is no longer used and useful. We will set the amortization period at six years, or two GRC cycles, in order to reduce the total amount of return ratepayers will be required to pay. While the six-year amortization of $56,828,000 per year is more than the 18-year amortization of $18,943,000 per year contemplated by both TURN and PG&E, ratepayers will pay less for the rate of return component of PG&E's cost recovery. For example, at the currently authorized rate of return, the cumulative revenue requirement under the six-year amortization is approximately $480 million ($341 million in amortization expense and $139 million for rate of return)57 as opposed to approximately $759 million under PG&E's proposal ($341 million in amortization expense and $418 million for rate of return).
Under the six-year amortization, PG&E will still receive full recovery of the December 31, 2010 undepreciated electromechanical meter plant balance and a rate of return on the unamortized amounts. However, as discussed below, we believe that the applicable rate of return should be adjusted consistent with previous Commission decisions where rates of return were reduced commensurate with reduced shareholder risks.
In most of the cases cited in testimony and briefs, the utilities either did not receive a rate of return on the undepreciated balance; or, if a rate of return was authorized, the rate was reduced such that the return on equity was equal to the embedded cost of debt or 90% of the embedded cost of debt.
PG&E and SCE reference D.83-08-031 to support PG&E's position, the only case cited in which a utility was permitted to continue earning a full rate of return on plant that was no longer used and useful. However, as discussed below, due to the specific circumstances in that case, we are not convinced that D.83-08-031 is an appropriate precedent.
SDG&E indicates that the lower rate of return in the restructuring decision (D.95-12-063) should not apply to PG&E, stating:
It should be noted that the CPUC provided a lower rate of return in the restructuring decision in order to provide utilities with an incentive to divest fossil-fueled generation assets. No such incentive is applicable to retired meters. Furthermore the CPUC stated that the reduced return reflected reduced risk associated with these assets "as we accelerate the return of their net book value through the CTC recovery." In contrast here, the recovery period for retired meters is not accelerated, and while the Commission established a non-bypassable charge to recover transition costs, no equivalent mechanism exists with respect to retired meters.58
While it is true that there is no incentive available for PG&E to raise the rate of return similar to that provided in the restructuring decision, the more important considerations are that by this decision, PG&E will have accelerated recovery of the net book value over six, rather than 18 years, and, while there is no non-bypassable charge, there is no risk associated with the recovery of the remaining net book value. As the Commission stated, regarding cost of capital and related regulatory risk:59
Regulatory risk pertains to new risks that investors may face from future regulatory actions that we, and other regulatory agencies, might take. Examples include the potential disallowance of operating expenses and rate base additions, comparability of utility ROEs throughout the United States and rating agencies' outlooks for the California regulatory environment.
By this decision, such regulatory risk is minimized if not eliminated. There is certainty with respect to cost recovery and that cost recovery will occur over a shorter period than originally anticipated.
This case presents a unique set of circumstances compared to the previous cases. In cases in which the utility was denied any rate of return, the plant in question had become inoperable either due to order of a federal regulatory agency (Humboldt Bay)60 or due to a misestimation of the available energy resource (Geysers Unit 15). Where the utility was granted a return on equity at or below the cost of debt, concerns existed about the plant's ability to continue operating cost-effectively (SONGS 1) or the possibility that utilities would face stranded costs for plants that may not have been competitive in a restructured market. With respect to recovery of potential stranded costs due to restructuring, the Commission stated:
We note that we are not required to guarantee full transition cost recovery. We are required only to design a rate structure the total impact of which provides the utilities with the opportunity to earn a fair return on their investment. [citation omitted] We are allowing the utilities the opportunity to recover generation plant-based transition costs and providing an appropriate risk-based rate of return until those costs are recovered.61
In the current case, there is no concern or uncertainty that the assets in question may be uneconomic due to competitive pressures. Rather, PG&E has been encouraged to definitively retire assets that would have otherwise remained used and useful and on which it would have continued to earn a full rate of return. We do not wish to discourage utilities from replacing their existing assets with new technologies under these circumstances, especially when we have found the replacement to be cost-effective for customers. We are concerned that if we reduced utility returns on the replaced assets below the rate of return on debt, the reduced return would send the wrong signal to investors who may wish to consider future technological replacements that could better serve customers. Normally, equity investors receive the opportunity to earn a return above debt returns because equity investments face higher risk.
Offsetting this consideration are two factors. As discussed above, the reduced amortization period reduces the risk of recovering the capital invested in these assets. The other factor is fairness to ratepayers. As Aglet argued, "PG&E is asking the Commission to approve a rate of return on two meters for every customer."62 In balancing the considerations of reduced risk to PG&E of recovering shareholder investment, the interest of the ratepayers who are now paying a full rate of return on the new SmartMeters, and the cause of the early retirement of the electromechanical meters, we will authorize a return on equity of 6.55% for the electromechanical meters. This yields an overall after tax return of 6.3%.
The utilities argue that PG&E's proposal to use group accounting principles is proper and consistent with Commission Standard Practice U-4 (Determination of Straight-Line Remaining Life Depreciation Accruals) and standard industry practice. PG&E and SCE also note that, in the case of the electromechanical meters, under group accounting utilities could have proposed to significantly reduce the recovery period to match the shortened lives. The shorter remaining lives would have recovered the investment so that the assets would be fully depreciated by the end of the deployment of the AMI meters. However, this was not proposed by either PG&E or SCE because of the impact it would have on rates. Instead, PG&E and SCE have proposed to recover the remaining capital costs of the retired electromechanical meters in rate base over what would have been their remaining book lives had they not been replaced.
The Commission's general approval of the use of group accounting principles reflects the fact that, over time, the undepreciated balances of premature plant retirements have been retained in rate base exactly as proposed by PG&E for meter devices replaced by SmartMeters, although on a much smaller scale. However, the effect of retaining those smaller balances in rate base has been offset, at least to a large degree, by plant assets that exceed their expected lives. That is not the case here where meters are being retired early, on a wholesale basis, with significant financial consequences that are not balanced out over time. Because of this, it is appropriate that the Commission should critically review the use of group accounting and alternatives, for this particular circumstance.
We agree that PG&E could have alternatively shortened the expected lives of the meters, on a prospective basis, in calculating depreciation rates. However, they did not, and even if they had, the question of appropriate ratemaking for a large amount of prematurely retired plant would need to be analyzed in the same way as was done in this decision for PG&E's proposal.
We note PG&E and SCE reference D.83-08-031 and assert that it supports PG&E's proposal. However, we are reluctant to use this case as a precedent to justify PG&E's proposal. In that case, it was determined that Pacific's migration strategy and technological change were principally responsible for a depreciation reserve shortage and the need to increase depreciation rates. While it is true that the decision only excluded migration costs from rate base and recovery from ratepayers, and did not exclude costs due to technological change, it is not clear what the effect of technological change was in this particular circumstance. Estimates of the amount of stranded investment on Pacific's books at that time ranged from $19 to $95.7 million (D.83-08-031, Finding of Fact 12). Also, the amount associated with the migration strategy was $19 million (Finding of Fact 13). Thus, the amount of remaining stranded costs (as low as zero to as much as $77 million) may not have been of significant magnitude to justify the need to consider alternatives to balance any shareholder/ratepayers risks associated with stranded plant, especially in light of the fact there were certain cost reductions due to the exclusion of migration strategy related plant in its entirety. The circumstances were also different in that the Commission provided that the remaining stranded amount, if any, and any future amounts caused by the shortening of the expected lives of plant assets would be recovered by the straight line remaining life method for calculating depreciation by evaluating the expected lives on a frequent, possibly annual, basis.63 In that way there would be no stranded costs as shown in the examples that were included in Appendix A to that decision. That is, the amount of plant that is not used and useful for possibly a number of different plant assets would be minimized, or eliminated, by adjusting the estimated service lives on an ongoing basis.64 That is not the case with respect to PG&E's proposal where a large amount of undepreciated plant for a particular asset will no longer be used and useful and will be amortized over a lengthy period of time.
Also, the difference in industry (telecommunications versus electric) may be a reason to differentiate how this issue is treated, because the depreciable lives of telecommunications equipment appear to be shorter than that for the electric industry. In the D.83-08-031 Appendix A examples, assumed lives in the range of four to six years are used, as opposed to the 18 years associated with the electric meters. In general, since the lives are relatively short to start with, adjustments to the estimated service lives would not be as significant as they would be if, for instance, PG&E had prospectively reduced the estimated life for the electromechanical meters from 18 years to, for example, four years. With the shorter lives in the telecommunications industry, the long term affect of ratepayer funding of return costs on undepreciated balances is minimized when compared to the electric industry and specifically to the electric meters at issue here. For example, in this case, the ratepayer costs associated with the rate of return on the undepreciated meter balance amounts to approximately
$420 million over 18 years as opposed to approximately $140 million if it were amortized over 6 years.
To summarize, the circumstances related to the Pacific case are not the same as that of PG&E. The decision resolves the Pacific issue in a manner that would result in little or no net plant balances being associated with plant that is retired. That is because the estimated lives of the assets would be evaluated and adjusted on an ongoing basis so that the assumed and actual lives are balanced out. This result is directly opposed to the issue being addressed now for PG&E, which is what to do with the significant net plant balance associated with meters that are no longer used and useful. Also, it is not clear that significant net costs were imposed on ratepayers as a result of the Pacific decision.
With respect to comments related to public policy, the decision on this issue is sufficiently different from the TURN proposal to mitigate most of the concerns. By analyzing this issue, resolving it in a manner consistent with prior Commission decisions and resolving it in a manner that minimizes total ratepayer costs, public policy considerations are enhanced, not diminished. It would be poor public policy to include large amounts of plant that is not used and useful in rate base without a full analysis and consideration of the specific facts and circumstances. Even if it is determined to be appropriate to retain such assets in rate base, it would be poor public policy to not minimize the costs to ratepayers to the extent possible, because ratepayers are no longer getting any use of that plant.
We note the utilities' argument that the SmartMeter Upgrade proceeding did not take into consideration the additional benefits associated with a different methodology for handling the undepreciated plant balance associated with retired electromechanical electric meters. PG&E states that the Commission's weighing of costs and benefits for the AMI project clearly did not include the rate base benefit associated with removing the electromechanical meters from rate base. We do not see this fact as a reason to be concerned with taking up the issue at this time or deciding it in the manner that we do. In the SmartMeter Upgrade proceeding, the Commission determined that PG&E's proposal was marginally cost-effective.65 Despite this, the Commission authorized the program. It did so for a number of reasons including that, "It is likely that there are other benefits that have not been quantified by PG&E . . . "66 That there now actually may be additional benefits only substantiates the Commission's decision to approve PG&E's SmartMeter program in the first place. It does not unfairly disadvantage PG&E. We would not change any of the outcomes, conditions or requirements of D.09-03-026 based on the identification of additional benefits that justify the program.
TURN and DRA both assert that PG&E has not met its burden of proof by providing "clear and convincing" evidence to demonstrate the reasonableness of its proposal. We do not agree.
First, we do not agree that clear and convincing is the appropriate standard of proof for GRC matters. As noted by both TURN and DRA, in
D.09-03-025 the Commission addressed the "preponderance of evidence" and "clear and convincing" standards of proof, stating:67
With the burden of proof placed on the applicant in rate cases, the Commission has held that the standard of proof the applicant must meet is that of a preponderance of evidence, which the Commission has, at times, incorrectly referred to as "clear and convincing" evidence. Evidence Code § 190 defines "proof" as the establishment by evidence of "a requisite degree of belief." We have analyzed the record in this proceeding within these parameters.
In that decision, the Commission determined that for resolving GRC matters the "requisite degree of belief" can be established with the "preponderance of evidence" standard. The Commission also indicated that this standard was incorrectly referred to as "clear and convincing" in a number of previous decisions. TURN and DRA indicate that the clear and convincing standard should be affirmed. However, by principally citing previous decisions where the term "clear and convincing" was used and where the Commission has since stated that such characterization was incorrect, TURN and DRA have not provided sufficient reason for reversing the latest decision on this matter.68 Also, the Commission's determinations in D.09-03-025 are consistent with California Evidence Code, Section 115, which states:
"Burden of proof" means the obligation of a party to establish by evidence a requisite degree of belief concerning a fact in the mind of the trier of fact or the court. The burden of proof may require a party to raise a reasonable doubt concerning the existence or nonexistence of a fact or that he establish the existence or nonexistence of a fact by a preponderance of the evidence, by clear and convincing proof, or by proof beyond a reasonable doubt. Except as otherwise provided by law, the burden of proof requires proof by a preponderance of the evidence. (emphasis added.)
Second, and more importantly, as previously discussed, PG&E's proposal for retired electromechanical meters was made in the prior AMI proceedings. The proposal was laid out in testimony, was not opposed, and is reflected in the current ratemaking treatment for the SmartMeter program. Subsequent to being reflected in adopted ratemaking treatment and calculations, we do not expect that a utility should reestablish the reasonableness of that element or any other of the number of already approved elements used in the revenue requirement calculations each and every time those calculations are used. That PG&E did not do so with respect to the retired meter issue is consistent with our expectations. That PG&E demonstrated that its proposed treatment of the meters is consistent with the Commission's decisions in its AMI proceedings is sufficient with respect to meeting its initial burden of proof. However, providing such evidence does not necessarily ensure adoption or use of the proposal going forward. Certainly, elements of the revenue requirement calculation can be questioned in subsequent proceedings, just as PG&E's retired meter proposal was in this proceeding, and modified, if necessary, just as the Commission has done in this instance.
TURN suggests that an alternative to removing the meter investment from rate base would be for the Commission to direct PG&E to pursue securitization of the remaining meter investment. According to TURN this would produce ratepayer savings by achieving lower cost of financing than rate base recovery and would be similar to the financing used on the Ratepayer Reduction Bonds under Assembly Bill 1890 and PG&E's bankruptcy. TURN adds it may well require legislation as was the case for the two examples. DRA also suggested that PG&E be allowed to recover the cost of its remaining investment over the
18 years with a market based interest rate or possibly over a lesser number of years at some reasonable short-term interest rate.
It appears legislation would be required to implement securitization as alternatively recommended by TURN. There is no certainty as to when, or even if, such legislation would be undertaken and finalized. Also, with respect to DRA's suggestions, there is no record as to what an appropriate level would be for a market based rate or a short-term interest rate and why it would be appropriate to use either rate in addressing the particular circumstances of this issue.
With respect to PG&E's arguments regarding inconsistent ratemaking and tax treatments associated with the accelerated tax benefit that is reflected in the SmartMeter decision, we do not believe these arguments apply to our resolution of the meter retirement issue in this decision because, rather than zero rate of return as recommended by TURN, a rate of return on the undepreciated meter balance is being authorized.
With respect to Aglet's argument regarding the changed mortality characteristics of the electromechanical meters, we agree that expected lives for meters that are being retired prematurely are much different than the new meters that are being installed. However, it is not clear how that fact would change any of the determinations made in this decision regarding the retired meter issue. If Aglet is asserting that the estimated remaining life of this asset group needs to be reevaluated, that may or may not be the case. DRA and PG&E have settled on the depreciation rate for meters, and neither party had an opportunity to respond to Aglet's concern, since it was expressed in Aglet's reply brief. If necessary, this can be explored in PG&E's next GRC.
Use of the six-year amortization and the reduced overall rate of return from 8.79% to 6.3% results in a revenue requirement of approximately $85.4 million in 2011, $80.2 million in 2012, $75.0 million in 2013, $69.8 million in 2014, $64.6 million in 2015, and $59.4 million in 2013. An alternative calculation would result in 6 equal amounts of $74.0 million/year for each of the years 2011 through 2016. With respect to this issue and how it affects the Settlement Agreement attrition allowances for 2012 and 2013, it appears that the Settling Parties agreed that the attrition increases remain fixed irrespective of how the meter retirement issue is resolved. This is consistent with the adoption of TURN's position on this issue since the associated revenue requirement would not change year to year. However, if PG&E's position were adopted the revenue requirement associated with the meter issue should decline year to year due to the amortization of the undepreciated balance over time. It would not do so under the Settlement Agreement. Therefore, rather than adopting declining revenue requirements associated with the meter issue and imposing attrition increases that are different from what is included in the Settlement Agreement, the levelized cost of $74.0 million will be used for each of the years.69 The authorized attrition increases will then be consistent with the Settlement Agreement, while correctly reflecting the adopted results of this decision with respect to the retired meter issue.
For 2011, the decision amount is $55.1 million higher than TURN's recommendation of $18.9 million and $11.1 million higher than PG&E's request of $62.9 million. However, the amortization period will be 12 years shorter than that proposed by both PG&E and TURN. By this decision, total costs to ratepayers over six years will amount to $444 million. This is $315 million less than PG&E's 18-year amortization request of $759 million. Even though the ratepayers will be paying more money upfront and there is a time value of money impact, the ratepayers should be better off by this decision as opposed to PG&E's proposal. While the decision will result in $103 million more in ratepayer costs when compared to TURN's 18-year amortization proposal, we have determined that, for the circumstances of this case, TURN's proposal should not be adopted.70
Due to the manner in which this issue has been resolved, the authorized revenue requirement increase for test year 2011 will be $237 million (7.9%) for electric distribution, as opposed to the $183 million (6.1%) increase reflected in the Settlement Agreement. The total test year 2011 increase for electric distribution, gas distribution and electric generation is $450 million (8.1%), as opposed to the $395 million ($7.1%) increase reflected in the Settlement Agreement. Tables related to the Settlement Agreement that change as a result of the decision on this issue are included in Attachment 3 (Changes to Appendix A of the Settlement Agreement) and Attachment 4 (Changes to the Results of Operations Tables).
For the 2011-2013 GRC period, the cumulative increase authorized by this decision is $1.9 billion, which is still significantly less than the $4.0 billion amount requested by PG&E and discussed in Section 4.7.2 of this decision. When considering the long-term ratepayer benefit of amortizing the undepreciated net plant balance for the retired meters over an accelerated time period and reduced rate of return when compared to PG&E's proposal, our determination that, when looked at in total, the Settlement Agreement produces a reasonable outcome holds for the increases authorized by this decision.
Consistent with the Settlement Agreement premise that the attrition allowances for 2012 and 2013 are fixed, the amortization amounts for 2012 and 2013 are similarly fixed irrespective of any changes to the authorized cost of capital during that timeframe.
In PG&E's next GRC, for the remaining three years of the amortization, parties may present recommendations to change the amortization amount to reflect an updated authorized rate of return or the use of a declining rather than levelized amortization expense.
27 A.05-06-028, Exhibit 5 at 5-5.
28 D.06-07-027, Ordering Paragraphs (OPs) 1 and 2.
29 D.09-03-026, OPs 1 and 2.
30 D.06-07-027 at 2-3. Footnote 3 to this quotation states that PG&E's plan was to retrofit 54% of the existing electric meters and 96.1% of its existing gas meters.
31 D.09-03-026 at 18.
32 Retirements of plant, as quoted by PG&E, is discussed in Chapter 2, Revenue Requirement, in Exhibit 4 in A.07-12-009. PG&E's cost recovery proposal is discussed separately in Chapter 1 of that exhibit.
33 No party disputed the use of PG&E's results of operations model for the purpose of calculating the revenue requirements associated with the SmartMeter Upgrade.
34 We do not agree with the DRA proposal to defer consideration of the issue to the next GRC. There is sufficient record to fairly resolve the issue now.
35 45 CPUC2d 274, 276.
36 64 CPUC2d 1, 62.
37 76 CPUC2d 627, 737.
38 64 CPUC2d 241, 272.
39 12 CPUC2d 150, 167.
40 16 CPUC2d 205, 230.
41 16 CPUC2d 205, 229.
42 16 CPUC2d 205, 228.
43 15 CPUC2d 123, 127.
44 20 CPUC2d 115, 143.
45 20 CPUC2d 115, 143.
46 18 CPUC2d 592, 599.
47 47 CPUC2d 143, 267.
48 D.07-05-026 at 9.
49 57 CPUC2d 1, 54.
50 4 CPUC2d 725, 777.
51 TURN does not specify the mechanics of its recommendation with respect to how rate base should be adjusted. That is, how the undepreciated balance should be removed from rate base to exclude a commensurate rate of return and still accommodate calculation of depreciation expense that would provide recovery of that undepreciated balance over 18 years. However, the Settlement Agreement accomplishes this by leaving PG&E's undepreciated plant balance in rate base for calculation of both depreciation expense and rate of return and then backs out the rate of return element by reflecting a negative expense in the results of operations model.
52 16 CPUC2d 205, 228.
53 The revenue requirement offset was computed by multiplying the incremental deferred tax resulting from meter retirement by a pre-tax rate of return.
54 See D.84-05-036, 15 CPUC2d 42, 47-49 and 52.
55 D.92-08-036, 45 CPUC2d 274, 276.
56 While AMI was encouraged by the Commission, the full replacement of existing electromechanical electric meters with SmartMeters was PG&E's own proposal.
57 The rate of return number also includes associated taxes, uncollectibles and franchise fees.
58 SDG&E Reply Brief at 4, footnote 3.
59 D.07-12-049 at 31.
60 In the case of Humboldt Bay, the Nuclear Regulatory Commission prohibited operation of the facility due to concerns about the plant's ability to operate safely in light of faults discovered after the plant's construction. See 18 CPUC 2d, 593.
61 64 CPUC2d, 61 - 62.
62 Aglet Reply Brief at 4.
63 12 CPUC2d 150, 167-168.
64 This is similar to what PG&E and SCE indicated they could have done, but did not do.
65 D.09-03-026 at 153.
66 D.09-03-026 at 154.
67 D.09-03-025 at 22 (footnotes omitted).
68 We note that neither DRA nor TURN sought to appeal D.09-03-025 with respect to this matter.
69 By this method, the amortization schedule for the $341 million amount associated with undepreciated electromechanical meters replaced by SmartMeters will be as follows: $44.7 million for 2011, $49.0 million for 2012, $53.7 million for 2013, $58.8 million for 2014, $64.4 million for 2015, and $70.5 million for 2016. These amounts include the original amortization of $18.9 million per year for these meters.
70 For comparison purposes, the present value (PV) cost of the different alternatives was calculated using a conservative discount rate of 10%. For the adopted result, the PV cost is approximately $312 million. For PG&E's proposal, the PV cost is approximately $375 million. For TURN's proposal, the PV cost is approximately $145 million. If TURN's proposal were modified to amortize the balance over six, rather than 18 years, the PV would be approximately $240 million.
