The most contentious issues in this phase involve determining the appropriate amount of utility discretion in applying transition cost revenues to incurred costs and deciding whether the utilities’ requests for flexibility impacts the risk of transition cost recovery addressed in the statute and our Preferred Policy Decision. To the extent that utility proposals for ratemaking mechanisms to track transition cost recovery differ from current ratemaking approaches, we must determine whether this is acceptable.
The utilities assert that the proposed accelerated recovery of costs and deferral of certain current costs are required by AB 1890. Because AB 1890 provides for the recovery of employee transition costs and restructuring implementation costs after the end of the rate freeze (that is, after March 31, 2002), the utilities hold that such costs may be deferred in order to allow recovery of generation-related transition costs, which are at risk for recovery by December 31, 2001. In addition, because costs related to BRPU settlements, irrigation district exemptions, and the costs of providing renewable resource programs may be collected during the period after December 31, 2001 and before March 31, 2002, there have been proposals to defer these costs as well.
This Joint Recommendation was crafted late in the schedule for Phase 1 and was brought to the ALJ’s attention on January 29, after opening briefs were filed. The moving parties to this Joint Recommendation are CAC/EPUC, CIU et al., Farm Bureau, CUE, PG&E, Edison, and SDG&E.
These parties ask the Commission to adopt the Joint Recommendation which would settle the most contentious issues in this case and provide certainty in the recovery of transition costs. In summary, the Joint Recommendation recommends the following:
1. The utilities should be given flexibility to accelerate depreciation and collection of those costs specified in § 367 that must be collected by December 31, 2001 (so-called "at-risk" costs) to minimize the potential for write-offs under Generally Accepted Accounting Principles (GAAP).
2. If necessary to allow for the recovery of those costs, the utilities may defer the recovery of employee-related transition costs and BRPU costs until after December 31, 2001, and may recover up to $50 million of at-risk costs attributable to irrigation district exemptions through March 31, 2002.
3. To the extent that the costs of renewable programs addressed in § 381(d) displace the recovery of these at risk transition costs, such at-risk costs may be recovered after December 31, 2001, but not later than March 31, 2002. Similarly, to the extent that the Commission-approved restructuring implementation costs addressed in § 376 displace the recovery of these at-risk costs, the § 367 costs may be recovered after December 31, 2001 until fully recovered.
4. The utilities agree to recover as much employee-related transition costs, BRPU-related transition costs, and irrigation district exemption-related transition costs as is feasible during the rate freeze period, provided that such recovery does not inhibit the utilities’ ability to recover the at-risk transition costs. Furthermore, the utilities will recover the current costs associated with employee-related transition costs, BRPU-related transition costs, and irrigation district exemption-related transition costs prior to recovering the costs of buy-downs and renegotiations of QF contracts and other power purchase agreements (on an aggregate basis) and prior to accelerating the recovery of nuclear decommissioning. Costs related to QF buy-outs, buy-downs, and restructurings should be addressed in the aggregate; therefore, in the short term, some contract modifications may increase costs, which will be offset by other modifications in the long term.
5. The issues related to the reasonableness and scope of employee transition costs should be deferred to future transition cost reasonableness reviews and would not be addressed in Phase 2.
6. CUE agrees to support implementation of the ISO, Power Exchange, and direct access by January 1, 1998, and CUE will continue to maintain that an environmental impact report is not necessary to evaluate major policy questions resolved by AB 1890. More specifically, CUE agrees not to contest the market structure issues at FERC, but may advocate before this Commission that divestiture is not the sole measure of horizontal market power and is not critical to achieve implementation of the competitive generation framework by January 1, 1998.
As we discuss below, we do not adopt this Joint Recommendation. Rather than giving this proposal "great weight," as urged by Edison, we consider this Joint Recommendation merely as one proposal among the various other proposals presented during Phase 1. Therefore, prior to discussing our findings in this regard, we summarize parties’ positions and proposals regarding establishing the transition cost balancing accounts and the type of flexibility that should be provided to the utilities.
Absent the recommendations of the Joint Recommendation, the major dispute in this phase is whether certain costs which are incurred before 2001 must be recovered as current costs in the year incurred or whether their collection can be deferred until after 2001. PG&E contends that the employee-related transition costs, the renewable program costs, the irrigation district exemption costs, and the restructuring implementation costs related to direct access and establishing the Power Exchange and ISO are cost categories which are not included in current rates and thus would not have occurred but for industry restructuring. Moreover, because recovery of these costs as incurred will reduce PG&E’s ability to collect what it characterizes as at-risk generation-related costs, PG&E believes that it is reasonable to apply revenues to these costs after December 31, 2001. PG&E recommends a limited after-the-fact reasonableness review of the utilities’ exercise of flexibility in acceleration. PG&E therefore proposes an annual transition cost proceeding which would review the recovery of transition costs during the previous year to verify compliance with Commission-adopted guidelines and would also provide a forum for reasonableness review for those categories of costs that must be found reasonable in order to be recovered.
PG&E recommends that the following principles should be adhered to: 1) the utilities should have sufficient flexibility to avoid write-offs under GAAP; 2) the utilities should have sufficient flexibility to match CTC revenues with costs; 3) utilities should have flexibility to accelerate recovery of their generating assets to approximate market value; and 4) the utilities should attempt to minimize the ratepayers’ costs and risks.
PG&E does not recommend an intensive review of its efforts to depreciate generation plants to market value because such a process would require litigation of market value of the plants on an annual basis. PG&E proposes to provide information reports to notify the Commission of its changes in depreciation schedules, which would not be subject to Commission review.
PG&E recommends establishing an overall transition cost balancing account mechanism, with three categories of cost accounts, all with several subaccounts, and one revenue account:
PG&E proposes to apply monthly revenues to current costs first, except that it would not apply these revenues to post-2001 employee transition costs incurred currently, and would either apply any remaining revenues to the accelerated costs subaccounts or carry over the remaining balance in the revenue account to the next month. To the extent that additional revenue remains, PG&E would then choose whether to apply these revenues to the post-2001 account. If PG&E chooses to allow the balance in the CTC revenue account to be carried over, a 90-day commercial paper interest rate would be applied to the balance; similarly, balances in the accelerated costs account or the post-2001 costs account would be carried over to the next month, using the same interest rate.
PG&E believes that it is not necessary for the Commission to prescribe rules for acceleration, because the utilities have a strong incentive to recover as much of the at-risk costs as possible by December 31, 2001. "Since ratepayer and shareholder interests are aligned in this regard, there is no reason for adopting strict rules which would mandate recovery of certain items over others." (PG&E’s Reply Brief, pp. 5-6.)
PG&E wants to accelerate the recovery of these at-risk costs as quickly as possible, but states that it intends to do so consistent with both avoiding writeoffs of regulatory assets under GAAP and reducing its generation assets to their market value but not below; i.e., so that at the time of market valuation, book value approximates market value. According to PG&E, this means that acceleration priority might have to be given to generation plants that are due to be market valued, but possess book values in excess of market. But PG&E also states that the result will not be to increase ratepayer costs or to prolong the rate freeze.
PG&E asserts that adopting a strict requirement that puts recovery of regulatory assets last because they earn lower returns than generation-related assets could result in write-offs. PG&E would then be unable to conclude that it is probable that its regulatory assets will be fully recovered. PG&E asserts that such a requirement could deprive the utilities of fair opportunity to fully recover transition costs because its adoption could result in the write-off of regulatory assets at the outset, which would be in conflict with AB 1890. If these write-offs occurred for financial accounting purposes, they would not occur for ratemaking purposes. Therefore, PG&E would still collect these costs utilizing CTC revenues; however, PG&E states that financial write-offs would be significant and could negatively impact PG&E’s bond ratings and access to capital markets. PG&E believes AB 1890, the Preferred Policy Decision, and the Rate Restructuring Settlement (authorized in AB 1890 as an example of a cost recovery plan) allow for this acceleration and flexibility. Because of the fixed recovery period, PG&E states that it is exposed to significant financial uncertainty in its ability to achieve full recovery.
The risk of write-off of plant costs is subject to different accounting standards and is less likely to occur, according to PG&E. Plant costs are subject to market valuation and must be divested, spun off, or appraised by 2001. At that time, if there are any unrecovered uneconomic costs, PG&E asserts that these uneconomic costs would become regulatory assets and therefore subject to the same risks as other regulatory assets.
In testimony and briefs, EPUC/CAC asserted that deferring recovery of certain current costs is inconsistent with AB 1890 and current ratemaking. According to PG&E, now that EPUC/CAC is a signatory to the Joint Recommendation, it now recognizes that atypical ratemaking (i.e., deferral of current costs in favor of acceleration of future at-risk costs) is appropriate in limited circumstances where specified in the legislation. Consistent with current ratemaking practices, PG&E intends to reduce ratebase by the amount of deferred taxes, thus reducing the return on ratebase and giving ratepayers the time value of money. However, PG&E asserts that such rate base reduction would not be appropriate for other regulatory assets, such as Post-retirement Benefits Other than Pensions (PBOPs), because these assets have already been net present valued in order to reflect the time value of money.
PG&E agrees that there is a general consensus that the Commission should adopt certain guidelines applicable to utility acceleration of transition costs that would serve as a framework for subsequent after-the-fact reasonableness reviews. PG&E suggests that the annual Revenue Adjustment Proceeding (RAP) proceeding may be appropriate. [ The RAP was discussed in D.96-12-077 and D.96-12-088.] PG&E recommends that the standard for review should be whether the utilities exercised reasonable judgment in balancing the conflicting guidelines for accelerated recovery, given the information available at the time. PG&E disputes TURN et al.’s contention that market value of all utility-owned generation-related assets should be determined administratively and that the utilities should be required to accelerate depreciation on these assets to a level determined annually by Commission. PG&E also disputes TURN et al.’s, ORA’s, and FEA’s contention that if utilities voluntarily defer costs, they should not earn interest on that deferral.
Finally, PG&E requests that the Commission should clarify that it is neither possible nor necessary to allocate transition cost responsibility to each rate schedule, tariff option and contract because the fire wall will adequately ensure that there is no cost shifting. This is a consensus recommendation by all parties, reached in the Energy Division workshops.
Edison proposes that an overall transition cost balancing account be established with two categories of costs and separate subaccounts within each category. Category I costs include those current period costs that must be paid because of contractual obligations and costs which must be collected by December 31, 2001. For example, Edison proposes to establish Category I subaccounts which include QF transition costs and interutility contracts transition costs through 2001, as well as subaccounts for those costs which must be collected by year-end 2001, e.g., San Onofre Nuclear Generating Stations (SONGS) 2&3 sunk cost transition costs, Palo Verde Nuclear Generating Station sunk cost transition costs, fossil sunk costs transition costs, and regulatory asset transition costs. Category II costs include those costs which may be collected after December 31, 2001, and Edison proposes to establish subaccounts for these cost such as, QF transition costs incurred post-2001, SONGS 2&3 Incremental Cost Incentive Pricing (ICIP) transition costs (for the period January 1, 2002 through December 31, 2003), regulatory asset transition costs (post-2001), employee transition costs, and restructuring implementation transition costs.
Under Edison’s proposal, market revenues and other credits and costs would be recorded on a monthly basis in the appropriate subaccount of Category I or Category II. For costs, Edison proposes to accelerate the recovery of nuclear and fossil sunk costs over the four-year period 1997-2001. Therefore, Edison proposes that the monthly recorded sunk transition cost revenue requirement to be recorded in the Category I nuclear or fossil cost subaccount will equal the depreciation expense based on a straight-line 48-month amortization period, plus taxes and a 7.35% annual return. [ In the Preferred Policy Decision, we determined that assets eligible for transition cost recovery would earn a reduced rate of return based on the embedded cost of debt for the debt component and 90% of the embedded cost of debt for return on equity. (Preferred Policy Decision, mimeo. at 123.) Section 367(d) affirmed this provision.] All other transition costs would be recorded into the appropriate transition cost subaccount as incurred. Edison is not proposing to accelerate the recovery of these costs. Edison further states that these non-sunk transition costs will not earn a return.
For revenues, Edison proposes that CTC revenues would first be entered into the Category I revenue subaccount, through the end of the rate freeze period, and thereafter into the Category II revenue subaccount. Edison proposes that revenues not be allocated among the Category I cost subaccounts, but total revenues would be available to offset the overall balance of all Category I cost subaccounts summed together. This overall Category I balance would then accrue interest at the 90-day commercial paper rate, whether it is over- or under-collected.
To the extent that the credit balance in the Category I revenue subaccount exceeds the overall net debit balance (i.e., Category I costs as incurred), Edison requests the flexibility to either leave any portion of that overcollection in the Category I account or transfer it to the Category II revenue subaccount, depending on the over- or under-collected status of the Category I and II accounts. Edison believes that this flexibility is necessary in order to apply GAAP principles for rate regulated companies to its financial statements for both Category I and Category II accounts. Edison therefore states that it cannot allow the Category I account to become too overcollected at the expense of Category II costs being too undercollected during the period.
In its opening brief, Edison explains that while Edison has proposed to amortize its generation sunk costs on a straight-line basis over a 48-month period, PG&E has proposed to recover its generation sunk costs in two components: a current cost component based on authorized revenue requirements (including associated taxes and full rate of return) and if additional revenues are available, an accelerated component at a reduced rate of return. Edison now states that in order to promote consistency among the three utilities, Edison would support PG&E’s model. Therefore, Edison would create a new Category II subaccount to record accelerated costs, similar to PG&E’s proposal, discussed above. All accelerated costs are subject to a reduced rate of return, as are nuclear sunk costs whether further acceleration is applied or not. Edison recommends that adjustments to sunk cost amortization be made annually and that these adjustments could be reviewed by the Commission in connection with the Revenue Adjustment Proceeding. Edison agrees with PG&E that the annual CTC reviews proposed by many parties do not provide an appropriate mechanism for consideration of appropriate adjustments to estimates of fair market value.
Like PG&E, Edison requests flexibility in managing the recovery of transition costs to mitigate the inherent risk due to the reduced time period for recovery. Edison urges the Commission to balance shareholder and ratepayer interests appropriately and contends that the proposals made by TURN et al. and ORA do not fairly balance the interests of shareholders, customers, employees, or potential new market entrants. Edison states that the proper interpretation of the statute based on the record is that employee-related transition costs were intended to be recovered post-2001, so as not to displace recovery of generation-related assets. Furthermore, Edison states that GAAP (specifically Financial Accounting Standards Board (FASB) Statement No. 71) precludes too large a disparity between costs incurred and those accruing in a balancing account; i.e., Edison must recover incurred costs at some point or write-offs will occur.
In its reply brief and supplemental brief regarding the Joint Recommendation, Edison states that the compromises achieved by the Joint Recommendation should be accorded great weight: the consumer representatives agreed to support the utilities’ request for flexibility in the transition cost collection process; the consumer representatives received the utilities’ commitment to recover transition costs as expeditiously as feasible, including those that may be deferred for post-2001 recovery. Employees have received the alleviation of risk that recovery of employee transition costs would displace recovery of other transition cost categories, which could result in the utilities’ reluctance to offer a package of reasonable employee transition assistance.
Edison disputes TURN et al.’s recommendation that tax deductibility be considered when determining order of acceleration. Edison states that tax deductibility has no bearing on ratemaking recovery, but is a matter of federal and state tax laws; i.e., whether an asset is accelerated or amortized over a longer period for ratemaking purposes has no bearing on its tax deductibility. Edison also disputes FEA’s allegation that lack of appropriate limits on the degree of discretionary flexibility on the utilities’ balancing account treatment could create a competitive advantage for the utilities. Edison also recommends that issues regarding the 10% shareholder incentive for restructured QF contracts are not before the Commission in this phase of the proceeding.
Edison agrees with ORA that if regulatory assets are to be accelerated, their prepayment must be treated as a rate base offset in order to prevent a windfall to the utility, except that it must be the net amount (less any taxes due). In addition, Edison states that the rate base credit should also be adjusted regularly to reflect only the funds which have been received in advance of the time they would have been received absent the acceleration.
Edison disputes TURN/DGS, ORA’s and FEA’s contention that if utilities voluntarily defer costs, they should not earn interest. Edison states that if it has to pay the costs of employee transition programs, for example, shareholders would have to finance these outlays, thus incurring short-term interest costs; accruing interest on any unrecovered balances in transition cost balancing accounts is therefore a means to make shareholders whole for these short-term borrowing costs. In general, the matching principle requires that revenues within an accounting period be matched to the costs incurred to produce those revenues; however, Edison states that regulatory ratemaking and accounting can depart from a strict matching process and that establishing a balancing account mechanism recognizes that any mismatch between revenues and costs subject to balancing account treatment should not harm or benefit either ratepayers or utility shareholders.
SDG&E proposes to divide its transition cost balancing account into six subaccounts to track the expenses and revenues for each component: fossil generation; nuclear; QF contracts; wholesale purchased power contracts; regulatory commitments; and rate reduction bonds. SDG&E agrees that flexibility is necessary to allow the utilities to manage their transition cost recovery and to minimize the risk of nonrecovery for those assets which must be fully amortized prior to the end of 2001. SDG&E recommends that if the utilities receive a return on their return-bearing assets for a shorter period of time than the Legislature intended, this would be inconsistent with AB 1890 and the Preferred Policy Decision, and we should therefore reject the ORA and TURN et al. proposal. SDG&E asserts that AB 1890 and Preferred Policy Decision grant utilities the discretion to defer recovery of employee-related transition costs incurred prior to January 1, 2002 until after December 31, 2001.
SDG&E believes that the Joint Recommendation is balanced in addressing the desire of customers to keep transition costs as low as possible, while providing utilities with a reasonable opportunity to recovery approved costs. SDG&E agrees with Edison that the standard for transition cost recovery is intended to be balanced between ratepayer and shareholder interests with a forward-looking view to a competitive future.
SDG&E agrees with PG&E and Edison that the Commission should reject the TURN et al. proposal that no interest be applied to current costs the utilities voluntarily choose to defer and agrees that the issue of tax deductibility is neither relevant nor material to the issue of asset acceleration.
TURN et al. urge the Commission to regulate the recovery of transition costs such that the interests of ratepayers and shareholders are fairly balanced, in accordance with AB 1890, and that the utilities recover transition costs in a manner than minimizes total costs recovered from ratepayers. TURN et al. recommend that the CTC revenues should first be applied to current costs. Then, to the extent that any acceleration is allowed, TURN et al. recommend that, until such time as plants are depreciated to their anticipated market value, any accelerated CTC recovery should be applied first to those transition cost assets with a high rate of return and in a manner which provides the greatest tax benefits. [ While the rate of return on assets eligible for transition costs is reduced, as provided for in the Preferred Policy Decision and § 367(d), this rate is still higher than the 90-day commercial paper rate that is generally applied to balances remaining in balancing accounts.] TURN et al. state that once plants have been depreciated to their fair market values, no further depreciation is appropriate and that this is an essential step in determining that the utilities recover as transition costs only the uneconomic portion of the net book value of the fossil capital investment, as required by § 367(c).
TURN et al. state that AB 1890 does not guarantee transition cost recovery, but affords the utilities an opportunity to recovery these costs. Moreover, TURN et al. assert that while GAAP rules for regulatory assets may be more stringent than for plants, this does not necessarily mean that these assets should be accelerated before plants earning a higher rate of return. TURN et al. recommend that we review the range of circumstances surrounding this recovery.
TURN et al. state that the utilities should be required to follow a consistent approach in establishing the transition cost balancing accounts. Annual proceedings are necessary to review each utility’s adherence to the Commission-established guidelines for transition cost recovery. Finally, TURN et al. argue that utilities should not be allowed to assess interest on balances they voluntarily choose to carry in balancing accounts because they are deferring the application of revenues to those categories of costs which can be recovered post-2001.
In support of their proposal, TURN et al. stress that stranded costs and CTC are not interchangeable: while all transition costs may be recovered through CTC revenues, not all CTC revenues will be directly related to recovery of transition costs; rather, some of the CTC revenues will cover return and taxes associated with stranded costs. This distinction is important, TURN et al. allege, because utilities have been given a fair opportunity to fully recover stranded costs, but that recovery must be consistent with a strategy to keep total CTC paid by customers to a minimum.
TURN et al. recommend that their proposal should be implemented because it is straightforward, and relatively easy to implement, and will serve to minimize the total amount of CTC revenues that will need to be collected in order to provide an opportunity for full stranded asset recovery, which is consistent with § 330(t). Because TURN’s et al. approach reduces the amount that pays for associated carrying costs, the CTC revenues that go to stranded asset recovery are maximized, allowing stranded asset recovery to be completed earlier. TURN et al. assert that the utilities’ approach would lead to a higher total amount of CTC being collected in order to achieve full recovery and result in a longer period of CTC recovery. Furthermore, TURN et al. note that AB 1890 is silent on the issue of broad accounting flexibility, but specific regarding the expeditious completion of transition cost recovery.
TURN et al. state that avoiding writeoffs is a legitimate goal; however, the concept of risk is inherent in § 368(a), which states that "the electrical corporation shall be at risk for those uneconomic generation related costs not recovered during [the rate freeze] period." Furthermore, TURN et al. assert that there will be ample opportunities to consider whether preventive action is warranted and recommend that the utilities make annual filings that would provide a forum for raising concerns such as regulatory assets write-offs and acceleration to below-market values. TURN et al. agree that the RAP could serve to review, track, and compare costs and revenues and therefore can be the forum to identify and, where appropriate, address any threat of undue asset write-offs or below-market acceleration.
Given the degree of utility benefit from voluntary cost deferrals and control over whether such deferrals take place, TURN et al. recommend that their proposal to have such deferrals occur without interest is both reasonable and consistent with past Commission decisions. (D.93-12-044, mimeo. at pp. 21, 48; D.94-12-047, mimeo. at pp. 28, 31, 39-40.).
PG&E asserts that TURN et al.’s proposal to accelerate recovery of return-bearing assets first cannot decrease costs to ratepayers unless it is assumed that PG&E is able to recover CTC-eligible costs prior to year-end 2001. PG&E believes TURN et al.’s proposal would lead to write-offs of regulatory assets and that the potential dollar impact of TURN et al. ’s proposal is relatively small; PG&E’s witness calculates that it is $20 million over the 4-year period, but does not explain how this amount is derived.
Edison and SDG&E dispute TURN’s et al. proposal that in addition to requiring costs with a high rate of return to be recovered before costs with a lower or no rate or return, the Commission should consider tax implications in establishing prioritization guidelines for accelerated recovery of various categories of costs. Edison states that the tax criterion is not valid for making acceleration decisions, because tax depreciation schedules would not be changed simply because amortization is accelerated for book or ratemaking purposes. TURN et al. concede that this is true for assets which are subject to tax depreciation schedules. For those assets not subject to tax depreciation, TURN et al. argue that the tax implications of accelerated recovery should be considered in establishing an order of priority. Furthermore, TURN et al. recommend that accelerated recovery of materials and supplies, inventories, and fossil decommissioning costs should be delayed because recovery of these costs may not provide tax benefits and because these assets may be sold along with the divested units during the transition period. [ The eligibility of these costs for transition cost recovery will be addressed in Phase 2. ]
TURN et al. emphasize that statutory interpretation by this Commission is essential, recommend that the views of single legislator or lobbyist are of little value in ascertaining legislative intent and remind us that the overriding principle for statutory interpretation is that first source for determining what a statute means is the statute itself. Finally, TURN et al. insist that nothing in the record supports PG&E’s claim that "no party has opined or even suggested that sufficient headroom might exist that would allow PG&E to fully recover the $8 billion to $14 billion in CTCs during the four-year transition period" (PG&E’s Brief, p. 16) and that the Commission should deem full recovery to be an improbable outcome. The majority of proposals in relation to balancing account issues presumed full stranded asset recovery prior to end of rate freeze period; in fact, if full recovery is not achieved by that time, concerns about the order of recovery and deferral of costs are less meaningful. TURN et al. recommend that the common presumption should be that full recovery is feasible.
ORA recommends that the utilities should sequence costs to be recovered on an accelerated basis so as to minimize ratepayer costs and agrees with the TURN et al. proposal. Specifically, ORA recommends that the utilities should pay current costs first, including employee transition costs and the costs related to renewable programs, prior to accelerating the recovery of future costs. ORA states that it is important to adhere to the matching principle of paying current costs out of current revenues. ORA agrees that the utilities should accelerate cost recovery of categories with high carrying costs first, which will reduce ratepayer interest payments to shareholders and create more headroom for the recovery of transition costs, and agrees with TURN et al. that this is similar to paying off credit cards with high interest rates first, then paying off lower cost loans.
ORA recommends that utilities accelerate the transition costs associated with fossil plants to but not below estimated market value. However, ORA states that hydroelectric, geothermal and other renewable assets should be retained by the utilities and should not be accelerated, but should be subject to generation PBR recovery, as provided for in the Preferred Policy Decision.
ORA further recommends that the utilities treat regulatory assets such as prepaid taxes as offsets to ratebase, which allows the utilities flexibility, but leaves ratepayers neutral regarding the management of transition costs. ORA also states that utilities should defer acceleration of non-plant assets, including fuel inventories, materials and supplies, and decommissioning costs, until after divestiture, because of a high likelihood that the associated assets might be sold during the transition period. ORA recommends that the utilities’ acceleration of costs should be consistent with GAAP and that the pre-payment of certain post-2001 expenses should not be permitted. ORA asserts that costs from QF contracts or Power Purchase Agreements should not be accelerated. ORA recommends that the utilities should pay employee-related transition costs as incurred and collect after 2001 only those costs incurred after 2001. ORA agrees with EPUC that the utilities are not allowed to defer until after 2001 recovery of all costs associated with irrigation district exemptions under § 374. ORA urges that AB 1890 be narrowly construed to prevent CTC extending indefinitely into the post-2001 time period to the detriment of ratepayers and customers, but agrees that the effect of § 376 is to defer the recovery of certain current restructuring implementation costs until after 2001.
ORA points out that the TURN et al. approach does not restrict utilities’ flexibility in terms of which plants to accelerate; rather, the aim is to dictate the sequence of accelerated recovery among categories of costs. ORA does not dispute that recovery of regulatory assets may be accelerated in accordance with GAAP but points out that write-offs would not occur unless there was a danger of transition costs not being collected within the headroom, which would result in write-offs anyway. Therefore, ORA agrees with TURN et al.: If all eligible transition costs are not collected at the end of the statutory periods, then a sequencing proposal does not matter; however, if the utilities can collect their transition costs during this period, then paying off the high carrying cost balances first benefits both ratepayers and shareholders.
Because there is no record to support the assertion that PG&E is unlikely to recover all sunk costs during the transition period, as PG&E claims in its opening brief, ORA recommends that the Commission should craft regulatory policies and mechanisms responsive to possibilities of both sufficient and insufficient headroom. ORA agrees with TURN et al. that the statutory interpretation must be based on the plain language of the statute.
ORA contends that costs which are voluntarily deferred should not earn interest; however, ORA agrees that costs which are deferred only because of inadequate current revenues to cover all current costs would be eligible for interest at the commercial paper rate only until such time that current revenues would allow payment of costs. ORA clarifies that it does not endorse the pro-rata approach, but instead recommends that earning no interest on voluntarily deferred costs would achieve the same result as matching current revenues with expenses and is a compromise between the more restrictive pro-rata approach and the flexibility sought by the utilities with regard to deferrals.
Finally, ORA believes that consistency among utilities in the balancing account structure will facilitate Commission oversight, but states that the accounts or tariffs do not need to be standardized.
FEA recommends that transition costs should be recorded in sufficient detail to enable the utilities, the Commission, and other parties to track and review each category of cost, that the cost categories and subaccounts should relate directly to AB 1890 and the Preferred Policy Decision, and that balancing account mechanisms and the accounting for CTC revenue should be as uniform as possible to facilitate comparative analysis and achieve consistency in the applicability of nonbypassable CTC. FEA also states that the accounting must include sufficient detail to fulfill the fire wall provisions of AB 1890 and therefore recommends that balancing accounts be established, rather than memorandum accounts.
FEA advocates establishing the following guidelines:
1. The recovery of accelerated transition costs should be guided by the principle of cost minimization. Therefore, FEA agrees with TURN and ORA that utilities should be required to accelerate collection of costs first which earn full rate of return and which are tax deductible. FEA also recommends a rate base offset.
2. The overall objective of creating a fair and competitive market should be considered in conjunction with the objective of balancing the interests of shareholders and ratepayers. Therefore, appropriate limits should be set on the degree of flexibility granted to the utilities.
3. To the extent such recovery is permitted, recovery of materials and supplies, fuel inventory, and fossil decommissioning costs should be deferred (i.e., not accelerated) until market valuation occurs, because the utilities’ recovery of such items is likely to be resolved when market valuation occurs.
4. Assets should be written down to estimated market value, but not to zero or below market value.
5. Employee transition costs incurred prior to 2001 should be recovered as much as possible before 2001, rather than deferring such collection. Deferrals of uncollected employee transition costs beyond 2001 should not earn interest after 2001.
6. Because recovery of QF and purchased power costs is permitted over the life of the contract, such costs should not be accelerated.
7. Costs should be recognized in the period benefitted. Because shareholders can retain 10% of net ratepayer benefits associated with restructured QF contracts, it would be appropriate to coordinate the timing of this cost recognition with the period during which ratepayers benefit.
8. Utilities should manage the acceleration of assets to achieve a matching of revenues to current costs plus the portion of noncurrent costs that is accelerated, in a manner to avoid major under- or over-collections of CTC.
9. Utilities should attempt to minimize ratepayers’ costs and risks.
10. Conformance with GAAP is important in determining which CTC-eligible costs to accelerate. However, the previous guidelines may make write-offs under GAAP inevitable; therefore, adherence to GAAP should be one consideration, but not an overriding consideration.
FEA recommends an annual CTC proceeding, with annual and monthly reports by the utilities. The annual CTC proceeding should consider the reasonableness of previous CTC-eligible costs during the prior year and to provide a review of utilities’ acceleration of CTC-eligible costs during previous year.
FEA is concerned about how the utilities propose to apply interest to the various components of the transition cost balancing accounts. For example, PG&E proposes to credit the CTC Revenue account at the commercial paper rate of interest for balances it decides to leave in this account. Simultaneously, PG&E would accrue an interest expense, computed at a significantly higher rate of interest, on its generation assets; therefore, PG&E would by choice leave a balance in the CTC revenue account rather than applying that balance to reducing higher interest-bearing transition cost balances, which at the same time, it chooses not to accelerate. FEA recommends that this should not be allowed or that revenue balances accrue interest at the rate of return applied to nuclear and fossil assets.
FEA asserts that the amounts of transition cost associated with regulatory assets are speculative; the amounts of regulatory assets eligible for CTC are a quantification issue which will be addressed in Phase 2 and may be a disputed factual issue. FEA states that the proposed accounting for accelerated recovery of Diablo Canyon sunk costs is inconsistent with PG&E’s accounting of other accelerated transition costs and should be modified. PG&E proposes to record these costs in the current costs CTC account. FEA recommends that the restructuring implementation costs addressed in § 376 should be recorded on the utilities’ books rather than using memorandum accounts. Because these are incurred costs, this separation should be formalized by using separate balancing accounts and/or subaccounts for costs and CTC revenues associated with each side of the fire wall.
FEA does not support major elements of the Joint Recommendation, although it generally agrees with certain statements. FEA disagrees with the recommendation that the utilities may select the order and degree of recovery of individual transition cost accounts and subaccounts as necessary to minimize the potential for write-offs which may occur under GAAP. FEA disputes the idea that litigation of reasonableness and legitimacy of employee-related transition costs should not take place in Phase 2 of these proceedings; rather, Phase 2 should be used to establish guidelines for reviewing and assessing the reasonableness of these costs and whether these costs should be offset by savings of employee-related costs reflected in existing rates.
In testimony and in opening briefs, CIU et al. recommend that no placeholder be held open for "other" transition cost subaccounts and that future annual proceedings with time for presentation of evidence are necessary to consider reasonableness of costs, amount, and eligibility of costs. CIU et al. suggest workshops to design a streamlined CTC procedure that will allow for full evidentiary hearings. CIU et al. recommend that the utilities should not be granted complete flexibility in recovery of CTC, particularly in terms of deferring recovery of costs eligible for post-2001 recovery. Other than § 376, there is no legal requirement for such deferral. In reply briefs, CIU et al. urge approval of the Joint Recommendation.
In testimony and opening briefs, EPUC/CAC recommend that flexibility be permitted for recovery of restructuring implementation costs (because § 376 specifically grants deferred recovery) and for employee-related transition costs (because AB 1890 is generally concerned with protecting utility employees and so states in its intentions). However, for all other categories of post-2001 costs, EPUC/CAC recommend that costs and revenues be matched. EPUC/CAC contend that the Legislature intended to expose the utilities to some risk and that the Commission should therefore require the utilities to recover transition costs and renewable program costs on an ongoing basis throughout the rate freeze period. EPUC/CAC state that unlimited flexibility alters the balance of benefits to ratepayers and shareholders intended by providing a rate freeze and the requirement that most transition cost recovery end December 31, 2001. EPUC/CAC propose that the utilities be required to recover the annual amortization of all eligible transition costs on a pro rata basis, including those costs which extend beyond the year 2001; that is, the monthly CTC revenues booked to the Transition Cost Balancing Account should be assigned to subaccounts based upon the relationship of the particular subaccount to the total transition cost balance.
CUE states unequivocally that reasonable employee transition costs are an obligation of ratepayers and any ratemaking mechanism that is adopted must not put the collection of generation-related transition costs at risk. According to CUE, legislative history demands this interpretation. CUE believes that if employee transition costs must compete for recovery with the recovery of generation-related transition costs, shareholders could ultimately be responsible for these costs. CUE asserts that this risk could impact the utilities’ willingness to offer reasonable transition benefits to their employees, as intended by the Legislature and the Commission. Therefore, CUE recommends that the Joint Recommendation be adopted.
The Farm Bureau agrees that an equitable balance must be maintained between ratepayer and shareholder interests and recommends that well-constructed annual transition cost proceedings will be necessary to ensure that balance is struck. The Farm Bureau also recommends that no additional exemptions to the CTC be granted, as discussed more fully below, and has expressed concerns regarding departing load lump-sum payments, which are addressed in the terms and conditions discussion.