33. Revenue Allocation

33.1. PG&E's Position

PG&E proposes to recover the incremental implementation costs through distribution rates. PG&E indicates that its proposal assigns and allocates the costs based on the function involved. Since the implementation costs are for things like the billing system, CSOL and customer services, which are distribution functions, PG&E assigns them to distribution and uses the distribution allocation factors, to allocate them to customer classes for recovery in distribution rates paid by bundled, direct access (DA) and community choice aggregation customers.

PG&E notes that similar dynamic pricing implementation costs have been unbundled as distribution in other cases. For example, all implementation costs for DR programs have been assigned to distribution for recovery. The same is true for all dynamic pricing implementation cost recovery related to the AMI and SmartMeter Update decisions. PG&E requests the Commission to approve the allocation treatment for incremental implementation costs in this proceeding that it has approved for the same activities in earlier proceedings. PG&E states that the activities to be funded in this proceeding differ from activities funded previously only in terms of their expanded size, larger scope and greater complexity, and there is no reason to treat allocation of these incremental costs for the same type of activities as in the AMI case differently than they are treated under existing programs.

33.2. DRA's Position

DRA's primary recommendation is to recover dynamic pricing implementation costs in rates paid by all users of PG&E's distribution grid, and allocate these costs by generation equal percentage of marginal costs (EPMC) in recognition of the primary role of generation in dynamic pricing cost causation. DRA states that this could be accomplished by establishing a separate rate component for dynamic pricing implementation costs, or, (preferably), by including dynamic pricing implementation costs as a subcategory of Public Purpose Program costs, analogous to Energy Efficiency program costs.

DRA's alternate recommendation differs from its primary recommendation only in proposing to allocate dynamic pricing implementation costs to all customers based on "equal percent of revenue," as was proposed by PG&E in its 2007 GRC for certain Public Purpose Programs such as Energy Efficiency and Renewables. According to DRA, such an allocation would reflect roles of both distribution and generation in dynamic pricing cost causation.

33.3. DACC's Position

DACC opposes PG&E's proposal to recover dynamic pricing implementation costs in distribution rates. It is DACC's position that, since the proposed dynamic pricing programs do not benefit DA customers or the energy service providers who serve them, the costs PG&E incurs to implement dynamic pricing should be recovered solely from PG&E's bundled service customers.

DACC states that a central tenet of DACC's participation in this proceeding is premised on the well established ratemaking principle that costs should be allocated on the basis of causation. It is DACC's position that, in the utility procurement context, the cost causation principle dictates that only those customers who have created the need for new programs and commitments should be required to pay for those commitments. Consistent with that principle, DACC's recommendations with respect to PG&E's dynamic pricing program proposal are as follows:

· The Commission should reject PG&E's proposal to have DA customers charged for costs incurred to provide a dynamic pricing program developed exclusively for bundled customers that DA customers are not qualified to receive; and

· The Commission should adopt DACC's proposal to have the costs associated with regard to PG&E's dynamic pricing program collected solely from the bundled customers that are eligible to participate in the program.

33.4. CLECA's Position

CLECA believes that these implementation costs are either customer-related or distribution type costs and that they should be allocated on the basis of distribution revenues. CLECA states these are not generation costs. They have nothing at all to do with generation. Rather, they are associated with PG&E's ability to render a bill for a new rate option and to explain that rate option to its customers. CLECA explains that these sorts of costs are normally considered to be distribution and/or customer-related costs and they are allocated to customer classes on the basis of distribution and customer allocators. CLECA also notes that the allocation of utility costs is normally an issue addressed in Phase 2 of a utility's GRC and suggests deferring the question to PG&E's pending GRC.

It is CLECA's position that while these PDP implementation costs are customer- and distribution-related costs, they should not be allocated to DA customers, because DA customers are not eligible for this rate option - they do not take bundled service from the utility.

33.5. TURN's Position

TURN recommends that the costs at issue should be recovered in distribution rates but allocated between customer classes based on generation EPMC.

TURN notes that the nature and purpose of the costs in this case are very similar to the various implementation costs for demand response and advanced meter installation. The goal of dynamic pricing is to reduce peak load, which is exactly the goal of various demand response programs and of the advanced metering infrastructure. The nature of the costs involves primarily IT improvements and modifications, which was exactly a component of authorized AMI costs. The costs of demand response programs and the AMI infrastructure are all recovered in distribution rates pursuant to various Commission decisions.

It is TURN's position that the costs at issue in this proceeding should be allocated by a generation EPMC because the primary purpose of these costs is to facilitate reductions in generation capacity and energy costs. TURN adds that, while the recovery of implementation costs should be in the distribution rate component, it is important to note that the actual CPP charges and credits will apply to generation rates.

33.6. Discussion

To address this issue, we feel it is important to consider the following facts:

· Implementation cost recovery authorized in this proceeding is for 2008 through 2010 PDP-related costs only;

· For the major electric utilities, revenue allocation, along with marginal cost and rate design, is a principal element of GRC Phase 2 filings. While generally contentious, this issue was settled in PG&E's last GRC Phase 2 proceeding, A.06-03-005. The uncontested Settlement Agreement on Marginal Cost and Revenue Allocation Settlement⁴⁴ was adopted by the Commission in D.07-09-004. That settlement also addressed rate changes between GRCs;

· Implementation cost recovery for 2011 and beyond will be determined in PG&E's 2011 and subsequent GRCs;

· Marginal cost, revenue allocation and rate design for 2011 and beyond will be determined in Phase 2 of PG&E's 2011 and subsequent GRCs; and

· Similar revenue allocation issues were addressed in D.09-03-026, concerning PG&E's SmartMeter Upgrade proceeding (A.07-12-009).

PG&E estimates the revenue requirement in this proceeding will total $32.1 million for the years 2008-2010.⁴⁵ With the adjustments made in this decision, the revenue requirement authorized in this proceeding will be less than that amount. To put these amounts in context, D.07-09-004 reflected a settlement revenue allocation of $11,023.6 million, with $10,753.1 allocated to bundled customers and $270.5 million allocated to DA customers. The amounts authorized and allocated by today's decision are therefore relatively small, 0.27% when compared to those total 2007 revenues. The use of different allocation percentages will have as small, or even smaller, effect on what is allocated to the different customer classes for 2010, which is the only revenue allocation being considered in this proceeding.

Also, these costs for 2011 and beyond will be authorized in subsequent GRCs and will be allocated in that context. Cost responsibilities for customer classes will be evaluated on a more complete basis than what is being considered in this proceeding. CSOL and CC&B upgrade costs while necessary in the context of implementing PDP rates will be viewed in a more complete context of how the upgraded systems and new functions relate to the different classes of customers over time. Also, whether and to what extent certain customers should be exempted from certain costs will be evaluated when examining all costs to be allocated.

In PG&E's SmartMeter Upgrade proceeding, A.07-12-009, DRA recommended that distribution infrastructure and related operations and maintenance (O&M) costs be allocated by a generation allocator, because Upgrade costs were primarily justified on demand response and energy conservation benefits. Also, in that proceeding, the California City-County Street Light Association (CAL-SLA) argued that since SmartMeters are not necessary for street lights and will not be installed on street lights, street light customers should not pay for SmartMeters.

In D.09-03-026, concerning the SmartMeter Upgrade, the Commission stated:

At this point, we will continue the use of the allocation methodology that applies to PG&E's original AMI authorization. In general, it is reasonable to allocate distribution infrastructure with distribution level EPMC related allocators, and PG&E's methodology is consistent with how SDG&E's AMI related costs are allocated. We will not preclude DRA, or any other party, from raising the issue in PG&E's next Phase 2 GRC proceeding. In fact, that would be a more appropriate forum for proposing such an allocation methodology that is based on principles which differ significantly from existing principles. (D.09-03-026, at 157-158.)

There were a number of settlements in Phase 2 of PG&E's 2007 GRC, which addressed marginal costs, revenue allocation and rate design. In the particular settlement on marginal costs and revenue allocation, (footnote omitted) Section VII.3 addresses rate changes between GRCs. The Upgrade will result in a rate change between GRCs, so it is appropriate that the Section VII.3 principles in the marginal cost and revenue allocation settlement should be followed in determining the allocation of Upgrade costs to the various customer classes. PG&E should allocate the Upgrade revenue increases accordingly.

CAL-SLA indicates that its primary recommendation does not comport with the Phase 2 GRC settlement but adds that SmartMeters were never identified in that proceeding as a cost to be allocated to street lights.

We do not know what was assumed by the settling parties, including CAL-SLA, when the marginal cost and revenue allocation settlement agreement was reached. Settlements generally represent a compromise among the Settling Parties' respective litigation positions, in order to agree on a mutually acceptable outcome. What may not seem to be fair, when viewing a portion of the settlement in isolation, may be fair, when viewing the settlement in its entirety. We can only judge issues such as this by the plain language of the settlement. Authorization of the Upgrade necessitates a rate change between GRCs. The settlement provides principles for rate changes between GRCs. There is nothing in that section of the settlement that limits the application of those principles, if the increase is driven by SmartMeter costs or any other specific costs. There is nothing that states that certain customers can avoid an increase, if the reason for that increase does not directly benefit those customers. In order to honor the settlement process, we have no alternative but to impose the principles for rate changes between GRCs, as identified in PG&E's TY 2007 Phase 2 marginal cost and revenue allocation settlement, in allocating the Upgrade related revenues to customer classes. In doing so, street light customers will receive an allocation of Upgrade costs, although that allocation will be substantially lower than what was originally proposed by PG&E.

By our determination today, we are not precluding CAL-SLA or any other party from raising the issue of how SmartMeter costs should be allocated in PG&E's next Phase 2 GRC proceeding. We expect such an issue would necessitate a fairly comprehensive analysis of what types of costs, beyond just SmartMeter costs, directly benefit or do not directly benefit the various customer classes and which of those costs should be assigned to particular customer classes. (D.09-03-026 at 160-161.)

As indicated previously, the revenue requirement increase for 2010 due to the implementation of the PDP program is relatively small. The effects of using different allocation factors or exempting certain classes from certain cost responsibilities are also small. At this point, we see no reason to deviate from the principles adopted in D.09-03-026. We will continue to allocate distribution-related capital costs and related O&M costs by distribution level EPMC-related allocators. The rate change for 2010 will apply to all distribution customers, including DA customers. We believe this is consistent with (1) how distribution costs are generally allocated, and (2) the marginal cost and revenue allocation settlement agreement adopted in D.07-09-004, with respect to rate changes between GRCs.

Parties can recommend different revenue allocation methodologies in PG&E's 2011 GRC Phase 2 proceeding, when the allocation of all costs are considered. It is a more appropriate proceeding for considering new or different revenue methodologies and for evaluating the need to exempt certain customer classes from specific cost responsibilities. Whether parties settle or the Commission decides, a more proper balance of parties' interests and a fairer outcome can be achieved when taking all of this into consideration with all other issues and factors in that GRC Phase 2 proceeding.

⁴⁴ The settlement is included as Appendix B to D.07-09-004. There were 21 signatories to that settlement, including PG&E, DRA, DACC, CLECA, and TURN.

⁴⁵ Exhibit 5, Errata 03/13/09 (PG&E-3) at 10-2.