Arkansas Administrative Code
Agency 126 - PUBLIC SERVICE COMMISSION
Division 05 - Secretary of the Commission
Rule 126.05.20-001 - Net-Metering Rules

Question 1: With respect to an electric utility's entire cost of providing service to each net-metering customer within each of the electric utility's class of customers, does a net-metering customer's use of the electric utility's capacity, distribution system, or transmission system impose additional costs?

Response: Yes.

Question 1a: If so, which, if any additional costs are quantifiable?

Response: Additional direct costs that are quantifiable include administrative costs and integration costs to maintain the proper frequency and voltage of the distribution system given variable exports. These costs are likely to be de minimisgiven the very low number of net metering accounts in Arkansas. Joint Report at 110-111.

Question 1b: How should any such quantifiable, additional costs be valued, for the purpose of Act 827?

Response: Integration costs are quantifiable based on the interconnection studies conducted by the utility. Administrative costs can be quantified and captured in the utility's COS Study. Joint Report at 111.

Question 1c: Are there existing or emerging technologies or policies that could mitigate such costs?

Response: Did not provide an answer.

Question 2: With respect to an electric utility's entire cost of providing service to each net-metering customer within each of the electric utility's class of customers, are there any quantifiable benefits associated with the interconnection with and providing service to the net-metering customer, including without limitation benefits to the electric utility's capacity, reliability, distribution system, or transmission system?

Response: Yes.

Question 2a: If so, which, if any of these benefits are quantifiable?

Response: Sub-Group 1 says its Crossborder study identifies quantifiable benefits associated with the interconnection and providing service to net-metering customers.

Joint Report at 112.

Question 2b: How should any such quantifiable, additional benefits be valued, for the purpose of Act 827?

Response: Sub-Group 1 says its Crossborder study identifies methodologies for valuing those benefits. Joint Report at 112.

Question 2c: Are there existing or emerging technologies or policies that could enhance such benefits?

Response: Did not answer.

Question 3a: As a matter of ratemaking, how should the Commission take into account immediate, or short-term cost or benefit causation, versus projected or expected longer term cost or benefit causation?

Response: Short-term evaluations of costs and benefits fail to accurately assess the full beneficial impact of distributed generation. The long-term costs and benefits of distributed generation can be amortized and factored into short-term analysis like a COS

study. Joint Report at 112-113.

Question 3b: Does evidence demonstrate that net-metering customers are materially different in terms of cost causation from other customers in their customer class (i.e., are net-metering customers their own class)?

Response: Sub-Group 1 has seen no evidence to date. Joint Report at 13-14.

Question 3c: Should rates incorporate time-differentiated rates for net-metering customers (either residential or commercial)?

Response: Time-differentiated rates can more accurately reflect the value of solar generation, which tends to occur during system peak periods. Sub-Group supports time-differentiated rates for net metering and non-net-metering customers alike. Joint Report at 114-115.

Question 4: What role might net-metered generation play in assisting with compliance with the Clean Power Plan or other environmental regulations?

Response: Net-metered generation will make it easier for Arkansas utilities to comply with environmental regulations by allowing reduced generation at those utilities' central stations, which would otherwise result in the need to acquire emission permits. Joint

Report at 115-116.

Question 5. How should the Commission consider or take into account economic costs or benefits beyond the utility's entire cost of providing service, including:

5a: Any public interest associated with economic development or job creation in the distributed energy sector, including the potential impact of federal tax benefits?

Response: Societal benefits such as economic development and job creation should be considered by the Commission as part of determining fair, just and reasonable rates for net-metering customers. The Crossborder study quantifies local economic benefits of distributed generation as part of the Societal Cost test. Joint Report at 117.

5b: Any public interest, beyond the direct costs and risks associated with compliance with environmental regulation, associated with environmental impacts?

Response: The Commission should consider the benefit to public health that distributed generation would have by displacing fossil fuel generation. The Crossborder study estimates the benefits associated with avoided greenhouse gas emissions, avoided SO2, PM2.5, and NOx emissions, and avoided water and land use as part of the Societal Cost test. Joint Report at 118.

Question 6: Should policies related to net metering in Arkansas take into account developments in smart-grid, demand response, storage, or other technologies?

Response: Yes. Smart grid technologies, such as advanced metering infrastructure, can allow utilities to collect more comprehensive data on the timing and level of solar customers' usage from the grid and exports. This data could then be used by the Commission to understand how net-metering customers' load profiles differ from others in their class. Joint Report at 118-119.

Question 7: What can be learned from the recent consideration of these net metering valuation issues in other states?

Response: Except for a few states, primarily with much higher levels of solar penetration, comprehensive cost-benefit studies conclude that benefits of distributed solar exceed its costs. Sub-Group 1 says an important lesson from other states is that public and comprehensive analysis of the costs and benefits of net metering is a prerequisite to policy changes that are accepted by key constituencies. Joint Report at 120-123.

Question 8: What other issues, if any, should be addressed in implementation of Act 827?

Response: Sub-Group 1 recommends that the Commission initiate a process that would encourage utilities to perform extensive monitoring and metering of distribution systems to discern marginal distribution capacity costs; the potential for avoidable and deferrable capacity investments over the near, medium, and long term; hosting capacity at feeder level resolution; and other information that would allow better distribution system planning and more clear identification of the potential for integration of distributed generation. Joint Report at 124-125.

Question 1: With respect to an electric utility's entire cost of providing service to each net-metering customer within each of the electric utility's class of customers, does a net-metering customer's use of the electric utility's capacity, distribution system, or transmission system impose additional costs?

Response: Yes. Additional costs imposed include costs such as billing, customer service, interconnections and operational impacts. Some of these costs would be expected to grow as the number of net-metering customers increases.

Question 1a: If so, which, if any additional costs are quantifiable?

Response: Interconnection costs are quantifiable based on the interconnection studies conducted by the utility. Other additional costs are quantified and captured in the utility's COS Study.

Question 1b: How should any such quantifiable, additional costs be valued, for the purpose of Act 827?

Response: Additional costs should be quantified using well-established COS methodologies based in each utility's specific COS data. These methodologies have been reviewed before the APSC for many years and follow the principle of cost causation.

Question 1c: Are there existing or emerging technologies or policies that could mitigate such costs?

Response: Yes. Existing technologies include sensors with communication capability, smart inverters, condition-monitoring sensors, and energy storage technologies. The impact of emerging technologies or future policies can be considered in future rate cases for each utility and recognized in the associated COS study. Id.at 186-189.

Question 2: With respect to an electric utility's entire cost of providing service to each net-metering customer within each of the electric utility's class of customers, are there any quantifiable benefits associated with the interconnection with and providing service to the net-metering customer, including without limitation benefits to the electric utility's capacity, reliability, distribution system, or transmission system?

Response: Yes. For purposes of establishing rates for net metering the benefits considered should be well defined, readily quantifiable, transparently accounted for, based on the actual embedded cost of providing service, and based on the individual utility's COS Study.

Question 2a: If so, which, if any of these benefits are quantifiable?

Response: Embedded generation and transmission capacity benefits occur if net-metering customers reduce their peak load requirements. Incremental energy adjusted for distribution line losses is avoided if net-metering customers export excess energy to the grid.

Question 2b: How should any such quantifiable, additional benefits be valued, for the purpose of Act 827?

Response: Benefits should be valued using traditional COS methodologies and rely on the most recent COS Study for the utility. Avoided incremental energy benefits can be quantified based on the annual hourly real-time LMPs for the previous historical year, plus distribution line losses. A weighted average annual avoided incremental energy cost per kWh should be determined.

Question 2c: Are there existing or emerging technologies or policies that could enhance such benefits?

Response: Yes. Many of the technologies discussed in response to 1c would be equally applicable to enhancing the benefits. Challenges exist in incorporating them. Also, they could bring additional regulatory challenges. Id.at 189-191.

Question 3a: As a matter of ratemaking, how should the Commission take into account immediate, or short term cost or benefit causation, versus projected or expected longer term cost or benefit causation?

Response: The Commission should take account of these by relying on the utility's most recent COS Study. This will appropriately balance short- and long-term cost causation.

Question 3b: Does evidence demonstrate that net-metering customers are materially different in terms of cost causation from other customers in their customer class (i.e., are net-metering customers their own class)?

Response: Not at this time. Net-metering customers are unique due to the fact that at times they may export power back onto the utility system. However this difference from other customers in their class is best addressed through rate design.

Question 3c: Should rates incorporate time-differentiated rates for net-metering customers (either residential or commercial)?

Response: Time-differentiated rates could be explored within the context of future utility general rate cases. Mandatory time-differentiated rates are not necessary at this time in

Arkansas due to the small number of net-metering customers. If available, a choice of rates should be available to all customers. Id. at 192-193.

Question 4: What role might net-metered generation play in assisting with compliance with the Clean Power Plan or other environmental regulations?

Response: The Clean Power Plan is currently stayed by the US Supreme Court. It is not possible to know the future of environmental regulations. Any reduction in utility's investments and expenses related to environmental compliance costs will be reflected in the utility's future COS Study or the fuel and purchased energy recovery mechanisms. Id. at 193-194.

Question 5. How should the Commission consider or take into account economic costs or benefits beyond the utility's entire cost of providing service, including:

5a: Any public interest associated with economic development or job creation in the distributed energy sector, including the potential impact of federal tax benefits?

Response: Such benefits are not comprehended in the utility costs or recoverable by the utility and should not be considered by the Commission to determine just and reasonable rates for net-metering customers. They are also difficult to quantify and speculative in nature.

5b: Any public interest, beyond the direct costs and risks associated with compliance with environmental regulation, associated with environmental impacts?

Response: See response to question 5a. Id. at 194.

Question 6: Should policies related to net metering in Arkansas take into account developments in smart-grid, demand response, storage, or other technologies?

Response: Yes. Such developments that affect the utility's actual cost of providing service to all customers should be taken into account, but only at a time when they have emerged to a point where they have a quantifiable impact. Id.at 195-196.

Question 7: What can be learned from the recent consideration of these net metering valuation issues in other states?

Response: Many other jurisdictions have reached the conclusion that net metering rates which provide a kWh credit equal to the full retail rate for excess generation from net metering facilities fail to recover the full cost of serving those net-metering customers and shift costs to other customers. Many jurisdictions have had proposed, or have adopted, a 2-Channel Billing framework the same, or similar to, that proposed by Sub-Group 2.

Those that have implemented 2-Channel Billing type framework vary in their valuation of the excess energy. See also Attachment B-3 to Sub-Group 2's recommendations. Id.at 195-196.

Question 8: What other issues, if any, should be addressed in implementation of Act 827?

Response: None at this time. Id. at 196.

Lessons Learned From Other States and Jurisdictions

See Attachment B-3 to Sub-Group 2's recommendations. Id.at 197-216.

Pulaski County believes that there is no legal presumption, pursuant to Act 827, requiring the Commission to impose a different rate structure than already exists for net-metering customers. Further, Pulaski County asserts that there has been no factual basis presented to change the existing net-metering compensation structure because the existing universe of net-metering customers does not provide enough relevant data to quantifiably demonstrate that there are either costs to the electric utilities associated with net-metering or tangible benefits to the grid. Thus, Pulaski County argues, ongoing independent study of Arkansas-specific data should be conducted to approach Act 827 conservatively, ensuring that ratepayers and the electric utilities are protected and that the demands of Act 827 are met. Any proposal that changes the existing net-metering compensation model is likely overly complicated and will hinder the intent of the AREDA, which Pulaski County urges the Commission to avoid. Pulaski County asserts that a simple and straightforward net-metering rate structure can accomplish AREDA's intent, leading to additional distributed generation, thus creating new tax revenue, which in turn will support local governments and schools. Pulaski County Comments at 306.

In its Recommendations in the Joint Report, Pulaski County states that while the relevant statute, Ark. Code Ann. § 23-18-604(b), does use the language "shall [e]stablish appropriate rates, terms, and conditions for net-metering contracts[,]" the statute creates a contingent precedent for rates being imposed: evidence presented that there are quantifiable additional costs to the electric utilities "associated with the net-metering customer's use of the electric utility's capacity, distribution system, or transmission system and any effect on the electric utility's reliability[,]" and only if those costs are net of the benefits provided to the electric utilities by net-metering customers. Pulaski County submits that there is an affirmative burden, pursuant to Act 827, to establish that there are additional quantifiable net costs incurred due to net metering, before a change to the existing rate structure for net-metering customers is imposed. There is no inherent obligation created by Act 827 for the Commission to change the existing rate structure for net-metering customers. In fact, Pulaski County argues, creating an additional rate structure or modifying the existing rate structure at this time, absent proof of a quantifiable net cost to the electric utilities, is clearly contradictory to the codified public purpose favoring net energy metering set forth in AREDA. Id. at 306-307.

Pulaski County states that the burden set forth in the statute requires proof of net costs to utilities before proceeding to the ratemaking phase. For the Commission to create a new rate structure for net-metering customers, including that costs be imposed upon net-metering customers, would be clearly contrary to Act 827, as there has been insufficient evidence presented that there are quantifiable additional costs created by net-metering customers that outweigh the benefits of net-metering. Pulaski County further states that, because Act 827 does not necessitate a specific time period for the Commission to establish appropriate rates, term, and conditions for net-metering contracts, the Commission should not rush into promulgating rates, terms, or conditions, as the record lacks relevant information reflecting the actual quantifiable benefits and costs associated with net-metering. According to Pulaski County, the Commission should take a conservative approach, ordering a long-term, independent study that analyzes usage patterns, actual occurrences, practices, and results. Id. at 306.

Pulaski County further asserts that any proposal regarding costs and benefits of net metering is improperly speculative until an Arkansas-specific study and report is produced by a qualified, independent third party, with thorough data analysis, as has been done in other jurisdictions. Based upon evidence presented at the hearing in Phase 1 of this docket, Pulaski County stipulates that there are 500 net-metering customers in Arkansas, which it asserts does not provide enough relevant data to quantifiably demonstrate that there are either costs to the electric utilities associated with net metering or tangible benefits to the grid. Consequently, Pulaski County argues, the impact in cost and benefits of 500 net-metering customers may not be consistent with the costs and benefits of 5,000 or 50,000 net-metering customers. Thus, the study Pulaski County recommends would enable the Commission to promulgate rates, terms, or conditions that accurately reflect the actual quantifiable benefits and costs associated with net metering for each rate class, for each utility. Id. at 308.

Finally, Pulaski County notes in the Joint Report that AREDA contemplates economic development and job creation as a motivation for adoption, thus necessitating that the Commission consider the impact of the net-metering rules and rate structures on those matters. Pulaski County states that through its Order No. 5 regarding grandfathering of net-metering customers, the Commission has recognized that uncertainty, complexity, and shifting winds deter investment. Additionally, Pulaski County believes it is a generally accepted principle that simplicity and certainty are good for investment, whether in energy production or any other industry. As such, Pulaski County submits, "grandfathering" of existing users for a sufficient term, to reasonably calculate future expectations, directly addresses this potential for disincentives. However, if a rate modification or additional fee is warranted by demonstrable, quantifiable net costs to electric utilities, Pulaski County urges the Commission to keep it simple to avoid driving away investment, especially for residential and small commercial customers that traditionally struggle to receive capital investment. Pulaski County states that direct investment in distributed generation and net-metering results in a capital improvement to real property and results in the collection of sales taxes on the sale of capital goods. This produces additional tax revenue to cities, counties, and school districts, which does not occur through traditional power production, where there are generally a few large facilities, directly impacting the tax districts where the improvement resides. Pulaski County extols net metering for its simplicity and argues that any proposal that changes the existing net-metering compensation model is likely overly complicated and will hinder the intent of AREDA. Id. at 309.

The Alliance for Solar Choice (TASC) did not actively participate in Phase 2 of this Docket and abstained from formally joining any part's recommendation in the Joint Report. On November 21, 2017, TASC requested to withdraw as a party. The Commission granted the request by Order No. 18 on November 22, 2017.

On November 28, 2017, Solar Energy Arkansas, Inc. filed a Motion to Withdraw, which was granted by Order No. 19 on November 29, 2017.

In his short Recommendations included in the Joint Report, Mr. Ball states that Act 827, a statutory sub-chapter of AREDA, requires the Commission to examine the balance of costs and benefits of net metering within the context of a statute aimed at promoting customer-owned distributed renewable energy production. Mr. Ball observes that there has been little progress in reaching a consensus among the Parties. He notes that there is debate on the value of the benefits that Arkansas enjoys as a result of net metering. If one believes that sustainability, economic benefit, distribution system benefits, public policy benefits, and environmental benefits are important, he says, then one would recognize the importance of robust development of our renewable energy resources. He acknowledges that it is very difficult to assign a monetary figure to the universal value of net metering. He agrees with comments from some Parties that establishing a rate schedule or protocol that is "a guess or a wish on the part of Parties on either side of the arguments" is putting the cart before the horse. Id. at 309-310.

Mr. Ball states that both obvious and intangible benefits must first be fully and fairly evaluated and points to remedies being adopted by other states as indicating that some have valued benefits more highly than others. Some jurisdictions have determined that, far from shifting costs, net-metering customers create net value to the grid and all grid users, while other states have focused more on costs to a utility and somehow "keeping them whole." He asserts that a program whereby utilities could purchase all energy, or just net excess energy, produced by a net-metering customer could be considered if one is attempting to keep the utilities whole and if purchase prices include the value of benefits derived from sustainable energy generation. He adds that utilities could recover their purchases through existing mechanisms and, in purchasing, gain ownership of the Renewable Energy Credits (RECs) associated with renewable energy.

Mr. Ball disavows a belief that utilities care only about protecting profits and monopolies that have never faced competition, asserting that calculating things like cost, return, and rates in an era of anemic demand growth, aging infrastructure, and shifting policy goals is difficult, even absent disruptive technologies knocking on the door. He states that some of those technologies will provide greater universal benefit in the form of grid services that communicate with and aid the grid. He suggests that providing policies that nourish robust net metering growth and encourage further development and experiences with grid services technologies should be our goal. Among those are time-of-use pricing, peak shaving after the sun goes down, self-consumption, grid zero, grid support (Rule 21 in California), and requiring inverters to have "ride through" capabilities that support a grid that may be experiencing voltage variations as opposed to simply shutting down as has been the norm for autonomous inverters. Mr. Ball notes that Arkansas has very low penetration of solar power and suggests that policy that recognizes public policy benefits of bringing the future to Arkansans could well be an under-recognized benefit of net metering. Id. at 310-311.

Mr. Ball submits that the consideration of 2-Channel billing to effect fees to net-metering customers is an approach that basically negates net metering as a policy driven by statute. Regardless of fees that may or may not be charged to net-metering customers, he states, net metering is an exchange of a kWh for a kWh, no matter the cost of that kWh. If the Commission approves any additional costs to net-metering customers, he urges, at the very least the Commission should (1) wait until a full study of benefits is completed and (2) adopt rates that are phased in relative to the growth of net metering and flexible in order to account for future costs and benefits brought on by changes in technology. Id. at 311-12.

Mr. Ball notes that he has argued that there are minimal "additional costs" to a utility from a net-metering customer that are not incurred by the utility serving non-net-metering customers within a given customer class. If lost revenues are not part of the consideration, he states, there are only three areas of cost to a utility that are worthy of discussion:

Mr. Ball states that Act 827 was intended to enhance net metering by stipulating that net excess generation credits never expire and by raising then-current limits on the size of a residential or commercial net-metering facility. The requirement that the Commission resolve whether net-metering customers are "paying their fair share" was intended to prevent unintended consequences in light of enhanced benefits directed by the Act, he asserts. He concludes his comments in the Joint Report by stating that AREDA, when passed in 2001, provided that the Commission "may authorize an electric utility to assess a net-metering customer a greater fee or charge, of any type, if the electric utility's direct costs of interconnection and administration of net-metering outweigh the distribution system, environmental and public policy benefits of allocating the costs among the electric utility's entire customer base." He observes that AREDA did not require an amendment directing the Commission to evaluate the prudence of assessing a net-metering customer a greater fee, noting that that authority has been there all along. Perhaps, he concludes, the rate structures for all customer classes do not accurately reflect the actual cost-of-service to those customers. Id. at 313.

Sub-Group 1's White Paper does not further discuss Issues 2 through 6, noting that they are addressed and quantified in the long-term benefit/cost study prepared for the NMWG. The remainder of the paper addresses and quantifies the first issue - the failure of Sub-Group 2 to perform a complete COS analysis that includes the impact of the DG power used on-site on the cost to serve a DG customer's Channel 1 load. Id.at 34.

In revising the costs to serve DG customers' on-site Channel 1 loads to determine how the addition of DG changes the costs to serve the on-site load of a residential customer, Sub-Group 1's White Paper authors used the same COS approach used by SubGroup 2. The authors note that the addition of DG changes the size and profile of the DG customer's load on the utility system, as measured by the Channel 1 meter in the SubGroup 2 proposal for 2-Channel Billing. They also used the same cost allocation methodologies to assess the impact of adding DG on the energy, production, transmission, and distribution costs allocated to the Channel 1 loads of residential customers. They extended the Sub-Group 2 COS analysis to the Channel 1 loads by cost component, assuming a 5kW DG system, as discussed in detail below: Id. at 34-35.

* Energy - Sub-Group 2 correctly used the solar-weighted LMP in the MISO energy market in Arkansas. This incremental or avoided energy cost is larger than the average embedded cost of energy that is the fuel charge component of rates. Thus, the portion of DG output which serves the customer's onsite load reduces the utility's costs by the solar-weighted LMP times the amount of DG output used onsite. The authors deducted the avoided energy cost from the DG customer's pre-solar fuel charges to determine the energy costs for the DG customer's Channel 1 usage. Id.at 35.

* Production - For EAL, embedded production capacity costs are allocated based on coincident peak loads in the four summer months (4 CP loads). For example, adding a 5 kW-DC DG system reduces the 4 CP loads of an average residential customer from 3.18 kW to 0.66 kW, i.e., to 21 percent of the pre-solar level. This reduces the production capacity costs allocated to the average residential customer from $0.03836 per kWh to $0.01222 per kWh, as illustrated in Figure 1 on page 36 of Sub-Group 1's Reply Comments. This calculation accounts for the fact that, with a 5 kW-DC system, the post-DG kWh usage of the customer is 65 percent of the usage before adding DG. Id.at 35-36.

* Transmission - For EAL, transmission costs are allocated using coincident peak loads in all 12 months (12 CP). Based on Sub-Group 2's model, the DG system reduces the 12CP loads as well, from 2.82 kW to 1.22 kW, and transmission costs allocated to this customer decrease from $0.01038 to $0.00647 per kWh, which again accounts for the fact that the post-DG kWh usage of the customer is 65 percent of the usage before adding DG. Id.at 36.

* Distribution - The White Paper authors assumed that 50 percent of distribution costs are allocated based on the NCP and 50 percent based on the number of customers. The 50 percent allocated based on customer count is a fixed dollar amount per customer. When a customer reduces its usage by adding DG, this portion of distribution rate increases on a per unit basis. For example, if a customer with a 5 kW-DC system reduces its usage by 35 percent, the per unit rate for the fixed 50 percent of distribution costs allocated to this customer will increase by a factor of 1/0.65 = 1.54, i.e., a 54 percent increase. The portion of the distribution rate allocated on the basis of NCP also will increase, on a per unit basis, after a customer adds DG, but by much less than the portion that is invariant to usage. Thus, the authors state, with respect to distribution costs, their analysis shows that the Channel 1 usage of a solar customer is more costly to serve, per kWh, than a non-solar customer. This is less favorable than Sub-Group 2's assumption of no impact on distribution costs allocated per unit allocation of distribution costs. Table 1 shows the combined results of the Sub-Group 1 authors' analysis, which concludes that the costs to serve the Channel 1 loads of DG customers are 35 percent lower than the cost to serve the average residential customer.

Table 1: Functional Base Rate Components: Pre-solar mid Channel 1 ($/kWh)

Id. at 34-38.

If net metering is to be analyzed using a COS frameworks, the authors state that the additions they made to Sub-Group 2's analysis are necessary to accurately reflect the COS for the Channel 1 loads of DG customers. They contend that under a fully cost-based application of 2-Channel Billing, customers who install DG should receive a significant rate reduction for their Channel 1 usage, alongside the lower export rate that Sub-Group 2 calculates. Combined, they note, this actually results in higher bill savings for DG customer than they would receive under net metering at the full retail rate. Table 2 shows that fully cost-based rates for both Channel 1 usage and Channel 2 exports - including retail rates for the Channel 1 usage of DG customers that are lower than standard retail rates - would result in greater bill savings for DG customers than now available under current net metering.

Table 2: Monthly Bill Savings ($) for Resiential DG Customers

The Sub-Group 1 authors also examined a conservative, worst-case sensitivity that assumed 100 percent of distribution costs are fixed and are the same for all residential customers. Even in this worst-case DG customers bill savings remain higher than under today's net metering. Table 3 shows the results of this worst-case analysis.

Table 3: Sensitivity: Monthly Bill Savings ($) with Fixed Distribution Costs

Sub-Group 1 Reply at 40-41.

Sub-Group 1's White Paper authors' conclusion is that the complete COS analysis shows that fully cost-based compensation for net metered residential DG customers actually would increase their compensation compared to current net metering at the full retail rate. Current net metering thus does not impose a burden or a cost shift on ratepayers who do not participate in the program. In fact, the authors state, the conclusion of this short-term COS analysis is the same as the long-term benefit/cost study prepared for Sub-Group 1: there is no cost shift from solar DG in EAL's service territory under today's net metering rules, and all ratepayers benefit from the installation of this new clean energy infrastructure. Sub-Group 1 Reply at 41.

Mr. Ball states that providing policies that nourish robust net-metering growth and encourage further development and experience with "grid services" technologies should be the goal, citing time-of-use, peak shaving after the sun goes down, self-consumption, grid zero, and grid support. Ball Reply at 1-2.

Mr. Ball states that Act 827 was intended to strengthen net-metering policy by stipulating that net excess generation credits never expire and by raising then-current limits on the size of a residential or commercial net-metering facility. He notes that a path to recover cost weighed against benefits has been in AREDA all along and asserts that utilities could have pursued extra fees for net-metering customers at any time since the passage of AREDA. He concludes that this is no time to weaken Arkansas's net-metering policy. Id.at 2.

Reply Comments of Pulaski County

Noting how far apart the parties are in this matter, Pulaski County asserts that the plain language of Act 827 clearly does not create a presumption of a different rate structure for net-metering customers. Accordingly, Pulaski County believes that there is an affirmative burden, pursuant to Act 827, for the electric utilities to establish that there are additional quantifiable costs incurred due to net metering, before a change to the existing rate structure for net-metering customers is imposed. Pulaski County observes that the two Sub-Groups are inextricably divided in their views of net metering:

* Sub-Group 1 does not really acknowledge that there are any "quantifiable additional costs associated with the net-metering customer's use of the electric utility's capacity, distribution system, or transmission system and any effect on the electricity utility's reliability[,]" as contemplated by Ark. Code Ann. § 23-18-604(1)(A)(ii)(a). Nevertheless, it states, Sub-Group 1 is not alone in zealously advocating for the position that is best for its members.

* Sub-Group 2's recommendation does not appear to acknowledge that there are any "quantifiable benefits associated with the interconnection with and providing service to the net-metering customers, including without limitation benefits to the electric utility's capacity, reliability, distribution system, or transmission system [,]" as contemplated by § 23-18-604(1)(A)(ii)(b).

Pulaski County Reply at 1-2.

Pulaski County further states that while Sub-Group 2 does not appear to acknowledge that there are any quantifiable benefits associated with net metering, it believes that no tangible evidence has been produced by Sub-Group 2 demonstrating that there are any quantifiable additional costs associated with net metering. However, Pulaski County believes that pursuant to Act 827, Sub-Group 1 has no affirmative duty to demonstrate any quantifiable additional benefits of net-metering until Sub-Group 2 demonstrates that there are quantifiable additional costs associated with net metering. Accordingly, Pulaski County argues, since Sub-Group 2 has failed to fulfill its obligations pursuant to Act 827, Sub-Group 1 has no real obligation to address the quantifiable additional costs of net metering. Nevertheless, Pulaski County does not necessarily believe the Commission should accept as true all of Sub-Group 1's positions. Pulaski County observes that Sub-Group 1 is "burdened by a dearth of data," and despite what may appear in the Crossborder Study, Pulaski County believes that all of Sub-Group 1's recommendations are speculative as well. Id. at 2-3.

In conclusion, Pulaski County states that based on Act 827's lack of an explicit mandate to change net-metering rates, without the condition precedent of quantifiable evidence that costs associated with net-metering are net of benefits provided by net-metering, the Commission should do nothing. The Commission should let net metering develop and progress. Pulaski County adds that if the Commission feels obligated to do something, it could set a threshold of net-metering penetration that will provide the SubGroups and the Commission with enough data to accurately determine if the quantifiable costs of net-metering are in excess of the benefits. Once the threshold is met, Pulaski County states, this docket should be re-opened and a neutral facilitator retained to present a study on the matter and facilitate the docket activity. Only then can the Commission fulfill its obligations pursuant to Act 827. Id. at 2-3.

Walmart Surreply Comments

Walmart notes in Surreply that while it participated in the NMWG established in this docket and was named as one of the Joint Parties in the Joint Progress Report and Proposed Procedural Schedule, it takes no position on the disputed net-metering rate issue and requests that it be excused from the procedural hearing. The Commission granted its request by Order No. 18.

Sub-Group 1 says its Crossborder study is highly relevant because it is the only evidence in the record demonstrating that distributed generation helps utilities avoid direct system costs. Sub-Group 1 summarizes the findings of its study as follows:

Sub-Group 1 believes that Sub-Group 2's proposal is technically flawed and demonstrates selective application of COS principles and therefore will not promote distributed generation in Arkansas. Sub-Group 1 argues that Sub-Group 2 never says what the cost to serve a net-metering customer, as defined by AREDA, actually is. Sub-Group 1 contends that Sub-Group 2 has simply assumed incorrectly that the cost to serve net-metering customers is the same as any other customer in the class. Sub-Group 1 also argues that Sub-Group 2 has incorrectly assumed that any benefits associated with the net-metering customer's system are captured by its "excess generation credit rate." Sub-Group 2's assumptions for how it determined cost responsibility for net-metering customers ignores the benefits net-metering customers create by reducing their peak loads. SubGroup 1 argues that the peak reduction savings should be added to Sub-Group 2's "excess generation credit rate," which would actually mean net-metering customers are providing higher bill savings than the current net metering rate. Sub-Group 1 says there is a second flaw in Sub-Group 2's "excess generation credit rate" calculation. Sub-Group 1 says the calculation is incorrectly based on the output from a 5 kW solar system. Sub-Group 1 argues that the average solar system size for net-metering customers is 8 kW, which if used instead of 5 kW, would have resulted in higher avoided costs for net-metering customers. Sub-Group 1 Surreply at 19-21.

* The need for grandfathering is premised on the assumption that the Commission will establish a new rate structure in Phase 2 of this Docket..However, the Commission will not pre-judge any positions on a new Net-Metering rate structure and makes no findings in this Order on whether a new Net-Metering rate structure should be adopted or, if it is, the details of that new rate structure.

* The Commission finds that adoption of a grandfathering period to provide such notice and to promote certainty in the market for Net-Metering Facilities need not conflict with Act 827's requirement that "each" Net-Metering Customer pay its entire cost of service. In Phase 2 of this proceeding, the Commission may or may not determine that a new rate structure is necessary. Agreement may be reached quickly by the parties, or it may require a longer period or be further adjusted in future years. Under any of these scenarios, a grandfathering period beginning with the date of any order, if any, adopting a new rate structure and ending with a "drop-dead date: 20 years later ensures that each Net-Metering Customer will transition to any new rate structure adopted by the Commission.

* The Commission finds that the most reasonable date to use for grandfathering is the date of the order, if any, in Phase 2 which adopts a new Net-Metering rate structure.

Sub-Group 2 states that the underlying premise of its approach to determining the net-metering rate is that the current embedded COS (infrastructure and other services) to serve all customers, including net-metering customers, does not change and is the appropriate basis for determining the costs that should be recovered from net-metering customers. Sub-Group 2 states that differences between customers within a class are generally addressed through rate design, as is the case in Sub-Group 2's determination of the EGCR. Id.at 9-10.

Sub-Group 2 cites to its Reply Comments (at 166) as describing how its COS Study and the RTO Market data encompass the full, quantifiable costs and benefits of the utility's capacity, reliability, distribution system, and transmission system and form the basis for defining the EGCR. Sub-Group 2 argues that its proposed 2-Channel Billing approach is not discriminatory, as it is based on actual COS data and evidence underlying rates in Arkansas -- in contrast to Sub-Group 1's "maintain the status-quo" approach, which SubGroup 2 contends is based on assumed and speculative information regarding the "hypothetical future value of solar generation." Furthermore, Sub-Group 2 argues, SubGroup 1's proposed approach does not align with the requirements of AREDA or the statutory framework that underlies ratemaking in Arkansas. Id.at 10.

Sub-Group 2 rebuts Sub-Group 1's allegation that Sub-Group 2 did not explain the cost to serve net-metering customers, arguing that it has provided a clear explanation of these costs. Sub-Group 2 notes that currently, net-metering customers are credited at the full retail rate for excess kWh that are exported to the grid, and asserts that a credit equivalent to the full retail rate for excess generation results in a credit for utility-provided services and programs that are not avoided by net-metering customers. According to Sub-Group 2, this means that the electric utility does not recover its entire cost of providing service to each net-metering customer, net of quantifiable benefits as required by Act 827. Therefore, Sub-Group 2 argues, the current net-metering policy must be changed for new net-metering customers. Id.at 10-11.

Sub-Group 2 elaborates by explaining that, for EAL, when a net-metering customer receives a capacity credit at the full embedded COS amount, the customer receives a credit of 4.5 cents per kWh in excess of the benefits the net-metering customer provides when it self-generates. Further, Sub-Group 2 asserts, the utility does not avoid and continues to incur 4.5 cents per kWh in infrastructure and operating costs to provide service to the net-metering customer during hours of the day when the utility is responsible for serving the net-metering customer's load and to allow the net-metering customer to export self-generated excess energy to the grid.16 Id.at 11.

Sub-Group 2 acknowledges that Act 827 contains no requirement that a rate change be premised on the existence or determination of cross-subsidies, or quantifying the magnitude of such cross-subsidies, as the result of net metering. But, Sub-Group 2 asserts that AREDA does require that the Commission establish rates that recover the entire cost of serving net-metering customers, net of any quantifiable benefits those customers provide. Sub-Group 2 argues that under the current full retail approach, these entire "costs to serve" are not collected from the net-metering customers and must be paid by other customers through the ratemaking process. Id. at 14.

Sub-Group 2 explains that the reduction in purchased energy from the utility associated with behind-the-meter (BTM) generation is similar to conservation and energy efficiency activities such as turning off lights, adjusting the thermostat, adding insulation, sealing leaks, replacing windows, installing LED lights and/or purchasing more efficient appliances. Sub-Group 2 states that because its 2-Channel Billing approach does not change the underlying residential rate structure, for purposes of COS ratemaking SubGroup 2 did not seek to treat the lost revenues associated with BTM energy conservation resulting from self-generation any differently from the way lost revenues are treated for any other type of customer-directed energy conservation effort. Therefore, under 2-Channel Billing, Sub-Group 2 states, net-metering customers continue to effectively receive the full retail rate for their conservation behind the meter and are treated like all other customers when they are taking service from the utility under Channel 1.18 Id.at 15-16.

Sub-Group 2 further explains that net-metering customers are different, however, from all other customers when they are exporting excess generation to the grid. Consistent with traditional ratemaking methodology, Sub-Group 2 asserts, this difference among customers within a class is addressed through rate design - in this case the establishment of the EGCR for net-metering customers. Sub-Group 2 thus used a COS approach to determining the EGCR, which includes providing the net-metering customer with the quantifiable benefits of avoided capacity costs associated with the net-metering customer's entire self-generation, both BTM generation and excess generation exported to the grid. Id.at 16.

According to Sub-Group 2, the EGCR also appropriately recognizes costs that are essential to provide utility service that are not avoided by net-metering customers and should not be credited to net-metering customers. Excess generation exported to the grid is simply electrons and does not include all of the attributes of utility service such as billing, metering, reliability, EE programs, and other approved investments and ongoing costs essential to maintaining utility infrastructure. Sub-Group 2 states that the net-metering customer does not offset these essential utility costs when it exports kWh to the grid and should not be credited for these services as is the case when the net-metering customer is credited at the full retail rate. Sub-Group 2 thus argues that the EGCR ensures that the utility recovers its entire cost of providing service, net of quantifiable benefits, from net-metering customers, adding that the difference between the effective rate for BTM conservation and the EGCR is fully consistent with COS principles and recognizes the ratemaking differences between conservation and excess generation exported to the grid. Id.

Sub-Group 2 also responds to Sub-Group 1's contention that Sub-Group 2's treatment of BTM usage creates "a perverse incentive for distributed generation customers to use more electricity while their systems are producing, which is detrimental in many respects,"19 citing the definition of net metering in Ark. Code Ann. § 23-18-603(6)(E) as: "intended primarily to offset part or all of the net-metering customer requirements for electricity." Sub-Group 2 states that the most efficient way for a customer with self-generation to serve its own energy needs is to directly consume its self-generated energy behind the meter, and therefore, Sub-Group 2's treatment is consistent with AREDA and appropriate, not perverse or detrimental in some manner. Id. at 16-17.

Historically, Sub-Group 2 observes, the Commission has developed rates using COS Studies, which provide the regulatory framework for establishing rates based on costs that include not only COS, but also benefits associated with the costs avoided by net-metering customers. Sub-Group 2 states that the General Assembly is presumed to know how the Commission defines and determines COS, and therefore its treatment of avoided costs is historically consistent both with the Commission's ratemaking process and AREDA. Id.

Sub-Group 2 reiterates its position that any benefits related to the utilities' embedded costs, including investments in generation, transmission, and distribution plant that may occur over the longer term as the result of providing service to net-metering customers will be captured in future, updated utility COS Studies and approved revenue requirement and rates. The same is true for any utility investments to comply with environmental regulations associated with existing generation - the benefits of those embedded costs will be reflected in future COS Studies and future rates, Sub-Group 2 asserts. Id.at 18.

For the kWh measured on Channel 1, Sub-Group 2 recommends using the base rate in each utility's tariff and using a COS approach for developing just and reasonable rates for the net-metering customer's excess generation that is exported to the grid and measured on Channel 2. The EGCR methodology considers all of the net-metering customer's generation capacity and only focuses on the energy exported to the grid to the extent that the net-metering customer delivers excess energy to the grid. Id. at 19.

Sub-Group 2 asserts that its recommended 2-Channel Billing approach also uses traditional COS and rate design methods in developing the EGCR and uses the known billing determinants - namely energy measured on Channel 1 and Channel 2, which represent the net-metering customer's usage of the grid and export to the grid, respectively, and provides clear and accurate price signals. Sub-Group 2 further describes the 2-Channel Billing framework and EGCR methodology as simple to understand and apply universally to all utilities in Arkansas. Sub-Group 2 states that Attachment B-4 of Sub-Group 2's Recommendations shows that estimated customer impact is consistent across all utilities. Id. at 19-20.

According to Sub-Group 2, any rate mechanism that deviates from the billing determinants that reflect the service provided to the customer will make it increasingly difficult to recover the entire cost of serving the net-metering customer and does not send customers the proper price signals that encourage efficient use of the system. Sub-Group 2 contends that a 2-Channel customer's bill is highly correlated with the customer's actual use of the electric grid, including both the consumption of energy measured on Channel 1 and exports of energy measured on Channel 2. Sub-Group 2 asserts that this is not the case with the current 1:1 full retail rate credit reflected in net-metering rates. Id. at 20.

Sub-Group 2 agrees with Sub-Group 1's assertion "that many of the cost savings associated with net-metering come from behind-the-meter usage," but emphasizes that under the recommended 2-Channel Billing framework, the same BTM savings that current net-metering customers receive today will still be available to new net-metering customers in the future. Sub-Group 2 states that its recommended approach will allow the net-metering customer to retain the significant benefit of lower overall consumption and a lower bill, compared to non-net-metering customers. Id.

In addition, Sub-Group 2 argues, the 2-Channel Billing framework provides the correct economic price signals that promote and encourage net-metering customers to maximize the savings associated with the BTM usage. Sub-Group 2 also notes that the current 1:1 full retail rate credit has the practical effect of valuing all net-metering generation as if it were consumed directly behind the meter, and consequently, all of the cost savings associated with net-metering under the current 1:1 full retail rate credit comes from the level of net-metering generation and not with BTM usage. Id. at 20-21.

Sub-Group 2 argues against Sub-Group 1's suggestion that properly evaluating the BTM usage with a COS approach requires adjusting the Channel 1 rate as well as the Channel 2 rate, and disagrees with the "flawed assumption" that the current base rates contained in a utility's tariff are not capable of recovering a fair and reasonable level of costs from each customer based on their use of the utility system. Id. at 21.

In support of its position, Sub-Group 2 asserts that net-metering customers' infrastructure requirements for electric service are not different from those of other customers, noting that net-metering customers will still take energy generated by the electric utility via transmission and distribution facilities. Some customers will require more electricity and some less, depending on their needs, Sub-Group 2 says. Further, net-metering customers, like non-net-metering customers, expect safe and reliable service, and both use the same metering and billing systems, customer care and customer service functions and programs, and other utility systems. In short, Sub-Group 2 argues, when receiving electric service from the utility, a net-metering customer does not differ from any other customer and the electric service it receives will be measured on Channel 1. Id.

Sub-Group 2 states that the rates for energy charges are designed for the residential class to include all functional costs (generation, transmission, and distribution). SubGroup 2 adds that the energy charge for Channel 1 is based on the per kWh rate for electric service based on the class under which the customer takes service each month. Sub-Group 2 observes that the energy charge will vary between customers based on the usage needed and requested by each customer in the class; however, the approved rate per kWh (based on the cost to serve the class) will not change based on a net-metering customer's usage in the month. In other words, Sub-Group 2 states, the net-metering customer's bill may be less due to lower usage recorded on Channel 1, but the cost per kWh will not be less. Id. at 21-22.

Sub-Group 2 states that the current rate designs used by utilities in Arkansas for usage on Channel 1 appropriately recognize that customers have varying usage and demand profiles. According to Sub-Group 2, the only difference between a net-metering customer and a non-net-metering customer is that the net-metering customer owns generation, consumes a portion of its own generation behind the meter, and, at times, exports excess energy to the grid. Sub-Group 2 notes that the exported energy will be measured on Channel 2 and netted against the "imported" energy measured on Channel 1 "during the applicable billing period," as required by Ark. Code Ann. § 23-18-603(4).

Sub-Group 2 stresses that even when a net-metering customer's self-supplied energy is greater than energy received from the utility, the utility's obligation to serve the net-metering customer has not changed, and the investment incurred to fulfill the obligation to serve the customer likewise has not changed. Sub-Group 2 argues that SubGroup 1's flawed COS approach would lead to a new base rate for the energy measured on Channel 1. In fact and as demonstrated in its Attachment A, Sub-Group 2 states, SubGroup 1's COS approach cannot be applied to all customers, given that it would require a customized Channel 1 rate for each individual customer. Sub-Group 2 recommends against an approach that changes the base rate structure that is applied to all other customers in the class as part of this rulemaking proceeding. Sub-Group 2 contends that such an approach would likely entail separate rate proceedings to determine the COS for net-metering customers for each jurisdictional electric utility and the potential for implementing a rate structure with fixed or demand charges, which, Sub-Group 2 argues is ironically a result that solar proponents in other states have strongly opposed.22 Id. at 22-23.

Contrary to Sub-Group 1's assertion, Sub-Group 2 states that its proposed EGCR includes the benefits of distribution system line losses associated with the cost of delivering energy. Sub-Group 2 adds that its recommendation that no capacity-related distribution system benefits be included in the calculation of the rate credited to excess generation kWh measured on Channel 2 is based upon the COS studies underlying current rates. Sub-Group 2 contends that currently, there are no quantifiable distribution benefits provided by the net-metering customers, whether customers are receiving kWh from the utility as measured on Channel 1 or exporting excess kWh to the grid as measured on Channel 2, since the net-metering customer is using the poles, wires, transformers, and other distribution facilities of the utility. Sub-Group 2 states that if in the future net-metering customers provide any distribution system benefits, those will be reflected in future COS Studies for each utility and reflected in the rates the net-metering and other customers pay. Id. at 23-24.

Sub-Group 2 states that Sub-Group 1's argument is inaccurate because electricity consumed and produced is only measured in kWh. Noting that AREDA has mandated that the Commission establish a rate for net-metering,24 Sub-Group 2 states that 2-Channel Billing complies with all aspects of AREDA, as the approach measures the "electricity supplied" on Channel 1 and the electricity "fed back" on Channel 2 in kWh during the applicable billing period and establishes a cost-based credit for the electricity supplied to the grid by the net-metering customer. Id. at 25.

Sub-Group 2 observes that the statutory definition of net metering does not speak in terms of netting based on kWh; however, since electricity consumed and produced is only measured in kWh, Sub-Group 2 is simply establishing a monetized value (EGCR) for the measured amount of electricity (kWh) exported to the grid by the net-metering customer over the monthly billing period, which is consistent with the statutory definition of net metering in AREDA. Id.

Sub-Group 2 argues against Sub-Group 1's contention that 2-Channel Billing is confusing. Citing to Sub-Group 1's statement that "[t]he notion that a customer could have a bill today for energy usage, and also a kilowatt-hour credit that they cannot apply to the bill, is counter-intuitive and frankly, confusing,"33 Sub-Group 2 notes that the billing scenario that Sub-Group 1 describes regarding unused excess kWh rolling over to the next month is the same way billing is done today, is something net-metering customers understand, and is not confusing. Id. at 28.

Sub-Group 2 responds to Sub-Group 1's allegation that unlike the current net-metering policy, in which a customer "can look at past bills, compare to the system's output and calculate the monthly bill savings,"34 the 2-Channel approach contains "significant uncertainty" that makes it "very difficult" to determine the payback period of the net-metering facility."35 According to Sub-Group 2, AREDA neither requires the Commission to ensure a particular payback period or return on investment for net-metering customers, nor that the non-net-metering customer absorb the utility's cost of serving net-metering customers. Instead, Sub-Group 2 argues, AREDA requires the Commission to establish rates for net-metering service that recover the utility's entire cost of serving net-metering customers from those customers. Id. at 29.

Furthermore, Sub-Group 2 asserts, there is uncertainty surrounding the calculation of any long-term "payback period." The calculation is, at best, an estimate that is full of assumptions that never results in a precise estimate, according to Sub-Group 2. SubGroup 2 states that the standard rate for electricity pricing applied to Channel 1 is readily available, and the standard rate for calculating Channel 2 EGCR will be readily available as well, if 2-Channel Billing is approved. Using these two rates, Sub-Group 2 states, along with reasonable estimates of all of the other factors required to calculate a payback (including usage patterns), will result in a payback range. As shown in Sub-Group 2's Attachment B, Sub-Group 2 asserts that several other jurisdictions around the U.S. have adopted net-metering mechanisms that constitute a form of 2-Channel Billing. Sub-Group 2 adds that the prospective customers in these other jurisdictions that utilize 2-Channel Billing appear to be able to reasonably calculate a payback range and make a decision one way or another regarding investing in solar. Sub-Group 2 expresses confidence that Arkansas net-metering customers (with the assistance of their installers) would be able to do the same. Sub-Group 2 argues that any attempt to imply that a precise payback period can be calculated onlywith a full retail net-metering rate offset and/or with a precise customer-specific load profile is misleading, since there are so many other factors that can skew the numbers (including the weather, solar patterns, future rate changes, equipment performance, etc.). Sub-Group 2 views the expectation of a risk-free calculation as unrealistic, even with the best information. Id. at 29-30.

Sub-Group 2 re-stresses its assertion that under 2-Channel Billing the net-metering customers will continue to receive the full retail rate value for energy they self-generate and use behind the meter, which constitutes the majority of a customer's return on investment. Sub-Group 2 notes that the change in billing mechanisms only affects the energy exported to the grid and shows in Figure 3 below an example of an average EAL residential customer installing a 5 kWDC solar net-metering system, who would still be able to save over $50 per month under 2-Channel Billing in comparison to that same customer without net-metering. In addition, Sub-Group 2 states, the difference between the current rules and 2-Channel Billing is estimated to have less than a $10 impact on a customer's total average monthly bill.

Figure 3: Comparison of Net-Metering Savings

Id. at 30-31.

In response to Sub-Group 1's concern about the uncertainty that arises from the fact that the exported generation rate will presumably change with every COS update, the fact that the net-metering customer would thus need to forecast how their exported generation credit would change over the years, and that such a complex, essentially unpredictable rate design would frustrate the emerging self-generation market, Sub-Group 2 points out that all ratemaking contains, and will continue to contain, an element of uncertainty in forecasting long-term utility rates. Sub-Group 2 characterizes this as explicit in the nature of ratemaking and notes that all utility customers bear that uncertainty. No one, SubGroup 2 states, including current, grandfathered, net-metering customers, is guaranteed that rates will remain unchanged, and it should be no different for net-metering customers subject to the Commission's decision in this docket. Id. at 31.

However, Sub-Group 2 states, to minimize changes, the EGCR is designed to be relatively stable and to mirror changes in underlying base rate costs. Fuel costs, which make up a significant portion of the EGCR, Sub-Group 2 notes, will vary with the cost of fuel, just as is the case today, and 2-Channel Billing does not add to the uncertainty of forecasting rates over 20-25 years. Id.

Sub-Group 2 states that this type of billing structure for net metering has been adopted in numerous states without sparking any jurisdictional issues at the state or federal level concerning net sales or Qualifying Facilities (QFs) under PURPA, Pub. L. 95-617, 92 Stat.3117, enacted November 9, 1978) or the Federal Power Act, 16 U.S.C. Chapter 12. Sub-Group 2 states that FERC has ruled previously that sales of energy from net metering would only constitute a jurisdictional sale if it is a net sale, meaning that the exported generation is greater than the consumer generation over the course of the applicable monthly billing period. With net metering, Sub-Group 2 states, there is no sale; instead, there is a netting of kWh through the use of monthly billing credits. Sub-Group 2 explains that the net-metering customer is credited for excess kWh exported to the grid, and the credits serve to offset future kWh consumed by the net-metering customer. In conclusion, Sub-Group 2 cites MidAmerican Energy Co., 94 FERC ¶ 61,340 at 61,345 (2001) for the proposition that "[n]o sale occurs when an individual homeowner or business installs generation and accounts for its dealings with the utility through the practice of netting." Id. at 33.

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Id. at 33-34.

Sub-Group 2 takes issue with Sub-Group 1's conclusions regarding four figures SubGroup 1 provides comparing the energy consumed and energy exported by Sub-Group 1's five customers and Sub-Group 2's three modeled kW systems. Sub-Group 1 stated that "As expected, seasonal changes in grid energy use are readily apparent for Sub-Group 2's model systems and somewhat less discernible among the five customers. Likewise, seasonal patterns are obvious for Sub-Group 2's model and apparent, but more muted among the customers."38 The four figures are shown below. Id. at 35.

Fig.

Sub-Group 2 appends Attachments A, B, and C to its Sur-Surreply Comments as rebuttal to Sub-Group 1's Attachment A to its Reply Comments. Attachment A reproduces and responds in detail to Sub-Group 1's tables showing monthly bill savings for residential net-metering customers. Sub-Group 2 argues that Sub-Group 1's "flawed" COS approach cannot be applied to all customers, given that it would require a customized Channel 1 rate for each individual customer. Given that adjustments to Channel 1 rates cannot be individualized for every possible net-metering system, and setting aside the question of whether this would result in discriminatory rates, Sub-Group 2 argues that it is impractical from a ratemaking perspective to engage in such an analysis, since rates are designed for classes of customers, not individual customers. Sub-Group 2 further asserts that its 2-Channel Billing approach is simple to understand and can be applied universally to all utilities in Arkansas with bill impacts consistent from utility to utility. By contrast, SubGroup 2 states, Sub-Group 1's analysis is significantly more complicated, makes assumptions that are not in accordance with longstanding COS principles, and has bill impacts that do not remain consistent from utility to utility. Id. at 43-45.

Sub-Group 2's Attachment B purports to show examples from more than a dozen states that have approved net-metering crediting mechanisms where either 100 percent of the energy generated by a net-metering system is credited at a different value than the full retail rate (i.e., buy-all/sell-all arrangements) or only excess energy that is exported to the grid net of behind-the-meter usage is credited at a different value than the full retail rate (i.e., 2-Channel Billing, or net billing). Id. at 46-49.

Sub-Group 2's Attachment C responds to Sub-Group 1's development of tables showing an ANEC amount that is paid by each of the five actual customers provided by Sub-Group 1 using both the current 1:1 full retail rate credit and Sub-Group 2's proposed 2-Channel Billing.41 Sub-Group 2 notes that Sub-Group 1's analysis analyzes the annual percent increase in bills in support of its argument, while Sub-Group 2's analysis looks at the average monthly dollar increase in bills compared to the current net-metering rates.

The Commission cited Mr. Ball's comments (Joint Report at 311) recommending that the Commission look at remedies being adopted by other states, and that if the Commission does approve any additional cost, it should wait until there has been a full study and perhaps phase-in any new rates relative to the growth of net metering. Transcript Vol. 142 (T.) 610-11. When asked whether he had in mind any particular state that he thinks "gets it right in striking the right balance" and that the Commission should emulate, Mr. Ball responds that when one looks at the other states and what they have done, one sees that both sides are winning. Some states and local governments, like the city of Austin, Texas, actually did an evaluation and found that energy produced from solar net metering was worth more than the retail rate. Other states, like Nevada, found contrary to that, Mr. Ball states, and did something that was "quite onerous" from the perspective of pro-renewable energy development, and they had to come back and change that. He notes that they eventually grandfathered 32,000 installations that they had not done so on the front end. T. 611-12.

Mr. Ball testifies that Arizona took four years to come up with a satisfactory result, which he states somewhat emulates what he has tried to get passed through the Arkansas General Assembly since 2009, which was a law that would essentially monetize or give the ability to monetize production from solar and let utilities buy that power. By doing that, he asserts, the utilities would own the renewable energy credits and would be able to be reimbursed for it as a fuel adjustment charge because they are actually buying that energy. Mr. Ball cites as an example a poultry farmer that, under net metering, decides to produce his 5,000 kWh per month with solar, causing the utility to lose that sale and simply charge the customer a customer service charge. Whereas, if a process similar to that in Arizona were employed, the farmer would produce 5,000 kWh/month on a separate meter, which the utility would buy at a fair market value. The farmer would still buy his 5,000 kWh on his consumption meter and be repaid for his investment. The utility would retain the renewable energy credit (REC) and be able to recoup its purchase cost. Mr. Ball states that Arizona found that net-metering generation is worth about 12 cents per kWh. T. 612-14.

When pressed whether he believes there is enough data or penetration of solar to do a study in Arkansas, Mr. Ball states that he does not, citing as a contrasting example Louisiana, which has 25,000 solar systems and noting that Louisiana took Arkansas's net-metering statute and substituted Louisiana for Arkansas, but also embraced renewables by adopting a 50 percent income tax credit. T. 614.

In response to a Commission question regarding the Little Rock Port Authority and a project Mr. Ball is participating in, Mr. Ball acknowledges that the commercial and industrial (C&I) customers in that project pay a demand charge and states that he had suggested in the NMWG meetings that there be consideration of changing from a volumetric approach to a demand approach for residential customers. He states that he thought he got some consensus from the utilities that the way net metering was originally set up it did not envision what the impacts would be. Whereas, he notes, for C&I customers, they are paying their fair share of the grid through their demand charge. Mr. Ball testifies that he believes that Walmart agrees with him, thinking that commercial customers would not necessarily be negatively affected because they already pay a demand charge and are thereby already paying their fair share of supporting the grid. T. 615-17.

Responding to a Commission question regarding whether there is or should be a silo around solar through net metering, whereas it is not the only distributed energy technology, Mr. Ball states that the Distributed Energy Resources (DER) proceeding in Docket No. 16-028-U is going to be a "tough docket." He asserts that there is less experience with wind, biofuel, and other potential DERs than there is with solar and thus may require more direction from the legislature on how to proceed with distributed generation. Mr. Ball cites examples of utility-scale wind or solar projects that, under state law, allow utilities to make the investment through a power purchase agreement (PPA) and to get a "special dispensation" to increase what they charge from that investment, but points out the unfairness of customers in all classes investing their capital in solar not having the same liberty to enter into PPAs and get a more fair market price for the energy they produce. The only recourse for most of those customers, he states, is net metering. T. 618-19.

Mr. Ball responds to a question about how storage will work under the existing net metering law, stating that if there is a decision that would seriously negatively impact net-metering customers, there will be a lot more storage, since the customer will be incentivized to keep all of his/her consumption behind the meter and not export anything. Customers will store energy in their batteries and when the sun goes down draw from them and use their own power and self-consume. He cites Hawaii as an example of a state that reached 20 percent of solar penetration and could not distribute or dispatch the amounts of solar energy being produced during the middle of the day. He states that Hawaii thus did away with net metering and went to battery-based self-consumption. Mr. Ball states that he has been approached by utilities to evaluate storage so that during the day when solar is making energy, there is nothing put on the grid until after 5 o'clock p.m. when solar can be used to keep the peak demand down. Mr. Ball opines that storage and other technologies are in their infancy regarding services they will be able to supply and urges continued support for net metering to be able to capture these additional benefits. T. 620-21.

Mr. Ball responded to Commission questioning regarding how distributed energy resource alternatives can be consider in the integrated resource planning (IRP) process, so that one can figure out which is the best value for customers going forward, stating his concern that utilities have not considered the possible exponential growth of electric vehicles (EVs) in their IRPs. He advances the possibility that EVs may produce so much growth in demand on the electrical infrastructure that "we're going to be begging for more solar." Mr. Ball agreed that since one can't predict the future, there is a need for a policy that can accommodate a fairly wide range of technologies without having to go back and do "do-overs" like was done in Nevada. He concludes with the recommendation that the best move is to go slowly and make adjustments as conditions change. T. 623-24.

Mr. Fogleman, attorney for Pulaski County, responded to Commission questions, acknowledging that if the Commission were to agree with Pulaski County that a wait-and-see approach should be taken until there has been enough solar penetration in the state to justify a study, that approach would provide certainty for net-metering customers up to that level of penetration, but would carry with it a degree of uncertainty. Mr. Fogleman adds that the Commission needs to make rules that are durable and ask whether adopting a rule that may last for five years would be sufficiently durable, considering the rate of solar implementation and saturation. He questions whether there has been adequate evidence presented to demonstrate a net cost shifting to the utility, given the current level of penetration. He suggests that if the Commission does nothing now and at some future point a sufficient saturation level is reached, it would be appropriate to grandfather people from the reopening of a docket until a new rule is adopted. That approach, he opines, would permit net-metering customers to be able to take advantage of a stable policy structure that allows them to project into the future in order to make sound investments. T. 626-30.

Mr. Fogleman expresses a concern that a non-residential customer currently operating under a tariff with a demand charge should not be excluded from the possibility of shifting its usage to a rate class with a lower demand charge and a higher volumetric rate and thereby being able to reduce their cost by agreeing to net metering under a higher volumetric rate. With respect to demand response, storage, and other DER, and how to make the net-metering rules consistent with what the Commission may do in Docket No. 16-028-U, he states that it would depend on what rules the Commission adopts in that docket or what the legislature may do in the future. T. 631-33.

At the conclusion of Mr. Fogleman's testimony, Mr. Ball voiced the opinion that for purposes of determining saturation levels of solar, it does not matter whether the resource is utility-scale or residential, adding that in Arkansas, about 2,500 MW of nameplate solar capacity will equate to around 20 percent saturation. T. 633-34.

Mr. Beach is the author of The Benefits and Costs of Net Metering Solar Distributed Generation on the System of Entergy Arkansas, Inc.(the Crossborder Study), Attachment A1 to the Joint Report of the NMWG; the supplemental COS analysis, Attachment A to Sub-Group 1's Reply Comments; and a response to the critiques leveled by Sub-Group 2 to his cost-benefit analysis, Attachment A to Sub-Group 1's Surreply Comments. He responds to Commission questions regarding these analyses, which were submitted on behalf of the Sierra Club and Sub-Group 1. T. 635-36.

Mr. Beach testifies that the NMWG did not reach agreement among the group as a whole to do a comprehensive study, but that the Crossborder Study of EAL was done for Sub-Group 1. He states that the study that was done was good, given the data that was available, although it is probably not as accurate as it could have been with better data. Mr. Beach states that when assessing penetration levels, one can look at either the number of net-metering customers or the amount of megawatts of solar. He cites Hawaii as an example of a state that has high penetrations of solar, approaching 20 percent of customers, making it very clear that they needed to move away from net metering because they were starting to have problems on their distribution circuits with too much solar in the middle of the day. T. 638-41.

In response to Commission questioning, Mr. Beach explains how California undertook to evaluate the economics of net metering and its effects on participating and non-participating ratepayers in a 50,000 MW system that has just less than 5,000 MW of solar - approximately 10 percent penetration based on nameplate capacity of distributed generation as a percentage of peak demand. He states that California, using a consultant, developed and made public a tool that employs all of the tests that Crossborder did for its Arkansas study. He notes that the parties to the proceeding, called Net Metering 1.0, submitted comments and results regarding whether there was or wasn't a cost shift, using that template of the public tool. He states that, in the end, California made some small changes to its net metering rates, which have an export rate that is slightly lower than the regular retail rate. California is now in Net Metering 2.0 and will continue on that path for several years and may look at it again in 2019. T. 642-44.

Mr. Beach provides Arizona as an example of another state with a large system and about 5 percent penetration of solar and opines that the importance of the penetration level is a matter of both the importance of having a good amount of data to use and of considering whether there is more than a de minimisimpact on non-participating ratepayers. He states that when the penetration level gets to the 5 percent customer level, where solar starts to have an effect on the system, one starts to see lower prices in the middle of the day and "duck curve" issues, with sharper ramping needs in the evening when the sun goes down. T. 644-45.

Mr. Beach was questioned by the Commission regarding Sub-Group 1's assertion in Attachment A to its Reply Comments (p. 31-41 of the White Paper) that there is a lesser cost to serve net-metering costs, as contradicted by Sub-Group 2's response in its Surreply that net-metering customers' infrastructure requirements for electric service are not different from those of other customers and that the utility has the same obligation to serve them. He was also asked to respond to Sub-Group 2's assertion that Sub-Group 1's approach would lead to a new base rate for EAL on Channel 1 and would, in fact, perhaps require a customized Channel 1 rate for each net-metering customers. Mr. Beach responds that Sub-Group 1 is not advocating for a different rate on Channel 1, noting that Sub-Group 1 does not agree with Sub-Group 2's COS analysis, which he notes was directed only at revising the export rate. He testifies that Sub-Group 2 did not apply their own COS analysis to the Channel 1 usage. He explains that when a customer installs solar, it changes the profile of the service they take from the utility, and the Channel 1 usage of a solar customer is quite different than the usage of a regular customer. Mr. Beach further explains that while Sub-Group 1 is not advocating for a separate rate class for solar customers or a lower rate on Channel 1, it is pointing out that Sub-Group 2 forgot to take into account that analysis of Channel 1 usage shows that solar customers are actually less expensive to serve than regular customers. If a net-metering customer is going to continue to pay the same rate under Channel 1, Mr. Beach states, there is actually a subsidy going the other direction, with solar customers subsidizing regular customers. T. 646-48.

Asked by the Commission why a separate rate for net-metering customers would be bad, Mr. Beach responds that the great virtue of net-metering is its simplicity and that customers understand that it means running your meter backwards and feel that it is fair to solar customers. T. 648-49.

Mr. Beach acknowledges that one could look at 2-Channel Billing as consisting of three buckets: Channel 1, in which electric service from the utility is paid for at the regular retail rate; a "neutral" one-for-one bucket of energy produced from the customer's solar panel for instantaneous use on-site and which effectively offsets the retail rate; and a third exported power bucket compensated at the retail rate, which Sub-Group 2 contends is getting too much credit and undercutting costs in the first bucket. Mr. Beach responds, however, that Sub-Group 1 contends that when one puts solar panels on a house, part of the power stays on-site and is used to offset load. The net effect of that, he argues, is that you reduce the amount of power that you have to take from the utility, which Sub-Group 1's analysis shows turns that solar customer into one that is less expensive to serve. He reiterates that Sub-Group 2 did not take that into account. T.t 649-51.

In response to Commission questioning regarding the differences between a net-metering customer and a customer that reduces its load and energy consumption through implementation of energy efficiency, Mr. Beach explains that a customer with solar can produce up to 100 percent of his usage using solar and thereby provide benefits to the utility, which is more than one can do with an energy efficient appliance or measure. He asserts that Sub-Group 2 wants to cut the export rate in half, which is unfair to the solar customer that is providing benefits to the utility. In short, he argues, the net-metering customer would be taking a big cut on Channel 2, but the benefits the customer is providing on Channel 1 are not being taken into account. T. 651-52.

On the subject of the benefits side of the equation, the Commission asked which of the largest direct, quantifiable benefits of avoided energy, avoided generation, capacity, avoided transmission, avoided distribution, and avoided line losses does Sub-Group 1 assert are not being fairly credited by Sub-Group 2. Mr. Beach responds that the biggest difference would probably be avoided transmission and distribution costs. He also notes that Sub-Group 1 did a long-term analysis that goes over the life of a distributed generation system rather than just a single-year analysis. That approach, he states, results in energy benefits being somewhat higher because Sub-Group 1 considers the fact that energy prices are going to escalate over time. T. 653-54.

Mr. Beach discusses Sub-Group 1's expanded set of benefits, some of which are quantifiable and others which are not. He cites reduction of fuel price volatility as quantifiable and acknowledges the difficulty of quantifying reliability and resiliency and the fact that solar cannot provide backup power. On the other hand, he cites solar as a foundational element for a microgrid, which with batteries becoming more economic, could provide a backup system to enhance reliability and resiliency. T. 654-56.

Mr. Beach testifies that "cost of service" is a "trick term," and describes Sub-Group 1's analysis as a COS analysis that looks at the COS over 25 years, not just over a single test year. Sub-Group 1 looks at how the utility's costs going forward will be reduced by distributed generation, he states, noting that those are costs that would otherwise land in the COS. T. 656.

Mr. Beach expresses unfamiliarity with the Entergy Mississippi "adder" for unquantifiable benefits and the state's taking a pause to do a study, but he acknowledges that some states have adopted a similar adder in the energy efficiency context when societal and non-energy benefits are difficult to quantify. T. 657.

Mr. Beach explains the meaning of "intermonth netting" as netting imports and exports of energy on a time scale between instantaneous and monthly, depending on meter capabilities. T. 657-60. He also discusses Sub-Group 1's suggestion that the Commission initiate a process that encourages utilities to study their distribution system with an eye to increasing efficiency, improving the transparency of distribution system planning, and understanding how emerging distributed energy resources can be leveraged for the benefit of all customers. He cites New York and California as states that are starting to make a serious effort to guide the deployment of DERs to parts of the grid where they produce the most benefits. T. 660-663.

Mr. Beach elaborates on Sub-Group 1's failure to advocate changing the Channel 1 rate to recognize the benefits provided by the net-metering customer, stating a preference to keep things simple for the customer and thus to keep the export rate and the import rate the same. In short, he said, Channel 1 balances out Channel 2. He also expresses support for implementing pilot programs to get more data on net metering, citing the example of Xcel Energy in Colorado, which is implementing Advance Meter Infrastructure (AMI) infrastructure and piloting time-of-use rates of various kinds in order to increase the accuracy of the rate design and send better price signals to customers. He states that these kinds of initiatives would be important steps before making changes to net metering. T. 664-65.

In response to Commission questions concerning the Crossborder Study, Mr. Beach testifies that there is no projection in the Study of how many net-metering customers there will be in the future. Instead, he states, the Study looks at the costs and benefits for a customer who installs the distributed generation study today, because that system will be around for 25 years. For example, he explains, it is known that the system will avoid the utility having to produce energy in one of its power plants, so the Study did a 25-year projection of what that avoided energy cost would be for the solar panel that's being installed today. He states that the Study looks at marginal costs - the kilowatt-hour produced from a solar panel that's installed today will turn down a power plant and save the marginal kWh for the next 25 years. The Study forecasts what the cost of that is by looking at what the gas price forecast is over time. T. 665-66.

For avoided generation and transmission capacity, Mr. Beach states that the Study looks at a levelized cost of capacity. For example, he explains, you assume that if you're providing a kilowatt of capacity from a solar panel, that will avoid having to put in a kilowatt of a combustion turbine, and you calculate what the levelized cost of that combustion turbine is over the 25 years. The same is done for transmission and distribution, he states: what does installing a kilowatt of solar do to reduce the future investment of T & D that results from that savings of a kilowatt? T. 667-68.

Mr. Beach disagrees with Sub-Group 2's claim that these benefits will materialize over time, arguing that these are costs that the utility will never have to incur - they are avoided costs. He adds that the costs that will show up over time are actually lower, whereas if you just continue to do a set of COS studies the way Sub-Group 2 recommends, you will be significantly undervaluing the solar resource. In response to questions regarding whether the Sub-Group 1 study should have conducted a projected future or an after-the-fact re-dispatch to calculate the marginal value of a missing generation unit, Mr. Beach cites California's 5 gigawatts of solar and expresses concern that trying to reconstruct what a system would have been without those resources is going to be pretty speculative. He suggests that it is better to do it the way Sub-Group 1 did, where one is looking at what is the value of just what you're installing this year. He states that this is exactly the same analysis that one does with energy efficiency programs. He testifies that the benefits are not sunk costs, but are future costs that you are not going to have to spend. Mr. Beach acknowledges that trying to project the benefits and costs over a long period of time with any long-lived resource requires a forecast of fuel prices and other things and presents challenges. He states that one needs to look at sensitivities and key input assumptions, but notes that is the way one does planning. T. 669-73.

Mr. Beach responds to Commission questioning regarding the challenges of getting to a glide path from a 2-Channel Bill approach to a market system, where a demand charge becomes the basis of a capacity cost and the energy is the energy cost, and that's how it gets compensated. He recommends that the Commission work on metering infrastructure and rate design such as TOU rates, even demand charges (though he is not a fan), while letting the solar market in Arkansas grow beyond its fairly small stage today. He also recommends watching what other states with higher solar penetrations do with their net-metering programs and rate experiments and acting on information you will get when you reach 5 percent of customers. T. 673-75.

With respect to demand charges that assertedly give one a price to beat to determine whether to deploy storage, Mr. Beach expresses concerns that such charges are often inaccurate. For example, he states, a demand charge covering transmission costs driven by demand between the hours of 3:00 p.m. and 7:00 p.m., actually applies charges to a customer's highest demand 24 hours a day - which might occur at noon and thus not be a driver of transmission costs. This, he says, causes the customer to pay a very large bill that month - a nonsensical result. With a demand charge like that, he notes, storage ends up discharging in the morning or at noon, when it's not really beneficial to the system. T. 676-77.

Mr. Beach testifies that one of the issues Sub-Group 1 has with the Sub-Group 2 proposal is that they have designed an export rate based on solar alone, while there are a lot of DER technologies such as batteries, EVs, smart thermostats, etc. that would be better accommodated by a whole proliferation of different rate schedules for different kinds of technologies. He asserts that it is better to work on overall rate design and get price signals right across all the hours of the day. T. 677-78.

With respect to duck curve issues, Mr. Beach testifies that the most important driver is whether you have so much solar on your grid that it's changing the fundamental economics of the system. In California, he notes, there are now very low prices in the middle of the day and fundamental changes in load profiles. When that occurs, he states, that is the time to take another look at the economics of net metering, but it takes quite a bit of solar for that to happen. T. 679-681.

Ms. Niebaum testifies in support of continuing the current net-metering policy, stating that Arkansas is an example of a state that is "getting it right" and allowing the growth of the solar industry, with associated job growth. She states that both the reduced export rate and a departure from the simplicity of the full retail rate would chill this growth. She states that the Sub-Group 2 approach is overly complex and would require a solar provider to electrically meter-log a client's residence for a full year to get an accurate picture of what a customer's usage is before proposing and installing an array. These complexities would dampen and stifle deployment and growth, she notes. She acknowledges, however, that moving toward a market-based world so as to integrate all of these technologies is going to take some complexity, and expressed the opinion that it is a goal AAEA shares. T. 682-86.

Mr. Halter responds to Commission questions regarding whether an additional study should be conducted and whether there is a subsidy being provided by non-net-metering customers, including low-income customers. He states that Sub-Group 1 from the beginning of the NMWG felt that a study was the best way to get to a more precise answer. Second, he states, there is not enough data to do everything that is asked in the law, because the law asks that this be done utility by utility. The constraint there, he notes, is that some utilities have only a handful of net-metering customers, with little data. Mr. Halter cites the experience gained in other states and asserts that, directionally, the Arkansas-specific answers are unlikely to differ dramatically. Accordingly, he states, one can get some useful information from comprehensive studies that have been done in other states. He expresses the belief that there are less than a thousand net-metering residential customers in Arkansas. With this assumption, and assuming that the average utility bill is $70 per month or $840 per year, there would be $840,000 of total billings to those customers. He suggests that the cross-subsidization of that $840,000 would amount to "a hill of beans." Acknowledging a Surreply estimate in the record of a $60,000 cross-subsidy, Mr. Halter urges the use of common sense and asserts that ratepayers are already paying for more than that in legal fees to deal with the NMWG (perhaps racking up that much in one meeting of the Group). He asserts that Arkansas is not far enough along to be doing a lot of radical surgery on net metering. T. 688-94.

Mr. Halter asserts that a residential customer that is considering solar is faced with at least a $10,000 expense and the need for the solar provider to project what that is going to save in electricity bills over 25-30 years, plus consideration of the federal tax credit, and the need for financing. He states that this is already a tough decision that is information-constrained since the customer doesn't know what's going to happen with energy prices down the road and other unknown variables that could change. He acknowledges that the Commission's job is to make sure that the regulatory environment gives as much certainty as possible. With 2-Channel Billing, he states, all of a sudden the confusion and risk for the customer is suddenly ramped up because the payment to the customer varies over time. T. 695-67.

With respect to the asserted cross-subsidy by non-net-metering customers, Mr. Halter contends that the Sub-Group 1 study shows that the subsidy is going the other way. He suggests that with 2-Channel Billing, it borders on impossible for the customer to predict how much energy is going to fall into the excess channel, or what the specificity of its timing is. On top of that complexity, he notes, Sub-Group 2's proposal will change the prices for the customer year-by-year, which leaves the customer no way to accurately predict what he's going to save over time. Finally, he notes, if the customer can't predict it, the bank is not going to finance it, and thus he contends that 2-Channel Billing will deal a mortal death blow to residential solar. T. 698-701.

Mr. Halter testifies that a residential solar system producing excess energy is likely producing more excess energy when the value of that electricity is higher, namely at peak. He cites as an example the large commercial facility his company is installing for Clarksville Light & Water, which provides power during daylight hours on peak. Thus, Clarksville's system is providing not just energy savings, but demand charge savings for that municipality, as well as reductions in transmission charges that they face. He asserts that what Scenic Hill is doing for a municipal utility on a commercial basis a lot of residential solar systems collectively would be doing for the utility in their service territory - providing a benefit. T. 701-03.

With respect to utility assets that are "on the books" and must still be paid for, Mr. Halter notes that there are generating assets in the system that are going to be shut down. A better thing to do, he states, is to allow the private sector to provide incentives to deploy solar to replace the generation capacity from those assets that are going to be taken off the system. Using private sector capital to do it, he notes, means that the developers don't get a guaranteed return on their investment. He states that market incentive works pretty well for such developers - if they don't do it right, they're out of business. T. 703.

In response to a Commission question regarding how to get to a future in which private solar projects that are not dispatchable can be taken account of in a system where utilities have an obligation to stand ready to serve everyone 24/7, Mr. Halter states that utilities size their generation assets to address peak load, which is when private solar plants are helping shave that peak load. He adds that, while Arkansas does not have a duck curve problem, by the time that phenomenon might occur, there will be storage technology that eliminates the duck curve. Wind energy will be imported at night, stored in batteries, and dispatched as electricity during the day, he states. He states that he does not foresee doing without regulated utilities, but notes that other places have used private sector generating assets to help solve some of these problems. T. 703-05.

Mr. Halter extols the power of competition, the power of the free market to allocate resources appropriately, and the long-term desire of citizens for as much consumer choice as possible. He urges the Commission to address these three things in a way that helps, not harms, the system. T. 705-06. While noting that tracking systems address the declining value of the last hour of solar generation, he acknowledges the dilemma pointed out by the Commission: that while solar is highly correlated with peak and the time of day, the Arkansas statute says we can't differentiate that power or the value of those hours because we have got to trade kWh for kWh instead of value kWh for kWh, which makes it complicated to capture that value. T. 706-08.

In a discussion regarding fuel price volatility, Mr. Halter asserts that unpredictable shifts in the price of natural gas make the case for installing as much solar power as possible, noting that he can tell you to one one-thousandth of a penny what you're going to pay for solar power 30 years from now if you put in a plant today. He states that you have completely hedged fuel price volatility the more solar you deploy. On the other hand, he notes, if gas prices go down, gas customers will be celebrating, natural gas companies are happier, and solar providers are still happy. In short, he says, everybody is happier than in the alternative state of the universe where we didn't have enough fuel price hedges in place. He asserts this is an additional value of solar that needs to be put in the model. T. 708-14.

Mr. Halter agrees with the assertion that it is preferable to gradually move to a market run by individuals with different views about prices rather than a regulatory decision on what prices are going to be and urges the Commission to let that market work. With respect to that market, Mr. Halter asserts that there are two major sources of market inefficiency when it comes to renewable assets:

Ms. Costner responds to Commission concerning her experience as a 3.3 kW solar-plus-storage customer of Carroll Electric Cooperative Corporation since 2005. She provides Attachment B to Sub-Group 1's Reply Comments, which contain data and analysis that illustrate the different impacts that 2-Channel Billing would have on her residential net-metering account. She states that her bill is almost always $12.61 per month, comprising just over $10 for the monthly customer charge and $2 in taxes. She states that Attachment B shows what she is paying every year for electrons alone -- $0 for electricity under one-to-one retail net metering. According to her calculations, she says, under 2-Channel Billing she would pay $48.54 per year. She states that she has invested $35,000 in her system, for which, when she started it in 2005, the cost was $10 per watt; she believes the cost is now down to $3.85 per watt on a national basis. She notes that Carroll Electric Cooperative Corporation has been very cooperative over the years, although they have had difficulty getting the billing right from an accounting perspective, and observes that 2-Channel Billing would be more of a challenge for them. T. 730-736.

Ms. Costner provides in her Attachment B an analysis of the bills under both billing approaches for four of her neighbors' systems, each of which have larger systems than hers and none of which have storage. The results are as follows: Customer PB2, with a 9.8 kW system, had an annual energy bill of $147, which would go up to $528.93 under 2-Channel Billing, an increase of 258 percent. Customer PB3, with an 8 kW system, would go from $661.20 to $815, and increase of 23 percent. Customer PB4, a 6 kW system, essentially offsetting all their usage, has a zero bill for energy under current net metering and a $200 bill under 2-Channel Billing. And Customer PB5, a 10.8 kW system, pays $11 under net metering and $511 under 2-Channel Billing, a 359 percent increase. T. 736.

Ms. Costner concludes from her analysis that the larger the solar system, the longer the payback period. She does not agree that this is just because those larger systems tend to export more to the grid, but thinks the 2-Channel Billing system disincentivizes people to discourage them from building a system that is going to be closer to getting them their maximum offset. However, when questioned further she does agree that it makes sense that the larger systems, having a larger quantity of export, and that the export is reduced more under 2-Channel than the current one-for-one approach, and thus the more export you have, the more impact. T. 736-40.

Ms. Costner testifies that records show there are 632 net-metering customers at the end of 2016, as compared to about 495 at the end of 2015. The 2016 numbers thus amount to 0.045 percent of the ratepayers, which, she says, under a trend line would lead to about 1200 customers in ten years. She cites to the public comment testimony of one of her neighbors as saying that if he had been looking at installing a system under 2-Channel Billing, he would not have gone forward with it. She states her belief that this will be the case for most people - 2-Channel Billing discourages people from investing in solar. T. 740-41.

Ms. Costner addresses the subject of pilot studies and opines that focusing on more systems in a smaller area, such as Carroll Electric, might make for easier access and data retrieval than with a larger system in a larger area, like Entergy's. Ms. Costner describes her battery system, which enables her to flip a switch when the grid goes down. She notes that none of her neighbors have battery storage. T. 742-44.

The Commission questioned Mr. Rabago regarding Sub-Group 2's assertion that the 2-Channel Billing approach is desirable because it tries to treat people who adopt energy efficiency the same way as net-metering customers, in that if you're offsetting your own usage instantaneously, then you're charged the same rate on Channel 1 as every other residential customer. Thus, the only thing the 2-Channel approach does is change the credit given for exported power. Asked whether the 2-Channel proposal seeks to treat everybody the same on the cost side, but maybe not on the benefits side when it comes to energy efficiency, Mr. Rabago states that at a very simplistic level, the fact that a customer reduces electricity use, however they do it, results in a reduction in what they otherwise would have paid. He explains that they could either do it by turning off the lights or by having their solar system run or discharging their battery if the grid is down. T. 744-46.

Mr. Rabago testifies that tariffs are contracts that are binding merely by acceptance by a qualified offerer and, because utilities have immense market power, we only pay for what we use, and don't pay for what we don't use. He says that is embedded in net metering and is reflected in the fact that if you don't use some electricity because of energy efficiency, or self-generation, it nets out. Thus, he agrees that it is different as to the exports, but it's not different just as to the rate. Mr. Rabago states his understanding that Arkansas has a differential rate for excess generation, but notes that what is different is the netting period. He observes that Arkansas's statutory definition of net metering is the same as the PURPA statutory definition, which is netting within the billing period. This, he explains, goes to some log-time that looks like instantaneous or very close to it, as opposed to allowing you to net on the monthly basis against your total gross consumption against your gross production. That, he says, is even more important than the export rate. T. 746-47.

As to the compensation rate for exports, Mr. Rabago says there is a difference between EE and net metering because you don't export from EE - you free up electricity but you don't make some. If you make an extra kWh with a solar system, he states, it goes immediately to the closest possible load on the grid, which is a neighbor, and then it goes through their meter and gets billed as if the utility made it. T. 747-48.

With regard to valuing the excess energy credit on an embedded COS method, Mr. Rabago cites Mr. Beach's report as saying that using the embedded COS study is like trying to drive 100 miles an hour with your eyes firmly fixed on the rearview mirror: All you know is what it cost to serve during that historical test year, which is based on antique data with known and measurable adjustments for one year's worth of service, a snapshot of amortization, the current state of capital acquisitions, the capital plan included in that rate, and the operating expenses as of that year. He states that when he was a regulator it was not how he evaluated energy efficiency or any other resource. T. 748-49.

Mr. Rabago states that this is a fundamental difference in the two approaches and asks whether the utilities are proposing to treat this as a resource or are they treating it as a deviation from the expected level of revenues for an average customer in that class, which is what the embedded COS study does. He states that all the embedded COS study turned into a rate does is take those numbers, applies the forecast, and says that if I then charge this resulting rate, the resulting revenues will equal my revenue requirement. He adds that the embedded COS approach used by the utilities and Staff says that if you reduce your consumption below the level that we expected, we now have a cost: It creates costs out of failure to consume the average consumed level for your class. He acknowledges that this gets into the three buckets way of looking at it, discussed by the Commission earlier in the hearing. If Bucket 1 is net consumption, Bucket 2 is consumption that is offset, and Bucket 3 is net product, he says it is a fair question to ask whether you should still be charged the same rate per unit of consumption for when your usage pattern changes. Going back to how rate cases are done, he states, they deploy a number of sample meters, come up with a sample profile of use by customers within that class, and then classify and allocate costs according to that pattern for all those customers. Since solar customers shift their peak off the average, in general, he says, they tend to contribute less to the system peak, although they don't eliminate it. T. 749-52.

Asked if some energy efficiency programs also reduce the system peak, Mr. Rabago says yes, they do, and when asked why do we not then charge them a lesser rate, he responds that actually we do charge them a lesser rate by providing incentives to cure the market failure that fails to compensate them for bringing that value to the system. You do that with a clean conscience, he observes, because as conservative and market-oriented as you may be, you know that you can pay those incentives, not cross the cost-effectiveness barrier, and still end up doing well by all customers. Thus, he states, you're already correcting for the under-compensation for those customers, but you do it with incentives. T. 752-53.

Questioned by the Commission about using an embedded COS approach to quantify benefits, Mr. Rabago - a lawyer - testifies that he cannot imagine why Sub-Group 2 went through the contortions they did to try to put blinders on the Commission's decision-making. He opines that the approach is not supported by the plain language of the statute. He states that it strains credibility to say that you will get your reward in heaven - or whenever we do our next COS study. Mr. Rabago states that there are a bunch of benefits and that there are IRP-types of analyses for looking at the long-run life of resources. He says that utilities regularly use production cost models and look at resources that last 20 and 30 years and have ways of bringing those all back to a LCOE comparison so that one can start identifying which resources to use. He states that the embedded COS study is so far from that, that it's convenient to think of the way that Sub-Group 1 put forward Mr. Beach's report as being in the middle. He says it uses as much real data as it possibly can, but of course, so does an IRP, and it asks: If we add another kWh of electricity from this solar when it's likely to appear, what other costs will it avoid? He adds that even PURPA lists a much broader range of benefits than was used by Sub-Group 2. T. 753-55.

Mr. Rabago testifies that excess energy credit is a rate or a billing determinant, but the full rate is the net-metering rate. Clearly, he states, Sub-Group 2 proposed a 2-Channel alternative as a bundle of rate components that they propose as a rate. He notes that all commissions set rates considering a wide range of factors and are encouraged by the full language of the act to keep those issues in mind as a matter of policy. He states that commissions deviate all the time from one person's opinion about what is the right way to calculate a rate because there's a lot of subjectivity in ratemaking. He also states that he does not "get" the idea that - because somewhere rates for consumption are described in a statute that was written for the notion that the only thing customers would do is consume - that somehow in spite of very different language in a new statute, you must give no meaning or intent to the new statute and hold yourself to the unchanged language of the old statute. In short, he says he has never seen an approach that, absent an explicit mandate, says that when you set the net metering rate you should ignore the benefits that you find. T. 755-78.

On the subject of value-of-solar studies, Mr. Rabago points to Minnesota as the gold standard and Maine as another one of the best, most recent comprehensive ones, various ones of which are cited in Sub-Group 1's Appendix A to its initial comments in the Joint Report. He notes that Minnesota completed its study in six months with a third-party facilitator and hundreds of comments, plus three rounds of Commission review, plus another round of review when the utilities adopted it. He also cites to a recent working group process in Rhode Island that created a table of all the bulk and small-scale net-metering values, which was adopted by the commission. He notes that in conducting a study it would help to have thousands of customers, so you could get some real statistical meaning to how their load curves change. T. 758-61.

Mr. Rabago cautions that there are other issues to deal with in doing such studies, because to the extent that the COS studies rely on non-coincident peaks (NCP), you'll run into a situation of erasing any of the peak-shifting benefits of solar. Just looking at the Channel 1 costs of a subgroup of solar customers, pretending as if they were on an island served by one grid themselves, which is what NCP approaches do, then you'll miss the fact that they're integrated into the grid in general and they actually help improve asset utilization and improve load factor for the entire grid by shifting their peak off-peak. He states that NCP systems don't catch that, and that you need more of a focus on coincident peak. T. 761-62.

With respect to the market, Mr. Rabago shares the idea that what we're trying to do is figure out, if these customers with solar are exporting, how do we create a system in which they only export the good stuff - the stuff that's worth more, the stuff we really want -- to displace what the utility made. In his view, Mr. Rabago states, the reduction of a cost does not create a cost. What that does, he says, is demonstrate that the utility thought they were going to sell a hundred, but now they're only selling 90 and they are going to reallocate the 10 they thought they could get. He notes that some have been calling for solar for 20 years; and now that it's appearing, the utilities are saying - wait, I built this distribution system as if there'd be no solar. And so, he states, there's a question of what price signal do you want to send in the marketplace to the utility to do a good job of forecasting, and do you want to insulate them from the consequences of bad forecasting? T. 762-63.

On the point of the law requiring that utilities recover their prudently incurred costs and the question on making an exception so that the responsibility falls on the utility, not the customers, Mr. Rabago responds that it is important to take the longer view. He testifies that if you limit yourself only to those embedded costs and treat all fixed costs as sunk costs, which he says is a kind of category error, then you will ignore the fact that there is a demonstrated reduction in future fixed costs. He agrees that in the long run, all costs are variable. But, he states, you know that you will experience a reduction and have to take into account the fact that, yes, there's a 10 kWh shift now, we'll allow them to recover it, but we're balancing that using LCOE against the fact that we believe there are more avoided costs in the future. That's what we do, he says, when we look at it as a resource. T. 763-64.

Asked how can the utility plan, with distributed generation that can pop up anywhere in either ideal or not-ideal places, Mr. Rabago responds that at a very simplistic level, you need data - short-, mid-, and long-run marginal distribution capacity cost at the sub-nodal, maybe feeder level through your grid. You need the utilities to know it, he says, and to know what does the next increment of capacity or energy cost at the sub-nodal level. He urges the gathering of that data so that you can do things like New York is trying to do - come up with the locational system resource value (LSRV), saying that if this solar system ends up over here, it's worth an extra penny per kWh., but if it comes up over there, it's going to be adding to a pre-existing congestion problem and it's not worth that extra penny, it may be even worth one penny less. But, he continues, until you have that data, you won't be able to send that market signal. T. 764-65.

Mr. Rabago states that the utility has to act like a bit of a billboard for prices, which is why some in other states are talking about a platform model. He adds that the utilities have to resist the temptation to live by a mantra that they and only they should be able to generate electricity, and instead treat generation that comes from customers as a resource that could have value in the right location and at the right time. T. 765-66.

Asked how the traditional distinction between energy and capacity plays in the absence of a demand charge - i.e., how can you retain that when you have two different price signals - one for capacity and one for energy, Mr. Rabago responds that he has real problems with demand charges. He notes that most utilities propose demand charges as NCP-type charges or ratchets, acting as if everybody's NCP was cumulated into the system's coincident peak. He states that the utilities need to disaggregate from that and take a first great step toward that with time-variable rates - peak-time rates or critical peak pricing - which allow you to send a market signal to lots of people. With solar customers, Mr. Rabago states his belief that the policy goal should be to maximize the benefit of the kilowatt-hour that the customer has the ability to control whether and when to export. Policy should encourage them to do the thing that allows it to be exported if it's worth more, if it's a good kWh, he says. Ask yourself, he states, how 2-Channel Billing works, how net metering works, and then how your future ideal works. Today, he observes, net metering is about retail, he states, but given that most people don't exercise control over their solar production and, given the relative coincidence between solar production and system peaks, the odds are (and Mr. Beach has confirmed it) that an extra kWh in your system at your current penetration rates is going to be worth more. That's the import of Mr. Beach's Crossborder study, he says. Therefore, Mr. Rabago urges the Commission, at least out to several more percents of penetration, to rest assured that you have met the requirements of the statute to ensure that there is a rate in place for distributed solar that does not create an improper cost shift and that, in fact, has benefits that exceed costs if you just stick with net metering. He contends that that is what SubGroup 1 has offered with empirical analysis to support it. T. 767-68.

Mr. Rabago poses a question of what happens on the 2-Channel Billing when a solar system is putting out a lot of kWh during a sunny time and there's high coincidence with peak. What does the rate encourage the customer to do: turn on a resistance heater because they maximize their return from that kWh by using it to offset load? Perhaps it will be a meaningful load, he says, but perhaps it will be, "Hey kids, hang out in front of the open refrigerator because we're making electricity and getting 10 cents per kWh when we do it. " T. 768-69.

Mr. Rabago observes that most customers don't have the time and tools to participate fully in a meaningful way, since they don't have rate signals coming from their utilities saying they are about to hit their peak or the utility's peak; they don't have devices saying when the cloud has passed and their solar system is starting to kick in; they don't have any practical experience measuring their consumption and tracking on any basis other than the monthly basis that the statute defines for net metering. He states that there is much more work to do to build a cohort of customers who are ready to engage and only release those extra kWh by backing off a load selectively or by discharging a battery, or vice versa. He agrees that an alternative would be to set up a system that has incentives to develop an automated tool that will do that for them; he calls that "third parties." He adds that it is necessary to figure out how to unwind and make available the data from AMI, distribution automation and distribution management systems, to set in motion a massive customer education effort, to mine the potential of time-varying rates of various kinds that would work complementarily to regulatory goals - not like 2-Channel Billing, which is contrary to your goals - and to turn non-dispatchable resources like solar into dispatchable resources through their electric vehicle or their stationary battery. T. 770-772.

Asked if the electric system overbuilds capacity, how does one determine ratepayer responsibility for that and what is the market signal that says we don't need more capacity, Mr. Rabago responds that he agrees with Mr. Ball - the best load growth potential is an aggressive pursuit of transportation electrification. He suggests that this would do a lot of good for poor communities, including communities of color, by getting diesel buses and other sources of pollution out of their neighborhoods by replacing them with EVs and solar. He recommends emulation of what other state commissions have done by starting with articulation of a vision, citing Hawaii, California, New York, Maryland, Missouri, and Iowa, and suggests that the DER docket might be the best vehicle for giving a description of where the Commission thinks this ought to go and then gauging the incremental steps toward it so as to maximize the benefits. He asserts that it is egregious to suggest that you have to have blinders on in addressing this, when everyone is watching to see whether there will be a really good demand response market, or energy storage, or EV market, or all sorts of opportunities in Arkansas, notwithstanding the narrow blinders that Sub-Group 2 is trying impose. T. 773-74.

Mr. Rabago acknowledges that in the IRP process, when projections show that a gas plant is the winner, the rates are not based on the projection, but on the actual fuel costs. Mr. Rabago was asked how you do that with distributed generation resource costs. He states that there is no way to guarantee that you can get a perfectly right projection, but you do your best when you realize the benefits that the IRP reveals. He states that the first tool you have to improve the accuracy of your IRP is to open it up, to get much more involvement, many more voices, so that you can overcome any intentional or unintentional bias that the utility might bring to it. Utilities are just normal, human, and have business plans they would like to see carried out. He recommends an iterative process and cites his involvement in Virginia with the Southern Environmental Law Center, where the Commission has taken a deliberate step-by-step basis to develop initial rough estimates of high-level solar integration costs, where the utility (Dominion) is participating in a DOE-funded project, and where the parties are watching how the numbers change and estimates change and their impact on the 20-year forecast. He notes that it doesn't really change a lot in the five-year short-term action plan. T. 774-75.

Mr. Rabago notes that because of the volatile - in many good ways -technological and economic environment, many states are looking at future test years and more frequent rate cases. He mentions that there are tools available to address "slow" rate cases and dealing with reductions in utility revenues, such as targeted earnings adjustment mechanisms (EAMs), which create an opportunity for an increased rate of return for doing stuff you want, such as low-income EE services, achieving faster interconnection of distribution generation, achieving higher penetration of EVs. This, he says, rewards utilities for being customer-facing - acting a bit more aggressively in the regulator's role as the substitute for the forces of competition. He notes that many people have said that the market is pushing this way and that the existential choice for commissions is: Are you going to be sort of handmaiden to resisting the change or work to find ways to usher utilities into the new environment? He acknowledges that we will make some mistakes, but will be able to diversify that risk if there is increased market participation by third parties, expanded opportunity for stakeholders to give input, and if more incremental decisions can be reviewed more often, as opposed to having to wait longer. T. 776-779.

Witnesses for Sub-Group 2

Sub-Group 1 parties and other non-Sub-Group 2 parties did not waive cross-examination of Sub-Group 2 witnesses.

As a representative of the organization of Arkansas's large industrial customers, AEEC, Mr. Mullins testifies that, although Sub-Group 2's proposal focuses on residential customers, it could turn into a problem that affects his members. He lauds how Arkansas has done well in making planning decisions that have resulted in low rates when compared to the rest of the country. He states that if the Commission acts proactively, it can avoid some of the negative consequences that have happened in other states. In response to Commission questioning regarding whether getting pricing right on demand and energy in the face of increased natural gas costs would provide options not only to net-metering customers but to industrials, Mr. Mullins answers "potentially." But he notes that ratepayers pay embedded costs, not marginal costs, and states that most industrial customers see the costs on the margin to be very low, perhaps below $30/MWh, in contrast to the $117 MWh of avoided costs calculated in the Crossborder study. T. 781-83.

Mr. Ball posed a question to Mr. Owens regarding how a customer could take advantage of meter aggregation to own a solar array offsite that would have no load and no consumption at the generator site. He asked how meter aggregation would be affected under the 2-Channel Billing approach and, in particular, whether the entire production from that customer's solar system would be on Channel 2 and thus get only half the value of that energy. Mr. Owens responds that the recommendation made by Sub-Group 2 affects accounts that have energy consumption at the load. He does not completely agree or accept it as a given that, under meter aggregation, the meter that the generator is connected to the meter does not have load. He cites his experience as a witness in an earlier matter where one of Entergy's customers was using meter aggregation and the load that was connected to consume most of the energy, but they were availing themselves of meter aggregation relative to their other accounts. He notes that most of those accounts were demand-metered and would be unaffected by the Sub-Group 2 proposal, although he says that they may have had some very small accounts that otherwise could have been affected. Mr. Owens goes on to observe that a location that doesn't have any load sounds like an independent power producer, which has a clear market in either MISO or SPP. He further notes that the MISO market is likely to be in the 2 1/2 to 3 1/2 cent per kWh range, which is quite a bit less than the 5 1/2 cents per kWh value that would be ascribed by Entergy Arkansas, Inc. Transcript Vol. 243 (T2.) 5-8.

Sub-Group 1 attorney Casey Roberts questioned Mr. Owens regarding a statement by Sub-Group 2 in Attachment B to the Joint Report, at page 156, wherein Sub-Group 2 recognizes that there may be limited exceptions to the recommendation that demand-billed tariffs will continue to be billed the same way they are today - based on utility-specific rate schedules that are not specifically recognized as demand- or non-demand-based rate schedules. She inquired how a rate schedule can be neither demand- nor non-demand based. Mr. Owens responds that there are instances in which on the very small end of the commercial class of customers, often called Small General Service (SGS), there is a delineation between a customer that is very small and one that is a little bigger. He gives the example of a fast-food restaurant with an 80 kW load and a nail salon with a 6 kW load. Oftentimes, he says, a rate schedule will bill the very small customer sub-segment -- that looks as though it is a residential customer - on a volumetric (kWh) rather than demand (kW) basis. He acknowledges that those SGS customers with such a small load will be subject to 2-Channel Billing under Sub-Group 2's proposal. Mr. Owens further explains that it does occur that some such SGS customers want to switch around - get bigger, get smaller, or become more efficient. It is conceivable, he says, if the customer's load is actually being reduced, that the customer with that shrinking load might fall below the load threshold and be switched from net metering to 2-Channel Billing. T2. 9-18.

On re-direct examination by EAL counsel, Mr. Owens clarifies that although both existing one-for-one net-metering customers and the proposed 2-Channel Billing customers are all net-metering customers, the existing SGS customers would be grandfathered, and new customers would be metered under the new rules. Id.at 18-19.

Mr. Owens testifies that the monthly billing increment is a technological accumulation of all the individual customer interactions that produced exports during the month, but that with a bi-directional meter, the utility doesn't know when the customer generation occurred. In the AMI world, the utility will be able to tell when a customer is exporting and importing. He acknowledges that in the AMI world one could make those hours price differentiated to a real-time price. He states that this opens the doors to provide a lot of flexibility, perhaps with a pilot option with a Locational Marginal Price-based credit rate. While it may require complex billing, Mr. Owens states that it may allow customers to provide the utility with value through time-of-use rates, real-time pricing, and critical peak pricing that may be coming. T2. 89-90.

In response to earlier questioning regarding SGS net-metering customers that are on a demand-charge tariff, counsel for EAL stated that the utility's rate administration group clarified that all such customers will still receive full one-to-one offset under 2-Channel Billing. T2. 92-93.

Mr. Shields testifies in response to Sub-Group 1 questioning that in the case of electric cooperatives, there should not be any ambiguity about customers that have a demand-type rate, such as a pumping tariff based on horsepower. Even though they don't have a demand charge per se, he states, there is still an implicit charge based on demand and the customers would still receive the one-to-one swap under 2-Channel Billing. He agrees that this is likely to apply mostly to agricultural customers. T2. 95-96.

In response to Commission questioning about applicable minimum bills and non-bypassable charges, Mr. Shields testifies that distribution cooperatives generally have only one - the service availability charge - that can vary between co-ops from as low as $6 up to $20. He states that this charge will include transformation and metering, but that it does not include all of the fixed-cost components that supply distribution service, some of which end up in the volumetric energy charge. He asserts that this creates a market distortion, which can be changed by setting the proper price signal. He urges determining this signal today instead of when saturation is reached. T2. 96-97.

Mr. Shields states that the cooperatives do not favor doing a study, which would be expensive for their members, when some cooperatives have very few or even no net-metering customers. On the subject of de minimiscosts, he acknowledges that there may be very little cross-subsidy for a cooperative with just one net-metering customer, but states that even one penny is being taken from the non-net-metering customers. T2. 98-99.

On the subject of the lack of a Sub-Group 2 explanation or quantification of the amount by which net-metering customers are not paying their "entire cost of service," Mr. Shields responds that it is empirical that they are not. He states that Sub-Group 2 went through an exercise of calculating Channel 2 at five cents as compared with the full retail rate of ten cents and asserts that this proves that there is overcompensation for rates that are totally volumetric, roughly in the amount of four-and-one-half cents. He states that as a rate analyst, he believes it speaks for itself that these volumetric rates on a one-to-one swap are being overcompensated because there are fixed-cost components in that rate. He agrees that the crux of that assertion is that there are embedded costs which they cannot avoid, but for which they are nonetheless being credited at the full retail rate. He contends that the work Sub-Group 2 did through the COS study quantifies that and that it is a good proposal that is justifiable and reasonable to address the requirements of Act 827. He states that a more appropriate rate design might be a demand rate, asserting that it is native to believe that in the future net-metering customers will not have demand rates. He asserts that the 2-Channel approach is a glide path toward demand rates - a "softer" treatment of net-metering customers than going to a three-part rate44 with a demand charge. T2. 101-103.

Asked if a penetration level is reached that's the equivalent of a gas plant and that plant never gets built, how that benefit would be factored in, Mr. Shields responds that if the plant was never built, the cost was never incurred. He states that customers are receiving that benefit under 2-Channel Billing, since there is no new cost. He acknowledges that, to some degree, those benefits are shared equally - socialized - among all customers, when the cost incurred to avoid the gas plant were disproportionately incurred by net-metering customers. He states that the cost is also shared equally, including the cost of the net-metering credit, which ratepayers have to share in. T2. 104-105.

Mr. Shields states that the generation export credits for some cooperatives are lower than Entergy's, perhaps driven by the fact that the cooperatives tend to peak later in the day than Entergy does. But, he agrees that they are roughly similar. T2. 105.

Questioned by Mr. Ball, Ms. Alexander testifies that she does not question that there are adverse health impacts due to air pollution generally, but notes that to the extent that the utility has incurred costs to respond to directives to reduce air pollution, those appear in rates and would be reflected in Sub-Group 2's methodology. She observes that to date the Commission has not made changes in rates based on a calculation of social impacts and that Sub-Group 2 did not think it appropriate to propose that for initial adoption in this proceeding. She agrees that there are significant benefits to the net-metering customer and to all ratepayers in the form of avoided generation when a net-metering customer invests its own capital to produce clean energy. Where the two Sub-Groups differ, she states, is with respect to the distribution and transmission costs that are embedded in the rate structure, which essential services and costs are not avoided by the net-metering customer and which, if net-metering customers do not contribute, must be borne by other customers. T2. 107-108.

Ms. Alexander professes unfamiliarity with Mr. Ball's aggregated solar center, for which he paid $7,000 for a transformer which the utility now owns as infrastructure, but responds that she is reacting to the vast majority of residential customers who install solar panels and do not provide any additional investment to the utility to deliver or export their energy into the system. T2. 109.

In response to Commission questioning, Ms. Alexander testifies that another study would produce nothing other than what exists already, which is the Crossborder Study of estimated and predicted benefits that are not guaranteed to be delivered by anybody anywhere. These projected benefits and calculations, she states, would not answer the question of what actually is being provided as a benefit right now by a net-metering customer in Arkansas. The projected numbers do not tell you what rate should be paid for exported energy from a net-metering customer, she states, since they are not indicative of the ratemaking question now facing the Commission. T2. 110-111.

Regarding the entire cost of service net of quantifiable benefits, Ms. Alexander states that Sub-Group 2's approach is to use the plain language of the statute to calculate what it is that net-metering customers do with their solar systems on the roof - namely, generate electrons (kW and kWh). As a result of that, she says, net-metering customers use far less than other customers, and the 2-Channel approach grants them all of that benefit. She states that the reduction in usage that results in a commensurate reduction in the net-metering customer's bill is allowed to be retained under Sub-Group 2's approach and is a very significant benefit. The reduced usage means a lesser contribution to the utility system's revenue requirement and eventually that will all flow back to other customers, she states. T2. 111-112.

Asked whether it costs less to serve net-metering customers on Channel 1, Ms. Alexander responds that Sub-Group 2's opinion and recommendation was to focus only on the exported and excess energy for the purposes of the ratemaking process. She opines that delving into whether or not there should be a change in how they are allowed to keep the full value of their reduced usage would require a significant rate design proceeding that would need to look not only at net-metering customer's reduced usage, but everyone else's who takes action to reduce usage in their home, thereby contributing less to the established revenue requirement of the utility. T2. 112-113

When confronted with the fact that Sub-Group 1 did not advocate such a rate design change, but simply delineated or described the lesser cost to serve net-metering customers by way of showing the benefits of net metering, Ms. Alexander responds that Sub-Group 1's idea of lesser costs include distribution and transmission service with which Sub-Group 2 does not agree and for which there is no evidence to support. Asked why those cannot be quantified for the purposes of the statute, she says because there was a unanimous view of every utility that there was absolutely no lower distribution or transmission cost from the 1,000 or fewer solar customers in Arkansas. She agrees that, as solar grows there will be benefits, but only when they can show that benefits have actually been provided. She asserts that the beauty of the 2-Channel Billing approach is that the methodology for calculating actual generation supply benefit from these customers can be altered in the future based on actual fact-based evidence that solar customers have provided a benefit that would allow an expansion of the dollar amount that Sub-Group 2 recommended. T2. 113-114.

Asked how the benefits of net metering would flow through the generation credit and whether it would only flow through to the extent net-metering customers are offsetting more power than they are getting from the utility, Ms. Alexander responds that electric bills in Arkansas are not unbundled and the variable energy (kWh) rate includes many aspects of utility service, which does not allow the clear delineation of the distribution, transmission, or generation part of that service. She states that while that is not really known, it is known that when a solar customer generates some electrons on their roof, they are not avoiding the call center, the billing system, the metering system, the poles and wires that they rely on to deliver and obtain their electrons, storm restoration costs, AMI, etc. She states that those will not be avoided in any near-term sense. T2. 115-116.

Ms. Alexander acknowledges that there are states that are not unbundled and yet have come up with mechanisms to value exported power that is not based as strictly on the methodology that Sub-Group 2 is proposing and that have more generous payments for excess energy than the one proposed by Sub-Group 2. When asked whether there is conceptual difficulty in focusing only on the exported power rate when the statute may require quantification of whatever amount of the entire cost is not currently being paid, Ms. Alexander responds that Sub-Group 2 is asking the Commission to assume that net-metering customers are contributing to the cost of the system as any other residential customer is contributing, with the actual usage that they end up with after they have netted what they obtain from the rooftop system. She agrees with Mr. Owens that Sub-Group 2's comments state that all costs are being recovered on Channel 1 for the power that is actually supplied by the utility and consumed, noting that these costs are recovered in the same way they are recovered from all other residential customers. Therefore, she states, Sub-Group 2 stopped its analysis. T2. 116-117.

Asked whether the Commission is required to act if the impact of net metering in Arkansas now is de minimis, Ms. Alexander responds, yes, since the statute directed a new look and a potential change. She asserts that the difference between five-and-a-half cents and nine-and-a-half cents is not de minimis, adding that with every rooftop or solar customer that is added with the grandfathering provision already adopted, you have signed a 20-year contract to pay those customers nine cents or more per kWh for something they are delivering. She states that it is not worth that, when no solar in the market is getting nine cents, when you can get it for five or less. She predicts that the Commission will have to rent a convention hall to have its next hearing if it wants to make this change later and not now. T2. 117-118.

Ms. Alexander testifies that the Commission is not required to capture the value of exported power on some predicted 25-year analysis of estimates over which it and the solar customer and the solar industry have no control or risk to deliver. She emphasizes that it is not included in the quantifiable benefits since it is not subject to regulatory control to make sure it is delivered. She distinguishes between a solar project and a supply-side power plant justified with a long-term analysis which results in an approved contract and construction that the utility could not deliver at the price it proposed. With the power plant, she states, the Commission has the authority to do something because the utility is subject to oversight, audits, and regulation to ensure that the promises made are delivered. With solar, she asserts, the Commission has no tools available to ensure that the predicted benefits are actually delivered. T2. 118-119.

Ms. Alexander recommends against a sliding scale or glide path approach as solar penetration increases, stating that the Commission has an obligation under the statute to look at the facts and evidence about what is going on right now with regard to rates, ratemaking, and the cost shift that occurs with net-metering investments by customers. She notes that the vast majority of Arkansas customers cannot participate in solar power, citing Census data on income, health insurance, housing, and mortgage costs. T2. 119.

Ms. Alexander states that, to the extent they are avoided by net metering, distribution and transmission costs will result in lower costs for those systems for everyone, and they will show up in the cost of service. She asserts that the Commission should not be in charge of giving certainty to a small group of customers at the expense of the remaining customers who bear the risk every year that their investments in home energy efficiency will be whittled away with higher rates. T2. 122-23.

Asked how she knows that subsidy exists now and what the evidence for that is, Ms. Alexander states that she can assure the Commission that net-metering customers are not delivering a generation supply product worth nine cents per kWh. She states that SubGroup 2 built up its proposed credit amount based on the potential generation benefits appropriate to be paid for the energy produced, but asserts that they are not avoiding the distribution and transmission costs that are worth about four-and-a-half cents.

Consequently, she states, by valuing the exported power, that by definition identifies the subsidy. When asked if it is not actually quantified on the cost side, but by negative implication from the exported value side, Ms. Alexander responds that it is quantified based on COS studies to determine what the value of generation is. She states that one is then left with the other aspects of COS studies that tell what part of T and D are not being provided.

When asked about flowing back benefits to solar customers if it could be established that the reason a lower distribution investment was necessary was because solar facilities were added, Ms. Alexander responds that the benefits should be spread to everybody because that is how rates are set for the residential class. Until the Commission does something differently, ratemaking ought to be looked at as a class-based exercise, she states. In the absence of a contract, she professes not to know how one could calculate so as to compensate or split the benefits with a customer who makes an investment in solar that produces distribution benefits. She cites experiments and pilots looking at locational-based distribution upgrades. She concludes with the assertion that if you need to pay more because you're getting more than five-and-a-half cents in benefits, you should pay more, but you should actually get it.

In response to Mr. Ball, Mr. Klucher disagrees with the characterization that universal benefits such as avoided carbon emissions or the deferral of new power plants are not being compensated by Sub-Group 2, asserting that Sub-Group 2 believes it is recognizing benefits provided by solar generation through the whole 2-Channel bill methodology. He asserts that the approach is a billing framework as a whole that represents the cost of serving a net-metering customer, including the net benefits they provide to the system. He denies that Sub-Group 2 is not quantifying any benefit and disagrees that Sub-Group 1's Crossborder Report is a COS report. He testifies that it compares lost-revenues - the subsidy or cross-subsidization - and identifies numerous hypothetical benefits that will occur over a long period of time and, then, show they outweigh the subsidy. Therefore, he states, since the benefits outweigh the subsidy, you do nothing. He disagrees with this approach. T2. 130-131.

What Sub-Group 2 has done, Mr. Klucher testifies, is not to run a COS Study to develop benefits, but to use methodologies similar to what is done in COS to quantify the benefits and "to a certain extent the less-costly-to-serve customers that net metering does have" and how to determine what that cost to serve is. He states that one cannot do that by looking at whether some hypothetical future benefit outweighs a cross-subsidy. T2. 131-134.

Mr. Klucher explains traditional COS mechanisms and discusses regulatory lag and cost-causation rate design principles. He compares a net-metering customer, which he states looks different from other customers, to an energy efficiency customer who doesn't export energy. He states his belief that a customer that has done energy efficiency projects is less costly to serve, but notes that he is still on the same rate structure as his neighbor who has not. He asserts that the EE customer benefits because rates are designed to recognize the fact that within a class, one customer may be more costly to serve than the other. Mr. Klucher states that there is both a benefit and a cost associated with export of energy, in that without the grid, it cannot happen. T2. 134-139.

Asked how he has specifically addressed economic development benefits that a net-metering policy will bring to Arkansas under Act 827, Mr. Klucher responds that he cannot identify any particular way to value in a rate the benefits of externalities that exist over a long period of time. On redirect examination regarding Table 1 of Sub-Group 2's Reply Comments, Mr. Klucher testifies regarding the provision in Act 827 that says that quantifiable benefits associated with the interconnection and providing service to net-metering customers must be netted against the quantifiable benefits. He states that he does not think this encompasses economic benefits. T2. 143-144.

In response to Commission questions regarding the three buckets and whether there might be lesser costs to serve net-metering customers, Mr. Klucher discusses SubGroup 2's excess generation credit rate methodology, described beginning on page 168 of the Joint Report. He states that, for Entergy, the Channel 1 rate is the base rate, excluding fuel, for all residential customers, and includes distribution equipment such as wires, poles, transformers, customer service, the utility's return on investment, and the recovery of the cost of generation and transmission equipment. He notes that the utility needs approximately six cents per kWh to get that cost back. He describes how Sub-Group 2 used allocation methodologies to get to the six-cent base rate. He states that Channel 2 offsets Channel 1. He acknowledges that Channel 2 values two components - fuel and capacity. He explains that Sub-Group 2 allocated solar generation based on solar's capacity factor during the four coincident peak months (June -September), in a fashion similar to that done by Sub-Group 1. He states that this approach both values a capacity benefit and also gives credence to the lesser cost to serve a net-metering customer. Mr. Klucher states that if you were to do a class COS separate for a net-metering customer, you would most likely see lower generation costs. He acknowledges that Oklahoma Gas and Electric did a study that showed on a per-customer basis their cost to serve is lower. He asserts that the lesser cost to serve a net-metering customer is woven into the capacity because capacity is based on the average capacity they can produce during the peak hour. He states Sub-Group 2 takes the 4 CP months average of 41 percent and recognizes that the lower cost to serve and benefits are generally going to exceed the average, then SubGroup 2 looks at the maximum solar generation of 52 percent to make sure that the benefits are captured. T2. 145-154.

Asked to explain why Sub-Group 2 uses only COS to value current benefits, Mr. Klucher explains that the current benefit of solar is avoided fuel, and there is no capacity benefit to the utility at this point. With increased penetration of solar, he states, there is hopefully some reduced cost in the future. What Sub-Group 2 does, however, he states, is offset Channel 1 at nine cents with additional offsets above and beyond fuel that represent capacity at five-and-one-half cents. Because anything consumed behind the meter is paid the full nine-cent value, he states, the more energy the consumer can use behind the meter, the more value they have. T2. 155-157.

Asked how the benefit of a power plant that is never built flows through either to all customers or specifically to the net-metering customer, Mr. Klucher cites the Crossborder Study as projecting that a customer will experience cost over a 25-year period at a full retail rate of 12 cents and since the projected benefit the customer is going to experience in the future will exceed that, the customers who are not net metering are not paying more than they should. What Sub-Group 2 says, according to Mr. Klucher, is that 2-Channel Billing uses essentially the same concept except it does not guess at when or if it is ever going to happen, although they hope it does. He states that because the net-metering customer still gets a one-to-one setoff for self-consumption behind the meter, that compensates them for these long-term benefits. He adds that there are two places where that happens - both in Channel 2 and behind the meter. He states that Sub-Group 2 doesn't know how to calculate what that is on a real meter, but can quantify it through modeling, as shown on Exhibit B-4 at page 217 of the Joint Report. T2. 158-161.

Mr. Klucher explains that the exhibit shows that under the existing one-to-one rate, the net-metering customer is effectively credited at 10.8 cents per Kwh, whereas under 2-Channel Billing, the same customer would effectively be credited 9.1 cents per kWh, or about 84 percent of what the utility is paying them today. He explains that that amount includes the lesser cost that it takes to serve net-metering customers and the concept of the power plant that never has to get built in 10 or 20 years. He states that under COS the way Sub-Group 2 attempted to do it, "kind of includes all of that, we quantify these benefits to the extent a customer has exports if you just look at their generation." Mr. Klucher states that he can say with this record what the amount of the entire cost is that net-metering customers are not paying now. He points to the $8 difference between $77 and $68 that Mr. Owens referred to as representing their cost to serve. T2. 161-165.

With respect to "additional costs," Mr. Klucher states his understanding that there would not be any additional costs that roll into this rider directly, although he says they would roll in indirectly by ending up in base rates. He distinguishes additional costs from the types of interconnection costs described by Mr. Ball, which are paid by a customer and do not end up in base rates. He notes that such additional costs will increase base rates, but will also have the impact of benefiting the net-metering customer to the extent it is set off one-to-one behind the meter. If that goes up, Mr. Klucher notes, all things being equal, the Channel 2 excess generation credit rate also goes up. T2. 165-66.

Mr. Klucher testifies in response to Sub-Group 1's assertion that non-coincident peaks may not change, stating that Sub-Group 2 quantified that through modeling, as shown in Surreply Comments. He states that it is included in Sub-Group 2's valuation of benefits to the extent the customer consumes it behind the meter. He adds that as utilities become more AMI compatible and better data can be collected, different allocations could be chosen. The cost correlation chosen from the available data uses 54 percent for generation, 36 percent for transmission, and zero for distribution. He states that one can always get better data and identify better factors. T2. 166-68.

Mr. Klucher testifies that if 2-Channel Billing is approved, Staff and the utilities would verify the functionalized cost of every utility. He recommends that this vetting be done to set the rates the first time rather than in the next rate case. He suggests that to identify different types of cost causation, Sub-Group 2 recommends something similar to unbundling to identify what goes where. T2. 168-170.

With respect to meter aggregation, Mr. Klucher opines that it is a physical limitation not a policy one, adding that a customer who aggregates is very different in that every single time they need that kWh, they need access to the grid to do so. He points to a tradeoff of cost and benefit and states that Sub-Group 2 could not figure out a way to quantify it; it is likewise with distribution, he states. T2. 170.

On the subject of future benefits that cannot be quantified, Mr. Klucher agrees that the customer is overpaying 10 cents in Channel 1 and that over time, Sub-Group 2 will do "rough justice" because you'll be paying 9 cents. He states that Sub-Group 2 aimed to find the best cost causation drivers for net metering, just as would be done when developing rates for any other class. T2. 174.

Mr. Klucher testifies that the 2-Channel method can be used to phase in a new billing method, perhaps by putting a valuation to another piece of the cost - a higher generation value for example, until you hit a certain penetration level. He states his understanding that return on investment is important and, consequently his belief that 2-Channel helps push storage. He states that under full one-to-one net metering, if a customer's choice is to do it based on return on investment, the customer would have no incentive whatsoever to ever install a battery. As an example, he states that if a customer generates enough electricity to serve all his needs today, his bill is $12, but if he installs just $1,000 worth of batteries, his bill is still $12, which means there is no return on investment. He opines that we need a mechanism that encourages all distributed generation, not just one and that 2-Channel Billing is a step in that direction to make more distributed generation resources viable to customers. T2. 174-77.

Mr. Klucher states that if the Commission wanted to have a 2-Channel Billing mechanism that encourages solar to some level of penetration and would be willing in the short term to go above and beyond what Sub-Group 2 believes is the cost to serve, he would start with generation, perhaps by moving above the 54 percent number. One could also go to the distribution rate, which is two to three cents for Entergy. In short, he says there are different ways to go about it, including what Mississippi did with its adder for a certain period of time. He cautions about the need to deal with grandfathered customers if one of these other alternatives is pursued, asking whether a grandfathered customer who gets 100 percent would stay at that level or fall to whatever the valuation is as penetration rises; if so, a customer who comes in Year 6 will have a system that is going to be worth a lot less than a customer who comes in today. He recommends determining how you want to send that incentive by addressing that up front to let customers know that either they keep it forever or it goes away at some point. T2. 178-180.

Introduction

The AG begins by asserting the Staff took it upon itself to file its own proposed net-metering Rule in its Strawman Proposal. She argues that the NMWG did develop an extensive list of contested issues, which Staff failed to file and that this will mean the Commission and parties will not be working from a single contested issues list. The AG also alleges that Staff and EAL have attempted to isolate and peel off certain issues into either a separate docket or on a separate expedited schedule within this Docket. Regarding this allegation, the AG footnotes references to Staff's application filed September 13, 2019, in Docket No. 19-055-U (Document 1) and to EAL's Motion in this docket for an interim net-metering rate schedule and accelerated procedural schedule. The AG argues that both actions serve to undermine the rulemaking the Commission has undertaken in this Docket and urges the Commission to keep all issues regarding Act 464 and net-metering in general in this Docket alone. AG Initial Comments at 3-4.

Rate Structure

The AG asserts that the rate structure issue is the most important contested issue in this Docket, noting that Order No. 22 has given the Parties an opportunity to re-evaluate previous positions in light of the new statutory landscape. The AG states that in the time between the recommendations of Sub-Group 2, which has since disbanded, and the present, the AG has been able to fine-tune its priorities specific to net-metering. The AG continues to advocate for a fair allocation of cost between net-metering and non-net-metering customers. The AG advocates for a "Do-No-Harm" approach that considers the benefits of changes from the status quo, but places a strong emphasis on potential negative impacts of making changes too quickly without due consideration of these potential negative impacts. Id. at 5-6.

The AG states that Act 464 now provides clearer guidance on which rate structures are allowable, specifically for customers who receive service under a rate that does not include a demand component. The AG acknowledges that Act 464 gives the Commission broad discretion on the net-metering rate as described in Order No. 22:

With regard to the rate structure issues, the Commission notes that the General Assembly left entirely to the Commission the decision to choose one of the various options set forth in the Act, or a hybrid thereof - for example, whether to:

* retain the current one-for-one net excess generation credit approach favored by Sub-Group 1 in Phase 2;

* adopt the 2-Channel net excess generation credit approach proposed by Sub-Group 2;

* develop an avoided cost approach for net excess generation credits, with an "additional sum" up to 40 percent of avoided cost; and/or

* recognize in net excess generation credits the monetary value provided to a utility by the use of net metering as specified by market mechanisms, if any, of the regional transmission organization of which the electric utility is a member and market mechanisms, if any, that measure utility distribution system benefits.50 Id. at 7.

In light of Act 464's clarifications of allowable rate structure options, specifically the option of a hybrid approach, the AG continues to support as a reasonable compromise the overall premise of 2-Channel Billing and the original position of Sub-Group 2. The AG asserts that this is a pragmatic solution to addressing cost allocation and recovery issues, while allowing customers the continued choice to install net-metering facilities to lower their energy bills. Id.

However, while continuing to support 2-Channel Billing and its protection for non-net-metering customers, the AG states that it is important to evaluate whether or not an immediate change to 2-Channel Billing would promote appropriate public policies, noting that abrupt changes in net-metering rate structures could have immediate, harmful effects that are not outweighed by their immediate benefits and thus violate the AG's "Do-No-Harm" principle. Id.at 8.

Accordingly, the AG recommends a gradual move towards full 2-Channel Billing while mitigating negative effects. The AG cautions against an abrupt move to 2-Channel Billing and cites the negative results of Nevada's sudden change to phase out the full retail credit. The AG favors a tiered or phased-in approach (such as the one in Nevada that resulted from legislative changes) that would move toward a credit based on avoided costs utilizing tiers that would be developed in this proceeding. The AG states that a tiered approach finds a balance between Sub-Group 1's and Sub-Group 2's original positions.

Thus, while the AG strongly advocates an end-point adopting full 2-Channel Billing, the AG recognizes the benefits of phasing in that rate structure. The AG discusses the 2-Channel Billing plus an "adder" approach adopted from the beginning by Mississippi and distinguishes Arkansas's circumstances from those in that state, noting that Arkansas should consider concerns such as job losses from a change in the rate structure. Id. at 9-10.

The AG cites Indiana as an example of how a phased-in approach could be beneficial for Arkansas, noting that Indiana moved away from a 1:1 credit mechanism, but took a more tempered approach by phasing this out over time. The AG observes that the main impact of the phase-out will impact net-metering customers in years much further out, thus demonstrating the benefits of a gradual change. Id.at 10.

The AG proposes a phased-in approach that would move toward a credit based on avoided costs, utilizing tiers to be developed in this proceeding. For example, the AG suggests that the first tier could begin with the credit equaling the retail rate with a phasing over time to a credit fully based on the avoided cost. Under this approach, the amount paid to the customers could be based on the separate reading of the amount being delivered back to the grid, but it would not initially be paid at an avoided cost rate. Instead it would be paid at the retail rate and over time it would be adjusted to an avoided cost rate by adjusting the weighting of each component. Id.at 11.

The AG argues that the tiered approach applies the concept of gradualism, similar to what frequently occurs in general rate cases: as cost-of-service studies show the proper allocation of revenue requirements across different rate classes, interclass subsidies are sometimes identified, and an effort to eliminate the subsidies may be undertaken. The AG notes that if subsidies are large and a change to eliminate all subsidies would cause rate shock for a given class of customers, the subsidies are usually not fully eliminated in that rate case. Instead, the AG states, the subsidies can be reduced in future rate cases over time to mitigate rate shock to any one particular rate class. The AG asserts that this same principle of reasonably mitigating negative effects should apply to net metering. Id.

The AG notes that while grandfathering would help eliminate rate shock to existing participating net-metering customers, the rooftop solar industry could experience a negative economic impact as was seen in Nevada. The AG states that it is sensitive to this impact, as rooftop solar businesses across the state have made business investments, like company vehicles and equipment and the hiring and training of personnel. The AG expresses concern that these companies may be unduly harmed if an immediate change of rate structure is implemented. Id.at 11-12.

The AG asserts that the phased-in approach would allow businesses to adjust over time as net metering grows in the state, and it would also allow solar equipment and installation costs to decrease, offsetting some of the lost opportunities from a lower payback on the investment for net-metering customers. The AG also believes the adoption of 2-Channel Billing could also act as a market stimulant to other energy management technologies: home energy management systems and batteries will be more appealing as net-metering customers will have an incentive to shift their energy loads to times of the day when the net-metering facility is generating electricity, or to store self-generated electricity for use during other time of the day to avoid the need for utility-supplied electricity. The AG notes that costs of battery technology will also likely decrease over time, giving customers an option to use more of their self-generated energy on-site. Id. at 12.

Grandfathering

The AG states that Act 464 sets out three levels of grandfathering:

* Level 1 - customers net metering prior to July 24, 2019, are automatically grandfathered at the full 1:1 retail rate. However the length of the grandfathering is not specified. The AG believes that Level 1 grandfathering should be limited to 20 years.

* Level 2 - net-metering customers that submit an interconnection request between the effective date of the Act and December 31, 2022. The AG contends that Level 2 requires the net-metering customer to individually seek review and approval from the Commission on a case-by-case basis to be grandfathered at the rate structure in place at the time of the signing of the standard interconnection agreement, for a period not exceeding 20 years.

* Level 3 - interconnection agreements submitted after December 31, 2022. The AG asserts that the statute does not contemplate grandfathering for those net-metering customers.

Id. at 12-13.

The AG states that Level 1 grandfathering acknowledges that net-metering customers prior to Act 464 made a significant financial investment decision based on the best information they had at the time. Although the proceeding in this Docket began in April 2016, the AG notes that there was no Commission decision made related to the rate structure. The AG states its belief that the treatment of net-metering customers prior to Act 464 is not being challenged by any party to the proceeding. According to the AG, Level 2 grandfathering provides the possibility of grandfathering with notice, opportunity for public comment, and approval by the Commission. Id. at 14.

Consumer Protection Rules

The AG expresses concern that in an effort to maximize profit during this period of uncertainty without clear NMRs, third-party developers may mislead utility customers and insert contract terms into agreements that could be harmful to customers. The AG notes that one element used to mislead potential net-metering customers is the short- and long-term benefits of the installation of net-metering facilities or, as Act 464 now allows, the short- and long-term benefits of a lease of net-metering facilities. The AG states that the Commission must consider the fact that unregulated entities are not currently restricted by Commission rules or standards in the marketing and development of facilities allowed under Act 464. For example, the AG states, there is a very real danger that onerous contract terms could be inserted into agreements, placing undue and unwarranted risk on ratepayers regarding changes to rates, escalating construction costs, and failure of contract terms to contemplate costs associated with replacement, repair, malfunction, or shutdown. The AG argues that contract terms must be clearly disclosed, displayed, and easy for lay persons to understand, adding that any assumptions used in payback calculations should also be clearly displayed. According to the AG, these should include, but not be limited to: full cost of equipment and installation; projected future maintenance costs; avoided rate; avoided rate escalation factor; projected on-site usage of self-generated electricity; and projected excess generation. Id. at 14-15.

To reduce these concerns the AG recommends that an ongoing working group be established by the Commission to develop a Code of Conduct and a process to certify providers and be responsible for setting terms and conditions for participating in net-metering in Arkansas. The AG suggests this could be similar to the Parties Working Collaboratively for energy efficiency programs. Id.at 15.

Leasing and Service Agreements

Regarding leasing providers (as well as other third-party developers), the AG expresses concern that a legislative solution may be needed to grant statutory authority to the Commission to regulate these providers. The AG submits that rules developed in Phase 3 should address Commission oversight of solar installers and net-metering facility owners that offer leasing options. The AG recommends that the leasing option be provided under the Code of Conduct, with terms that should be clear and conspicuous, and that leasing providers should be subject to the same program/expulsion rules developed by the customer protections workgroup. Id. at 15-17.

Draft Net Metering Rules

The AG recommends that a completely new set of NMRs be developed using Act 464 as the starting framework. The AG provides a draft of its recommended NMRs (Appendix A) that were provided to Parties during the one meeting of the NMWG. The AG also provides an analysis of the current NMRs and if/how they would need to change to comply with Act 464 (Appendix B). Id. at 17-19.

Rate Structure

OG&E acknowledges that Staff's proposed NMRs allow for utilities to submit individual utility-specific net-metering solutions that will balance the interests of both its participating and non-participating customers. OG&E supports this approach, as it will allow the Commission to develop experience with multiple net-metering solutions that can assist future refinements that improve the balance of interests for both participating and non-participating customers. OG&E attaches its proposed redline refinements to the Staff's proposed rule changes. OG&E Initial Comments at 1-2.

OG&E requests that the Commission approve a rate structure to replace the current 1:1 rate structure. OG&E recommends that any new rate structure approved by the Commission be based on each utility's cost of service. Of the three new rate structure options allowed for by Act 464 (2-Channel billing, grid access charge (or similar), and three-part rates that include a demand charge, or a hybrid thereof), OG&E's preference is the adoption of a grid access charge rate structure for all applicable net-metering customers. OG&E believes such a rate structure is the most effective mechanism to mitigate the current unreasonable allocation of costs to non-net-metering customers. OG&E Initial Comments at 2-3. OG&E also responds to the potential rate structures listed in Order No. 22. Id. at 2.

Current 1:1 rate

OG&E states that the current rate structure leads to unreasonable allocations of costs to non-participating customers because the net-metering customers are no longer paying for the customer- and demand-related services that are embedded in the credit they are receiving. Additionally, OG&E states, under a 1:1 net-metering rate structure, non-participant customers are required to pay far more than market rates (SPP and MISO Day-Ahead) for unscheduled excess energy delivered onto the utility grid by net-metering customers. Id. at 3.

2-ChannelBilling

OG&E notes that 2-Channel Billing was a compromise among Sub-Group 2 parties and OG&E did not oppose it. If 2-Channel Billing is adopted, OG&E recommends that that each utility be allowed to set its own rate structure components (grid access charge, demand charge, etc.) at a level that limits unintended subsidies and minimizes above-market payments for excess energy. If the Commission were to determine that utility-specific net-metering rules are not desirable, OG&E requests that the Commission approve a grid access charge mechanism for net-metering customers. OG&E states that a grid access charge should be designed to recover the costs that are not avoided by a net-metering facility, at a minimum including the cost of utilizing the distribution grid. OG&E states that under the current 1:1 credit mechanism, a net-zero kWh customers will avoid all costs of utilizing the distribution grid, which means all other customers are footing the bill for these costs. Under an unavoidable grid access rate structure, any net excess energy within the billing cycle would be credited at the rate of the utility's avoided cost. Id. at 3-4.

Avoided Cost Plus an Additional Sum

OG&E notes that under Act 464, the burden of proof for any "additional sum" up to 40 percent of avoided costs is on the party seeking the sum. OG&E states that the evaluation of an additional sum should be based on quantifiable benefits and should also consider the impact on non-net-metering customers. OG&E urges caution in including any Quantifiable Benefits that cannot be tied to an accounting or market mechanism, or any amount not currently included in a utility's cost of service. Id. at 4-5. Benefits Related to RTO Market Mechanisms

OG&E states that it is unaware of any explicit RTO (SPP) market mechanism that measures the utility distribution benefits provided to a utility by the use of net metering. OG&E further notes that the grid provides a substantial benefit to distributed energy resource customers equal to battery backup storage within varying time intervals and urges the Commission to consider those benefits in the calculation of any Quantifiable Benefits. Id. at 6.

Customer Protections

Protections for Non-Net-Metering Customers

OG&E states that either a grid access charge or 2-Channel Billing would reduce the unreasonable allocation of costs to non-net-metering customers. OG&E also suggests adopting a three-part rate structure with an appropriate level of demand charge, and treating net-metering customers as a separate rate class. OG&E asserts that this will provide more accuracy and granularity into cost allocation to increase protections to non-net-metering customers. Id. at 6-7.

Gaming

OG&E supports developing a regulatory mechanism to guard against the gaming of new 1,000 kW threshold net-metering projects. OG&E also requests the Commission take administrative notice of the FERC Notice of Proposed Rulemaking in Docket Nos. RM 19-15-000 and AD 16-16-000 in which, in part, FERC is proposing to increase its protections against gaming. OG&E proposes as an additional step to mitigate the potential for gaming, that the contact information for the owner of a facility needs to be listed on any interconnection agreement, and all solar lessors and aggregators should be required to register with the Commission, so as to establish mechanisms for enforcing common ownership rules. OG&E recommends establishing a process to allow utilities and/or other parties to file a complaint regarding any potential gaming, as third-party solar installers are not regulated. In addition, OG&E urges, penalties for gaming should include, but not be limited to, forfeiture of ability to participate in net metering. Id. at 7-8.

Staff's Strawman

SWEPCO supports Staff's revisions to the NMRs with one exception: Rule 2.03 -New or Additional Charges. SWEPCO suggests that the language from Ark. Code Ann. § 23-18-604(a)(4) be incorporated in the Rule rather than just referring to the section. SWEPCO Initial Comments at 2. SWEPCO next discusses the contested issues.

Rate Structure: 2-Channel Billing

SWEPCO supports the adoption of the 2-Channel net excess generation credit because it appropriately recognizes the utility's costs that the net-metering customer avoids and provides for an additional credit of up to 40 percent of the utility's avoided costs. SWEPCO discusses other benefits that make this method a fair and reasonable choice for all parties. Id. at 2-3.

Quantification of Additional Sum

SWEPCO points out that the utility must be able to actually quantify the benefits based upon cost-based ratemaking already approved by the Commission and not by subjective "societal" benefits which may be claimed by the net-metering customer. The quantifiable benefits can also consist of benefits from RTO market mechanisms, but SWEPCO is unaware of any such market mechanisms in SPP. Id. 3-5.

Rate Structure: 1:1 Approach

SWEPCO does not support the existing 1:1 rate structure because it shifts costs to non-net-metering customers. SWEPCO argues that the current full retail rate credits the net-metering customer for investments in embedded costs that the customer is not avoiding by merely reducing their consumption. SWEPCO notes that in the first seven months of 2019, the Company issued 263 "net kWh zero bills" in Arkansas. These are bills that reflect a net-zero kWh usage for the month which means the only payment made by the customer is the fixed customer charge, which typically recovers the cost of meters and billing. The customer does not pay for fuel, energy efficiency programs, or any factor that is based on kWh usage. Id. at 6-7.

SWEPCO notes that the number of net-metering facilities in Arkansas has been increasing dramatically, noting that according to annual filings with the Commission, there were 1,500 net-metering facilities - both residential and commercial - among utilities with customers in Arkansas in 2018. This, SWEPCO states, was a 52 percent increase in the number of facilities from 2017. Furthermore, SWEPCO states, in 2017 there was a 53 percent increase in the number of facilities from 2016. SWEPCO itself issued over 200 "net kWh zero bills" in Arkansas in 2018 for net-metering customers, and for the first seven months of 2019, SWEPCO issued 263 "net kWh zero bills" in Arkansas. Like all Arkansas utilities, SWEPCO states that it is experiencing an increase in the number of residential and commercial net-metering customers, as well as full-blown marketing campaigns to schools, cities, and other municipal entities. SWEPCO states that as of its October 15, 2019 filing, it had received 62 net-metering applications and interconnected 68 new net-metering facilities in 2019 and is forecasted to receive another 90 applications and interconnect 84 new facilities before the end of the year. Given this unprecedented growth, SWEPCO asserts that the existing 1:1 rate structure is unsustainable. Id.at 6-8.

Current Demand Tariffs (GS Tariff)

SWEPCO recommends that the Commission should make an exception to the NMRs regarding the continuation of the existing 1:1 net excess generation credit approach for net-metering customers who receive service under a rate that includes a demand component for any current demand tariff under which the Company is not fully recovering its cost to serve. As an example of such a case, SWEPCO points to customers under its General Service (GS) tariff that do not meet the 6 kW demand charge threshold. SWEPCO notes that a significant portion of the Company's costs for such customers under the GS tariff are thus achieved through the energy charge. SWEPCO argues that while the proposed NMRs are a reflection of the statutory provisions of Act 464 for customers with a demand component, it believes that the statutory language does not properly take into consideration the new rate structure on current demand tariffs. Therefore, SWEPCO urges that the 2-Channel Billing approach should be extended to net-metering customers on the General Service tariff, as well as any current demand tariff under which the Company is not fully recovering its cost to serve, as an exception to the Commission's NMRs. Id. at 8-9.

Gaming/Oversizing Facilities

SWEPCO notes that while Act 464 provides limits for the size of net-metering facilities for residential customers, it does not have a mechanism for "policing" customers who oversize their systems. SWEPCO states that Ark. Code Ann. § 23-18-603(8)(E) provides that a net-metering facility is "intended to primarily offset part or allof the net-metering customer requirements for electricity."57 SWEPCO notes that while Commission review is required for interconnection of a net-metering facility over 1,000 kWAC for a commercial or industrial net-metering customer, there is currently no disincentive for commercial of industrial net-metering customers to oversize a system. Rather, SWEPCO states, conditions have changed in a way that makes 1:1 netting and cost payment an inducement to oversizing. Therefore, SWEPCO supports the adoption of rules that specifically define a level of "over-sizing" and provides either penalties or terminates the Standard Interconnection Agreement and removes the customer from net-metering service until the size of the net-metering facility is reduced to comply with the Ark. Code Ann. § 23-18-603(8)(B)(i). To guard against gaming, SWEPCO also recommends developing rules or guidelines to define a level of "over-sizing" and provides either penalties or terminates the Standard Interconnection Agreement and removes the customer from net-metering service to that of a cogeneration facility until such time as the size of the net-metering facility is reduced to comply with Ark. Code Ann. § 23-18-603(8)(B)(i). SWEPCO also urges the Commission to develop rules or guidelines to guard against the possibility that a large net-metering facility that would otherwise exceed the new 1,000 kW threshold is not broken into multiple small net-metering facilities under common ownership to avoid Commission review. Id. at 9-10.

Data Sharing

SWEPCO points out that the Commission is currently addressing issues related to data privacy, data access, and data sharing in Docket No. 16-028-U. Therefore, SWEPCO believes it is premature to attempt to define and establish a market-based incentive for credit for data sharing until those data issues are addressed in Docket No. 16-028-U. SWEPCO also notes that it has not deployed AMI meters or separate production meters, both of which are necessary to gain increased visibility into the distribution grid. SWEPCO states that production meters are owned by the customer and are installed behind the customer meter in such a fashion that they are capable of directly measuring the output of a customer's net-metering facility. Production meters, in conjunction with AMI meters, thus allow a utility to completely understand consumption, generation, import from the grid, and export to the grid in such a way that the true costs and load impacts to the grid by that customer can be quantified definitively. Because SWEPCO has an obligation to serve and the customer's production data is necessary to provide that service, SWEPCO does not believe it should have to pay for such information from the customer. SWEPCO states that, at this time, there is little incentive for the utility to provide distribution system information in exchange for a customer's data information or develop market-based incentives to increase net excess generation credits in exchange for information from net-metering customers. Id. at 10-12.

Grandfathering

SWEPCO believes Act 464 requires the Commission to approve net-metering facilities that seek to be grandfathered. SWEPCO also believes that Act 464 did not supersede Order No. 10, which provides that grandfathering will be determined based upon the date of the Commission's order, which has yet to be issued, adopting a new net-metering rate structure. SWEPCO notes that Act 464 provides that net-metering customers who sign a Standard Interconnection Agreement (SIA) between July 24, 2019, and December 31, 2022, will be subject to the rate structure in effect at the time they sign the SIA. Therefore, SWEPCO argues, it would seem logical that the date of the Commission's order adopting a new net-metering rate structure will be date upon which ALL net metering customers at the time of the order would be grandfathered. For example, SWEPCO states, if that date is January 1, 2020, then all net-metering customers who are current customers, or have signed an SIA, will be grandfathered at the current 1:1 rate structure, and there would be no more grandfathering after that date. Additionally, SWEPCO contends that, as written, the Act 464 requirement for Commission approval58 applies only to the net-metering customers who submit an application between July 24, 2019 and December 31, 2022, or to any customer who has submitted a signed SIA prior to the date of the order adopting a new net-metering rate structure. Thus, SWEPCO states, the application of the grandfathering provision will also require the distinction of rates applicable to grandfathered customers versus new net-metering customers who will be subject to the rate structure as determined by the Commission. SWEPCO believes that the NMRs need to reflect and address these issues. Id. at 12-14.

Third-Party Leasing

SWEPCO believes that the addition of third-party leasing of a net-metering facility may require the Commission to adopt additional rules or guidelines regarding eligibility and criteria for such leases, beyond the listed limitations in Ark. Code Ann. § 23-18-603(7)(B)(i) -(ii). Id. at 14.

Definition of Net Metering Facility

Empire cites Proposed Rule 3.02(C), which states that "A Net-Metering Facility shall not be modified or changed to generate electrical energy in excess of the amount necessary to offset all of the Net-Metering Customer requirements for electricity." Empire states that the NMRs should also clarify that the intent is to restrict the initial sizing of the net-metering facility to ensure that those facilities are not intended to generate electrical energy in excess of the amount necessary to offset all of the Net-Metering Customer requirements for electricity. Additionally, Empire states that the Commission should ensure that the NMRs address the potential disqualification of a facility as a net-metering facility if its production level becomes excessive as a result of the reduction of the electricity requirements of the Net-Metering Customer. Empire Reply at 1-3.

Rate Structure

Empire recommends that each utility be given a range of options for its proposed rates, terms, and conditions for net metering within its service territory. Empire argues that a single prescriptive rate structure solution applicable to all utilities requires that all utilities have sufficient technical capabilities to implement the prescribed solution which is not the case in Arkansas. Empire contends that a prescriptive one-size-fits-all solution would, by default, limit itself to the "lowest common denominator" or be limited to the technical capabilities of the least advanced utility. Empire suggests that as utilities implement new metering and billing technologies which support better solutions, those utilities should be encouraged to incorporate those advanced capabilities into their rates. Id. at 3.

Aggregation of Meters

Empire notes that the Proposed NMRs address meter aggregation in Rule 2.04(C) and in Rule 2.05 and recommends that the Commission consolidate the meter aggregation rules into a single rule for brevity and clarity. Id.

Introduction

AECC explains that it is imperative that the Commission exercise flexibility given the vast diversity among the electric cooperatives in Arkansas. If, however, the Commission adopts a uniform rate structure, AECC recommends a rate based on wholesale rate for energy (kWh) - e.g., the avoided cost, noting that it is also the rate recently used by several states, including the neighboring state of Louisiana. AECC Initial Comments at 1-3.

Staff's Strawman

AECC proposes changes to Staff's Strawman, which are attached as AECC Initial Exhibit-1, in order to help clarify certain ambiguities or unintentional errors, and to better protect non-net-metering customers against the potential for unreasonable cost shifts.

Definitions - Additional Meter

AECC suggests a change to the Strawman definition for "additional meter." Specifically, AECC states that the Strawman's language does not reflect that Ark. Code Ann. § 23-18-604(c)(2)(A)(ii) prohibits, rather than promotes, meter aggregation. By focusing on singularly on common ownership, AECC asserts that Staff's Strawman's proposed language opens the door to limitless aggregation amongst different governmental or tax-exempt owners within a single service territory. Id. at 4-5.

Applicable Period

AECC recommends that the term "applicable period" be defined to avoid confusion. AECC suggests the definition read as follows: "The period of time used by the Electric Utility to determine Net Metering or Net Excess Generation." AECC argues that to avoid creating a cost shift that becomes a subsidy for net-metering customers, excess generation must be accounted for anytime a net-metering facility feeds energy back to the utility. Otherwise, AECC asserts, the net-metering customer receives more than the avoided cost - i.e., a non-market based rate, for generation it sells to the utility. Such a result, AECC contends, is contrary to the existence of wholesale power markets and negatively affects non-net-metering customers. AECC contends that the reality is that most utilities have the ability to measure energy flow both to and from customers. Because a net-metering facility provides energy only, AECC argues that its excess generation is effectively purchased as additional wholesale energy by the utility. By contrast, AECC argues, the energy a utility customer (including a net-metering customer) consumes comes with the infrastructure required to deliver it, on demand, and as much as is needed. AECC asserts that the distinction between the energy flowing to and from the utility means that excess generation from a net-metering facility has a distinctly lower value than the retail energy flowing to the consumer. AECC thus argues that continuing to compensate lower-value energy at an artificially inflated price does not serve the public interest. Id. at 5-6.

Applicable Rate

AECC recommends adding a definition for "Applicable Rate" and suggests it read as follows: "The Net-Metering tariff rate filed by the Electric Utility that is multiplied by the kilowatt hours generated by the Net-Metering Facility and fed back to the Electric Utility."

AECC recommends that Commission adopt rates that are tailored to each public utility's approved cost-of-service and system characteristics. In the absence of a utility-specific rate, the Commission should adopt the utility's annual avoided cost rate for wholesale energy. Payments in excess of avoided cost should be based on a customer- and facility-specific determination and supported by substantial evidence. AECC argues that paying for excess generation at any rate above the utility's avoided cost also requires all other customers to pay premium prices for energy that is (1) non-dispatchable, (ii) unable to be scheduled when needed, and (iii) not subject to the control of the utility. Id. at 6-7.

Net Excess Generation Credits

AECC recommends that Staff's Strawman's proposed definition for Net Excess Generation Credits be deleted because it is unnecessary to carry out the law or to clarify the current Net Metering Rules. Id. at 7.

Quantifiable Benefit

AECC believes there is a legal question as to whether the Commission is preempted to implement a rate for the purchase of energy above the utility's average annual avoided cost of wholesale energy under federal law - specifically, the Federal Power Act and the Public Utility Regulatory Policies Act. Subject to this argument, AECC suggests a procedural modification to the term Quantifiable Benefits to make it more consistent with Act. 464. AECC's proposed definition includes additional language, as follows:

Id. at 8-9.

Demand Component Rates with Unique Characteristics

AECC urges the Commission to be flexible and consider alternate rate structures, including the phase-in of demand billing for certain Net-M customers with unique characteristics. For example, AECC submits, customers with seasonal accounts for irrigation, poultry houses, and other agricultural accounts should not receive full retail credit. Id. at 10.

Rate Structure

Carroll supports the comments provided by AECC and notes that it has the highest concentration of net-metering customers (relative to total customers) of any utility in Arkansas. In Exhibits A through F, Carroll provides extensive evidence of the growth of net-metering in Arkansas and its own service territory, as well as examples of poor solar installations and a proposed Customer Bill of Rights and Code of Conduct. Carroll states that the total number of net-metering customers reported to the Commission has grown from 24 in 2007 to 1,507 in 2018. Carroll Initial Comments at 2. Carroll supports grandfathering of net-metering customers. Carroll's most recent internal report shows a total of 459 net-metering customers (primarily residential) are interconnected or pending interconnection to its distribution grid. Id. Exhibit B at 8. Carroll recommends that the SIA be clarified so that both AC and DC ratings of net-metering proposals are listed with the limiting rating highlighted. Id. at 2-3.

Carroll recommends adopting a flexible, utility-specific Floor and Ceiling approach for setting a new rate structure. Carroll states that a reasonable Floor would be Avoided Cost, since net-metering facilities lack dependable capacity. An appropriate Ceiling would be the 1:11 full retail rate. Id. at 3 and 5.

Consumer Protections

Carroll recommends developing a Customer Bill of Rights, a Code of Conduct for Utilities, and a Code of Conduct for Net-Metering Vendors. In Exhibit D, Carroll provides the following examples:

* 2019 Solar Consumer Protection Guide, California PUC

* Consumer Guide to Rooftop Solar PV, Arizona Residential Utility Consumer Office (RUCO)

* Consumer Complaints with Solar Installation Companies, Webpage of the NPUC's Consumer Complaint Resolution Division

Carroll also provides Exhibit E which is the sworn affidavit of Joey Magnini, Carroll's representative for all net-metering interconnection agreements. Mr. Magnini provides numerous examples with pictures of faulty installations. In addition, Carroll provides a proposed Net Metering Customer Bill of Rights and related Codes of Conduct for utilities and Net-Metering vendors. Id. at 5.

Rate Structure

These five distribution cooperatives filed a one-page comment supporting the comments and recommendations submitted by AECC in the filing of their Initial Comments. Additionally, each of the cooperatives listed above has a goal to implement cost-of-service based rates and rate structures for net metering customers that are tailored to the unique characteristics of their individual cooperatives and are consistent with Commission approved cost-of-service principles.

Introduction

AEEC explains that the NMWG met only one time following the issuance of Order No. 22 and found little or no consensus on any issues. AEEC also notes that Staff's Strawman failed to provide a recommended resolution of the major contested net-metering issues or even a list of the contested issues. Therefore, AEEC limits its comments to criticism of Staff's suggested red-line amendments to the NMRs, and a summary of AEEC's general position on some of the contested issues. AEEC Initial Comments at 2.

Staff's Proposed Amendments to the NMRs

Changes to the NMRs

Walmart supports changes to the Net-Metering tariff that are applicable to net-metering customers receiving service under a rate schedule that includes a demand component. Walmart proposes the following revisions:

* In order to ensure that net-metering billing aligns with changes in customer billing demand, for net-metering customers who receive service under a utility rate that includes a demand component, in addition to crediting the net-metering customer for any net excess generation as set forth in Staff's Strawman at Sections 3.5 and 3.6, the electric utility should also reduce the net-metering customer's billing demand to reflect any applicable reduction in demand resulting from the net-metering facility; provided, however, that billed demand cannot be reduced below zero.

* Walmart proposes the following revision to Staff's Strawman at Section 3.2 to clarify that a net excess generation credit is not the only bill reduction available to net-metering customers with a rate that includes a demand charge:

On a monthly basis, the net-metering customer shall be billed the charges applicable under the currently effective standard rate schedule and any appropriate rider schedule. Under net-metering, the kilowatt hour (kWh) and kilowatt (kW) units of a net-metering customer's bill are netted.

Walmart Initial Comments at 1-2.

Introduction

Scenic Hill Solar notes that it does not serve the residential market, so although it supports the joint filing on the Strawman NMRs by Distributed Solar Advocates, it has limited its comments to how Act 464 impacts demand-metered customers. Scenic Hill Solar Initial Comments at 1.

Staff Strawman

Scenic Hill Solar supports Staff's changes to the NMRs that incorporate the uncontroversial provisions of Act 464. Id.at 2.

Meter Aggregation and Applicable Billing Period

Scenic Hill Solar supports the joint comments of Distributed Solar Advocates, Audubon, and Sierra Club regarding Act 464's provisions for meter aggregation and the applicable billing period. Id.

Demand Metered Customers

Scenic Hill Solar asserts that Act 464 does not give the Commission the authority to modify the rate structure for customers on demand component bills. Instead, Act 464 provides prescriptive language for net-metering demand billed customers. Scenic Hill Solar points out that during Phase 2, there was agreement within the NMWG that demand-metered customers are only netting the energy portion of their consumption, and are not causing any significant cost shifting. Scenic Hill Solar quotes from the NMWG Final Report, prior to the enactment of Act 464, wherein the utilities in Sub-Group 2 explicitly stated, "Sub-Group 2 recommends that demand-billed tariffs continue to be billed as they are today."63 Id. at 3.

Grandfathering

Scenic Hill Solar recommends a modification to Rule 2.07 that strikes the phrase "subject to approval by the Commission" to make it clear that the Commission is not required to engage in case-by-case grandfathering adjudication, but has issued its approval by establishing generally applicable rules for grandfathering. Scenic Hill Solar also argues that statute itself provides an inherent limitation to the applicability of a general grandfathering period by specifying that it applies only during the time period beginning with enactment of Act 464 and ending at December 31, 2022, the date at which federal tax credits expire. Scenic Hill Solar argues that Act 464 granted automatic approval for projects greater than 300 kW, but less than 1 MW in size, and thus the Act cannot reasonably be interpreted to delay these projects for a case-by-case grandfathering review, when such review would essentially subject them to the same delays that the General Assembly sought to eliminate by automating their approval. Scenic Hill Solar further argues that it cannot escape notice that the General Assembly applied uniform grandfathering language to all projects - making no distinction for a grandfathering decision (as was the prior practice of the Commission) between automatically approved projects and those subject to project-by-project approval. Scenic Hill Solar asks the Commission to maintain 1:1 net metering for demand-metered customers in its NMRs, as required by Act 464, and take all actions allowable under Act 464 to foster the distributed solar energy market in Arkansas to allow the state to achieve significant penetration, as intended by Act 464. Id.at 4-12.

In Reply Comments, the AG addresses rate structure, grandfathering, customer protections, leasing, and draft rules.

Rate Structure

Gradualism. The AG reiterates her support for a transition to 2-Channel Billing that would move closer to an excess generation credit based on avoided costs as net-metering penetration increases. This transition would balance the AG's goal to move towards a more equitable allocation of costs while being sensitive to the market disruption net-metering developers could experience from an abrupt and dramatic change in rate structure. The AG's review of Initial Comments does not change the AG's position that a gradual change of the rate structure is necessary. The AG notes that Staff came to the same conclusion regarding gradualism and the concern regarding cost shifting. However, the AG does not believe it is reasonable to downplay the subsidization concerns of the utilities, especially when planning for the future of net-metering in Arkansas. The AG is working informally with EAL to gather information specific to EAL's system that will further inform the AG's view regarding the magnitude of the cost shifting and assist in crafting reasonable solutions within reasonable time frames. Therefore, the AG continues to support a long-term policy that mitigates subsidization, or eliminates it if possible, while seeking a reasonable gradual transition to a rate structure that accomplishes this policy goal. AG Reply at 2-4.

Flexibility. The AG supports flexibility for the utilities in how net-metering is implemented and, to some degree, in how net-metering rates are set, citing Empire and AECC as advocates for flexibility, given the diversity of the utilities' abilities to implement technologies capable of supporting advanced solutions and the material differences between electric cooperatives and investor-owned utilities. Notwithstanding this, the AG continues to support a standard rate structure as the default, such as the 2-Channel Billing rate structure. However, the AG agrees that there may be utility-specific circumstances where a 2-Channel Billing rate structure is not feasible or is overly burdensome for some or all of its rate classes. The AG would thus support a mechanism whereby any utility that desires to deviate from the standard 2-Channel Bill approach can make a filing with the Commission requesting an exemption or variation, and propose and alternative net-metering rate structure that it believes is more reasonable for its customers and its customers' specific circumstances and is likewise in the public interest. Id. at 4-5.

Quantifiable Benefits. The AG states that numerous Parties addressed the term "Quantifiable Benefits" as it relates to setting a reasonable net-metering rate structure, noting that Distributed Solar Advocates asserted in their combined Initial Comments that while Act 464 does provide a more specific definition of the term than was suggested in the prior statute, the use of Quantifiable Benefits is not required when the Commission chooses to pursue any of the other rate structures within its authority, and as such "is a clear sign of legislative intent to move away from a rigid cost-based rate structure." On the other hand, the AG states, Carroll argues in its Initial Comments that Act 464 provides the Commission discretion to consider Quantifiable Benefits and costs associated with net-metering customers, seeing the application of Quantifiable Benefits as an area where the Commission can foster flexibility and the use of utility-specific information. According to the AG, OG&E also states that it is of the utmost importance to develop net-metering rates that are reasonable and based on truly Quantifiable Benefits, urging caution in including any such benefits that cannot be tied to an accounting or market mechanism or any amount not currently included in a utility's cost of service. Id. at 6.

The AG agrees with OG&E and believes that any additional monetary benefits included in net-metering rates must be quantifiable. The AG asserts that the term Quantifiable Benefits has been sufficiently defined in Act 464 and as reflected in the AG's draft NMRs.69 The AG urges the Commission to consider establishing a standard formula to calculate Quantifiable Benefits to eliminate ambiguity on what can and cannot be included in net-metering rates. The AG also support's Carroll's desire for flexibility and the need to use utility-specific information and data when setting net-metering rates, and believes a standard formula to calculate Quantifiable Benefits will achieve this goal. Id. at 6-7.

Grandfathering. The AG reiterates her Initial Comments interpretation of three levels of grandfathering created by Act 464 and notes that there seems to be a significant divergence of views on grandfathering within the Phase 3 comments filed by others. At one end of the spectrum, the AG observes, the view is that there should be no grandfathering at all. On the other end, says the AG, the view is that the rate structure at the time of interconnection should be grandfathered in for the life of the net-metering facility. The AG states that it and some other commenters fall somewhere in between. Id. at 8.

The AG recounts the positions of the Parties on this topic, and then repeats her original position that Act 464 gives the Commission authority to grandfather net-metering customers who fall into Level 2 (net-metering customers submitting an interconnection agreement between the effective date of Act 464 and December 31, 2022) on a case-by-case basis, noting that the specific language of Act 464 supports a case-by-case determination.

The AG points out that the statute clarifies that any possibility for grandfathering can only occur "following notice and opportunity for public comment."70 That AG believes that all grandfathering, both Level 1 (net-metering customers established before the effective date of Act 464 - July 24, 2019, who are automatically grandfathered into the current rates at that time: 1:1 Billing) and Level 2, should be limited to twenty years, as described by Act 464, beginning from the date the interconnection agreement is signed. The AG argues that its current recommendation on grandfathering would fall squarely within the plain language of Act 464. Id. at 8-10.

Customer Protections

Code of Conduct. The AG states that there seems to be general agreement in the Initial Comments that a code of conduct for net-metering participation should be developed to protect customers, citing proposals from AECC and Carrol, which actually included a Proposed Customer Bill of Rights and Code of Conduct. The AG repeats her original suggestion that customer protection issues, including discussion of Carroll's proposal, should be addressed through a separate working group that allows for flexibility as issues arise. The AG recommends that such a working group should consist of Staff, the AG, net-metering providers, and the utilities. The AG cites the successful PWC on matters related to energy efficiency programs as an example of a successful working group in Arkansas. However, the AG suggests that additional parameters be established for the net-metering customer protections working group, including a deadline for filing a Net-Metering Code of Conduct for Commission approval. In addition, the AG recommends that the working group should be required to meet at least semi-annually to address any new issues that need to be added to the Code of Conduct or revisions to be approved by the Commission. The AG suggests that more frequent meetings can also be set to deal with urgent issues. Id. at 11-12.

Regulation of Non-Utility Providers. The AG recounts her concerns in her Initial Comments that the Commission does not have statutory authority to regulate certain non-utility providers and notes that other Parties share this concern. The AG agrees with some of those Parties that net-metering providers should be required to register with the Commission prior to installing net-metering facilities in the State and be subject to program suspension or expulsion due to non-compliance with a Commission-approved Code of Conduct. However, the AG observes that to gain such authority for the Commission, legislation would be required. Without such legislation, the AG recommends that the Commission craft rules and regulations in such a way that utilities, which ultimately hold the responsibility for net-metering interconnection and which are strategically placed to protect the net-metering customer, bear the responsibility of customer protection. Id. at 12-13.

The AG asserts that it is reasonable for the Commission to enact rules such that if an unregulated third-party net-metering provider or participant does not adhere to the Code of Conduct, interconnection will not be completed or allowed to continue by the utility. The AG comments that this approach puts more burden on the utilities, which is not preferable, but absent legislation that gives the Commission general direct oversight of net-metering providers, there are limited options that will properly protect customers. The AG encourages the Commission to seek appropriate legislative changes that would place enforcement of the Code of Conduct where it belongs rather than punishing utilities for failing to adequately police unregulated third-party participants. Id. at 13.

Consumer Rights and Consumer Education. The AG agrees with numerous other Parties that there is a need for both a Consumer Guide and a Customer Bill of Rights and recommends that one of the assignments given to the customer protections working group include their development. The AG suggests that the Commission explore requiring the submission of a customer acknowledged copy of the Consumer Guide and Customer Bill of Rights with any net-metering interconnection request forms. The AG believes that the submission requirement is an appropriate term and condition for net-metering under Act 464. Id. at 13-14.

Leasing. In keeping with her recommendations regarding customer protections, the AG states that necessary legislative changes may be required to compel net-metering leasing providers to register with the Commission prior to installing net-metering facilities in the state and be subject to program suspension or expulsion due to non-compliance with a Commission-approved Code of Conduct. The AG expresses appreciation to EAL for suggesting that either a review process be established for lease agreements to be submitted to Staff and the utility, or the creation of a form agreement that net-metering providers would be required to use for leasing options. The AG states that this is also an issue best handled in the context of a customer protections working group. Id. at 14-15.

Net-MeteringRules. The AG reiterates her argument that it would be more administratively efficient to begin with the language of Act 464, as that represents the current public policy of the State of Arkansas and that draft rules be narrowly tailored to the statute. This, she asserts, is preferable to shoehorning Act 464's fundamental alterations to net metering into the existing NMRs. The AG continues to urge caution due to the dictates of Ark. Code Ann. § 25-15-220 requiring rules to be narrowly tailored to only that which is absolutely necessary to affect the statute. Id. at 15-16.

Introduction

Primarily addressing the comments from Staff and the Distributed Solar Advocates, EAL states that according to those Parties, there are no concerns that the Commission needs to address with any urgency, and most surprisingly, nothing that the Commission has any authority to address in several key areas. EAL argues that the Distributed Solar Advocates and Staff are misguided, and EAL submits that the Commission's swift action is needed for the protection of all customers. EAL Reply Comments at 1.

First, EAL asserts, there is a very real problem and the Commission should be concerned that:

* Contrary to the erroneous and patently self-serving claims of the Distributed Solar Advocates, sub-scale net-metered solar is clearly uneconomic, and the Commission can and should reach that conclusion readily, without the need for further study.

* The 1:1 full retail credit rate structure creates a significant incentive for customers to pursue uneconomic sub-scale solar, at the expense of non-participating customers - this too, requires no further study or analysis.

* Cost shifts are occurring now. There is urgency for the Commission to act, given the magnitude of the subsidy under the current 1:1 full retail credit rate structure and the volume of projects that have sought Preliminary Site Review and/or been announced. Claims that cost shifts currently are, and will continue to be, de minimisare false.

Second, EAL states that claims that the Commission lacks authority to address the problem in certain key areas are incorrect in that:

* The Commission retains the authority to modify the rate structure applied to customers with demand charges, either by eliminating the 1:1 full retail credit or by imposing an additional charge.

* The Commission retains the authority to determine whether a proposed generation facility actually qualifies for net-metering.

* Requests to grandfather the rate structure applied to a net-metering facility remain subject to review and approval on a case-by-case basis by the Commission.

EAL argues that, in short, the Commission faces an urgent choice between two very different futures: one - the preferred course - where grid-scale solar is aggressively pursued at economic prices yielding the twin benefits of economic capacity and energy for all customers as well as economic development and environmental benefits for the region; or the other - contrary to the public interest - where misguided net-metering policies result in substantial investment in uneconomic sub-scale solar for the benefit of the very few at the expense of the many. EAL urges the Commission to choose the first path and act now to ensure that its promise is realized. To be clear, EAL states, it is not advocating in any way, shape, or form that customers should not have the opportunity to install their own self-generation; rather, the Commission's net-metering policies and rules must ensure that other customers are not made to subsidize that choice by having to pay higher electric rates, which is the current path for the State of Arkansas in the absence of immediate action by the Commission. Id.at 2-3.

EAL summarizes its request that the Commission take the following actions in an order addressing the issues raised in Order No. 22:

* Implement 2-Channel Billing for non-demand billed customers (e.g., residential and certain small commercial customers);

* Implement either 2-Channel Billing or a grid charge for customers who pay a demand charge;

* Confirm that, in order to qualify for net-metering, the renewable generating facility must be physically attached to the customer's load (i.e. behind-the-meter), with appropriate sizing and aggregation requirements;

* Confirm that grandfathering, given its cost-shifting and distortive effects, will not be available for a customer unless approved for the customer through a specific order from the Commission Id. at 3-4.

Rate Structure Issues

EAL states that the Commission can and should act now to implement a rate structure that sends the correct pricing signals to customers considering investing in a net-metering facility. EAL argues that the predictable consequence of leaving the 1:1 full retail credit rate structure in place is a vastly more significant problem that will only become more difficult to address with the passage of time. EAL further states that the Commission has the opportunity and the duty now to design an appropriate rate structure, given the proliferation of solar opportunities now enabled by Act 464, that satisfies the "apples to apples" comparison that was presented to the Senate Committee as the overarching goal when the General Assembly was considering the Senate Bill that ultimately became Act 464. More particularly, EAL states:

Gaming Issues

Cost Recovery and Rate Structure

OG&E states that contrary to the opinions of the Distributed Solar Advocates, Act 464 should not be interpreted as an attempt to maintain the status quo for net-metering rate structures in Arkansas, noting that while the Act may allow for the continued use of the 1:1 crediting structure, it does so with the provision that any rate structure should be in the public interest. To date, OG&E argues, no Party to this Docket has presented viable evidence to counter the overwhelming support that the 1:1 crediting structure unfairly burdens the non-participants of the current net-metering program with costs that are unreasonably allocated to them by the participants. OG&E Reply at 1-2

OG&E asserts that the position held by some Parties that because of low penetration levels or potential impacts to existing customers with net-metering facilities, only a small step be taken now toward a more appropriate net-metering rate structure be taken at this time is in direct conflict with the Act's intention to promote a net-metering rate structure that is more in line with the public interest. OG&E states that this position would be to say that a known problem should be allowed to fester until becomes a more serious one. OG&E argues that it is not the intent of Act 464, nor should it be the intent of this process, to artificially support an industry on the backs of non-participating customers. OG&E states that an advantage Arkansas currently has is that it can establish rules that are sustainable and do not create subsidy issues that will have to be addressed in the future. Id. at 2-3.

OG&E observes that those Parties supporting 2-Channel Billing, grid access charge, or utility-specific solutions are the same Parties (the utilities) supporting the Act's intent to promote a net-metering rate structure that is more in line with the public interest. While OG&E maintains its support that net-metering solutions should be utility-specific due to unique operating and consumer circumstances, absent a utility-specific solution, it recommends a grid access charge as the most reasonable path forward for all customers. OG&E states that support for this proposal was laid out in its Initial Comments as well as those EAL and AEEC, and it was acknowledged as a potential path forward by Staff, the AG, and AECC. Id. at 3-4.

OG&E states that, in conjunction with the changes outlined in the Act for net-metering, it would be supportive of separating net-metering customers into their own class in a cost-of-service study to analyze and design an appropriate rate structure specific to these customers, whether it be TOU rates or otherwise. OG&E notes that taking service under a TOU rate structure would allow net-metering customers to realize the time-specific value of the energy that they produce. If this process is undertaken, OG&E states, it should be intended "to ensure that the on-peak windows selected, and the rates imposed for usage (and exports) during different periods, accurately reflect the cost to the utility of providing service during peak times," citing Initial Comments by the Distributed Solar Advocates.104 To aid in reducing the current unreasonable allocation of costs to non-net-metering customers, OG&E suggests, a transition to net-metering-specific TOU rates could be addressed by all utilities in their next proceeding in which a new cost-of-service study can be presented and net-metering customers can be analyzed in a standalone class of customers. Id. at 4.

With respect to customers served under a demand rate, OG&E acknowledges that the law certainly allows for maintaining the current 1:1 rate structures, but states that there is a need to ensure that the demand rates being charged to these customers are set at an appropriate level to fully recover the demand portion of the cost to serve. Otherwise, OG&E states, it will result in an unreasonable allocation of costs to non-net-metering customers under the 1:1 net-metering structure. OG&E supports a process going forward that allows for the examination of the current price level of demand charges to ensure each utility is recovering the appropriate level of demand-related costs to mitigate unreasonable allocations of cost to non-net-metering customers. Id. at 5.

Finally on the subject of rate structure, OG&E opposes inclusion in any part of the NMRs or utility tariffs in Arkansas Walmart's proposal that "[u]nder net metering, the kilowatthour (kWh) and kilowatt (kW) units of a net metering customer's bill are netted."105 OG&E cites to the express language of AREDA and Act 464 providing for the netting of kWh or kWh multiplied by the applicable rate of a net-metering customer's bill, and thus does not allow for netting of kW.106 Id. at 5-6.

Aggregation

OG&E references Distributed Solar Advocates' support of an amendment to the NMRs that establishes an "easy, clear, and non-controversial means for customers to establish common ownership of multiple accounts for purposes of meter aggregation," but replies that it is unclear how the provision of a tax ID or other defining trait could possibly be intrusive or unnecessary, citing the benefits of using such an ID. OG&E requests that the Commission implement a means for establishing common ownership that includes, but is not limited to, the provision of a customer's tax ID. OG&E also supports EAL's Initial Comment that defining common ownership is a significant issue that still remains to be addressed. OG&E agrees with AECC's Initial Comment that the Staff Strawman does not reflect the following found in Ark. Code Ann. § 23-18-604(c)(1), "an electric utility shall separately meter, bill, and credit each net-metering facility even if one (1) or more net-metering facilities are under common ownership." While OG&E agrees that there are exceptions for how net-metering credits are applied to common ownership facilities, it recommends the implementation of rules that reflect the law's prohibition on meter aggregation. Id. at 6-7 (emphasis added).

Grandfathering

OG&E notes that grandfathering under the current net-metering rate structure, not price level, ends on December 31, 2022. OG&E asserts that the purpose of grandfathering is to acknowledge that customers who construct facilities under prior rules/statutes may have made different decisions than under new rules/statutes, which means it only applies to the net-metering customer and not the facility. OG&E states that it should not be tied indefinitely to a customer or a facility as changes in ownership should take into consideration the rules/statutes in place at the time of that change. Id. at 7.

OG&E contends that the approach taken by Distributed Solar Advocates and Scenic Hill Solar to strike "subject to approval of the Commission" is in direct contradiction to the Act and is inherently flawed, arguing that the choice and length of time for any grandfathering decision should be based on a public interest finding in accordance with the Act. OG&E argues that there is currently no evidence to support the maximum allowable length of time as being in the public interest and, to make these findings, the Commission needs to have the ability to appropriately review the net-metering structure and price levels for each situation to determine if grandfathering is in the public interest. These determinations should remain subject to the approval of the Commission, according to OG&E, and made on a case-by-case basis. OG&E adds that this position is clearly supported by Staff when it states, "Prior to Act 464 the Commission has allowed grandfathering on a case-by-case basis. The Act requires no change to this practice."107

OG&E supports the second and third level of the 3-Level explanation of grandfathering provided by the AG, as it is reasonable and captures the language and spirit of Act 464.108 In addition, OG&E encourages the Commission to reject Distributed Solar Advocate's revision to Rule 2.07, to extend the grandfathering exemption to December 31, 2022, stating that had the General Assembly intended to extend the exemption until that date, it would have omitted the language permitting Commission approval on a case-by-case basis, as identified by Staff in its comments. OG&E also reiterates comments made by AECC, that "[t]he Commission's discretion to disallow grandfathering must be protected when it is evident that the proposed activity at the current rate structure does not protect other utility customers from unreasonable cost shifts. To hold otherwise would render the discretionary approval grant to the Commission meaningless."109 Id. at 8.

Data

OG&E disagrees with Distributed Solar Advocates regarding the topic of data and visibility into the distribution system, asserting that they are inappropriate for inclusion in this Docket and not based on any factual evidence. OG&E notes that the Commission is explicitly considering these issues in Docket No. 16-028-U and agrees with SWEPCO that attempting to define and establish a market-based incentive before these data issues are addressed in that docket seems premature. OG&E asserts that hosting capacity access is not a net-metering issue, but is a business request of third-party solar providers that would be paid for exclusively by all Arkansas customers, both net- and non-net-metering. Id. at 9.

Interconnection

OG&E states that the IREC Model Interconnection Procedures for 2019proposed by Staff for consideration by the Commission need to be more thoroughly vetted prior to any potential adoption, and that the appropriate docket in which to review it is Docket No. 16-028-U, where this specific issue is already being addressed. Id.

Consumer Protections

OG&E cites and supports the AG's proposals to protect consumers from predatory practices by third-party solar developers that are unregulated entities, noting that while the Commission may not be able to regulate the prices set by third-party providers, it certainly has the authority to impose certain requirements in accordance with the rules and statutes. For example, OG&E states that the Commission has the authority to determine if net-metering lease arrangements qualify to participate in net metering. If a customer enters into an arrangement that the Commission determines is not permitted under net metering, OG&E states that it is still able to participate under the small power producer rates (e.g., OG&E's COG-1 rate). OG&E supports the AG's suggestion of the formation of a working group to address "setting terms and conditions for participation in net-metering, including suspension or expulsion from the program, basic requirements and prohibitions for marketing materials, and customer contract requirements. OG&E supports the inclusion of utilities in such a working group if it is formed. OG&E also fully supports EAL's recommendation that the Commission address consumer protection rules that will assure that Arkansas consumers are not entering into long-term contracts or leases for solar generating facilities based on misleading or false claims and representations by solar developers with respect to the product they are selling to consumers. Id. at 9-10.

Leasing

OG&E recommends that the Commission adopt rules regarding third-party leasing of net-metering facilities and make explicit the types of facilities and agreements that will qualify for net-metering eligible leasing. OG&E supports statements by EAL, which states that these rules should (1) establish a review process for lease agreements to be submitted to Staff and the utility to ensure compliance; or (2) establish a form agreement that either must be used or that, if used, would allow the net-metering customer to forgo APSC review. Additionally, OG&E supports EAL's recommendation that the Commission clarify the standards that each net-metering customer will be required to meet to confirm their leased facilities or the energy purchased under a "service contract" are actually eligible for net metering. OG&E also supports EAL's recommendation when it states in part, ".the addition of third party leasing of a net-metering facility may require the Commission to adopt additional rules or guidelines regarding eligibility and criteria for such leases, beyond the listed limitations."110 OG&E supports the statements made by both EAL and SWEPCO and recommends that the Commission establish clear guidelines and rules for the definition, eligibility, limitation, form, and review of all third party net-metering lease proposals in an effort to protect all customers. OG&E recommends that the Commission establish clear guidelines and rules for the definition, eligibility, limitation, form, and review of all third-party net-metering lease proposals in an effort to protect all customers. Id. at 11.

Gaming

OG&E agrees with EAL's recommendations to the Commission around gaming, including a requirement that any net-metered facility must be behind the customer's meter and must displace some amount of electricity that the customer consumes. In particular, OG&E urges the Commission to establish rules that recognize Ark. Code Ann. § 23-18-604 requirement that net-metered facilities register the flow of a net-metering facility in two directions. In accordance with this law, OG&E states that rules should be established that prohibit facilities from qualifying specifically for net-metering (OG&E notes that they can potentially qualify as a Small Power Producer) if said facility is not located behind a customer meter in which load is offset. OG&E expands on this, by asking that the rules further clarify the restrictions for what qualifies as a proper account which a net-metering facility can appropriately be placed behind. OG&E cites as one example that should be avoided, the placing of a net-metering facility behind a security light to establish an account in which load would be offset. Id. at 12.

Other Issues

OG&E agrees with EAL's position that because Act 464 promotes the production and use of renewable energy, a customer that obtains energy from a facility but does not retain the renewable attributes through RECs, that customer is not receiving renewable power and is therefore not qualified for net metering. OG&E states that Ark Code Ann. § 23-18-603(7) is clear in this regard. Id. at 14.

Rate Structure

While it is SWEPCO's position that the 2-Channel approach for net-metering customers who receive service under a rate that does not include a demand component is the most effective mechanism to mitigate the current unreasonable allocation of costs to non-participating customers, SWEPCO would also support the recommendations of AECC, Empire, and OG&E that the Commission consider rules that would allow for utility-specific rate structures. This, SWEPCO asserts, would allow each utility the flexibility to select the best available option for proper rates based on long-standing cost-of-service principles, individual needs, and implementation of new metering and billing technologies. Additionally, SWEPCO endorses changes to the net-metering rate structure for demand-billed customers where current rate schedules do not recover the majority of fixed, functionalized costs through existing demand charges. SWEPCO does not support the continuation of the existing 1:1 credit rate structure for all the reasons included in its previous comments, but rather continues to support the adoption of the 2-Channel Billing approach. With regard to net-metering customer compensation in addition to the utility's avoided cost, SWEPCO reiterates that quantifiable benefits are defined as "[r]easonably demonstrated costs that:

Introduction

AECC asserts that the 1:1 full retail rate is overly compensatory, unduly preferential, and is against the public interest, noting that wholesale energy markets allow utilities to purchase generation for approximately 3 cents per kWh, on average. By contrast, AECC states, the current NMRs and conforming tariffs require utilities to pay net-metering customers between three and four times more than the market rate for generation. AECC Reply at 1.

Rate Structure

AECC notes that it has been argued by Staff117 that Act 464 does not require a change in the current net-metering rate structures currently established by the Commission. If true, AECC responds, the corollary is that Act 464 does not require retention of the current net-metering rate structures, either. AECC cites testimony of the Commission Chairman at a Senate committee hearing in support of its position that it has been acknowledged - even as the basis upon which Act 464 was passed - that the current, full-retail rate regime is unsustainable.118 AECC thus argues that now is the time for Arkansas to move away from over-compensating end-use generators who are neither operating in the wholesale energy markets nor complying with the same dictates that wholesale generators must satisfy. AECC states that such compensation is also contrary to well-established principles of ratemaking and public utility service. Id. at 1-2.

Nine electric distribution cooperatives filed Rebuttal [Reply] Comments pertaining to Staff's Strawman NMRs and point out issues with the current 1:1 full retail rate structure for demand-billed tariffs as discussed in Staff's Initial Comments. The Joint Cooperatives respond to Staff's Initial Comments stating that "[f]or customers with a demand component, the Act continued the current 1:1 rate structure, which the parties recommended for demand-metered customers." The Joint Cooperatives state that in those Initial Comments, Staff is relying on comments made in the Joint Report filed in Phase 2 of this Docket on September 15, 2017, by Sub-Group 2, where Sub-Group 2 recommended 2-Channel Billing to non-demand billed tariffs. While Sub-Group 2 recommended that demand-billed tariffs continue to be billed as they are today, the Joint Cooperatives note that there were a lot of assumptions and a vastly different statutory framework under which the Parties were collaborating to reach a settlement in Phase 2.

Joint Cooperatives Reply at (unnumbered) 1-2.

According to the Joint Cooperatives, the challenge with that compromise, particularly given the increased facility size (from 300 kW to as large as 20 MW) allowed under Act 464, makes the deficiencies in existing 3-part rate structures more difficult to navigate. For the distribution cooperatives, the Joint Cooperatives assert, it is simple to determine whether the existing 3-part structure is overly compensatory to net-metering customers: Each cooperative has a Cost of Energy Adjustment, which passes through inflation in fuel cost and TO/RTO charges billed to the cooperatives by their power supplier, AECC. Except for the TO/RTO demand-related charges, the Joint Cooperatives state, the pass through of these costs plus AECC's energy charge represent volumetric energy-related costs. The Joint Cooperatives state that to determine the fixed costs recovered in the volumetric base energy charge, an individual could find the difference between the energy charge for demand-billed tariffs and the cost of energy embedded in the cooperatives' base energy rates. For example, Rich Mountain's Large Power Service rate has an energy charge of 3.862 cents per kWh. The cost of energy embedded in the energy charge is 2.8264 cents per kWh. The difference of components is 1.0356 cents, which would represent fixed costs embedded in the volumetric energy charge instead of the customer or demand charge. Id. at 2.

The Joint Cooperatives provide Exhibit 1 showing fixed costs embedded in the energy charges for demand billed tariffs for the nine cooperatives. According to the Joint Cooperatives:

* Fixed costs embedded in the volumetric energy charge range from $0.00081 to $0.14237 per kWh sold. While there are demand-billed tariffs that align closely to cost of service, there are many that do not. C & L Electric Cooperative Corporation, Woodruff Electric Cooperative Corporation, and Mississippi County Electric Cooperative, Inc. have irrigation class tariffs that would be crediting to a net-metering customer as much as an additional $0.14237 of fixed cost per kWh sold under the existing 1:1 rate structure, which would create significant subsidies between net-metering and non-net metering customers. * Another example is Southwest Arkansas Electric Cooperative Corporation's rural three-phase rate. This rate's demand is currently being phased in as it previously did not have a demand component. The current energy charge is $0.08232 per kWh sold, which is $0.04447 per kWh sold above the cost of energy embedded in the energy charge.

* Each of the nine cooperatives listed reserves the right to address over-compensation for net-metered generation due to fixed cost recovery shifts between net-metering and non-net-metering customers.

* The cooperatives should be able to develop net-metering rate tariffs consistent with the present tariff revenue requirements as approved by the Commission by shifting costs to the customer and demand charges while lowering the existing energy charges.

Id. at 2-3.

Rate Structure

AEEC disagrees with Staff's contention that changes to the current net-metering rules should not be rushed absent a showing of unreasonable cost shift or increase in costs and its questioning whether the current 1:1 credit for net-metering customers results in cost shifting from net-metering customers to other electric energy customers. AEEC points to the Comments of Sub-Group 2 (which included Staff as a member) in Phase 2 of this Docket, stating that the Comments establish the opposite - that the 1:1 netting in rate classes that recover most of their fixed costs through volumetric rate components allows participating net-metering customers to avoid paying their fair share of fixed costs, thereby shifting those costs to other customers and creating a subsidy. AEEC asserts that Staff's "wait-and-see" approach is wrong and states that good public policy demands addressing the cost-shifting issue now - before the subsidy gets much larger and harder to address. AEEC Reply at 1-2.

With respect to the contention of the Distributed Solar Advocates that no subsidy or cost shifting exists, AEEC asserts that the Comments and testimony of Sub-Group 2 in Phase 2 of this Docket discredited Mr. Beach's Crossborder Report and that these same contentions are also refuted by the Initial Comments filed in Phase 3 by EAL, SWEPCO, OG&E, and AECC. AEEC states that significantly, neither Staff nor the Distributed Solar Advocates and Scenic Hill Solar refute the fact that the expansion of the opportunity for net metering made possible by Act 464 (primarily achieved through the raising of the caps and the loosening of the definition of "owner") will exacerbate the cost shift to non-participating customers, unless the Commission modifies the current rate structure. Id.at 2-3.

AEEC continues to support 2-Channel Billing (with an appropriate credit for excess energy) for net-metering customers in classes without a demand charge, or the concept of a Grid Usage Charge, and suggests that the Commission enact changes to create a reasonable net-metering rate structure as soon as possible, consistent with due process. However, AEEC opposes a phased-in approach, as suggested by the AG, and instead supports the approach to setting net-metering rates advocated by EAL, SWEPCO, and OG&E. Id.at 3.

Grandfathering

AEEC reiterates its Initial Comments position that the Commission must determine, on a case-by-case basis, whether a particular net-metering customer (or potentially a group or groups of customers) will be grandfathered so as to utilize the current rate structure. AEEC notes that its position is supported by Staff, the AG, AECC, EAL, and SWEPCO. In view of its Initial Comments and those of all non-solar parties in this Docket, AEEC urges the Commission to exercise the discretion afforded by Ark. Code Ann. § 23-18-604(b)(10)(A) and choose not to grandfather additional net-metering customers, asserting that a decision to grandfather would effectively enshrine a significant subsidy in rates for a period of time. Alternatively, AEEC suggests that the Commission exercise its discretion to grandfather customers for a short period of time (such as six to twelve months). Id. at 4.

Comments on Staff's Proposed Amendments to the NMRs

AEEC reiterates its suggested changes to Staff's proposed amendments to the NMRs made in its Initial Comments and, in addition, specifically support two AECC recommendations as alternatives to AEEC's:

Mr. Ball submits his observations and beliefs from a broad perspective, stating that the current net-metering rate structure and level of penetration do not significantly risk cost shifting to non-net-metering customers. He cites the testimony of Mr. Beach as demonstrating that the benefits of net metering equal or exceed the retail value of a kWh purchased from a utility in Arkansas: some benefits are realized by the utilities, some by utility customers, and some are universal benefits. He asserts that the utilities have largely refused to acknowledge a number of environmental, societal, and life cycle values that cannot be denied, and notes that California utilities have been forced to cut power to millions of customers to avoid potential fires that are now the new normal brought on by climate change. He cites this as an example of costs/benefits that are not recognized in a typical cost-of-service assessment. Ball Reply at (unnumbered) 1-2.

In response to EAL's Initial Comments contention that the benefits asserted by the Crossborder Report and other proceedings around the country have largely been challenged by the emergence of low-cost, grid-scale solar facilities, which deliver the same environmental benefits at a fraction of the cost, Mr. Ball states that it makes no sense to compare an investment made by a utility with funds that are ultimately derived from ratepayers, to an investment made by private capital. He notes that EAL in the same Comments minimizes the benefit of large projects being pursued by customers because they are injecting solar power into the grid at one location and consuming grid power at a different location or locations. Mr. Ball notes that every large commercial solar facility that has been installed in Arkansas, or is currently being pursued, is now serving or will serve customers that pay a demand charge. The result, he says, is that the customer is helping reduce demand for the utility at the solar facility while still paying demand charges at the locations(s) they consume grid power. Additionally, he asserts, meter aggregation is not retail wheeling, since the customer's facility is offsetting part or all of their energy requirements, whether their facility is located behind their meter or at a location with no customer load. Id. at 2.

With regard to RECs, Mr. Ball states that the NMRs are clear - RECs belong to the customer, not the developer nor the utility. He notes that Arkansas does not have a renewable portfolio standard and RECs have little economic value; that they can only be sold by the owner, whether with the help of a developer or not; and that if they are sold, neither the owner nor any other person except the purchaser can claim the environmental attributes of RECs. He asks, rhetorically, whether if the customer decided to give the RECs to the utility, would the utility claim the customer is not actually using (or purchasing) renewable energy and that the customer is thus simply ineligible for net metering? He states that he knows of no RECs that have been sold by Arkansas customers and that their minimal economic value is not being realized. He thus has no problem with the transfer of REC ownership to the utilities at the discretion of the net-metering customer. Id. at 2-3.

Mr. Ball states that if the Commission decides to alter the rate structure for net metering, he believes there are more equitable methods than using 2-Channel Billing, noting that net metering constitutes a kWh-for-kWh exchange, and that the utility does not purchase kWh from a net-metering customer. He considers the 2-Channel Billing method outlined in Act 464 to be too prescriptive and states that the limits listed in the Act are likely the reason the utilities supported the legislation. He states that limiting the value of net excess generation to avoided cost plus an adder not to exceed 40 percent of avoided cost would turn what is currently a marginal return on investment into an investment that most would not make. Mr. Ball states that if changes to net metering are necessary, he believes a grid access charge applied to all volumetric rate customers to be a preferable option. He submits that such an approach would consider impacts to all volumetric rate customers and be less likely to target only net-metering customers. He states that the grid access charge, if any, should be based on the size of a customer's electric service and if they are a net-metering customer, it should not be based on the size of their net-metering facility. Id. at 3-4.

Mr. Ball believes that EAL's request that all meters aggregated for the purpose of net metering should be under a common tax ID is a red herring. He notes that the rule states that all meters aggregated must be in the same account name and within the utility's service territory. He considers a requirement that all accounts be under one tax ID to be an attempt to suppress net metering. Mr. Ball states that in the case of third-party ownership where the net-metering customer is leasing the system, the developer provides numerous guarantees and insurance coverage that is in excess of the mutual indemnification requirement currently in place. He states that this is especially true in the case of government or other entities where the requirements for mutual indemnification are already waived. Id. at 4.

Mr. Ball asserts that it is disingenuous for utilities to accuse renewable energy developers of gaming a system in which the utilities hold all of the cards. He cites an example of a solar company that submitted a Preliminary Site Review to a utility on behalf of a customer and within twenty-four hours a utility-affiliate solar entity contacted the customer and informed them that "the interconnection would cost a lot less if they did the project instead of the private solar company." Mr. Ball supports the idea of including consumer protection language in the NMRs and suggests that there is also a need for language protecting renewable energy developers from utilities. Id. at 4-5.

Mr. Ball states that even if the utilities projections of lost revenues in the many millions of dollars are accurate, they represent revenue lost to competition that will affect their shareholder's bottom line and not lost revenues that they would otherwise invest in maintaining the transmission and distribution infrastructure and that the utilities therefore need to replace those losses by shifting costs to non-net-metering customers in order to support the grid. Id.at 5.

Mr. Ball observes that grandfathering is the only certainty in an uncertain renewable energy market. He states that Act 464 has increased the number of larger scale and third-party applications, but the increase in rooftop solar installations has not been as significant. He asserts that if new net-metering rules following utility recommendations are implemented, coupled with declining federal tax credits, investment in rooftop solar will be non-existent. He submits that even if 1:1 net-metering credit continued for many years, it is not certain that significant cost shifting would occur. He believes that the existing plan to extend grandfathering of net-metering facilities under the 1:1 rule until December 31, 2022, is prudent and consistent with the scheduled decline in the federal tax credit. Id. at 5-6.

In introductory Reply Comments, the Distributed Solar Advocates note that the most contentious topic for the Commission to resolve is how residential customers who install solar for their own on-site use should be credited for any renewable energy that they incidentally send to the utility's grid. These advocates assert that net-metering customers' reduced on-site usage and exports reduce the overall distribution system load, thereby enabling the utility to avoid many costs that would otherwise be incurred over the lifetime of the net-metering system. They state that from the perspective of all customers, the long-term reduced system costs enabled by these customer-financed systems outweigh reduced revenue recovery in the short-term - asserting that there is a net benefit to all ratepayers. In addition, the advocates state, the unique nature of the benefits provided by net-metered systems further countenances the Commission's support of these valuable resources. The solar advocates note that net-metered solar systems and other renewable distributed generation provide long-term, low-maintenance climate and other environmental benefits, job creation and system resilience and diversity benefits, among others - all based on significant private investment and federal tax credit leverage by customer generators. They point out that these customer generators maintain the systems, insure them, and enhance the value of the real estate where those systems are sited. Distributed Solar Advocates Reply at 1-2.

The Distributed Solar Advocates submit that valuing net-metering systems based on their ability to avoid costs already incurred is a completely illogical concept and will not create the proper incentives for private investment that benefits all customers by avoiding costly new utility investment. As such, they say, it is not consistent with the public interest to compensate net-metering customers at levels that do not reflect the value of their investment, and will not support further investment. The solar advocates reiterate their position that the Commission should determine that under the very low levels of distributed solar generation currently installed in Arkansas, the existing full retail net-metering framework is in the public interest and does not result in unreasonable allocations of costs to other customers. However, they state, to support development of this resource in a way that maximizes benefits to other customers, the Commission should establish a process to consider and evaluate alternative rate designs in a gradual manner. Id. at 2.

Rate Design

Net Metering for Demand-billed Customers. Distributed Solar Advocates state that Act 464 definitively requires 1:1 kWh netting for customers taking service on a rate that includes a demand charge, citing Ark. Code Ann. § 23-18-604(b)(6), and declaring that there is simply no rate design issue for the Commission to resolve in this proceeding as it relates to demand-billed customers.133 The advocates state that the General Assembly's foundation for this decision stems from the fact that even Arkansas's electric utilities had very recently taken the position that there is simply no reasonable claim of a cost shift caused by net metering when customers are on a rate that charges for demand-related costs directly. Despite clear statutory language, the advocates state, several parties (EAL, AECC, and SWEPCO) specifically advocate for the Commission to alter net metering for demand-billed customers, or argue with the General Assembly's judgment in maintaining the status quo for such customers. Id. at 3.

Distributed Solar Advocates state that among those Parties taking issues with net-metering for demand-billed customers, AECC attempts to interpret the statutory language to offer the Commission some discretion regarding rate structure for demand-billed customers, but to no avail. The advocates contend that AECC asserts that Act 464 provides discretion through the definition of net excess generation, which is defined as an "amount of electricity as measured in kilowatt hours or kilowatt hours multiplied by the applicable rate." 134 However, Distributed Solar Advocates argue, the use of the term "net excess generation" in Ark. Code Ann. § 23-18-604(b)(6) does not introduce the ambiguity or flexibility that AECC suggests, because that section otherwise mandates the Commission to require utilities to "base the bill of the net-metering customer on the net amount of electricity that the net-metering customer has received from or fed back to the electric utility during the billing period." Thus, the advocates claim, this section is unambiguous as to whether "net excess generation" should be credited to demand-billed customers based on kilowatt hours or "kilowatt hours multiplied by the applicable rate." Distributed Solar Advocates assert that only the former is permitted. Id. at 3. Distributed Solar Advocates state that in their Initial Comments, some Parties cite evidence regarding the scale of an alleged cost shift based on examples from demand-billed customers as part of their case to urge the Commission to move away from net-metering generally, or not allow grandfathering. While the advocates disagree that net-metering of demand-billed customers results in any cost shifting, they argue that any cost shifting that mayresult from kilowatt-hour netting of demand-billed customers is irrelevant to the separate question of what constitutes a reasonable rate structure for non-demand-billed customers, or how grandfathering should apply to such customers. They further state that if there were such cost shifts due to lost revenues from demand-billed net-metering customers, those costs would generally be borne by others within the same rate class, not shifted to other classes. Notably, the advocates state, AEEC, which represents demand-billed customers, acknowledges that cost shifting concerns among that group are not problematic.135 Distributed Solar Advocates state that the Parties who attempt to alarm the Commission about the consequences of grandfathering residential net-metering customers by referring to large potential systems installed on behalf of demand-billed customers are "unhelpfully conflating these issues." For example, the advocates contend, EAL witness Schnitzer calculates cost shift associated with large-scale projects for demand-billed customers. Such a calculation is irrelevant to the issue at hand, the advocates assert, and misleadingly suggests that the scale of distributed generation development in the residential market is anywhere near as significant as what has been proposed in the commercial and public sector entity markets. Id. at 4-5.

Net Metering for Non-Demand-Billed Customers. Distributed Solar Advocates state that residential customers take service on tariffs without demand charges and Act 464 leaves the Commission with significant discretion in how to design net-metering rates for such customers. According to the advocates, Act 464 requires the Commission to select a rate design that is "in the public interest and do[es] not result in an unreasonable allocation of costs to other utility customers."136 The advocates state that in determining what constitutes the public interest, the Commission should consider the purposes of AREDA, to promote distributed renewable energy resources, for the attendant health, resilience economic development, and consumer choice benefits. Distributed Solar Advocates state that in determining what allocations or increases of costs are "reasonable," the Commission should consider changes to rates over a planning time horizon, not based simply on a snapshot of embedded costs. They assert that just and reasonable rates not only recover prudently incurred costs; they also send price signals supporting economic efficiency and policy implementation. According to the advocates, "reasonable" allocation of costs include practices that tolerate de minimiscost shifts that are favored by public policy or could only be eliminated through measures that would result in rate shock or other disruption. What is a "reasonable" allocation of costs, the advocates assert, must also consider the public interest and AREDA's purposes - the two parts of the standard work in tandem. Although AECC urges the Commission to define "unreasonable allocation" in this proceeding, and the advocates agree that the Commission will need to interpret this term in order to adopt NMRs on rate design, they urge the Commission not to adopt a rigid definition that would preclude its ability to modify the rate design as the market and technologies mature. Id. at 5-6.

Reasonable Allocation of Costs and Cost Shifting. Distributed Solar Advocates state that Parties who argue that residential net metering shifts costs to other customers take a restrictive view of the question before the Commission and that their arguments boil down to a comparison of the retail rate (credited to consumers for exports under the current 1:1 approach) and either the cost of utility-scale solar or other measures of avoided cost for energy. The advocates assert that these frames ignore the cost and challenges of delivering wholesale generation to load, as well as system savings associated with slower peak load growth, and overlook other benefits of distributed generation including resiliency and consumer choice.137 As a foundational matter, Distributed Solar Advocates state, the Commission should recognize that net-metered customers do not createany costs by reducing their dependence on utility-provided electric service. They assert that the cost-shift issue is about allocations of costs and the efficient and policy-justified design of rates. Id.at 6-7.

Distributed Solar Advocates agree with Staff's Initial Comments138 that the time frame for the Commission's analysis matters, stating that if one looks solely at whether certain embedded costs can be avoided instantaneously as a result of distributed generation, then distributed generation appears to offer more limited benefits. However, the advocates contend, this myopic view treats all costs other than energy as fixed and unavoidable and leads to a result where a private investment that reduces system costs over the long run would be discouraged if it results in any costs to other ratepayers in the short run. They quote from Mr. Beach's Corrected Testimony finding that "Solar DG is a cost-effective resource for EAL, as the benefits equal or exceed the costs in the TRC, Program Administrator, and Societal tests. As a result, in the long run, deployment of solar DG will reduce the utility's cost of service."139 Distributed Solar Advocates state that the Crossborder Energy analysis uses a "long-term, life-cycle analysis that covers the full economic life of a solar DG system, which is at least 25 years."140 Mr. Beach explains that this is standard practice for these analyses and a long-term, life-cycle analysis is also standard practice when a utility wants to build and then charge its customers for a new plant that will last for decades. He adds that the benefits of DERs are avoided costs and not the embedded, historical costs used in COS studies. He states that avoided costs are by definition counterfactual - they are costs that the utility never incurs because it procures a service from another source.141 He quotes the economic axiom he believes to be useful here: -- Over the long run, all costs are variable - but notes that likewise, over the very short-run, all costs are fixed. Just and reasonable rates, he states, strike the right balance in addressing both short- and long-run cost impacts. Distributed Solar Advocates argue that every utility cost is fixed only on a short time-horizon and can be avoided if utilities engage in more comprehensive and integrated planning, including at the distribution system level, that includes forecasts of distributed generation development and output. Id. at 7-8.

Distributed Solar Advocates state that fortunately, AREDA gives the Commission flexibility to interpret the public interest and reasonable allocations of costs using a longer-term view of the utility's system. Doing so, they contend, is consistent with the Commission's approach to energy efficiency, which requires utility expenditures on measures that will cost effectively allow customers to reduce their usage, on the basis that these measures will ultimately avoid more costs than they impose in the short run. The advocates argue that the conceptual similarity to energy efficiency is why Crossborder Energy and countless other net-metering cost-benefit studies utilize the same framework for analysis of how system costs and other ratepayers will be affected.142 Id. at 8.

Distributed Solar Advocates state that the updated Crossborder Energy analysis filed with their Initial Comments shows that over a 20-year period, net-metered distributed generation avoids more costs than it shifts to other customers. They note that while they anticipate responding to additional critiques that may be made in the Reply Comments, the testimony of EAL witness Schnitzer contains a limited rebuttal of the methodology in the Crossborder Energy study. They also note that the study comprehensively addressed previously filed criticisms of its study in an attachment to the Surreply Comments of Sub-Group 1 to Joint Report and Recommendations of the NMWG in Phase 2 of this Docket. Distributed Solar Advocates then undertake an extensive review and response to Mr. Schnitzer and EAL's arguments. Id. at 9.

First, Distributed Solar Advocates state, Mr. Schnitzer agrees with Crossborder Energy that avoided line losses are a benefit of distributed generation.143 They state that the study's analysis employs line losses developed by EAL, which increase the energy value of distributed generation by seven percent and its capacity value by eight percent. Second, the advocates state, Mr. Schnitzer begins to rebut the concept of avoided transmission costs, but ultimately takes issue only with valuing avoided transmission in cases of meter aggregation, where the generation is remote from some portion of the load offset on behalf of the net-metering customer.144 The advocates state that even this limited critique falls apart as a matter of common sense about grid operations since a net-metered resource is still behind a meter on the distribution system and close to other loads, so any exports will flow directly to the closest load on that distribution feeder, whereupon the utility will charge full retail despite not having provided any transmission service associated with that particular kilowatt-hour. They argue that the assertion that the energy exported from a net-metering system would use the transmission to reach other meters associated with that customer account rests upon an inaccurate description of how electrons flow and is irrelevant to the analysis of avoided costs. Id. at 9-10.

Distributed Solar Advocates next respond to Mr. Schnitzer's contention that Crossborder Energy's valuation of avoided distribution costs relies on unnamed "studies for other utilities that have shown that 80 to 90% of distribution feeders are not fully loaded, and thus there are no capital costs to be avoided."145 The advocates state that while it is challenging to address Mr. Schnitzer's concern given the lack of citation to these studies, it also appears that he misses a core concept with avoided distribution costs. They state that it is unsurprising and reflects conservative distribution system management as well as typical patterns of system use, for most feeders not to be fully loaded. If a distribution feeder is already fully loaded, they note, it is likely too late to avoid any costs associated with an upgrade of the feeder's components. According to the advocates, distributed generation preventsa feeder from becoming fully loaded, which is how it avoids expensive incremental distribution system costs (that in turn may have low asset utilization rates) over the 20-30 year life of these generation systems. For this reason, Crossborder Energy estimates avoided transmission and distribution costs based on the relationship over a 10 to 20 year period between load growth and transmission and distribution system investments.146 Id. at 10.

Next, Distributed Solar Advocates address the subject of Mr. Schnitzer's testimony and EAL's comments regarding the relative costs of utility-scale and distributed generation.147 They state that simple economies of plant scale are widely understood, so it is unclear why EAL spent ratepayer dollars on an expert to establish that distributed generation is more costly to install than utility-scale solar. Moreover, they assert, this comparison misses the point and is irrelevant to implementation of Act 464. They note that EAL argues that AREDA is intended to promote economic renewable energy resources broadly, but argue that in doing so misreads the statute.148 Distributed Solar Advocates observe that AREDA is specifically about customer-sited and customer-financing renewables, not renewable energy generation more broadly. They note that Ark. Code Ann. § 23-18-602(a), stating the purposes of AREDA, refers specifically to net metering as a mechanism to reduce barriers to entry for customer-financed renewables, and the statute focuses exclusively on policies for development, administration, and compensation of customer-financed solar. They state that were AREDA intended to incentivize efficient utility-scale renewable energy development, it should be considered by the Commission as part of its review process for every resource planning decision by the utilities. The advocates argue that the added jobs and local economic benefits of distributed generation are the reason for higher prices ofand higher benefitsfrom distributed generation.

Distributed Solar Advocates assert that AREDA does not permit the Commission to make a policy choice that because utility-scale renewable energy may be less expensive to install than distributed renewable energy resources, distributed generation should no longer be facilitated through utility net-metering tariffs. Doing so, they argue, would undermine the purpose of AREDA to facilitate the exercise of consumer choice and local economic development. Id. at 11.

Moreover, Distributed Solar Advocates assert, the cost of a value provided by utility-scale renewables are not directly comparable to that of distributed generation. They state that Mr. Schnitzer asserts that all benefits of distributed generation can be obtained from utility-scale installations, which they contend is a blinkered perspective that ignores not only the avoided line loss benefit of distributed generation that Schnitzer otherwise acknowledges, but also the avoided transmission and distribution costs associated with generating electricity close to load. Unlike utility-scale systems, the advocates state, distributed generation avoids the need to acquire land and possibly expand the transmission system, both of which can be costly and face community opposition. Additionally, the advocates state, citing the Crossborder Energy study, distributed generation also lays the groundwork for a more resilient grid as it is the foundational technology for hybrid distributed generation-storage resources that can ultimately allow vulnerable customers or those offering critical services to ensure continued service during transmission and distribution outages. Distributed Solar Advocates argue that utility-scale solar, or any remotely located generation, will never provide that benefit. Id. at 11-12.

Finally, Distributed Solar Advocates note that EAL makes the strange argument that the utility and its customers must choose between utility-scale and distributed renewable energy, and that net metering is somehow deterring the utility from investing in utility-scale solar they acknowledge is extremely affordable.149

The advocates declare that there is no such trade-off and cite EAL's postulation that there is a limit on how much solar can be integrated on the system, but cites no study establishing what such a limit might be. The advocates note that in California, nearly 20 percent of energy production, on average, is from solar resources, and the state plans to add substantial amounts of new solar as part of its goal to achieve 100 percent clean energy by 2045. Distributed Solar Advocates state that as complementary resources such as storage and demand response become more widely available, any current engineering cap on the amount of solar the grid can accommodate, will increase. They cite a recent NREL study that shows that with increased grid flexibility, 25 percent or higher penetrations of solar can be achieved at low cost. The advocates contend that the question of what any cap might be is practically irrelevant in the state of Arkansas, which currently produces less than 3 percent of its energy from all non-hydroelectric renewable energy sources combined.150 They state that EAL eventually acknowledges the supposed ceiling on solar is a long-run problem.151 The advocates state that should EAL or other utilities accelerate their procurement of utility-scale solar to the point where it faces challenges managing this resource become a practical reality, they would welcome a reconsideration of the public interest in further incentives for distributed solar generation. They contend that the fact many customers are choosing to install distributed generation because utilities are not moving quickly enough to satisfy consumer preferences for less polluting generation resources, because customers value non-monopoly solutions, and intrinsically understand the benefits of distributed energy resources. Here, they state, a utility is seeking to squelch consumer choice simply because the utility could - but is not - giving those customers what they want, even though it would be quite affordable to do so. Distributed Solar Advocates assert that is precisely the consumer choice gap that AREDA aims to address. Id. at 12-13. Proposed alternative rate designs will not achieve objectives of the statute.

Distributed Solar Advocates state that Parties advocating for immediate changes to the net-metering rate design for residential customers generally call for two types of changes: imposition of a 2-Channel billing rate design with Channel 2 compensation at the utility's avoided cost of energy, or imposition of a grid charge. They respond that neither of these proposed rate designs meets the standard of consistency with the public interest and avoiding unreasonable allocations of costs. Id. at 13.

2-ChannelBilling proposals. Distributed Solar Advocates state that Parties who propose 2-Channel Billing call for compensation of excess energy exported to the distribution system at the utility's avoided cost of energy only. They respond that compensation at this extremely low avoided cost rate inadequately credits consumer-generators for the value that distributed generation offers the grid. Put another way, they assert, 2-Channel Billing overcorrectsfor a perceived shifting of costs to other customers that does not exist, especially if one considers the full spectrum of costs that distributed generation avoids. In doing so, they argue, it also fails the public interest prong on the Act 464 standard because export rates at avoided energy costs will not be sufficient to cover costs for systems that would be installed by most, if not all, residential customers. This rate design would devastate the residential distributed generation market in Arkansas, they state, and not only be contrary to the General Assembly's objectives to promote customer choice, avoid imports of out-of-state fuels, and the many other state interests in distributed generation, but it would also increase system costs in the long run as costs that distributed generation would have avoided are instead incurred. Id. at 14.

Distributed Solar Advocates note that, as the AG's Initial Comments aptly describe, an immediate shift to avoided cost-only generation would likely lead to the loss of jobs at solar installation companies in Arkansas. The advocates urge the Commission to consider the experience in Michigan as it decides what course of action to take, noting that in 2018, the Michigan Public Service Commission switched from full retail net metering to a compensation scheme based on LMPs.152 They note that this created significant uncertainty and a fall-off in solar adoption in the state, and Michigan lawmakers are beginning the process of adopting a new law to switch back to a rate structure that will better support the residential solar market.153 Id.at 14-15.

Distributed Solar Advocates observe that none of the proposed export rates includes avoided line losses, despite EAL witness Schnitzer's admission of this benefit. To the extent that the Commission concludes that it is unable to consider the full spectrum of avoided costs due to the definition of "quantifiable benefits" in Ark. Code Ann. § 23-18-603(9), then the Commission should decline to redesign net metering for residential customers in line with the process set out in Ark. Code Ann. § 23-18-604(b)(2)(B). Id. at 15.

Distributed Solar Advocates state that while the most important problem with the proposed 2-Channel billing net excess generation rate is the exclusion of avoided costs other than energy costs, another matter for the Commission to consider is that LMPs do not accurately reflect utilities' avoided cost of energy due to many utilities' practice of uneconomically dispatching coal units. The advocates note that a recent paper published by the Sierra Club shows that LMPs may be suppressed by nearly one-third due to excessive uneconomic generation, primarily by utility-owned units.154 Distributed Solar Advocates contend that although utilities that engage in self-scheduling practices may be able to buy power at these suppressed rates, their customers are effectively charged more for the utility's own generation when the utility's units operate at a loss, but they recover their production costs in excess of LMP from customers through their approved revenue requirement. The advocates state that it would require further investigation by the Commission to determine the utilities' actual avoided cost of energy, when factoring in any uneconomic dispatch practices by utility-owned generation in Arkansas. For the purposes of their comments, the Distributed Solar Advocates simply note that this would be a topic for further consideration if the Commission were to go the route of compensating residential net-metering customers based substantially on LMP. For the foregoing reasons, the advocates argue that the Commission should not pursue 2-Channel Billing. Id. at 15-16.

Distributed Solar Advocates address an argument advanced by certain parties that interprets Ark. Code Ann. § 23-18-604(b)(2)(B)(iv) to require that the net-metering customer demonstrate quantifiable benefits as part of establishing the rate for net excess generation. This section of the statute states: "the additional sum added to the avoided cost of the electric utility may be applied after the demonstration of quantifiable benefits by the net-metering customer and shall not exceed forty percent (40%) of the avoided cost of the electric utility." Distributed Solar Advocates assert that the phrase "by the net-metering customer" refers to the benefits provided by that customer, not a showing that must be made by the net-metering customer. They state that to interpret this provision otherwise would require the Commission to conclude that the General Assembly intended individual residential customers who wish to net meter to present a case before the Commission for such benefits, after hiring an attorney and expert witness, and for the Commission to consider separate evidence and issue separate orders in each such case. Fortunately, say the advocates, the statute can be read to avoid such an inefficient process by placing the burden of establishing rates on the utility.155 They argue that the Commission can avoid this thorny issue entirely by declining to adopt 2-Channel Billing. Id. at 16-17.

Distributed Solar Advocates also urge the Commission to reject OG&E's argument that integration or "storage service" costs should be netted out of quantifiable benefits, suggesting that this approach appears to be a holdover from the prior version of Ark. Code Ann. § 23-18-604(b)(2)(B), but is not permitted by the current definition of quantifiable

Grid charge. Distributed Solar Advocates note that several Parties advocate that the Commission impose a grid charge on residential net-metering customers, acknowledging that such a charge is among the options specifically permitted by AREDA.

Ark. Code Ann. § 23-18-604(b)(2)(C) permits the Commission to:

Authorize an electric utility to assess a net-metering customer that is being charge a rate that does not include a demand component a per-kilowatt-hour fee or charge to recover the quantifiable direct demand-related distribution cost of the electric utility for providing electricity to the net-metering customer that is not:

Scenic Hill Solar's comments address in particular the comments of EAL regarding demand-metered customers, net metering penetration, common ownership, grandfathering, renewable energy credits, and energy storage, and provide correspondence with EAL for the Commission to establish that EAL has routinely delayed the most basic of interconnection reviews on spurious grounds. In addition, Scenic Hill Solar provides a correction to what it calls EAL's completely speculative and premature analysis that finds that a substantial cost shift will occur as a result of Scenic Hill Solar's interconnection of a net-metered system for the City of Hot Springs. As well, Scenic Hill Solar addresses some of EAL's "unsupported" redlines to its net-metering tariff and the Commission's NMRs. Scenic Hill Solar Reply at 1-2.

Further, given EAL's claims of net metering causing a cost shift to non-net-metering customers, Scenic Hill Solar provides as attached exhibits the reports cited in its initial comments, which were reports synthesizing individual studies at the state or utility level, and providing an extensive sampling of those studies. According to Scenic Hill Solar, these studies generally show net metering has either a de minimis impact or a net benefit on non-net-metering residential customers, implying that demand-metered customers, which have lower energy rates than residential customers, provided an even greater net benefit according to those studies. According to Scenic Hill Solar, the intent of including these studies is to show that EAL's claims of cost shifting are based on a simple avoided energy cost analysis that ignores other values commonly identified in studies. With Arkansas' low penetration of solar, Scenic Hill Solar asserts that whatever the impact of net metering is, it is certain to be very small as a percentage of retail sales. Scenic Hill Solar states that the Commission has plenty of time to determine the scope of an appropriate study and conduct the study, and expects that such a study will show that net-metering provides a net benefit, as other studies in low solar penetration states have shown. Id.at 2.

Demand-metered Customers

Scenic Hill Solar states that, along with EAL's initial comments, its witnesses Schnitzer and Owens filed testimony addressing the purported impact of demand-metered customers and steps that the Commission could take to mitigate these impacts. EAL's comments also incorporate by reference testimony filed by witnesses Castleberry and Talkington in Docket 19-042-TF regarding cost shifting. For purposes of the present rulemaking, Scenic Hill Solar contends that this blizzard of testimony should not be considered at all with respect to demand-metered customers. Id. at 3.

According to Scenic Hill Solar, Act 464 clearly preserves traditional kilowatthour-for-kilowatthour (1:1) net metering for demand-metered customers, so it is out of scope in this rulemaking to address alleged cost shifting caused by these customers. Nonetheless, Scenic Hill Solar questions the conclusions of these EAL witnesses, noting that Mr. Schnitzer provides calculations of the overall impact of net metering, including the "made up" specific example of a net-metering facility that he asserts Scenic Hill Solar may use to provide energy to the City of Hot Springs. Scenic Hill Solar states that Mr. Schnitzer's calculations for Hot Springs are refuted later in its comments, but also questions his overall results in light of the numerous studies attached to its comments that show much greater benefits than just the avoided energy costs that Mr. Schnitzer uses. Most notably, Scenic Hill Solar states, he shows that for LGS customers, the cost shift is just 1.1 cents per kWh using EAL's avoided energy cost as the only benefit.174 With even the most conservative of approaches acknowledging just over a penny of other benefits, Scenic Hill Solar argues that the cost shift for these customers becomes a net benefit for non-net-metering customers. To be clear, Scenic Hill Solar acknowledges that many of its customers have LGS meters. Most importantly, Scenic Hill Solar states, all that EAL knows about the Hot Springs project is that an agreement exists for a 12.75 MW facility and that neither Mr. Schnitzer nor anyone else at EAL knows anything more about the project, so it is impractical for them to opine on the impact of the project at this time.

Scenic Hill Solar asserts that it is a free country, so Mr. Schnitzer can speculate all he likes, but the Commission should ignore completely his speculation, as the APSC will have an opportunity to review the future Hot Springs projects when they have been fully developed. This will occur more quickly, Scenic Hill Solar states, if EAL stops its delaying tactics in processing preliminary interconnection site reviews. Id. at 3-4.

According to Scenic Hill Solar, Mr. Owens provides extensive testimony on how 2-channel billing can be established to pay for exported energy at avoided cost rates, including an example showing the process and supposed savings of using 2-Channel Billing for a demand-metered customer. Again, Scenic Hill Solar asserts, there is simply no point in providing this example, given that Act 464 preserved 1:1 net-metering for demand-metered customers. According to Scenic Hill Solar, within EAL's comments, the citations to testimony in Docket No. 19-042-TF include a summary of those results, with wildly unrealistic impacts based on all customers that have filed for preliminary review actually installing systems. What matters at the present juncture, Scenic Hill Solar asserts, is that solar penetration in Arkansas is so low that impacts are immaterial at this point, and any reported impacts should be based on an unbiased study that considers more than avoided energy costs. Particularly for demand-metered customers, Scenic Hill Solar states, a reasonable analysis accounting for more than just avoided cost would show a net benefit of the largest customers availing themselves of net metering. Id. at 3-4.

Net-Metering Penetration Scenic Hill Solar asserts that EAL's reported cost-shifting impact raises the issue of when the Commission should perform a study to look at the impacts of net metering from its unbiased perspective. Scenic Hill Solar suggests that the Commission has time to begin to formulate the approach it wants to use for study based on examples from dozens of other states, and hire an expert to perform a study of the impacts for EAL and to develop a model for evaluation of the impacts for other utilities. Further, Scenic Hill Solar suggests that changes to net metering should be based on such a study; at the current low penetration, and that the impact on non-net metering customers is de minimis. Scenic Hill Solar poses the question: When is the right time for a study? Scenic Hill Solar responds that looking at all generation in kilowatt-hours, as a percentage of the utility's total customer sales, would be a useful way to establish the timing of a review of net metering, noting that both Minnesota and New Jersey have used this percentage of retail sales approach. According to Scenic Hill Solar, Minnesota uses four percent of utility retail sales, at which point a utility can request to deploy a value-of-solar tariff. New Jersey uses 5.8% of total state retail electricity sales, says Scenic Hill Solar, at which point a supplier can ask that state's commission (the Board of Public Utilities) to let them stop offering net metering. Scenic Hill Solar suggests that to establish net- metering generation, it would be a cumbersome and unnecessary exercise to gather the data for all net-metering systems in Arkansas. Instead, the Commission could use average kWh/kW figures from existing Arkansas systems, together with data from NREL's PVWatts to calculate generation based on installed capacity. According to Scenic Hill Solar, the benefit of using a generation-as-a-percentage-of-sales approach would be that the percentage sets an absolute outer bound on cost shifting. In the example it presents, if the utility sees a reduction of 3.4 percent of its sales due to net metering, the impact on non-net-metering customer bills cannot be any more than that percentage. Even using only avoided energy costs, Scenic Hill states, the impact on non-net-metering customer bills would be in the range of only 2%, and with reasonable accounting for other benefits, argues that the impact would be to reduce non-net-metering customer bills. Id. at 5-6.

Scenic Hill Solar asks what the appropriate threshold is for a study using this approach. Given that AREDA has a clear intent to promote distributed renewable energy, and its language regarding avoiding "an unreasonable allocation of or increase in costs to other utility customers," Scenic Hill Solar suggests that the Commission would want to conclude a study before net-metering penetration exceeds five percent, at which point even with only an avoided energy cost approach, the impact of net metering on non-net-metering bills would be no more than perhaps 3%, and a reasonable study would likely show a minimal impact. Id. at 6.

Common Ownership

Scenic Hill Solar states that EAL simply ignores AREDA's language of "common ownership" and instead imposes a requirement of customers having the same tax identification number ("tax ID") in its place. Having gone through this discussion with EAL for a specific project, as discussed in both Initial Comments and the supplemental testimony of EAL witness Palmer, Scenic Hill Solar states that it is clear that the tax ID approach is unworkable. Id.at 6-7

More importantly to Scenic Hill Solar, the statutory requirement regarding common ownership cannot reasonably be interpreted to mean anything but ownership by the same person or entity. Scenic Hill Solar states that an entity such as a municipality can have more than one tax ID for different city functions, but if the city owns both the water pumping station and city hall, those two city functions with separate tax IDs are nonetheless commonly owned. Mr. Palmer discusses the request of Scenic Hill Solar's client, the City of Stuttgart, and states the crux of the problem as, "because it is reasonable to assume that a non-taxable entity has a single tax ID, EAL considers it clear in the statute that multiple tax ids would constitute multiple net-metering customers."175 Scenic Hill Solar responds that it is not reasonable to assume that a non-taxable entity has a single tax ID. For the City of Stuttgart, Scenic Hill Solar states that it has clearly demonstrated that the City has more than one tax ID, and has gotten the Mayor on the phone with EAL to affirm that the City has more than one tax ID. Scenic Hill Solar asserts that the effort has dragged on for months, as discussed later in its comments, for absolutely no reason, adding that EAL's response has been to refuse to complete a preliminary technical review based on its position that the City of Stuttgart is not the common owner of its city departments.

Scenic Hill Solar notes that EAL's comments address the Stuttgart example as well, over the course of three pages.176 Scenic Hill Solar states that it seems audacious that EAL can be aghast that it claims that, "three separate legal entities with separate federal taxpayer identification numbers (i.e., the City of Stuttgart, Stuttgart Municipal Waterworks, and the Stuttgart Public Library) now are "associated with" one customer, i.e., the City of Stuttgart." Scenic Hill Solar states that it does claim that these entities are under the common ownership of the City and asks that the Commission direct EAL to accept that city departments, despite having separate tax IDs, are under the common ownership of the city in question. According to Scenic Hill Solar, EAL goes on to posit that under its line of reasoning, a person who owns multiple businesses might claim common ownership.177 Scenic Hill Solar asserts that EAL's presumption seems to be that opening this floodgate will allow untold combinations, possibly even without actual ownership in common. In Scenic Hill Solar's opinion, an affidavit of common ownership would be sufficient, but it would also be feasible to show evidence of common ownership through corporate formation documents showing common ownership. However, Scenic Hill Solar urges the Commission to not apply such a rule to municipalities, arguing that proving that the library and the water department of a city are under common ownership is a frivolous exercise; common ownership in that case is self-evident. Id.at 6-8.

Grandfathering

Both Scenic Hill Solar's Initial Comments and the Initial and Reply Comments of Sierra Club/Audubon/AAEA [herein the Distributed Solar Advocates] discuss grandfathering at length, and the need for certainty. In contrast, according to Scenic Hill Solar, EAL asserts that grandfathering will perpetuate the cost shifting that they allege. As noted earlier in these comments, Scenic Hill Solar argues that by only looking at avoided energy costs, EAL is dramatically overstating the potential for cost shifting and asserts that grandfathering is critical for demand-metered customers. Scenic Hill Solar asserts that while 1:1 net metering is preserved by Act 464 for demand-metered customers, laws can change. Scenic Hill Solar asserts that just as a residential customer who installed a net-metering facility before Act 464 reasonably expects the 1:1 net metering that motivated her to install her facility will not be snatched away, a demand-metered customer installing a net-metering facility today should be able to rely on the continuation of 1:1 net metering. Id.at 8-9.

Scenic Hill Solar states that EAL has redlined the NMRs to add a grandfathering provision as Rule 2.11, providing only that, "Any customer who is already interconnected at the time of the enactment of these Rules may apply for grandfathering by submitting an Application with the Commission." Scenic Hill Solar states that asking every net-metering customer in the state to submit an application to the Commission for an individualized determination of grandfathering creates needless uncertainty and thwarts the goals of AREDA. Scenic Hill Solar asserts that consistency requires that the Commission establish a single period for grandfathering. Given that Act 464 allows for a period of up to 20 years, the Legislature clearly considered that amount of time to be in the range of reasonableness, and Scenic Hill Solar encourages that length to give the prospective net-metering customers the improved certainty that will spur more renewable installations as intended by the Arkansas General Assembly. Id.at 8-9.

Renewable Energy Credits

Scenic Hill Solar states that EAL makes the interesting though unsupported argument that net metering customers must retain the RECs associated with their net-metering facility's generation, or else the facility is no longer actually a renewable energy generator. Mr. Schnitzer cites the Energy Services Agreement that the City of Hot Springs has signed with Scenic Hill Solar as an example of a developer retaining RECs.178 The problem with this argument, according to Scenic Hill Solar, is that AREDA does not require that the net-metering customer retain the RECs associated with her facility, but only that, "[a] renewable energy credit created as the result of electricity supplied by a net-metering customer is the property of the net metering customer that generated the renewable energy credit."179 Like any property, Scenic Hill Solar observes, RECs can be sold. Scenic Hill Solar state that it does not assume that it owns the RECs, which is the reason that a provision about RECs is in the agreement with the City of Hot Springs cited by Mr. Schnitzer. In practice, Scenic Hill Solar states, it is difficult for an individual net-metering customer to become familiar with the processes for tracking and selling RECs, so the RECs have less value to the net-metering Customer directly than may be achieved by a developer on the net-metering customer's behalf. By taking ownership of the RECs, Scenic Hill Solar contends that it can offer the City of Hot Springs and other customers lower energy rates. Scenic Hill Solar asserts that the argument that selling energy generated by a solar array to a utility customer, while not selling the associated RECs to the customer somehow makes the solar array no longer a net-metering facility is unpersuasive. A net-metering facility is defined in relevant part as a facility that, "[u]ses solar, wind, hydroelectric, geothermal, or biomass resources to generate electricity.. ."180 Scenic Hill Solar states that it is unaware of any state that requires the net-metering customer to retain RECs -- the common practice is to allow the sale of RECs because it is another revenue stream that helps defray the cost for the customer. Given EAL's alleged intent to delay interconnection approval for the City of Hot Springs based on their assertion that the REC ownership issue creates uncertainty, Scenic Hill Solar requests that the Commission rule on this issue as soon as possible. Id. at 9-11.

However, with massive investments in battery technology underway, particularly for electric vehicles, Scenic Hill Solar states that the general speculation is that battery costs will continue to rapidly decline.181 Scenic Hill Solar suggests that at some point in the coming months, the Commission will need to clarify what types of storage facilities may be considered a part of a net-metering facility, given the changes in Act 464. Id.at 11.

Evidence of EAL Delays

Scenic Hill Solar notes that in Mr. Palmer's supplemental testimony for EAL, he states that, "some parties have alleged that EAL is obstructing the preliminary site review process and interconnection process for potential net-metering installations," and, "[t]o date, EAL has only notified three potential net-metering customers of such issues related to Act 464."182 The City of Stuttgart, a Scenic Hill Solar customer, is the first of the three customers that Mr. Palmer discusses. Scenic Hill Solar states that it has experienced issues with other applications, and attaches to its Reply Comments some of its lengthy correspondence with EAL to seek preliminary reviews, each of which is discussed at the end of this section. For these reviews, Scenic Hill Solar has paid $1,000 each, for a total of $12,000 to date. According to Scenic Hill Solar, the limited and non-binding technical review of whether an interconnection of a MW facility at a particular site will possibly require upgrades appears to require only a few hours of engineering time. Id.at 11-12.

Scenic Hill Solar notes that at the October 29, 2019 workshop in Docket No. 16-028-U, EAL clearly explained what is variously referenced in its comments in the present Docket: if it perceives that an applicant would not qualify for net metering, then it will not process the preliminary technical review. Scenic Hill Solar asserts that with the stated intent of not misleading customers that they might qualify for net metering, EAL refuses to even provide the most basic technical review of distribution circuit capacity. Scenic Hill Solar contends that the Commission has the sole authority to determine whether a proposed project qualifies for net-metering. Obviously, Scenic Hill Solar states, it would not waste time guiding a customer down a path towards development of a facility if it thought the facility would not qualify. While EAL might have a different opinion, Scenic Hill Solar asserts that it is not their prerogative to decide these issues on their own, especially in the preliminary site review process. Id.at 12.

Scenic Hill Solar attaches as Exhibit 1.a correspondence with EAL starting in July 2019 regarding the Stuttgart project. The first page summarizes the 23 major interactions on the pages that follow. Scenic Hill Solar states that the August 15th email from EAL in this Stuttgart correspondence details EAL's refusal to process multiple applications for a project in Camden (each of which Scenic Hill Solar paid EAL to process). As shown by the correspondence, Scenic Hill Solar states, it repeatedly represented that there were only two tax ID numbers associated with the City of Stuttgart, while EAL contended that there were three. After multiple emails over several months, Scenic Hill Solar states that it was finally able to get EAL to identify which meters had tax ID numbers other than the two now known to be associated with the City. The City of Stuttgart has supplied EAL with W-9 forms to correct errant tax ID numbers in EAL's records, per the final correspondence in the record. According to Scenic Hill Solar, this string makes it very clear that tax ID numbers are not a workable method for EAL to establish common ownership. According to Scenic Hill Solar, the common ownership of City of Stuttgart departments could have been accepted as obvious three months ago, and the project could be installed and operational at this point, but for EAL's delay. Scenic Hill Solar also attaches as Exhibit 1.b a timeline and 32 pages of correspondence with EAL regarding applications for multiple net-metering facilities to serve the City of Camden and Ouachita County, starting with initial applications in June. Again, Scenic Hill Solar cites delays based on multiple applications, each of which EAL was paid $1,000 to process, attributable to EAL's opinion that they are not required to undertake more than one study for any given customer at a time. Scenic Hill Solar provides Exhibit 1.c -- a four page email string with EAL regarding multiple applications for preliminary review of facilities to serve Forrest City. According to EAL, these emails also illustrate that EAL is asserting that it will not process more than one application at a time for facilities proposing to offset load at one or more of the same meters. Scenic Hill Solar's purpose in filing the email strings related to Stuttgart, Camden, and Forrest City is to demonstrate the pressing need for Commission direction that a utility cannot rely on tax ID numbers to determine common ownership (at least, not for municipalities), and that a utility should process preliminary technical reviews promptly, without delay based on its interpretation of Act 464 and the net-metering Rules. Id.at 12-14.

EAL Testimony Regarding the Impact of the City Hot Springs Utilizing Net-Energy Metering

Scenic Hill Solar states that in the Mr. Schnitzer's testimony, he shows that the energy rates for LGS and LPS customers are mostly comprised of his determination of 3.5 cents of avoided cost, with the remaining 1.1 and 1.0 cents, respectively, of those rate schedules' energy rates attributed to a "cost shift."183 Scenic Hill Solar asserts that Mr. Schnitzer thereby assumes the conclusion he wishes to achieve. While Scenic Hill Solar vigorously disputes whether there is a cost shift at all, even with Mr. Schnitzer's assumptions, it points out that the cost shift would be a fraction of what he has calculated. Scenic Hill Solar states that it does not wish to expend anyone's resources to review all of EAL's witnesses' calculations. As noted earlier, Scenic Hill Solar notes that the only information that EAL has concerning the Hot Springs project is that an agreement exists with Scenic Hill Solar for a 12.75 MW project; EAL is merely speculating about impacts without knowing any details about the project. According to Scenic Hill Solar, at the appropriate time the Commission will have an opportunity to review the specifics of a "real" project from Scenic Hill Solar for Hot Springs, rather than the "fictional" project examined by Mr. Schnitzer. Id.at 13-14.

Miscellaneous EAL Redlines

Scenic Hill Solar states that in EAL's redline of the NMRs, attached to its Initial Comments, EAL includes several provisions that are not supported by AREDA as modified by Act 464. Scenic Hill Solar's attention to these specific redlines is not meant to show support for any other elements of EAL's redlines. In NMR Rule 2.01, EAL adds in redline that a utility, "is not required to interconnect a customer installing a renewable facility that is not connected to its load." Scenic Hill Solar states that it justifies this position in its comments with the logic that AREDA calls for the use of a bidirectional meter, and such a meter would be unnecessary if energy only flowed in one direction, such as at remote generation site without load.184 According to Scenic Hill Solar, this argument suffers from several fatal flaws:

* First, AREDA only says that an electric utility "shall allow" interconnection of a NET-METERING Facility with a bi-directional meter; it does not require the use of a bi-directional meter;185 accordingly, EAL is free to use a uni-directional meter at a net-metering facility sited remotely;

* Second, nothing in AREDA requires load at the generation site, including the definition of a net-metering facility;

* Third, the concept of allowing generation to offset load at another site was conceived of, and has been discussed throughout workshops in this docket as a way for customers with load at a site with limited potential for solar generation to put an array on vacant [sic] land elsewhere and offset their load; and

* Fourth, a customer can install lighting at a remote generation site and thereby have load at the site.

Id. at 14-16.

Scenic Hill Solar next notes that in NMR Rule 2.09(C), EAL adds redline to prohibit multiple applications to offset the simple, non-binding reviews. As Scenic Hill Solar discussed previously, the customer pays $1,000 for these fairly simple, non-binding reviews. Scenic Hill Solar responds that in the interest of enabling distributed renewable generation, it makes sense for a developer to be able to ask about the potential to install a given net-metering facility on multiple locations and pick the most promising. Importantly, Scenic Hill Solar asserts, requiring sequential rather than parallel preliminary reviews would needlessly delay projects. In NMR Rule 2.10, EAL's redlines would prohibit applications that cumulatively exceed the 1 MW threshold unless there is Commission approval. Presumably, Scenic Hill Solar asserts, EAL intended this provision to apply to applications to serve the same load, such as three facilities to serve a single commercial customer. However, together with its proposal to have the developer sign an interconnection agreement along with the utility customer, Scenic Hill Solar argues that EAL's redline here would effectively prohibit any developer from having more than a single MW of applications submitted to a utility at any given time. As well, Scenic Hill Solar states, this relates to its discussion in the prior paragraph of the propriety of allowing multiple applications. Id.at 16.

Scenic Hill Solar notes that in Section 3.01, EAL's redline would have the developer sign the interconnection agreement along with the host, noting that to its knowledge, this is not done elsewhere. Scenic Hill Solar states that the developer is identified in the agreement and given authority to represent the utility customer, so that the utility can address any issue or emergency with the installer who has a deep understanding of the facility design and the interconnection. However, Scenic Hill Solar states, the utility has an existing relationship with the utility customer, and energy being exported from the site belongs to the utility customer, and therefore that is the appropriate contracting party. Id.at 16-17.

Finally, Scenic Hill Solar notes, in EAL's redline of its tariff, it adds in Section 52.1.1 that the threshold size for a commercial NET-METERING facility is the "lesser [sic] of 1) one thousand kilowatts (kW) for non-residential use unless otherwise allowed by the Commission and 2) one hundred percent (100%) of the Net-Metering Customer's highest monthly usage in the previous twelve (12) months of use." Scenic Hill Solar states that there is no such restriction in AREDA, other than a provision that for residential net-metering facilities the customer is restricted to the greater of 25 kW or the highest monthly usage in the past twelve months.186 Scenic Hill Solar asserts that for commercial customers with a fairly steady load, EAL's redline would severely limit the customer's ability to offset consumption: As an example, a customer with a completely steady load of 1 MW would require 8,760 MWh per year, but could only build a 1 MW system that might produce 1,500 MWh per year. Id.at 17.

Cost-BenefitReports and Studies

Given EAL's repeated claims of cost shifting, Scenic Hill Solar puts into the record for the Commission's consideration the reports and many of the underlying studies referenced in its Initial Comments. Attached as Exhibit 2 is the ICF 2018 report commissioned by the Department of Energy that reviewed 15 state studies. According to Scenic Hill Solar, of these studies, six were cost-benefit analyses for net-metering, while others were looking at DER values, and appropriate rates for value-of-solar tariffs, using much of the same methodology used to assess net-metering programs. From Scenic Hill Solar's perspective a particularly notable feature of all of these studies is their focus on residential solar. In all of the states represented in these studies, demand-metered customers pay energy rates that are lower than bundled residential rates, so the comparison to benefits would show a net benefit across all studies (except possibly the SAIC study). Id.at 17-20.

Conclusion

For the reasons stated in its Reply Comments, Scenic Hill Solar asks the Commission to maintain 1:1 net metering for demand metered customers in its NMRs, as required by Act 464, and to establish clear provisions in the Rules for demand-metered customers, net-metering penetration, common ownership, grandfathering, REC ownership, and storage provisions. Further, Scenic Hill Solar asks that the Commission establish that utilities be directed to conduct preliminary review of interconnection requests purely on the basis of technical feasibility. And finally, Scenic Hill Solar asks that the Commission find that based on the cost-benefit studies conducted over the past six years across the country that generally show net benefits of net-metering in states with low net-metering penetration, the Commission establish a process for Arkansas utilities to assess their costs and benefits, and establish that given the low net-metering penetration in Arkansas, such studies are not necessary in Arkansas at this time. Id.at 20-21.

Quantifiable Benefits

Staff notes that the term "quantifiable benefits" would only need to be determined if the Commission decides to choose one of the new rate structure or grid charge options outlined in Act 464. Staff agrees with the AG, SWEPCO, OG&E and Carroll that quantifiable benefits must be (1) demonstrated by the Net-Metering Customer, (2) tied to an accounting or market mechanism, or to an amount included in a utility's COS. Staff Surreply at 6-7.

Gaming

Staff agrees with other Parties that the Commission should adopt rules to ensure that a large net-metering facility is not broken down into smaller projects to avoid gaming the 1,000 kW threshold and Commission review. Staff recommends utilizing a broad definition of the term "facility" for the purpose of determining generation capacity limits.

To incorporate this protection, Staff proposes the following addition to Net Metering Rule 2.06(A) :(2) For purposes of Rule 2.06(A)(1), "generation capacity" includes the aggregate ability to produce electricity from all Net-Metering Facilities under common ownership that are located within a single utility's service territory.

Staff also recommends adding "Section 5. Rules to Guard Against Gaming" to the NMRs. This would include defining gaming, prohibition of gaming, and penalties for gaming. Staff also proposes Aggregation Procedures to determine if a net-metering customer has exceeded the 1,000 kW threshold. Id.at 7-13.

Common Ownership for Meter Aggregation

Staff strongly supports a clear, streamlined, auditable, and readily enforceable approach for determining common ownership. Staff reiterates its position that common ownership does not need to be verified solely by tax ID numbers, as EAL argues. Staff continues to recommend adopting a standard ownership form and sworn affidavit from the customer. Staff states that the Commission-approved process should allow utilities to seek Commission review by filing a request for declaratory order or filing a formal complaint. Id.at 13-14.

Remote Facilities

Staff asserts that the plain text of Act 464 grants the Commission discretion to allow remote generators to qualify for net metering. Staff believes the relevant question regarding the definition of "Generation Meter" is whether the net-metering facility must also be physically attached to the facility using electricity. Staff states that Act 464 only requires this type of physical attachment between the net metering facility and the facility using electricity for governmental entities claiming safe harbor protections. Staff argues that the General Assembly's decision to expand AREDA and allow net-metering customers to lease a net-metering facility demonstrates the legislative intent to allow net-metering for remote facilities. Although Staff supports allowing remote facilities to net meter, Staff points out that net metering customers who have net-metering facilities physically connected to their load clearly avoid more costs to distribution and transmission, since they consume part if not all of their facility's generation. By contrast, a remote facility exports all of its generation to the grid, and therefore would need the grid to provide more transmission and distribution capacity. Staff believes there should be incentives for customers to invest in net metering facilities that are physically connected to their load. In addition, Staff believes utilities could recommend adding a grid charge to customers with remote net metering facilities to account for the use of the grid. Id. at 14-16.

Service Contracts and Safe Harbor Provision

Staff proposes that the Commission approve a standard form and affidavit for customers to certify that the service contract meets the specific requirements to qualify for safe harbor, similar in format to the Act 253 Notice and Affidavits used in Energy Efficiency dockets. The Notice and Affidavit should certify that the net metering customer meets the safe harbor requirements as provided by the Internal Revenue Service in Revenue Procedure 2017-1942 and the Office of Management and Budget Memorandum M-12-21. Staff agrees that the Commission should designate Staff to review the agreements and attempt to resolve disputes regarding eligibility, including by confirming whether the agreement meets the eligibility requirements of safe harbor. Id.at 17-18.

Consumer Protections

Staff continues to support the development of a Consumer Guide (including a Customer Bill of Rights) and a Code of Conduct. However, several parties have suggested the Commission should regulate non-utility renewable providers, including maintaining a registry of providers, and should review contracts and leases between these providers and customers. However, Staff shares the concerns of the AG that such oversight by the Commission would require legislation. Id.at 18.

Rate Structure

The AG strongly disagrees with Staff's recommendation to allow utilities to change rate structures for net-metering customers but only after a general rate case in which a full cost of service study is produced. The AG argues that such an approach would be inefficient and not in the public interest. Instead, the AG continues to support adoption of 2-Channel Billing. AG Surreply at 2-6.

Grandfathering

The AG continues to support her interpretation of three levels of grandfathering created by Act 464. Id.at 6-7.

Regulation of Non-Utility Providers

The AG continues to express concern that the Commission does not currently have statutory authority to regulate certain non-utility net-metering participants, specifically providers. The AG supports the idea of a working group that would examine what tools the AG and the Commission have under their existing authority to enforce the code of conduct or otherwise hold companies interacting with ratepayers accountable for any misleading statements. The AG states that those discussions could also inform recommendations that could be made to the General Assembly regarding new legislation for consumer protection in this area. Id.at 7-8.

Introduction

EAL states that it reached out to various parties informally in an effort to narrow the scope of contested issues that the Commission must resolve. EAL has identified the following areas of potential agreement among the parties:

* the immediate establishment of a 2-channel billing rate structure applied to customers on a rate schedule without a demand component ("non-demand-metered customers") consistent with the requests of several parties;

* the establishment of a grid charge for customers on rate schedules with a demand component ("demand-metered customers") to help mitigate the cost-shift that will result due to those customers avoiding fixed infrastructure costs included in the volumetric portion of certain rates;

* grandfathering provisions to be applied for qualifying net-metering customers;

* an approach to demonstrate common ownership for the purpose of meter aggregation;

* sizing restrictions for net-metering facilities;

* establishing a definition of a generation meter; and

* a process for developing transparent interconnection procedures and consumer protections through the Net-Metering Working Group.

Id. at 1-4.

Rate Structure for Non-Demand Component Rates

EAL recommends the Commission immediately implement 2-Channel Billing for new net-metering customers on rate schedules without a demand component. Upon implementation each utility would make a compliance filing and provide a calculation of the applicable 2-Channel Billing credit rates. Thereafter, each utility would make an annual filing updating the rate with the utility's current avoided capacity and energy costs. For those net-metering customers that are fully interconnected before the Commission issues this Phase 3 Order, EAL recommends grandfathering for no longer than 10 years under the 1:1 retail rate. As an alternative, EAL states that the Commission could incorporate a more gradual, step-down approach, by applying the 40 percent avoided cost adder, with periodic step downs in that adder. Id. at 8-10.

Rate Structure for Demand Component Rates

EAL urges the Commission to adopt a Grid Charge for net-metering customers of all sizes that receive service under a rate schedule that includes a demand component. The Grid Charge would be a fixed charge approved by the Commission and based on each utility's cost-of-service. Any net-metering customer that is fully interconnected before the issuance of the Commission's Phase 3 Order would be grandfathered for 10 years. Id. at 10-11.

Grandfathering

EAL notes that it previously recommended in Phase 1 of this docket that it could support a reasonable grandfathering period and at that time did not oppose 20 years. EAL explains that the concept of grandfathering is not some automatic right but rather is intended to help ensure that a customer installing a solar facility has a reasonable opportunity to recover a portion of its investment. With that in mind, the grandfathering provision must consider the declining cost of solar facilities that has occurred since Phase 1 of this proceeding. Id.at 12-14.

Common Ownership for Aggregation

For any customer under a non-demand component rate schedule, EAL urges the Commission to continue the current practice of requiring a customer to demonstrate that the same tax ID remains in place for any aggregated account(s). With respect to demand-metered customers, EAL urges the Commission to adopt Staff's recommendation requiring an affidavit, supported by appropriate documentation, to demonstrate common ownership, and that is subject to reasonable and justifiable challenges. To avoid gaming, EAL states that any net-metering facilities under common-ownership must be considered a single project for purposes of Commission review and approval. Id. at 14-16.

Sizing of Net Metering Facilities

EAL argues that it is not reasonable to allow a net-metering facility to offset 100 percent of a customer's requirements in all hours of the year. The Commission should clarify now that such sizing practices cannot continue. For example, depending upon the specific characteristics of a customer's load profile, a net-metering facility sized to produce 100 percent of the customer's annual energy consumption could result in net exports in excess of 60 - 70 percent of total solar production. To prevent oversizing facilities under a demand component rate schedule, EAL urges the Commission to adopt a maximum size a customer is authorized to construct to remain eligible for net-metering. EAL recommends that the maximum size be set equal to the capacity needed to generate no more than 25% net exports based on the customer's annual solar production compared to annual usage. For customers on a non-demand component rate schedule, EAL continues to support the current rule of using a customer's prior 12 months energy usage as the maximum size for a net-metering facility. Id.at 16-19.

Defining Generation Meter

EAL continues to argue that "generation meter" as used in the currently-effective Net-Metering Rules, means the generation meter must be connected to the customer's load. EAL argues that there is no basis for revising the currently effective rule, because Act 464 made no provision authorizing remotely-located generation for purposes of net-metering. EAL states that maintaining the current rule avoids potential claims that the net-metering customer is participating in retail wheeling of energy. Id.at 19-20.

Matters to be Addressed by the Net-Metering Working Group

EAL agrees with Staff's recommendation that the Commission direct the NMWG to develop interconnection rules using the IREC uniform interconnection rules as a template. EAL agrees that the NMWG could also be directed to develop a Consumer Guide, mandatory standards for developers, as well as standard templates for Leases and Power Purchase Agreements/Service Agreements. EAL cautions that the IREC uniform rules create a number of requirements for the utilities to implement for purposes of interconnecting customers, the costs of which may be substantial as well as requiring significant time to develop and implement. Prior to implementation of such model interconnection rules, the costs and benefits of those interconnection policies should be evaluated by the Commission in a more thorough review of the implications of such a decision, including allocation of the costs to comply with those interconnection provisions. Id.at 20-22.

Cost-Shifting

OG&E provides excerpts of articles from several trade publications that support the existence of cost-shifting under the full retail net-metering rate. OG&E Surreply at 1-3.

Solar Penetration Policy

OG&E is supportive of the development of solar in Arkansas but encourages the Commission to use a reasoned approach that takes into account (1) customer impacts for both non- and net-metering participants, (2) an economical and market-based support for solar in Arkansas, and (3) sustainable long-term solar investment policies. OG&E argues that the current 1:1 rate should not be tied to a certain level of solar penetration. Id.at 3-5.

Rate Structure

OG&E disagrees with Staff's proposal that utilities only be allowed to change their net-metering rate structure through a general rate case. OG&E argues that Staff's proposal goes against the intent of Act 464 and is biased against those utilities that have chosen FRPs. Id. at 5-7.

Meter Aggregation

OG&E supports Staff's recommendation to require a standard form and signed affidavit to confirm common ownership of meters that are aggregated. However, OG&E does not agree that utilities should be prohibited from requesting a tax ID number as part of a request for service. Common tax ID numbers support an assertion that points of service are under common ownership. If points of service do not have common tax ID numbers, then additional documentation would be required to establish that said points of service are under common ownership and therefore qualify for net metering aggregation. Id.at 7-8.

Grandfathering

OG&E continues to argue that Act 464 gives the Commission authority to approve grandfathering on a case-by-case basis. Id. at 8-9.

Consumer Protections

OG&E supports the AG's recommendation that net-metering providers be required to register with the Commission prior to installing net-metering facilities in the State and be subject to program suspension or expulsion due to non-compliance with a Commission-approved Code of Conduct. However, OG&E does not agree that utilities should be solely responsible for policing third-party providers. Utilities are not in a position to be the monitors and enforcers of any Code of Conduct that may be adopted. Enforcement of any such Code is more appropriately placed with the Commission or the AG. OG&E also argues that the IREC Model needs to be more thoroughly vetted prior to any potential adoption as a consumer protection guide. OG&E recommends that this issue be taken up in Docket No. 16-028-U where the issue is already being addressed. Id.at 9-10.

Rate Structure

SWEPCO continues to argue that the existing 1:1 retail rate structure is not in the public interest. SWEPCO believes the Commission should address the rate structure in this proceeding and not wait until the utility files its next general rate case to alter the rate structure. SWEPCO states that it must serve all its customers at just and reasonable rates. SWEPCO believes that purchasing power from net-metering facilities at retail rates without billing for fixed costs that are recovered through volumetric rates, creates a subsidy from non-participating customers to net-metered customers - not just and reasonable rates. Id.at 1-3.

Grid Charge

SWEPCO believes that all net-metering customers that have a demand on the distribution system, whether during the system peak or not, should pay for distribution system costs. SWEPCO argues that some parties have a misunderstanding of how distribution plant costs are allocated. SWEPCO explains that distribution system is not sized to handle the system peak but instead is sized to handle the diversified peak loads of customers in each class for localized areas of the distribution system. Distribution systems must be capable of meeting the sum of each class' maximum demand, irrespective of system peak. This means that net-metering customers that use the system at any time also contribute to the class' maximum diversified demand, no matter when each customer's peak demand occurs, and therefore, contribute to the class' allocation of distribution system costs. Id.at 5-7.

Non-Demand-Component Net-Metering Customers

SWEPCO continues to support the 2-Channel approach and requests that the Commission enact changes to create a reasonable and sustainable net-metering rate structure as soon as possible. SWEPCO also supports the recommendation from other parties that the Commission consider rules that would allow for utility-specific rate structures. SWEPCO argues that Staff is incorrect in stating that changing to 2-Channel Billing would require updating COS information and other utility-specific information. Id.at 8-10.

Demand-Component Net-Metering Customers

SWEPCO again explains how its General Service tariff is inadequately structured to recover its fixed costs through the demand charge. Therefore, SWEPCO continues to support the 2-Channel Billing approach to net-metering customers on the General Service tariff as well as any current demand tariff under which SWEPCO is not fully recovering its cost to serve. Alternatively, SWEPCO supports a fee or charge be applied to those net-metering customers. SWEPCO states that the additional fee can be charged pursuant to the net-metering tariff and would not require additional tariff or rate changes. In other words, SWEPCO would not need to file a general rate case to effectuate the change. Id.at 11-13.

Quantifiable Benefits

SWEPCO states that parties are not in agreement as to whether Act 464 requires a net-metering customer to actually provide evidence of quantifiable benefits. Therefore, SWEPCO requests that the Commission clarify this provision. SWEPCO also supports the AG's recommendation that the Commission consider establishing a standard formula to calculate quantifiable benefits to eliminate ambiguity on what can and cannot be included in net-metering rates. Id.at 13-14.

Reporting Requirements

Staff recommends the adoption of additional annual requirements for net-metering facilities in Docket No. 06-105-U for the purpose of assessing renewable energy penetration on a utility-by-utility basis. SWEPCO explains that this could prove problematic for utilities to provide some of the information requested, such as the total production of a net-metering facility in kWh. Total production would have to be estimated as SWEPCO currently does not have an accurate measurement of the production the customer uses behind the meter. Additionally, providing the peak demand by customer on a monthly basis could also be difficult. Staff further requests solar PV installation information by rate class, but does not specify what type of information. Id.at 14-15.

Rate Structure

AECC argues that a net-metering customer's generation is worth what every other increment of generation is worth in the wholesale energy markets, i.e., the avoided cost. Absent proof that it is more valuable than other generation available to the utility, the price paid for a net-metering customer's generation should not exceed the wholesale avoided cost. For this reason, AECC argues that it is unnecessary to require a general rate case or new cost of service study before approving a new rate structure for individual utilities. AECC believes the Commission has the authority to set new rates and rate structures for each class of net-metering customers no matter whether the customer is a demand component rate or non-demand component rate. AECC Surreply at 1-5.

Solar Penetration

AECC argues that AREDA does not contemplate a minimum solar penetration level. AECC argues that by leaving the current net-metering rate structure in place until a certain penetration level is met is equivalent to imposing a renewable portfolio standard. AECC points out that even with the existence of federal tax credits that subsidize solar, added to an overly-compensatory retail rate in Arkansas for nearly two decades, Arkansas net metering penetration levels remain low because the cost of electricity in Arkansas is also low. AECC argues that perpetuating incentives to increase penetration at some unstated level or time in the future, without regard to the current economic consequences of that price shift, is against the public interest. Id.At 5-6.

Defining Terms in the NMRs

Carroll urges the Commission to define precisely the terms "net energy facility" and "net energy customer" from the language of the Act in the NMRs, with the inclusion by the Commission of specific examples that indicate what does and does not match the definition in the Act. Doing so will resolve much of the confusion and concern regarding both aggregation and gaming. As an example, Carroll points to the language in Ark. Code Ann. § 23-18-604 ©(2)(A)(ii), which if taken literally, this means "more than two" qualifying government/tax exempt entities do not have the discretion to apply net-metering credits to a bill for another meter. Carroll Surreply at 1-3.

Rate Structure and Solar Penetration

Carroll continues to support a Floor (avoided cost) and Ceiling (1:1 retail rate) rate structure. The Commission should consider each utility's cost/benefit analysis of implementing 2-channel billing, utility-specific avoided cost as well as retail cost, and special rate considerations. Carroll urges the Commission not to delay policy action until solar capacity becomes a problem, as has already happened in California, Nevada, Arizona, and Hawaii. Id.At 3-10.

Cost Shifting

AEEC continues to believe that the current 1:1 net-metering rate structure shifts costs to non-participating customers. AEEC argues that the cost shifting or subsidies will begin to emerge each time a utility files a new formula rate plan demonstrating a revenue shortfall that then has to be redistributed across all rate classes. AEEC warns that additional cost shifting could likely occur if certain customers in the large industrial rate classes begin to migrate to smaller commercial rate classes where they can obtain service using a favorable net metering rate. AEEC Surreply at 1-3.

Rate Structure

AEEC urges the Commission to adopt new rate structures immediately to address the subsidy before it expands. For non-demand component rate classes, AEEC does not recommend a specific new rate structure, but states that the new rate structure should address the subsidy by reducing the amount of the credit for net excess generation to a more reasonable level. For rate classes with a demand component, AEEC agrees with OG&E that the rate tariffs for those rate classes should be redesigned to recover more of the fixed costs through the demand component. AEEC worries though that adopting this policy would require waiting until a utility files a general rate case which may not happen for several years. Id.at 4-6.

Grandfathering

AEEC urges the Commission to choose not to grandfather additional net-metering customers, or at least set the duration for grandfathering at a short period of time. This policy choice will prevent the continuation of subsidies and serves the public interest. Id. at 6-7.

RECs and Customer Protections

AEEC agrees that customers should have the freedom to transfer renewable energy credits to another party in exchange for compensation or other things of value. AEEC also supports the recommendations made by the Staff and the AG that customer education measures and other customer protections should be developed. Id.at 8.

Reporting Requirements

AEEC agrees with Staff's recommendation to establish certain reporting requirements regarding net metering penetration levels no matter which rate structure the Commission adopts. Id.at 8.

Introduction

AAEA believes that the following contested issues need not be resolved in this proceeding in order to implement Act 464:

* Consumer protection

* Fees for interconnection or preliminary site review

* Rules regarding retention of renewable energy credits

* Rules regarding "oversized" net-metering facilities

* Changes to net-metering for demand-billed customers other than updating the rules to reflect revised statutory language.

AAEA Surreply at 1-2.

Demand Billed Customers

AAEA believes Act 464 requires the Commission to retain the 1:1 retail net-metering rate for demand-billed customers. AAEA acknowledges that some utilities have provided evidence showing the amount of "fixed costs" that are embedded in volumetric rates even under demand-billed tariffs. AAEA argues such evidence is simply not relevant to the decisions the Commission must make in this case, given the clear statutory mandate regarding demand-billed net metering customers. AAEA also responds to EAL's recommendation to continue the 1:1 full retail credit for demand-billed customers but also adopt a grid charge to recover the fixed costs. AAEA argues that it is also inconsistent with AREDA to impose a grid charge to recover fixed costs. AAEA points out that Ark. Code Ann. § 23-18-604(b)(4) states that the Commission may authorize an electric utility to assess a net-metering customer a greater fee or charge of any type, if the electric utility's direct costs of interconnection and administrationof net metering outweigh the distribution system, environmental, and public policy benefits of allocating the costs among the electric utility's entire customer base. AAEA argues that EAL has not provided evidence to establish that a grid charge is justified. Id.at 4-6.

Net Metering for Residential Customers

AAEA responds to EAL's belief that the benefits calculated by Crossborder Energy are unreasonable because they exceed the cost of utility-scale solar generation. In other words, EAL asks why it should be forced to pay the higher benefit cost for net-metered energy when it can buy utility-scale solar at a lower cost. AAEA argues that EAL's comparison is not apt, because utility-scale solar does not avoid line losses or transmission and distribution investments, nor does it support resilience or consumer choice or economic development to the same degree as distributed generation. Id. at 7.

AAEA urges the Commission to consider a long-term view of avoided costs, rather than a static, embedded view of those costs. Adopting such an approach will reduce costs over the long run for all customers, and best promote the purposes of AREDA. AAEA argues that even if the Commission rejects the relevance of long-term costs and benefits, Act 464 allowance for reasonable allocations of and increases in costs clearly permits de minimiscost shifting. Id.at 8-10.

Grandfathering

AAEA notes that the Commission has not required case-by-case adjudications of grandfathering previously, and should not interpret Act 464 to require such an approach going forward. Id.at 14-16.

Consumer Protection

AAEA states that consumer protection measures are not among the issues that the Commission needs to resolve in adopting the next round of Net-Metering Rules. AAEA continues to support the AG's recommendation to form a working group to develop any needed consumer protection measures and determine the appropriate means of implementing and enforcing those standards. AAEA agrees that legislative action will likely be needed for a robust consumer protection framework, but a Commission-initiated working group would be valuable in identifying and characterizing consumer protection issues. Id.at 16-17.

Gaming

AAEA agrees with Staff's recommendation to require the net-metering customer to use a standard form and sign an affidavit confirming common ownership of aggregated meters. Id.at 18.

Defining Net Metering Facilities and Customers

AAEA disagrees with some parties that argue that remotely located net-metering facilities should not be eligible for net-metering because the facilities are not behind a meter that is attached to the load. AAEA also disagrees with EAL's recommendation to limit the size of a facility to prevent what EAL calls "oversizing." Id.at 18-20.

Leasing Facilities and Service Contracts

AAEA recommends the Commission develop a standard form and designate a staff member to review such agreements and attempt to resolve any disputes with the utility regarding eligibility. The process should have the objectives of allowing consumers seeking to utilize lease or service contract arrangements to confirm early in the process that their system will be eligible for net metering, while not requiring those customers to jump through countless hoops or initiate a Commission proceeding in order to get approval for net metering. Id.at 22.

Cost Shifting

Scenic Hill Solar disagrees with EAL's claims that demand-metered net-metering customers are shifting costs to other customers. Scenic Hill Solar agrees with AAEA that the value of distributed solar appears to be above residential rates. Scenic Hill Solar Surreply at 1-3.

Solar Penetration

Scenic Hill Solar disagrees with EAL's assertion that Arkansas is not a low solar penetration state. Scenic Hill Solar states that utilities will likely continue to cite triple digit growth rates in net metered generation. Scenic Hill Solar argues that the utilities should also show analysis of when net metering might provide more than one percent of utility retail sales. Id.at 3-4.

1:1 Rate for Demand Metered Customers

Scenic Hill Solar argues that the Legislature, through Act 464, has directed the Commission to establish just and reasonable rates, and that it must have 1:1 Net-Metering for demand-metered customers. Scenic Hill Solar takes that to be a legislative presumption that 1:1 net-metering does not entail a cost shift, and is fully compatible with just and reasonable rates and appropriate net metering. Id.at 4-5.

Demand Metered Customer Rate Structures

Scenic Hill Solar explains that the rate tariff design is done in a heavily contested general rate case, therefore, the amount collected in the demand component may not recover all the fixed costs because there were opposing positions in the rate case. Scenic Hill Solar suggest that because this allocation of costs is exhaustively decided in rate cases, the Commission should accept that allocation as settled. The Commission should assume that energy ratesfor demand-metered customers, for the purpose of net metering, reasonably recover the energy and related production costs to serve those customers, and do not recover fixed costs to serve those customers. Id.at 5-6.

Mr. Ball made a filing stating that he did not wish to provide Surreply Comments.

Mr. Cotten testifies that in the past, the Commission has ruled on a case-by-case basis to decide the grandfathering of facilities that were larger than 300 kW. T. 540.

Staff recommends implementing net metering rates on a utility-specific basis. Ms. Hoss clarifies that per AREDA, a net metering facility cannot be located in multiple utility jurisdictions and therefore there would not be a problem of aggregated net metering facilities which cross jurisdictional boundaries. T. 542-544. Staff witness Kelly states that Staff recommended implementing net metering rates on a utility specific basis because the underlying cost and benefits may differ by utility. T. 542. Ms. Hoss and Ms. Kelly testify that the rules for all utilities would be set in this proceeding. Ms. Hoss goes on to state that Staff is asking the utilities to present rate design changes in a separate proceeding that would alleviate the cost shifting. T. 544-546.

Ms. Hoss testifies that neither 2-Channel Billing nor grid charges are perfect matches of costs to net-metering and non-net metering customers. Ms. Hoss states that the cost shift will vary by a utility's underlying cost and rate design that the utility has chosen and that the Commission has approved. She states that when and if there is some unreasonable cost shift, it is incumbent on the utility to propose the timing and content of their changes, and typically that has been done in a rate case. Ms. Hoss further testifies that Act 464 does not allow the Commission to modify the demand charge variable for grid charges for a customer on a demand component rate. However, she states that the Commission's authority to change that component is not altered in a general rate case context. Ms. Hoss states that she believes the Commission can consider TOU rates, although some utilities don't have the technological ability to do that to date. Ms. Hoss testifies that utilities can propose specific changes where there are multiple meters being aggregated, so a grid charge is something the Commission can consider for customers who do not have the demand component. She states that Section 604(b)(4) of the Act allows a grid charge or a fee for interconnection and administrative costs. Mr. Cotten adds that utilities already have the ability to recover any costs that are required to accept net metering facilities and they are already doing that. But, he adds, if there are additional administrative costs and billing costs, those aren't being collected from net metering customers today and might be a component of some additional charge. T. 547-550. Ms. Hoss testifies that with regard to Act 464 prohibiting demand customers to be assessed a grid charge outside of a rate case, Staff's position is that it depends on the type of cost inside that grid fee. For example, she states, Section 604(b)(4), which would apply to customers with a demand component, is limited to interconnection and administrative costs. So a customer with a demand component could be charged that fee, but a grid charge that included, for example, lost contribution to fixed costs may not be permissible under Section 604 (b)(4). T. 554.

Ms. Hoss states that it should be each utility's option to propose having a separate rate class. The economics of whether a separate rate class makes sense should be determined in a rate case. Ms. Kelly adds that other jurisdictions have required utilities to bring in cost-of-service based support and any other support to justify a separate rate class. Mr. Cotten states that Arkansas at this time does not have enough net metering penetration to get a statistically important enough signal to be able to establish a separate rate class, and what that cost is for that class. T. 550-551.

Mr. Cotten responds that a working group, not necessarily the NMWG, should be established to address issues such as the code of ethics, consumer protection guide and consumer bill of rights in another phase of this docket. T. 553.

Staff acknowledges that it is possible to use a utility's existing cost of service study with the existing class allocations and portion out the distribution only costs as a grid charge for those net-metering customers that are entirely in front of the meter. T. 557. Mr. Cotten states that a facility installed behind the customer's meter and which provides no excess energy back to the grid at all, probably provides distribution benefits because it reduces the amount of energy the utility had to supply over that distribution system. However, he states, if that same customer provides excess energy back onto the grid from a behind-the-meter, then the customer is relying on that distribution system to have someplace for that excess energy to go. And, he adds, if that customer expects credit back in future months, then the customer is basically using the utility system as a bank. Mr. Cotten states that if, on the other hand, the net-metering facility is remote (in front of the meter) and the customer is not offsetting their own load, then obviously the distribution system is still required to be there and is probably providing energy transport at a location that may be different from what the utility would have normally provided. T. 557-558.

Staff states that a remote facility could provide locational benefits, but it depends on a number of factors such as the specific circuit, location, need, and the utility's planning. For example, according to Mr. Cotten, if the circuit is loaded at a certain level, the utility might get benefits, but if the circuit is lightly loaded, then there may be no benefits. T. 559. Mr. Cotten states that net metering is an energy-only product, and any demand reductions that occur because of a net-metering facility's energy would only accrue to the customer if that facility was installed behind the meter and actually reduces the load on the utility system by the energy that the customer provides. Mr. Cotten states that a customer with a remote facility that aggregates multiple meters is only reducing its energy charge and not reducing its demand. Ms. Hoss states that to the extent the net-metering facility provides capacity that is coincident to utility's peak, the net metering system would be reducing the overall system peak or making some contribution to that. T. 561-562.

Ms. Hoss responds that in general the four California Standard Practice Manual tests used to evaluate energy efficiency programs could be applied to net metering but with some limitations. T. 562-563.

Mr. Owens states that EAL's methodology for calculating its proposed grid charge is consistent with Commission practice for normal ratemaking, and that no distribution costs are avoided. Mr. Owens further testifies that states that EAL's methodology does not assess whether any of those distribution costs are offset by quantifiable benefits from the net-metering facility with respect to the grid charge. T. 1273-1275.

EAL witness Schnitzer testifies that EAL has not calculated the cost shift associated with residential net-metering systems that have been proposed since the passage of Act 464 and that the closest calculation he has done was to compare EAL residential volumetric rate of 10.1 cents versus 3.5 cents, which is the cost for grid-scale solar, resulting in a cost shift of 6.6 cents. T. 1276.

Mr. Owens testifies that 2-Channel Billing or a grid charge do not ensure a perfect match of costs to net-metering and non-net-metering customers and that EAL continues to have a portion of fixed costs that would not be recovered under either of those solutions.

Mr. Schnitzer also states that 2-Channel Billing would mitigate the cost shift but would not eliminate it. T. 1277-1278. Mr. Schnitzer states that paying the 1:1 net-metering credit is effectively asking nonparticipating customers to pay the retail rate for solar kilowatt hours, when as an alternative EAL could be buying grid-scale solar directly at 3.5 cents or less. EAL witness Palmer states that using the cost shift estimates made in EAL witness Myra Talkington's testimony in Docket No. 19-042-TF, the impact may be close to $4 to $5 a month on a residential customer based on 1,000 kWh usage. T. 1278-1280.

Mr. Owens clarifies that the grid charge doesn't modify the customer's existing rate structure, noting that EAL's proposal would also preserve the 1:1 netting that occurs. What EAL proposes, he states, is to take its cost-of-service study and identify the distribution-related costs that are recovered in the volumetric rate that are not recovered in the demand charge and then convert that to a charge that EAL thinks would be very straightforward and simple to implement from a billing perspective. The grid charge would be the same number every month for a customer based on their system size. Mr. Owens states that EAL has other fixed infrastructure costs for generation and transmission that are recovered volumetrically that a customer would still be able to avoid. T. 1280-1281.

Mr. Palmer states that TOU would just be another rate design and asks what value that has to the customer. (Palmer gave a very long explanation and I couldn't decipher what his point was.) T. 1284-1286.

Mr. Palmer states that it is EAL's position that Act 464 either prohibits or otherwise doesn't allow for demand component customers to be assessed a grid charge outside of a rate case. T. 1287.

For 2-Channel Billing, Mr. Owens states that EAL's methodology could be universally applied because all of the Arkansas utilities operate in either MISO or SPP. He explains that EAL's methodology relies on the wholesale energy cost in the RTO. Mr. Owens believes it is the Commission's discretion to apply either a utility- specific or fixed additional sum as consideration for quantifiable benefits. T. 1288-1289. Mr. Owens states that if the rates today that are charged to customers today are assumed to be just and reasonable, then whether the cost of service was done four years, or seven years ago or even longer ago, then those are the rates that could be used to establish a grid charge. T. 1289-1290.

Mr. Palmer states that if a customer sizes his net-metering facility at 100 percent of annual consumption, then that customer is likely going to be exporting 50, 60, or 70 percent of the energy the net-metering facility produces. Mr. Palmer testifies that EAL's proposal to cap the net export based on customer's annual solar production and the annual use at 25 percent just felt like a more reasonable amount for a net-metering customer to be allowed to export. T. 1290-1294.

Mr. Palmer responds that he believes the community solar model used by Mr. Ball and Mr. Kelly is consistent with existing models with respect to the ability to aggregate. He adds that EAL is concerned with issues such as how to establish co-ownership, whether there should be a size limit and meter limitation on community solar projects, and who pays for the incremental upgrades to a circuit as new net-metering facilities are added. T. 1294-1296.

Mr. Owens states that the allocation method that EAL and other utilities use today, in a general rate case, is a methodology under which, generalizing, the closer you get to a customer, (i.e. going from generation to distribution) the less what's occurring (i.e. allocation of costs) has to do with coincident peak. T. 1296-1297. Mr. Owens states that, for example, a nightclub has a peak at 10:00 or 11:00 at night and that has nothing to do with EAL's coincident peak. He states that EAL is sizing its facilities, the transformer, the equipment, the distribution part of serving that customer's needs, based on their non-coincident peak, not EAL's coincident peak. Mr. Owens adds that when EAL allocates distribution costs, demand-related distribution costs, the methodology EAL uses doesn't address and doesn't reflect contribution during that peak hour, whether that's coincidental peak the one time a year or 12 CP over the 12 months. He states that this is the logic that EAL used for its recommendation on the grid charge. T. 1298-1299. Mr. Schnitzer also explains why EAL believes distribution costs are not avoided by net metering customers by stating that there are some empirical studies done by the MIT Energy Institute and others looking at distribution systems and asking the circuit-specific question: Would there be an avoided capital investment, associated with something going in on this circuit that would modify the peak load. Mr. Schnitzer states that if you look at most distribution budgets, they are split between investment required to connect new customers, new service types of things, and rebuilds of old equipment that has to be replaced, neither of which can be influenced by a new solar facility. T. 1300-1301.

Mr. Schnitzer states that because of economies of scale grid-scale solar is cheaper, in the range of $0.03 to $0.036 per kW/h compared to residential or medium-sized commercial systems that are at least twice that price. T. 1303-1304.

Mr. Owens responds that EAL is open to making changes to its SEPO Option B to put everyone on a level playing field but recommends that the question of how a one-year solar contract and a 20-year solar contract should be priced so that the two contracts are equivalent when considering disruption or price change risk should be discussed and addressed in EAL's SEPO Option B docket instead of this docket. Mr. Owens also points out that even under 2-Channel Billing or a grid charge net-metering customers will see significant bill savings. T. 1310-1312.

Mr. Owens states that the question of whether it is reasonable to measure cost shift as a cumulative total or as a percentage of any one transaction really reverts back to what happens with grandfathering. T. 1313.

Mr. Schnitzer states that it is difficult to answer how to design a rate that would incentivize net-metering facilities to correlate their generation more closely to the peak. He explains that experience in other states shows that as solar penetration increases, the peak moves from early evening to later in the evening when the sun has set, so solar cannot solve the problem. In other words, he states, increased solar penetration means solar will have increasingly marginal contributions to capacity over time. Mr. Schnitzer also states that volumetric energy credits of $0.10 kw/h or $0.08 kw/h under net metering do nothing to provide any incentive. T. 1314-1316.

Mr. Owens states that he is uncertain whether customers are aware that it is probably uneconomic to aggregate a large general service meter with other small general service meters. Mr. Schnitzer adds that customers may be able to cover the fixed costs of their net-metering facility and by adding a large general service meter they can make the net-metering facility a little bigger. Mr. Schnitzer also states that adopting 2-Channel Billing would eliminate any incentive to aggregate meters from two rate classes. T. 1318-1321.

Mr. Brice states that 2-Channel Billing does not address the cost shift for the portion of energy that is produced by the net-metering facility and used by the net-metering customer. T. 1374-1375.

Mr. Brice believes that the statute is not clear if Act 464 allows the Commission to modify the demand charge variable. For demand-metered accounts he believes Act 464 describes two different approaches to do (1) billing and (2) calculating the net excess generation. He believes the overall context of Act 464 gives the Commission the flexibility to apply the rate structure it deems best. Mr. Brice recommends the Commission adopt 2-Channel Billing for customers on SWEPCO's General Service tariff. T. 1375-1377.

Mr. Brice states that the Commission has the right to explore TOU rates, but SWEPCO does not have the necessary technology, such as AMI metering at this time. Mr. Brice admits that SWEPCO has AMR technology but adds that it would not be efficient or effective for administering a TOU rate. T. 1378.

Mr. Brice states that SWEPCO is open to a separate rate class for net metering customers, but at this point in time SWEPCO does not have the load data that would be needed to develop that class. T. 1378-1379.

Mr. Brice states that SWEPCO supports an adder if it is specific to the customer and not standard among all customers, and that he believes Act 464 allows customers under the 2-Channel approach to be paid avoided cost plus up to 40 percent of an additional sum if they could show quantifiable benefits associated with the net metering. He states that this additional sum should be considered on a case-by-case basis. T. 1379-1380.

Mr. Brice states his belief that the longer the period of time to measure unreasonable cost shifts, the harder it will be for SWEPCO to deal with the end effects. T. 1380-1381.

Mr. Brice states that SWEPCO could design a grid charge that both recovered that amount when they were under the limit and gave them a credit for what they were paying once they hit the demand charge against the grid charge and it would look similar to a minimum bill. T. 1381-1382.

Mr. Brice states that SWEPCO has explored building a grid-scale facility and seeing if it can sell solar to individual customers to participate in the market in a way that's similar to what EAL is proposing with SEPO B, but based on the Company's circumstances and the RTO they are in, SWEPCO believes there are more viable options. T. 1381-1382.

OG&E witness Schwartz states there are no perfect rates, but 2-Channel Billing or a grid access charge would be an improvement on the current rate structure. He adds that 2-Channel Billing is something that OG&E would consider moving forward with as it is a market-based solution that would be implemented outside of rate cases. T. 1457-1458.

Regarding the grid charge for a customer on a demand component rate, the Commission asks whether Act 464 allows the Commission to Mr. Schwartz states his belief Act 464 gives the Commission discretion to modify the demand charge variable. T. 1458. Mr. Schwartz states that TOU rates are effective in allowing solar customers to realize the time value of the energy they are producing, but OG&E does not believe that TOU rates alone would solve what the Company sees as the current subsidy issue. T. 1458-1459. On the subject of a separate rate class for net metering customers, Mr. Schwartz responds that TOU rates are something that should happen in the future. He adds that the Company stated in its testimony that putting customers in a separate class in the cost of service enables a more in-depth look at the cost and the load shapes of those customers. T. 1459.

Mr. Schwartz states that based on his non-legal opinion, he believes the statute gives the Commission latitude modify the demand charge variable or assess the grid charge without a rate case, or just assess a grid charge without a rate case. T. 1460.

Mr. Schwartz states that it comes down to size with regards to grandfathering. For example, he states, if you have a residential 10 kW project or a 5 MW project, the impacts of enabling a rate for a ceiling of 20 years, as the statute discusses, could have differing impacts. He adds that if an installation can quantify that they will provide benefits to the system, to the customers, to the public good, then OG&E thinks they have a viable case for proving their grandfathering need. T. 1461-1462.

Asked if OG&E has given thought to offering a grid-scaled solar project as competition with third parties, Mr. Schwartz states that OG&E has been actively investigating this and hopes to be able to share something with the Commission in the next few months. T. 1462.

Mr. Gillam testifies that Empire does not believe that 2-Channel Billing or a grid charge ensures a perfect match of costs Mr. Gillam believes that the Commission has the discretion to modify the demand charge variable regarding the grid charge for a customer on a demand component rate under Act 464 if warranted and Liberty-Empire would support that change. T. 1473. Mr. Gillam testifies that Liberty Empire currently, at least for the Arkansas jurisdiction, does not have the capability to employ a TOU rate structure.

He adds that TOU rates could get you a more definitive answer with regards to how costs should be allocated. T. 1473.

Mr. Gillam states that Liberty Empire is a small company, so it would take a significant number of customers switching over to net metering to warrant going to a separate rate class for net metering customers. T. 1474.

Mr. Gillam states that Empire would benefit from the Commission not imposing a one-size-fits-all solution to net metering given its low number of customers in Arkansas. T. 1474-1475.

Mr. Shields testifies that AECC's 17 distribution cooperatives could possibly file their own net metering proposal using Act 821 nder a utility-specific approach instead of filing a full-blown Section 8 rate case. T. 1537-1538.

Mr. Shields testifies that neither a grid charge or 2 channel billing rate is a perfect match of costs to net-metering and non-net-metering customers, but 2-Channel Billing provides the opportunity to fix the overpayment for generation and is a very close match. T. 1539-1540. He believes that Act 464 allows the Commission to modify the demand charge variable regarding the grid charge for a customer on a demand component rate." T. 1540. Mr. Shields testifies that TOU would be co-op specific and that he did not know who might like to pursue it and who might not. T. 1540.

Mr. Shields states that a co-op could propose a tariff filing that distinguished between a net-metering customer and a non-net metering customer within the same rate class and without establishing a separate rate class for net metering customers. T. 1541-1542.

Mr. Shields believes Act 464 gives the Commission options to decide what the appropriate rate mechanism is. T. 1542.

Mr. Shields states that the age of the cost-of-service study for some of the distribution co-ops, and that those distribution co-ops have sufficient data on distribution costs to reach the right conclusion if the Commission approved distribution-based grid fees. He adds that if rates are considered just and reasonable today, the existing cost of service could be used to determine a grid fee. T. 1543.

Mr. Magnini with Carroll states that from a high level, he believes you get a lot closer to a perfect match of costs to net-metering and non-net metering customer with 2-Channel than our current structure. T. 1605. Mr. Magnini opines that Act 464 allows the Commission to modify the demand charge variable regarding the grid charge for a customer on a demand component rate. T. 1606-1607. Mr. Magnini states that Carroll has not considered TOU rates internally. Mr. Magnini also states that the Company has AMI metering, but would need other programming mechanisms and processes to be fully equipped for TOU rates. T. 1606. He states that he should not answer whether the Commission should establish a separate rate class for net metering customers. T. 1607.

Mr. Magnini states that almost all of the net metering in Carroll is residential so the Company has not seen penetration that has caused engineering concerns yet. Mr. Magnini states that he does not know that non-participating customers would notice a cost shift because it is not a line item on their bill, and no one has brought it to the Company's attention. T. 1608.

Mr. Kronauer with Walmart states that he agrees with previous testimonies -- there is no such thing as a perfect rate structure. He adds that Walmart would prefer single-channel billing (i.e. 1:1 retail). T. 1615. Mr. Kronauer testifies that he believes that TOU rates can result in cost-based rates that reflect the cost of service. Mr. Kronauer testifies that Walmart recommended in testimony that a net metering customer's demand charge should be reduced by whatever the net metering facility's contribution to demand is, which would be measured at peak Mr. Kronauer states that he is not an attorney but he believes Act allows it. T. 1617-1618.

In clarifying the relevance of additional cost-benefit studies that were submitted by Scenic Hill Solar, given that there is already one in the record that is specific to an Arkansas utility, Mr. Halter states that most of these studies were with respect to residential solar, which is to say non-demand charge customers. He explains that it is a mathematical proposition that the net benefits of solar for demand charge customers are materially greater than they are for residential customers. He assumes that if these residential studies show that there is a net benefit to distributing solar deployment, then the net benefit of distributed solar generation for demand metered customers has to be that much larger. T. 2635-2637.

Mr. Halter testifies that neither 2-Channel Billing or a grid charge ensures is a perfect match of costs to net metering and non-net metering customers. He believes the Commission should be looking at the other benefits that are being provided by net metering systems. T. 2645-2646. Mr. Halter states that it is very clear that Act 464 states that the rate for demand metered customers is 1:1. T. 2650-2651. Mr. Halter states that he does not believe customers or various utilities are in a position to implement TOU rates. T. 2648.

The Commission asks Mr. Halter if he thinks. Mr. Halter does not believe the Commission has enough data to assess whether there is currently a cost shift occurring between participants and nonparticipants. T. 2651-2652. Mr. Halter testifies that the Commission should not worry about this as a mathematical proposition until three percent of the number of kilowatt hours in a utility's service territory (i.e. utility-specific, not statewide) are provided by third-party distributed generation. T. 2655. Asked if he can point to anything in the studies that he has submitted that specifically support the 3 and 5 percent threshold he has advocated, Mr. Halter states that he can point to multiple states that have much greater penetration than the three and five percent threshold he had advocated. T. 2657-2658.

Mr. Halter responds that his private-sector clients are very savvy about what their goals are and the assessment of risk when considering the hypothetical of how should a one-year solar contract and a 20-year solar contract be priced so that the two contracts are equivalent when considering disruption or price change risk? In other words, if EAL offers solar at one-year increments, and EAL is competing with someone that's offering solar at 20-year increments, should there be some price differential to compensate for the risk that somebody that is signing up for 20-years is undertaking when, if you're signing up on an annual basis and there's price change risk, that risk remains on the nonparticipants? T. 2659-2662.

Mr. Halter responded that he does not know whether the Commission has jurisdiction over non-utility third-party providers, T. 3663. He does not know how he can include what Wal-Mart proposes with respect to also being compensated for the amount of demand reduction provided by the net metering facility if he believes the only compensation for demand charged net metering customers is 1:1. Mr. Halter adds that it is pretty black and white that the statute says 1:1 for demand charge customers. T. 2663-2665.

Mr. Halter responds that under a scenario where the net metering facility is on the same circuit as the load, you could probably move the meter to get it behind the meter. He notes that would be geography-specific and dependent upon the circuit. Mr. Halter describes a net metering facility that was located on a circuit that had load, but not the net-metering customer's load and states that the net-metering facility is providing distribution benefits to the load that is on the same circuit as the facility. T. 2665-2668.

Mr. Tinsley states that AEEC is very supportive, and has been in all phases of this Docket, of 2-Channel billing, as a compromise that would mitigate some of the concern with regard to the cost shift that is occurring in residential rate classes. He states that regarding a grid charge for demand component customers, the best way to address the cost shift concern is to fix the rate design in those classes. T. 2697-2701. Mr. Tinsley also states that AEEC was concerned that some Large General Service customers, by adding a net-metering facility, will reduce their demand to the extent that they migrate to the Small General Service class. He states that this is would increase costs significantly for the remaining customers in the LGS class. T. 2704.

Mr. Tinsley testifies that he does not think TOU rates are a very good solution in the short term, but does think that TOU rates may be beneficial sometime down the road when the technology is more developed and maybe the data is more robust and some of those administrative issues are overcome. T. 2706-2707. Mr. Tinsley states that the amount of granularity or differences between the types of net metering customers, does not lend itself to creating a rate class that is solely dedicated to net metering customers. He thinks that the unifying aspects of the existing rate classes are probably still more salient than the differentiation that occurs when somebody installs a net metering system. T. 2707. Mr. Tinsley states that he thinks Act 464 allows the Commission to approve a tariff for a new grid charge outside a rate case. T. 2712-2714.

Mr. Ball recommends finding another method besides 2-Channel Billing to try to match costs of net metering and non-net metering customers, because he believes it is too prescriptive. He states, using 2-Channel Billing plus the 40 percent adder to allocate the cost almost cuts in half the value of what net metering means to a net metering customer today on volumetric rates. T. 2716-2717. Mr. Ball states that the Commission must be careful when charging a net metering customer a grid charge when another non-net metering customer within the same rate class is not paying a grid charge because it leaves open the possibility that that net metering customer could be discriminated against or penalized in some way. To prevent such discrimination, he argues that a grid charge should apply to all customers, net metering and non-net metering customers alike. Mr. Ball argues that a grid charge should not be based on the size of their generating facility but the size that they're paying for their access to the grid. For example, if the net metering customer has 200-amp service, or if they have 400-amp service, that is what the customer should pay to support the grid for that access. He states that it would not matter if the customer had one panel or 100 panels -- the customer has paid for their access. T. 2717-2719. Mr. Ball does not support a separate rate class because he believes it would have detrimental effects on net metering customers. T. 2719.

Mr. Rabago states that every value-of-solar study that he has seen shows that the value of net metering is higher than the average retail rate. He states that this is especially true in summer-peaking regions, where solar -- while not perfectly coincident -- certainly contributes most of its value during peak or peak-approaching times. So, he states, if a net metering customer exported during that time you would be paying them more and the compensation rate under 2-Channel would be even higher. T. 3029. Regarding a grid charge, Mr. Rabago has not seen any evidence that net metering customers cause incremental demand-related distribution costs. Therefore, he asserts, under traditional cost-of-service ratemaking, which the utilities have often invoked as a reason why they are blind to future benefits, then there is no basis for a grid charge because there is no incurred incremental cost that's not otherwise being recovered by the fully bundled rate that utilities have approved based on what they say are their actual costs of service. T .3030.

Mr. Moody states his belief that there is some fundamental data missing that is needed to evaluate whether or not the 2-Channel system was set up truly. For example, he argues that we need current cost-of- service studies to determine what the cost is to serve a net metering customer and how it differs from other customers within their rate class. He also argues that we do not know what the average load profile is in Arkansas for net metering customers in different rate classes. T. 3031.

On the subject of establishing a separate rate class for net metering customers, Mr. Beach states that there is analysis that was presented in Phase 2 that showed net metered customers are actually much cheaper to server than regular residential customers. For example, he states that if you set up a separate rate class for net metered residential customers on the EAL system, their rate would be 25 percent lower than regular residential customers. T. 3033-3034. Mr. Beach does not recommend a separate rate class for solar customers. He states that solar is just the first of many new technologies coming. He states that if you create a separate rate class for solar customers, you will have to add a class for solar plus storage and another class for solar plus EV, and things will become too complicated. T. 3034-3035.

Mr. Beach testifies that he is a proponent of TOU rates because the cost of electricity does vary throughout the day. He states as you add intermittent resources like solar, it's going to vary more widely during the day. He describes how California has implemented TOU rates, and notes that has shifted the peak period to 4:00 to 9:00 pm and incentivized customers to put in solar plus storage. T. 3036.

Audubon, AAEA and Sierra Club all believe Act 464 does not give the Commission authority to modify the rate structure for customers on demand component rates. T. 3040-3041.

Mr. Beach states that one of the issues he sees with the grid access charge is that it is designed strictly based upon the allocated distribution cost to a customer and there's no recognition that solar customers actually can avoid some distribution cost. He states that his study analyzed 15 years of utility investments in distribution plant as a function of peak demand. He notes that his study found that avoided cost for distribution was 13.5 percent of the marginal distribution cost. T. 3045-3046.

Beach states that the result is the same whether in front or behind the meter for residential customers who are going to be located on a distribution system that has a significant amount of load on it. Those customers are going to provide that benefit, he states, even if the panels are not physically located behind the meter. T. 3046-3047. Mr. Beach states that it is a question of what is the load on the distribution circuit when considering large customers. He states that if the size of the solar system has to be well below the minimum load on the circuit, then he does not believe there is going to be an issue. If, on the other hand, he states, the solar facility is in the middle of nowhere and there is no load nearby and you have to put the output up on to the transmission system to get it to the nearest customers, then the net metering facility is using the utility's system. T. 3047-3048.

Ms. Tacker testifies that the AG opposes Staff's recommendation that new net metering rates be individually set if and when each utility comes in for a general rate case. Ms. Tacker argues that Staff's approach is not practical and would not address quickly enough the subsidizing that is occurring. Ms. Tacker also believes Order No. 4 in Docket No. 19-055-U and the language in Act 464 require the Commission to affirmatively set rates, terms, and conditions after notice and an opportunity for public comment. T. 3120-3122.

Ms. Tacker recommends that a working group be formed, similar to the energy efficiency working group, with the parties working collaboratively to develop both a code of conduct for the participants, as well as a consumer guide. She states that information Carroll presented was an excellent start and that the AG would like to conduct a survey of other states that are farther along in net metering. Ms. Tacker also recommends that legislation be developed to give the Commission jurisdiction over third-party participants. T. 3123-3126.

Ms. Tacker states that the AG's Consumer Protection Division is charged with the enforcement of the Arkansas Deceptive Trade Practices Act. She states that the AG certainly would have enforcement authority over actors who engage deceptive or unconscionable business practices. Ms. Tacker states that the AG does not believe it has the resources to police the third-party participants in an adequate manner considering the increasing penetration of net metering, particularly rooftop solar. T. 3126-3128.

Ms. Tacker states that she does not believe that Act 464 strictly precludes 1:1 billing. Rather, she believes that in this proceeding, the Commission must affirmatively set the rates and that the metric by which the rates are set cannot cause an unreasonable allocation to other customers. Given those facts, Ms. Tacker states that she does not believe that 1:1 is a reasonable allocation based on information the AG has reviewed. T. 3130-3132.

Ms. Tacker testifies that the AG sees a difference in how Act 464 treats demand- and non-demand customers, as it pertains to 1:1 billings. She believes Act 464 specifically designates rate-setting treatment for customers that do not have a demand component. Ms. Tacker also believes that the Commission has the ability to establish rates, terms, and conditions for net metering for both demand and non-demand customers that is specifically authorized in Act 464. T. 3132-3133.

Ms. Tacker responds that the AG's consultant has reviewed preliminary data that indicates there is a trend that would support EAL's contention that subsidization is growing. Ms. Tacker states that the AG may be able to provide a final position in the next month to six weeks if additional information can be obtained from EAL. T. 3134-3135.

Ms. Tacker responds that she believes the 1:1 bill rate is causing a subsidization to occur. She believes that 2-Channel billing or a grid charge would help us move closer to that perfect match of costs to net metering and non-net metering customers. Ms. Tacker also points out that that Act 464 does not necessarily require a perfect match, but simply says that there cannot be an unreasonable allocation. T. 3137-3138.

Ms. Tacker testifies that it is AG's position that Act 464 allows the Commission to approve a tariff or specifically a grid charge for demand customers outside a rate case. T. 3138.

Ms. Tacker stated that the Commission should not treat retail [residential] customers similar to commercial customers and assume that retail customers have sufficient information to take any benefits and risks into consideration when making determinations to lock into a long-term contract T. 3139-3140.

Ms. Tacker states that the working group could begin working on a code of conduct while the Commission worked on legislation with regard to jurisdiction; or alternatively, the working group could begin working on both, with an order from the Commission for it to report to the Commission about legislation that would accomplish what the

Commission's directives are. She states that both are urgent and recommends that they begin immediately, regardless of who the task is assigned too. T. 3140-3141.

Ms. Tacker states that the AG has a good grasp on which activities and which actors the Commission should have jurisdiction over in order to fully protect ratepayers. In short, Ms. Tacker believes the working group can begin assembling language that could address the actors and activities which should come under the jurisdiction. T. 3141-3142. Ms. Tacker states that the new authority that the PSC would have would be more specific to the activities and the actors, and would be better tailored to address what is going on in net metering as compared to the Fair Trade Practice Act. T. 3142-3143.

The Commission interprets this provision as allowing the Commission to continue the existing 1:1 full retail rate for such customers.

The Commission interprets this provision as authorizing the adoption of other options that are in the public interest and that avoid unreasonable cost shifts to other utility customers when customers not served under a rate with a demand component engage in Net-Metering.

Net-Metering Rate Structure Options for Demand-Component Customers at or Below 1 MW

With respect to Net-Metering Customers who receive service under a rate that includes a demand component and are not covered by subdivision (b)(9) of Ark. Code Ann. § 23-18-604 - i.e., customers receiving service under a rate that includes a demand component and with generation capacity up to 1 MW - the Commission interprets the statute as requiring the continuation of the existing 1:1 full retail rate for such customers. This interpretation is based upon a comparison of the language of Ark. Code Ann. § 23-18-604(b)(6) - for customers served under a rate with a demand component - with that of Ark. Code Ann. § 23-18-604(b)(2)(A) - for non-demand-component customers. The crediting mechanism language is identical, except that the (b)(6) provision states that the Commission "shall require" what amounts to 1:1 full retail credit for demand-component customers (except for those larger projects covered under subdivision (b)(9)), whereas the subdivision (b)(2)(A) provision provides that the Commission "may require" 1:1 full retail credit as one of the Net-Metering rate structure options for non-demand-component customers.

As explained earlier in this discussion of customer categories after enactment of Act 464, subdivision (b)(9) is a complicated explication of considerations the Commission must apply in deciding whether to approve large (over 1 MW to 20 MW) Net-Metering Facilities. The provisions of subdivisions (b)(9)(A) and (b)(9)(B) are almost identical, with both calling for a public interest finding, but the 5 MW to 20 MW projects addressed by (b)(9)(B) are expressly subject to explicit, enhanced scrutiny under the condition that allowing an increased generating capacity greater than 5 MW and up to 20 MW "does not result in an unreasonable allocation of costs to other utility customers." There is no language in subsection 604(b)(9) or elsewhere in Act 464 that either mandates the retention of the current 1:1 full retail credit or circumscribes the Commission's authority to prescribe a different Net-Metering rate structure for these large customers served under a rate with a demand component.198 Accordingly, the Commission interprets the exception for large facilities provided in subdivision 604(b)(6) as preserving the Commission's discretion and authority to determine the appropriate Net-Metering rate structure under both "public interest" and "unreasonable allocation of costs" standards, as applicable to these large demand-component customers. The Commission may thus consider and implement various Net-Metering rate structure options, including a grid charge, as a condition for allowing a facility to exceed the statutory limits, if it is found to be an appropriate mechanism to address or prevent unreasonable cost shifting behavior or potential, and is in the public interest. These large Net-Metering Facilities will be subject to case-by-case, project-specific filings by Net-Metering Customers and utility-specific dockets seeking permission to implement a grid charge, with the procedures and guidelines governing each utility's demonstration of unreasonable cost allocations and cost shifting being addressed elsewhere in this Order. Such procedures will include appropriate provisions for notice and public hearing prior to a Commission decision on whether to approve the projects.

Grandfathering under Act 464

A new provision in Act 464, Ark. Code Ann. § 23-18-604(b)(10)(A), codifies the ability of the Commission to grandfather Net-Metering Facilities under an existing Net-Metering rate structure as one of the rates, terms, and conditions of Net-Metering. This provision states that the Commission: