Section § 399.20 contains a number of mandatory and discretionary considerations that apply to any pricing methodology adopted by the Commission for the FiT Program. The pricing methodology must also be consistent with federal law on avoided costs for wholesale transactions under PURPA. Today's decision adopts a pricing methodology that relies upon renewable market power pricing information from the RAM adopted in D.10-12-048 and takes components from a number of different pricing proposals presented by parties, including IREC, SunEdison, Silverado Power, Vote Solar Initiative, SCE and Staff. Importantly, we adopt an adjustment mechanism to increase or decrease the FiT price for a particular product type based on market conditions. The pricing methodology we adopt today, Re-MAT, complies with both state and federal law.
6.1. Compliance with Federal Law
In prior decisions, we found that the FiT price was constrained by the statutory cross-reference to § 399.15 within the FiT statute, § 399.20. We further found that, based on this cross-reference to § 399.15, pricing for FiT was limited to the MPR. Today, based on the removal of this cross-reference, we have greater latitude to consider other pricing options under state law.47 As discussed above, FERC's recent interpretations in response to a petition for declaratory order also support consideration of additional pricing options, as long as the facilities are QFs and the pricing options are an avoided cost. Therefore, it is reasonable for us to shift the price away from the MPR to the renewable power market. We further find that a FiT price that reflects the renewable market ultimately more fully reflects avoided costs under federal law. Therefore, relying on the existing RAM Program to establish the baseline for pricing is a reasonable starting point to determine avoided cost for the § 399.20 FiT Program.
Because the § 399.20 FiT Program seeks to implement a directive from the Legislature to procure energy from specific sources, renewable generation of 3 MW and less, and to consider the value of different electricity products, including baseload, peaking, and as-available electricity, we find using RAM contracts to set the § 399.20 FiT Program starting price, which includes these product types, is the most reasonable alternative to determining the cost of the resources being avoided.
Our finding is based on the fact that the market segment represented by RAM more closely represents the market segment covered by § 399.20 than other pricing proposals, including pricing proposals relying on the MPR. The discussion above at Section 5 fully addresses this matter.
The market segments covered by RAM and § 399.20, however, are not the same. RAM covers renewable projects sized up to 20 MW. The § 399.20 FiT Program covers renewable projects sized up to 3 MW. Other renewable procurement programs include the RPS Annual Solicitation and bilateral contracting process, which generally result in contracts greater than 20 MW and as large as 1,000 MW, with an average size of about 100 MW. Nevertheless, while not identical, the RAM Program presents the closest comparison and, as such, we find it reasonable to define Re-MAT, which includes the market adjustment mechanism, as an avoided cost, as required under federal law.
6.2. Compliance with State Law
In terms of compliance with state law, we find that our proposal meets the requirements of § 399.20. The Legislature provided specific information that we must consider in setting the § 399.20 FiT Program price but left the Commission with the discretion on how to factor these considerations into any pricing methodology that we ultimately adopt.
Section 399.20(d)(1) provides that the tariff price shall be, among other things, the market price determined by the Commission. Today, the Commission adopts a market price by relying on contracts approved from a specific renewable auction market, specifically the RAM auction set forth in D.10-12-048. In addition, the Re-MAT's adjustment mechanism seeks to account for any differences in pricing from the RAM Program and the § 399.20 FiT Program by increasing or decreasing the price if the initial price is too low or too high. The pricing methodology is also guided by other provisions of § 399.20 that are discussed elsewhere in this decision. These provisions include, for example, that the generation be "strategically located," that the tariff be offered on a "first-come-first-served basis," and that "ratepayers that do not receive service pursuant to the tariff are indifferent to whether a ratepayer with an electrical generation facility receives service pursuant to the tariff."
Specifically, the Re-MAT is in compliance with the following provisions of § 399.20:
Section 399.20(d)(2)(A) provides that the Commission shall establish a price in consideration of long-term market price for fixed price contracts pursuant to an electrical corporation's general procurement activities. The Commission has considered long-term market price for fixed price contracts pursuant to an electrical corporation's general procurement activities because today's adopted methodology, Re-MAT, relies upon RAM contracts as set forth in D.10-12-048, which are part of each electrical corporation's general procurement.
Section 399.20(d)(2)(B) provides that the Commission shall establish a price in consideration of long term ownership, operating and fixed-price fuel costs. The Commission has considered long term ownership, operating and fixed-price fuel costs because Re-MAT relies upon RAM contract prices as set forth in D.10-12-048 which includes such costs.
Section 399.20(d)(2)(C) provides that the Commission shall establish a price in consideration of the value of electricity products, e.g., baseload, peaking, and as-available. The Commission has considered the value of different electricity products because Re-MAT's adopted market-based methodology includes pricing for three product types.
Section 399.20(d)(1) provides that the tariff shall provide for payment of every kilowatt hour of electricity purchased. The Commission has adopted a mechanism that establishes a kWh price and, therefore, is in compliance with this provision.
Section 399.20(d)(1) provides that the tariff shall provide for payment for a period of 10, 15, or 20 years. The adopted price methodology permits contracts of any of these terms.
Section 399.20(d)(1) provides that the tariff shall provide for payment of, among other things, all current and anticipated environmental compliance costs, including, but not limited to, mitigation of emissions of greenhouse gases and air pollution offsets associated with the operation of new generating facilities in the local air pollution control or air quality management district where the electric generation facility is located. Re-MAT theoretically includes, as embedded within the starting price, general costs associated with producing renewable energy. We seek to pay generators the price needed to build and operate a renewable generation facility. We do not find, however, that specific costs, such as compliance costs in a particular air quality management district, are necessarily captured by the RAM methodology. More analysis is needed. We further discuss our proposal for compliance with § 399.20(d)(1) in a separate section.
A more specific discussion of the components of Re-MAT follows.
6.3. Three Product Types and Re-MAT Starting Price
The existing FiT Program based on the MPR does not distinguish among different product types and only offers one price. Section 399.20(d)(2)(C) directs the Commission to consider, and today's decision adopts, a price for each of the following three product types: baseload, peaking as-available, and non-peaking as-available. Our decision reflects an effort to better capture the value provided by different technology types. Baseload projects provide firm energy deliveries (e.g., bioenergy and geothermal); peaking projects provide non-firm energy deliveries during peak hours (e.g., solar); and non-peaking as-available projects provide non-firm energy deliveries during non-peak hours (e.g., wind and hydro).
For each of the three FiT product types, we adopt a Re-MAT starting price for the § 399.20 FiT Program based on the weighted average of PG&E's, SCE's, and SDG&E's highest executed contract resulting from the RAM auction held in November 2011. While a unique starting price for each product type was considered as an option, we opted otherwise because the November 2011 RAM contract prices contained insufficient market information for the three product types to render this option viable.48 As a result, we adopt PG&E's recommendation articulated in its November 2011 comments to use a weighted average of the highest executed RAM contract from each investor owned utility (IOU) to establish a single, statewide FiT starting price for each of the three product types. This is a reasonable starting price for the FiT because it is set by the most recent comparable competitive solicitation for renewable distributed generation.
In addition, we find it prudent to adjust this starting price by time-of-delivery factors based on the generator's actual energy delivery profile, since this captures the value of each generator to the utility. Lastly, we find that the price adjustment mechanism, described below, adequately functions to capture the different costs associated with the small renewable distributed generation market segment compared to the RAM market segment.
Based on the results from the November 2011 RAM auction, we anticipate that the starting price for each separate product type will be $89.23/MWh (pre-time-of-delivery adjustment). 49 PG&E, SCE, and SDG&E shall incorporate this starting price, the price adjustment mechanism, and incremental capacity releases, as discussed below, into their tariffs and standard contracts, as appropriate, for the § 399.20 FiT Program.
6.4. Re-MAT Price Adjustment Mechanism For Each Product Type
We also adopt a price adjustment mechanism for the three product types, i.e., baseload, peaking as-available, and non-peaking as-available. A proposal for triggering a price adjustment was included as part of SCE's August 5, 2011 comments,50 and we adopt SCE's proposal, in part. Under the adopted price adjustment mechanism, the price for a utility's product type may increase or decrease every two months provided certain conditions exist. Each utility will make the FiT prices publicly available on its website by the first business day of the month in which the price adjustment occurs.
A price adjustment mechanism will enable the FiT price to quickly respond to market conditions. It is also designed to prevent gaming by only increasing or decreasing provided that a defined level of market interest exists for a product type. 51
As part of today's decision, interested generators that meet the program's minimum project viability criteria (Section 10) must submit a program participation request form to the utility. Once the participation request form is deemed complete, the utility will establish a queue on a first-come-first-served basis for each product type. Every two months, the utility will offer generators a FiT contract at that two-month Re-MAT price in order of the Re-MAT queue. A generator can accept or reject the price. If a generator accepts the price, it enters into a FiT contract. The price is fixed for the term of contract. If the generator declines a contract at that price, it maintains its position in the queue until the next two-month period.
The price adjustment will be triggered only after least five eligible projects by different developers are in the queue. If there are less than five projects by different developers for any two-month offering, then the Re-MAT price remains the same for the next two-months. If at least five eligible projects by different developers are in the queue, the price may increase or decrease based on whether projects accept the Re-MAT price and a certain subscription level is met. If no developer enters into a FiT contract at the two-month price, then a price increase will be triggered for the following two-month period. Or, if the threshold of five eligible projects with different sponsors is achieved and the all available capacity is subscribed for in a product type, a price decrease is triggered for the following two-month period.
The manner in which the mechanism will function to increase or decrease the price is described below.
6.4.1. Increased Price - Illustrated
As stated above, if there are five projects with different developers in the queue for a particular project type and if certain conditions exist, the Re-MAT price will adjust in the subsequent two-month period. The condition for a price increase is either (1) if no projects subscribe or (2) if program subscription for a two-month period is less than 50% of the initial starting capacity for that project type. There must also be at least five eligible projects from different sponsors in a utility's queue for a product type. The price will increase for each consecutive two-month period until there is subscription capacity equal to 50% or more of the initial starting capacity for that product type. At that point, the price remains the same until the criteria for a price decrease are met. The following serves to illustrate how this mechanism works to increase the price:
· Months 1-2: Starting Price ($89.23/MWh). If no subscriptions result or less than 50%, then the price increases as follows:
· Months 3-4: Starting Price + $4.00/MWh (total $4.00/MWh increase over prior period) and, if no subscription results or less than 50%, the price increases as follows:
· Months 5-6: Starting Price+ $12.00 (total of $8.00 increase over prior period) and, if no subscription results or less than 50%, the price increases as follows:
· Months 7-8: Starting Price + $24.00 (total of $12.00 increase over prior period) and, if no subscription results or less than 50%, the price increases as follows:
· Months 9-10: Starting Price + $40.00 (total of $16.00 increase over prior period) and, if no subscription results or less than 50%, the price increases as follows:
· Months 11-12: Starting Price + $60.00 (total of $20.00 increase over prior period).
Any program capacity not subscribed in a two-month period will be distributed as described in Section 6.5.
It is our expectation that more expensive technologies such as biogas and forest biomass, may gain the opportunity to participate in the FiT Program by, for example, Months 9-10, after the price has increased by $40/MWh to $129.23, assuming no subscriptions in the product type have occurred before that date and a minimum of five project sponsors exist in the Re-MAT queue. Additional time may be required to reach that price if less expensive technologies subscribe to the product type.
To guard against ratepayer exposure to excessive costs due to market manipulation or market malfunction, PG&E, SCE, and SDG&E shall file a motion to temporarily suspend all part of program when evidence of market manipulation exists. The motion will be acted upon expeditiously. The motion shall identify the portion of the program suspended, the specific behavior and reasons for the suspension, and the utility's proposal for resolving the program. The motion shall be served on the service list of this proceeding or any successor proceeding. The utilities must rely upon this motion in a manner that minimizes disruption of the program. For example, if a utility identifies market manipulation or malfunction in one product type or by one project sponsor, the motion requesting the suspension should be limited accordingly. In this manner, the suspension will balance the need to protect ratepayers from excessive costs without unreasonably hindering the functioning of the program.
6.4.2. Decreased Price - Illustrated
As previously discussed, if there are five projects with different developers in the queue for a particular project type and if certain conditions exist, the Re-MAT price will adjust in the subsequent two-month period. The condition for a price decrease is if subscription in a two-month period equals 100% or more of the initial capacity allocation for that produce type, regardless of the total available capacity for that product type for the two-month period. The price will stay the same if subscription in the two-month period is less than 100% of the initial capacity allocation for that product type. The following serves to illustrate how this mechanism works to decrease the price:
· Months 1-2: Starting Price ($89.23/MWh). If subscription equals 100% or more of the initial capacity allocation for that product type, then the price decreases as follows:
· Months 3-4: Starting Price minus $4.00 (total $4.00 decrease from prior period) and, if subscription equals 100% or more of the initial capacity allocation for that product type , the price decreases as follows:
· Months 5-6: Starting Price minus $12.00 (total of $8.00 decrease from prior period) and, if subscription equals 100% or more of the initial capacity allocation for that product type, the price decreases as follows:
· Months 7-8: Starting Price minus $24.00 (total of $12.00 decrease from prior period) and, if subscription equals 100% or more of the initial capacity allocation for that product type, the price decreases as follows:
· Months 9-10: Starting Price minus $40.00 (total of $16.00 decrease from prior period) and, if subscription equals 100% or more of the initial capacity allocation for that product type, the price decreases as follows:
· Months 11-12: Starting Price minus $60.00 (total of $20.00 decrease from prior period).
6.5. Assignment of Capacity to Three Products Incremental Release of Capacity and Three-MW
Minimum to Start
In addition to allocating the program capacity among the three utilities, as discussed in Section 12.3, we direct utilities to assign an equal portion of this allocated capacity to three product types over 24 months, i.e., baseload, peaking as-available, and non-peaking as-available. Any remaining unsubscribed capacity at the end of a two-month period is reallocated to the end of the 24 months, starting with a new period, Months 25-26. The MW should be spread out among Months 25-26 and further in a manner that reflects the initial allocations across Months 1-24. We adopt this design in an effort to stimulate the market for small renewable distributed generation by providing an adequate supply of available capacity to each product type in response to demand.52
To implement this directive, each utility must divide the total program capacity by 24 and then assign one-third into each product type.
In Months 1-2, we require that each utility allocate a minimum of 3 MW to each product type.53 The same minimum obligation would apply to Months 25-26, if applicable.
Each utility is directed to publicly notice the amount of capacity remaining in each product type on its website by the first business day of each two-month period.
This overall plan to allow IOUs to propose reallocation of capacity over 24 months (or perhaps further) is designed to minimize ratepayer exposure to a large number of non-competitively priced contracts while ensuring that some capacity is available for each product type, for which there is market interest.
6.6. Program Forums and Future Modifications to the Adjustment Mechanism
Since the adjustment mechanism adopted today is a new feature for the FiT Program, the utilities shall convene stakeholders within the first year of the program to solicit market experience with the price adjustment mechanism. Utilities shall also set up an on-line feedback mechanism with, for example, public questions and answers posted on the web. 54 In such a manner, utilities can gain continuous input to improve their programs. The utilities and market participants should address specific elements of the adjustment mechanism, such as the adjustment time period (e.g., two-months versus one-month or four months), the amount of the periodic price increase or decrease, and any other implementation aspect of the adjustment mechanism. To the extent that changes to the adjustment mechanism or other aspects of the program are needed to improve the program, the utilities may file a joint advice letter with the Commission seeking specific changes to the mechanism. Alternatively, Commission Staff may propose modifications to the adjustment mechanism through a draft resolution for consideration by the Commission.
6.7. Environmental Compliance Costs
Section 399.20(d)(1) refers to environmental compliance costs that the Commission must consider in setting a FiT tariff price and provides, in pertinent part, that: "The payment . . . shall include all current and anticipated environmental compliance costs, including, but not limited to, mitigation of emissions of greenhouse gases and air pollution offsets associated with the operation of new generating facilities in the local air pollution control or air quality management district where the electric generation facility is located."55
The costs referred to in this subsection are specifically described as "compliance costs." We view these compliance costs as distinct from general environmental societal values associated with particular forms of generation, including biogas and biomass. In some instances, parties relied on § 399.20(d)(1) to support their position that the Commission adopt an environmental adder or, in some other manner, incorporate into the FiT price a component to reflect specific environmental benefits of different generation technologies. For example, parties representing the biogas industry, including CEERT, AECA, Sustainable Conservation and others discussed the value of the reduction in emission of methane. Similarly, parties, including Placer County and others, representing the forest biomass industry explained the value of reduced air emissions from wildfires, mitigated fire suppression costs, and public safety benefits.
We support these renewable generation industries and their potential to contribute to the reduction of greenhouse gas emissions and improve air quality. In addition, we are impressed with the potential for the forest biomass industry to improve public safety through the reduction of wildfires.
Today, however, our focus is on implementing the legislative mandates of SB 32 and SB 2 1X, which direct us to incorporate into rates, among other factors, environmental compliance costs. The legislation does not address the cost savings related to general environmental benefits or increased public safety.
We make this decision with some reluctance as we understand that a price adder is needed, in some instances, to more closely reflect the costs of certain emerging industries. Furthermore, we have heard from parties that, in the absence of such an adder, the growth of these emerging technologies may be hindered.
However, we expect the price adjustment mechanism to account for varied resource costs within a produce type and will monitor the program to ensure its success. In addition, we continue to be concerned about cost containment, generally, and in light of SB 2 1X have been closely reviewing cost containment in the context of overall renewable procurement in other aspects of this proceeding.
For this reason, at this point in time, we look toward the ratepayer indifference requirement in § 399.20(d)(3) and our goals of cost containment within the RPS Program for guidance on the extent to which the Commission should adopt a general environmental adder and find that, at this time, the ratepayer indifference clause of the statute and the directives on cost containment require us to refrain from general environmental adders even in those instances, such as biogas and forest biomass, where the environment and public safety qualities of the renewable generation technology is promising.
It is our intent, however, to encourage the growth of these technologies through the pricing mechanism we adopt today. The pricing mechanism is designed to respond to the market signals for different product types, including baseload. Biogas and forest biomass, presumably, will successfully bid into baseload in a manner that will further inform this Commission of the pricing requirements of those industries.
Turning now to the specific legislative directive in of § 399.20(d)(1) and an adder to reflect the cost of environmental compliance, a few parties submitted evidence on this topic. We find that specific costs, such as the compliance costs in a particular air quality management district, are not necessarily by the RAM pricing methodology. We remain open to adopting specific adders, such as those discussed by the County Sanitation District of Los Angeles County, to reflect compliance costs.56
Similar data was presented by FuelCell Energy.57 Other parties claim they submitted relevant data but we found much of this data to reflect general environmental costs and not, as specified by the statute, the cost of environmental compliance.
We are mindful of the importance of quantifying this cost and find it essential for the Commission's compliance with the statute. More analysis and data is required, however, to complete this task. We will prioritize this issue in this proceeding and will resolve this matter. Today, however, we find that insufficient evidence exists in the record to adopt and implement an adder reflecting the cost of environmental compliance under § 399.20(d)(1).
6.8. Resource Adequacy
Section 399.20(i) states "the physical generating capacity of an electric generation facility shall count toward the electrical corporation's resource adequacy requirement for purposes of Section 380."58 Parties presented a range of proposals on how to implement this provision.
The utilities stated that to count a generator for resource adequacy, the CAISO must deem the generator deliverable but, for this to occur, the CAISO must complete a deliverability study, which takes almost two years to complete and could result in costly system upgrades.59 Notably, at this time, generators interconnecting through the presently effective Tariff Rule 21 do not have the option to apply for a deliverability study.60
Based on the view that a deliverability study is overly burdensome from a time and cost perspective for very small generators, most parties and the Commission's Staff recommended rejecting the utilities' proposal. Specifically, in order to be studied for deliverability, a generator must request deliverability from the CAISO when it seeks interconnection. The CAISO only performs deliverability studies once a year and a generator must apply by March 31 in order to be studied that year. The deliverability study consists of two phases and application fees and deposits to stay in the study process. The total study process can take two years and the study may require costly upgrades to the transmission system in order to make the generator fully deliverable. Because these requirements are burdensome for small generators, on May 16, 2012, the CAISO Board of Governors approved the Resource Adequacy Deliverability for Distributed Generation initiative, which will provide an alternative path to deliverability for distributed generation.61 Those changes will not apply until the 2013-2014 Resource Adequacy year and the success of the revisions will not be known until much later.
In November 2011 comments, PG&E proposed a solution to address, in the near term, the concerns related to requiring a deliverability study but, at the same time, ensure compliance with § 399.20(i). PG&E recommends the Commission establish time-of-delivery factors for generators that do not provide resource adequacy. We find PG&E's proposal reasonable since it allows generators to choose to pursue a deliverability study if they want to receive a higher time-of-delivery adjusted price. It also removes the burden of pursuing deliverability if the costs and timing are too burdensome.
Moreover, since the deliverability study process can occur over a long period of time, generators can convert to full deliverability after their online date and receive the higher time-of-delivery factors at that time. As a result, full commercial deliverability status should not be a condition precedent for any generator seeking a contract under the § 399.20 FiT Program.
Accordingly, PG&E, SCE, and SDG&E shall offer two sets of time-of-delivery factors: one for generators that do not provide resource adequacy and another for generators that do provide resource adequacy. PG&E, SCE, and SDG&E shall add a provision reflecting delivery factors to the FiT Program standard form contract and/or tariff that is being developed in this proceeding in accordance with the schedule set forth in the January 10, 2012 ALJ ruling. The Commission will review this provision submitted by the utilities and, in a separate decision accept, reject, or modify the provision. Related FiT tariff modifications will also be addressed in this separate decision.
6.9. Define "Strategically Located"
Today's decision implements the requirement that generators participating in the § 399.20 FiT Program be "strategically located."
Section 399.20(b) contains four specific criteria that an electric generation facility must meet to sell electricity under the § 399.20 FiT Program. The third criterion is that the generation facility be "strategically located." The concept set forth in this provision is different than the concept in subsection (e) of § 399.20, which describes the value of a project's electricity as potentially influenced by its location on the distribution network.62 In contrast, the specific statutory provision in subsection (b) is a prerequisite to participation in the program and provides as follows: The electric generation facility is "strategically located and interconnected to the electrical transmission and distribution grid in a manner that optimizes the deliverability of electricity generated at the facility to load centers."63
This provision, in its current format, was first incorporated into § 399.20 by SB 380 but existed, in a more limited manner, in the original legislation, AB 1969.64 On August 5, 2011, SCE commented on the meaning of this statutory provision. Specifically, SCE suggested that the generator interconnect at one of the preferred locations as identified on SCE's circuit map posted on its website. The Renewable FiT Staff Proposal offered an alternative to SCE's suggestion. Specifically, the Commission's Staff suggested that generators be interconnected to the distribution system and not exceed the minimum load of the circuit when generating electricity. Both of these recommendations intend to target generators as eligible for the program that do not have impacts on the transmission system.
We find that the statutory language means that a generator must be interconnected to the distribution system, as opposed to the transmission system, and must be sited near load, meaning sited in an area where interconnection of the proposed generation to the distribution system requires $300,000 or less of upgrades to the transmission system.
In making this determination, we rely on our policy guideline to use existing transmission and distribution infrastructure efficiently. We further point out that our policy guideline is grounded in the legislation intent set forth in SB 32 (Sec. 1) which emphasizes the importance of encouraging the location of clean generation close to load centers in order to meet increases in demand for electricity.
To implement our interpretation of subsection (b)(3), we find that if a project's most recent interconnection study shows that the project requires more than $300,000 of transmission system network upgrades, that project is no longer eligible for the § 399.20 FiT Program65 As described in Section 10, below, one project viability criteria is that a project must have completed its system impact study or cluster study phase 1 study (the first of two interconnection studies). Therefore, the generator will have information on whether a project qualifies as "strategically located" before signing a power purchase agreement. We expect generators to use the utilities' Interconnection Maps, available to the public and online, to locate sites that have a low likelihood of transmission impacts. Furthermore, we find that this prerequisite, "strategically located," applies to all generators seeking a contract under the § 399.20 FiT Program.
Accordingly, PG&E, SCE, and SDG&E shall add to the § 399.20 FiT Program standard form contract and/or tariff that is being developed in this proceeding in accordance with the schedule set forth in the January 10, 2012 ALJ ruling the prerequisite that generators must be "strategically located." This means that the generator be (1) interconnected to the distribution system, as opposed to the transmission system, and (2) sited near load, meaning in an area where interconnection of the proposed generation to the distribution system requires $300,000 or less of upgrades to the transmission system. Such a provision shall be presented to the Commission for consideration in accordance with the schedule set forth in the January 10, 2012 ALJ ruling. The Commission will review this provision submitted by the utilities and in a separate decision accept, reject, or modify the provision. Related FiT tariff modifications will also be addressed in this separate decision.
6.10. Ratepayer Indifference
In March 2011 briefs and comments filed in July, August, and November 2011, parties addressed the meaning of the requirement under § 399.20 that "ratepayers that do not receive service pursuant to the tariff are indifferent to whether a ratepayer with an electric generation facility receives service pursuant to the tariff."66 Some parties, including CEERT, stated that ratepayers are indifferent to any avoided cost rate. Other parties found ratepayers to be indifferent to any rate that is value based. These parties include CALSEIA, Agricultural Energy Consumers Association (AECA)/Inland Empire Utilities Agency, and Clean Coalition. Clean Coalition also cited the Commission's application of a customer indifference provision in the implementation of AB 1613.67 Other parties, such as SCE, suggest that a market-based pricing methodology, which adjusts to reflect changes in the market, will ensure ratepayer indifference by establishing a price based on the market, thereby containing costs and ensuring maximum value to the customer and utility.
Notably, in D.10-12-048, we favored market-based pricing as a means of protecting ratepayers, stating that: "Administrative determination of contract prices is less likely to be as responsive to cost changes than is a seller determining the price it wishes to seek in an auction based on its understanding of the underlying project costs, and changes in those costs."68 Similarly, we find today that Re-MAT, a market-based pricing methodology, best ensures ratepayer indifference under § 399.20(d)(3). A market-based approach is in the best interest of California electricity customers. We now know that the state's renewable energy market has matured and prices have decreased.69
The market-based pricing methodology adopted today allows customers to realize the benefits of changing market conditions that result in potentially lower costs. In addition, it allows generators to set the market price through the bidding process, which theoretically will ensure the price is neither too high nor too low but, instead, will be reasonable to cover the generator's costs and encourage broad participation in the market. In contrast, administratively-determined pricing is static and, as a result, can result in pricing being either too high, leading to windfalls for project developers and unnecessarily high procurement costs for customers, or pricing that is too low, preventing program subscription. These scenarios based on an administratively-determined price do not achieve ratepayer indifference to the extent achieved by Re-MAT.
Accordingly, we find that the pricing mechanism adopted today complies with "ratepayer indifference" set forth in § 399.20(d)(3) by reflecting the supply and demand of the renewable generation market.
Re-MAT is consistent with the requirement that electric corporations make FiT tariffs available on a "first-come-first-served basis." The "first-come-first-served" requirement is set forth in § 399.20(f). In accordance with the rules of statutory construction, this provision must be read in manner consistent with all other provisions of the statute. This provision can not be applied to the § 399.20 FiT Program in isolation. For example, it is an untenable reading of that statute that contracts be accepted by electrical corporations on a first-come-first-served basis without regard to price. Price is a key component of the statute and, only after generators enter into contracts under the adopted pricing mechanism and any other statutory prerequisites, would the first-come-first-served provision apply.
On the other hand, this provision functions to restrict the Commission from creating program requirements that interfere with the first-come-first-served requirement as it applies to the program as a whole. For example, as discussed earlier in this decision, in the absence of any specific legislative directive, a Commission requirement that pricing be distinguished based on technology-specific basis would interfere with the application of the statutory provisions requiring first-come-first-served. The statute, however, allows for first-come-first-served on a product specific basis because the statute specifically directs the Commission to consider the value of different electricity products including baseload, peaking as-available, and non-peaking as-available electricity.70
For these reasons, we find that Re-MAT, which includes consideration of product types but not specific technologies, is consistent with the first-come-first-served provision set forth in § 399.20(f).
47 See Section 3.1, above, for a more detailed discussion of the changes to the statutory language in § 399.20 relevant to the cross-reference.
48 The utilities recently filed advice letter seeking Commission approval of the auction results from the first RAM solicitation, PG&E Advice Letter 4020-E (March 20, 2012), SCE Advice Letter 2712-E (March 29, 2012), SDG&E Advice Letter 2343-E (April 3, 2012).
49 SCE executed contracts from the first RAM auction on February 13, 2012. PG&E executed contracts from the first RAM auction on February 27, 2012. SDG&E executed contracts from the first RAM auction on March 30, 2012. The Commission's Energy Division Staff approved these contracts, effective April 29, 2012 for PG&E, April 30, 2012 for SCE, and May 3, 2012 for SDG&E.
50 SCE August 5, 2011 comments at proposed tariff "Special Condition #8 MP FiT Pricing and Cumulative Procurement Targets," Appendix A Schedule MP FiT, Sheet 5.
51 For example, a price adjustment mechanism should not create an incentive for generators to purposefully withhold executing a contract in order to force a price increase.
52 SCE, CEERT, CALSEIA, and FuelCell Energy suggest a similar approach.
53 The 3 MW should be subtracted from the total amount of MW prior to allocation of equally among product types.
54 SDG&E April 9, 2012 comments to proposed decision at 11.
55 § 399.20(d)(1).
56 County Sanitation District April 9, 2012 comments on proposed decision at 9 (presenting data on the compliance costs specific to the South Coast Air Quality Management District and estimating that for the County's 5.4 MW engine facility will require approximately $9.8 million in system upgrades and $.5 million in annual operations costs to comply with a recent proposal by the Air Quality Management District).
57 FuelCell Energy April 9, 2012 comments on proposed decision at 5-6, citing to March 7, 2011 brief (presents data by incorporating by web link to a UC-Irvine fuel cell study entitled Build-Up of Distributed Fuel Cell Value in California: Background and Methodology. This study is available at http://www.nfcrc.uci.edu/2/FUEL_CELL_INFORMATION/MonetaryValueOfFuelCells/PEMFuelCellValue_May2008.pdf and includes statewide data on avoided environmental costs, noting the specific values associated with air quality management districts. FuelCell Energy suggests that the Commission rely on this data, specifically the midpoint of the trading ranges for each pollutant over the prior 12 month period could be averaged from different sources and used to set the multiplier for each district to reflect costs associated with compliance in an air quality management district.
58 Section 380 provides, in part, that the Commission, in consultation with the CAISO, shall establish resource adequacy requirements for all load-serving entities.
59 The CAISO, not the Commission, determines whether a project obtains resource adequacy.
60 Pursuant to the revisions to Rule 21 proposed by the settling parties in R.11-09-011, the tariff would remain an energy-only tariff and would expressly state that an interconnection applicant under Rule 21 (revised) is not prohibited from applying for an assessment under the utility's applicable wholesale distribution access tariff. (See Motion for Approval of Settlement Agreement Revising Distribution Level Interconnection Rules and Regulations, Proposed Revised Rule 21 at Section E.2.b.iii.
61 California Independent System Operator, Resource Adequacy Deliverability for Distributed Generation Draft Final Proposal (March 29, 2012) (available at: http://www.caiso.com/Documents/DraftFinalProposal-Deliverability-DistributedGeneration.pdf). The Commission Staff collaborated with the CAISO in developing this proposal and fully supported the proposal before the CAISO Board of Governors.
62 Subsection (e) of § 399.20 states, in pertinent part: "The commission shall consider and may establish a value for an electric generation facility located on a distribution circuit that generates electricity at a time and in a manner so as to offset the peak demand on the distribution circuit."
63 § 399.20(b)(3).
64 AB 1969 enacted § 399.20(f) which stated: "Public water and wastewater facilities are strategically located and interconnected to the electric transmission systems in a manner that optimizes the deliverability of electricity generated at those facilities to load centers."
65 This figure is based on the highest per MW costs of the levelized median total upgrade costs of solar PV projects up to 3 MW from the Renewables Portfolio Standard Quarterly Report. Third Quarter 2011 at 10-11. This report can be found at: http://www.cpuc.ca.gov/NR/rdonlyres/2A2D457A-CD21-46B3-A2D7-757A36CA20B3/0/Q3RPSReporttotheLegislatureFINAL.pdf.
66 § 399.20(d)(3).
67 "In light of these considerations, we find that customer indifference under AB 1613 would not be achieved if the price paid under the program only reflected the market price of power. As discussed, since customers who are not utilizing the eligible Combined Heat and Power system will receive environmental and locational benefits from these systems, the price paid for power should also include the costs to obtain these benefits." (D.09-12-042 at 17.)
68 D.10-12-048 at 16-17.
69 See, e.g., DRA June 21, 2011 comments (noting that recent changes in the California renewable energy market make it reasonable to transition from basing the Section 399.20 tariff price on the MPR to a net surplus compensation rate). In contrast, Sustainable Conservation notes that some technologies, such as bioenergy, are still maturing and have not necessarily experienced cost decreases.
70 § 399.20(f).