Now that we have clarified our authority to identify an NSC rate based on avoided costs under PURPA, we turn to the various proposals offered by the parties.
AB 920 requires the Commission, when implementing the net surplus compensation rate, to consider whether the rate should include both the value of the electricity and the value of the renewable attributes of the electricity. The five utility proposals are similar in that each utility recommends a net surplus compensation rate that reflects a value of electricity based on the costs avoided by the utility for purchases of electricity. Most of the utilities then suggest an adder for the value of the renewable attributes of the power produced by eligible NEM customer-generators, i.e., generators using either a solar or wind turbine electric generating facility, or a hybrid system of both. (Section 2827(b)(4).) The actual basis for the electricity and renewable attribute values varies by utility. All five utilities generally argue that other ratepayers will be unaffected by an NSC rate as long as it is set equivalent to the costs the utility avoids by not generating energy itself.
The other, non-utility parties generally propose higher NSC rates, arguing that net surplus generation should be compared to the price of other renewable power sources. We describe the various proposals in greater detail below.
4.1. PG&E's Proposal
PG&E asserts that the NSC rate should be set equal to the cost the utility avoids by purchasing one less kilowatt hour (kWh) of energy from the California Independent System Operator (CAISO). Therefore, PG&E's proposed NSC rate is based on a simple average of hourly day-ahead locational marginal prices of electricity at the utility's default load aggregation point (DLAP). This simple average would be based on DLAP prices between the hours of 7 a.m. and 5 p.m., or the hours of daylight when NEM customers generally produce power, over the 12-month true-up period. PG&E calculates that for December 2009, this average DLAP price was 5 cents/kWh and that from April to December 2009, the average DLAP price was 3.9 cents/kWh. (PG&E, 3/15/10, Attachment B at 4; PG&E, 6/21/10, Appendix A at 3.) PG&E states that use of an established, fully accessible price as the basis for NSC would reduce utility implementation costs.
To compensate for renewable attributes, PG&E would then add to the DLAP price the average renewable energy credit (REC) price over a 12-month period representing the cost PG&E avoids by purchasing the same amount of renewable kWhs. Because RECs are not yet traded and there is no public REC price available, PG&E proposes that in the interim until REC market prices are publicly available, the net surplus compensation for all payments in a calendar year should be based on PG&E's system average generation rate in effect on January 1 of that year. PG&E states that although this is an embedded, or average cost, as opposed to an avoided cost, it includes both the value of electricity and the value of renewable attributes. Currently for 2010, PG&E's system average generation rate is 8.1 cents/kWh. (PG&E, 3/15/10 at 5.)
4.2. SCE's Proposal
SCE contends that because the Commission must identify a just and reasonable rate that does not shift costs between customer-generators and other customers, the net surplus compensation rate should be based on a market metric. ( SCE Testimony, 3/15/10 at 3.) SCE proposes to use a cost figure derived from the Market Redesign and Technology Upgrade (MRTU) Integrated Forward Market (IFM) as a reasonable proxy for a transparent market price for electricity that SCE would otherwise pay to procure electricity. Specifically, SCE would base its rate on the average of hourly MRTU-IFM South of Path 15 Generation Hub prices over a year, weighted using SCE's 2009 load profile for residential customers. (SCE, 6/21/10, Attachment A at A-1.) For the period May 2009 to April 2010, this price is 3.793 cents/kWh. (Id. at A-2.) SCE would then add to this a value for renewable attributes based on renewable premiums from voluntary green energy programs in the Western Electricity Coordinating Council (WECC), as published periodically by the United States Department of Energy (DOE). SCE states that the average premium reported for the WECC is 1.83 cents/kWh (Id.).14
SCE proposes that the ultimate NSC a customer would receive would be based on "discounting" any bill credit remaining at the conclusion of the relevant period. Under SCE's proposal, a customer must have a bill credit to receive NSC. SCE would use the bill credit to calculate a "payout percentage" by adding together a class weighted average MRTU price for the applicable period and the average premium for renewable energy in the WECC, and dividing that sum by the average retail price for the individual NEM customer's rate group. A customer's NEM bill credit remaining at the end of the period would be multiplied by the payout percentage to determine net surplus compensation to the customer. SCE would calculate the net surplus compensation payout percentage monthly for each rate group. (See Exh. SCE-1, 3/15/10 at 8.)
According to SCE, use of a market-based NSC rate such as the one it proposes ensures that non-participating customers are not impacted because the payment for net surplus reflects what SCE would otherwise pay in the market. In addition, SCE contends that its proposal minimizes the administrative costs of the NSC program, and therefore has a minimal effect on non-participating customers.
4.3. SDG&E's Proposal
SDG&E proposes a net surplus rate based on the 12-month rolling average of short run avoided cost (SRAC) energy rates paid to QFs. The rolling average would correspond to the NEM customer's 12-month true-up period. According to SDG&E, over the last five years, the 12-month rolling average for the non-time-of-use SRAC energy rate has ranged from 4.5 cents/kWh to 9.3 cents/kWh. (SDG&E, Davidson Testimony, 6/18/10 at LCD-6.)
SDG&E's proposal includes a method to account for the time of delivery of the net surplus. For commercial and industrial NEM customers with time-of-use (TOU) metering, surplus kWhs would be aggregated by the TOU period and paid based on the SRAC energy rate for each period. For all other NEM customers, NSC would be calculated using the non-TOU SRAC rate, adjusted for time of delivery using a representative profile of excess generation derived from SDG&E load research data from residential NEM customers. (SDG&E, 7/23/10 at 5.) SDG&E proposes an annual update of this adjustment factor based on changes to both the SRAC TOU factors and the representative load profile. According to SDG&E, since the NEM program is a tariff with no long-term commitment from the customer, payments for excess generation should be at SRAC.
In addition, SDG&E would compensate for renewable attributes by adding the Market Price Referent (MPR) greenhouse gas (GHG) adder, or 0.8 cents/kWh, to the net surplus compensation rate until a REC market in California can be relied upon to provide public information on a competitive REC price. (SDG&E, Davidson Testimony, 6/18/10 at LCD-11.) According to SDG&E, its NSC rate is transparent, has low administrative costs, complies with AB 920's mandate to not shift costs to bundled ratepayers, and meets FERC's avoided cost requirements.
4.4. PacifiCorp's Proposal
PacifiCorp proposes an NSC rate based on the QF avoided cost rates approved in its Oregon service territory, which are currently set at $.0512 per kWh for on-peak power and $.0395 per kWh for off-peak power. (PacifiCorp, 6/21/10 at 3.) A weighted average of these two rates based on the typical annual split of on-peak and off-peak hours results in a rate of $.0462 per kWh. (Id.) PacifiCorp also proposes an adder for environmental attributes and transmission and distribution system benefits of $.01 per kWh. According to PacifiCorp, only 34 customers take NEM service in its California territory and none of these customers has ever had net surplus generation at the end of the 12-month cycle.
4.5. Sierra Pacific's Proposal
Sierra Pacific has 20 NEM customers and only two had a net surplus in 2009. Given this low NEM participation, Sierra maintains that its circumstances warrant the use of a simplified approach. Sierra Pacific proposes to use the generation component for baseline quantities from its otherwise applicable retail rates as a proxy for the avoided cost of energy. According to Sierra Pacific, this generation component is currently equal to $.05745 per kWh. (Sierra Pacific, 6/21/10 at 3.) Sierra Pacific does not propose paying for renewable attributes of the electricity because customer generators are not currently eligible for the Renewables Portfolio Standard (RPS) program and most NEM customer generation is not tracked by the Western Renewable Energy Generation Information System (WREGIS). Sierra Pacific contends that absent revisions to the CEC's RPS Eligibility Guidebook, generation from NEM customers has no RPS value and it would be inappropriate to include a renewable adder in the NSC rate.
4.6. Responses to Utility Proposals
In response to the utility NSC proposals, most parties agree that the Commission should adopt a consistent methodology to set the NSC rate for all the utilities, but actual rates may vary by utility based on utility-specific cost data. Parties also generally agree that the Commission should minimize the administrative costs of implementing the NSC rate to avoid burdening non-participating customers.
Only two parties support a utility NSC rate proposal. CARE supports SDG&E's proposal to use SRAC energy rates as the basis for NSC, as well as PacifiCorp's proposal to compensate based on Oregon QF avoided costs prices. Wal-Mart supports SDG&E's proposal to use Commission-approved SRAC rates as the basis for NSC.
The remainder of the parties generally opposes the utility NSC proposals. According to the Joint Solar Parties, CALSEIA/EC, City of San Diego, and Acton, the utilities' proposals to use either short-term wholesale market prices, SRAC rates, or average generation rates do not reflect the costs the utilities would incur to procure a similar quantity of renewable generation to meet RPS requirements. CALSEIA/EC maintain that NSC payments based on average energy rates do not reflect that most NEM solar systems provide excess generation during peak periods of electricity demand. Thus, these parties contend that the utilities' proposals substantially under compensate customer generators for the value of on-peak, RPS eligible energy and fail to encourage surplus generation as envisioned in AB 920. Further, the Joint Solar Parties claim the utilities' proposals do not include any compensation for avoided capacity costs.
4.7. Joint Solar Parties
The Joint Solar Parties agree with the utilities in concept that the NSC rate should be based on avoided costs. In their view, however, the proper avoided cost should be the Commission-adopted MPR, which is the all-in cost of a new 500 MW central station combined-cycle plant built in California, and includes costs to mitigate the plant's GHG emissions. They contend that the MPR is the correct avoided cost to use since it represents the "brown power" resource that the utility avoids constructing by instead purchasing and receiving RPS credit for net surplus generation. The Joint Solar Parties assert that because utilities will get RPS credit for net surplus purchases, they will avoid the long term costs of purchasing renewable generation under the RPS program and the value of renewable attributes is captured by the GHG mitigation costs incorporated into the MPR. In the future, however, they suggest a market-based REC price could be substituted for this GHG adder.
The Joint Solar Parties propose adjusting MPR to reflect the time of delivery (TOD) of solar generation, plus an adjustment for avoided line losses and avoided transmission and distribution (T&D) costs. According to the Joint Solar Parties, surplus power from NEM customer-generators typically serves nearby loads and reduces the loadings of both the local distribution feeder and the higher-voltage transmission and distribution grid, thus avoiding line losses. Plus, they assert that collectively, surplus generation from a large number of NEM customers can avoid the need for additional T&D capacity.
Specifically, the Joint Solar Parties propose the following adjustments to the MPR to set a NSC rate:
NSC = MPR x TOD factor + avoided line losses + avoided T&D
The Joint Solar Parties' TOD factor is calculated by applying a representative hourly solar output profile to the TOD factors used in each utility's most recent RPS solicitation. Joint Solar Parties explain that this TOD factor implicitly assumes that net surplus generation has the same distribution as the typical solar output profile, and is a reasonable simplifying assumption. They recommend a single solar production profile for each utility. Avoided line losses and avoided T&D would be based on the Commission's most recently adopted avoided cost model for energy efficiency (the "E3 avoided cost model").15
Joint Solar Parties recommend that the MPR rate that should apply for an individual NEM customer-generator is the 20-year contract rate beginning in the year that the NEM customer begins operation, and the rate would be fixed for the life of the NEM system. The Joint Solar Parties assert this would provide the customer certainty and would provide ratepayers a hedge against future increases in the price of fossil fuels. Existing NEM generators who went into operation prior to the MPR taking effect in December 2009, would receive a rate based on the 2008 MPR for a 20 year contract starting in 2009. The Joint Solar Parties propose the NSC rate could be updated by advice letter each time the Commission revises the MPR.
The Joint Solar Parties provide estimates for their proposed NSC, which vary depending on the utility. For a project that begins operation in 2009 or earlier, rates would begin with the 2008 MPR of 11.1 cents/kWh, and then be adjusted by TOD factors, avoided line losses, and avoided T&D costs using values distinct for each utility. Projects that begin in 2010 would be based on the 2009 MPR of 9.67 cents/kWh, also adjusted for TOD factors, and avoided line losses and T&D costs. Given all these adjustments, the Joint Solar Parties proposed rates are as follows:
Joint Solar Parties' Proposed NSC Rates in cents/kWh16
NSC Rate for Projects that begin in 2009 or earlier
NSC Rate for Projects that begin In 2010
The Joint Solar Parties contend their proposed NSC is reasonable and will leave ratepayers unaffected because it reflects costs the utility will avoid through purchase of this generation. They maintain that an NSC rate based on MPR is appropriate because it includes payment for the value of capacity similar to the Commission's finding in D.82-01-103 that avoided cost rates should consider the value of energy and capacity from QFs. According to the Joint Solar Parties, the Commission already uses MPR to price surplus output from small renewable generators up to 1.5 MW pursuant to AB 1969,17 which is a program analogous to NSC. They contend that even if RPS legislation ends the use of the MPR for the RPS program, the Commission can maintain the MPR as an important pricing benchmark.
The utilities and TURN oppose the Joint Solar Parties' proposal to base NSC on the MPR. Acton supports use of the MPR, with suggested modifications. The details of the opposition to MPR are discussed below in Section 5.
CALSEIA/EC assert that the NSC rate should be based on the full value of peak-generated renewable electricity because it is essential to give NEM customers an adequate incentive to reduce their electricity consumption and avoid sending power to the grid without compensation. They claim that under the current NEM program, homeowners with solar installations have an incentive to waste electricity rather than give it away for free to their utility company. Therefore, they suggest the NSC be set at either of the following: 1) the full retail electric rate, or 2) the feed-in tariff rate for solar power systems that the Commission will determine when it implements Senate Bill (SB) 3218 in Rulemaking (R.) 08-08-009. CALSEIA/EC argue that when the Commission sets a feed-in tariff rate in R.08-08-009, that rate should include social and environmental benefits of solar as well as the electricity value.
CALSEIA/EC recommend that to calculate the NSC rate, the Commission should rely on a study they commissioned as part of the SB 32 feed-in tariff proceeding, which recommends a rate based on the MPR plus environmental and health benefits, time of delivery factors, avoided T&D and line losses, grid reliability, and REC values. They assert that the market value of a REC does not by itself represent the total value of renewable attributes. Therefore, they contend the Commission should consider environmental adders on top of the value of the REC in the NSC rate. Moreover, they suggest the NSC rate should be fixed for a ten-year period beginning with the date of online generation. CALSEIA/EC contend other ratepayers will be unaffected by their NSC rate proposal because few customers will be eligible for NSC. Thus, there will be minimal program cost to non-participants.
The CALSEIA/EC proposal is opposed by PG&E, PacifiCorp, TURN, and Acton, as discussed more fully in Section 5.1 below.
DRA proposes an interim rate to take effect on January 1, 2011, based on the most current MPR, adjusted based on time of delivery of the net surplus. SDG&E opposes DRA's interim MPR proposal, claiming it is not a proper avoided cost measure. Several parties oppose DRA's interim rate proposal, stating the Commission should simply adopt a final and permanent NSC rate at this time.
For a permanent NSC rate, DRA proposes the Commission set the NSC based on the DG avoided cost methodology recently adopted in D.09-08-026 and used in the NEM cost-effectiveness evaluation performed in accordance with that decision. DRA notes that DG avoided costs have not been subject to public input, so additional public input is needed before they could be used to set NSC rates. Furthermore, DRA suggests that the NSC be adjusted for each customer's net generation profile. DRA contends this would require only simple arithmetic calculations involving TOU data for each customer which DRA asserts should be readily available in the utility billing system. Several parties oppose this proposal, stating it would be too difficult and costly to implement.
4.10. City of San Diego
The City of San Diego is a large customer of SDG&E with an active Distributed Energy Resources Program involving over 18 MW of generating capacity. The City contends that ideally the NSC rate should be set at the utility's marginal cost for renewable generation. However, since this price is not publicly available, a reasonable proxy is the cost of utility-owned renewable energy facilities, such as the all-in average cost of power from the utilities' own photovoltaic (PV) generating facilities. The City of San Diego estimates this rate is 20 to 25 cents per kWh. In the alternative, the City proposes the NSC be set equal to the utility's full retail electric rate.
The City of San Diego asserts this is reasonable because most generation from NEM customers comes from PV, and although this power is intermittent, the Commission has previously paid QFs for capacity. It maintains that a large collection of NEM customers can provide a quantity of energy that is as predictable as power provided by utility-owned solar projects. The City of San Diego asserts its proposed NSC rate leaves other ratepayers unaffected since it displaces purchases of renewable power at the utilities' marginal cost.
The utilities and TURN oppose the City of San Diego's proposal.
According to Acton, the NSC should be based on the renewable energy prices defined in executed RPS contracts approved by the Commission. Specifically, the NSC rate should reflect RPS contract rates during the same true-up interval because the surplus generation is new renewable energy that the utilities can count toward their RPS goals, and it avoids purchases of renewable energy. Using RPS contract values will leave other ratepayers unaffected as they will pay the same for all renewable power. Customer generators should be paid for the actual value of their surplus energy and the best measure of this is actual contract prices, not short-term market prices as the utilities propose. Furthermore, Acton proposes that the NSC should be based on the time of delivery, i.e. the time the excess power is placed on the distribution network, relying on existing rate data.
IREC does not offer a specific rate proposal, but urges a single methodology where the precise rate can vary across utilities. IREC contends that solar installations by NEM customers are fixed additions to the grid that will provide energy over multiple decades, as recognized in the Commission's long-term procurement proceedings. Therefore, IREC supports the Joint Solar Parties' proposal to value excess energy at a long-run avoided cost using the MPR. Moreover, IREC asserts that to value surplus generation from NEM customer-generators at a short-run avoided cost price while valuing wholesale DG at a long-run MPR price creates an unexplained disconnect in the valuation of these similar resources.
4.13. Solutions for Utilities
Solutions for Utilities supports an NSC rate based on a utility's retail electric rate, which it further maintains should be the Tier 3 summer rate because the utility company will avoid transmission and distribution expenses and it will essentially sell the excess power to adjacent property owners at tiered rates. Solutions for Utilities contends its proposal will incentivize surplus generation.
PG&E and SDG&E oppose this proposal, claiming that payment based on Tier 3 summer rates would be in excess of utility avoided costs.
CARE does not provide its own NSC rate proposal, but it supports the proposals by SDG&E and PacifiCorp. In addition, CARE contends that any excess energy produced is FERC jurisdictional, and since TOU meters can take readings in ten second intervals, the applicable NEM true-up period should be a ten second interval. It is unclear from CARE's comments how the Commission would implement a ten second true-up period given the existing NEM program with an annual true-up.19
14 According to SCE, this figure is based on the average of 88 data points from utilities within the WECC. (SCE, 3/15/10, Exhibit SCE-1 at 4.)
15 The "E3 avoided cost model" is named after Energy and Environmental Economics, the consultants that developed it, and was adopted in D.05-04-024, updated in D.06-06-063, and is described in D.09-08-026.
16 Joint Solar Parties, 6/21/10, Tables 1 and 2 at 3-4.
17 Stats 2006, Ch. 731.
18 Stats. 2009, Ch. 328.
19 It was difficult to discern CARE's positions from its comments and in general, its comments provided little assistance in reaching the conclusions in this decision.