Net Metering in Colorado A Detailed Look

Transcription

1 Net Metering in Colorado A Detailed Look There has been a lot going on with net metering in Colorado recently. Keeping things as they are is good for the solar industry, and especially for solar customers, but there has been a lot of talk about changing the way net metering works in Colorado. The main advocate for change, Xcel Energy, also known as Public Service Company of Colorado (PSCo or Company), believes Colorado s current policy is unfair to non-solar customers, and wants to change the policy of paying the full rate to net metered customers. The Colorado Public Utilities Commission (PUC), the body that regulates utility matters like this one, has just finished a year-long series of panel discussions, legal briefings, and comments, by the many interested parties in the net metering debate with the goal of figuring out what to do, if anything, about the current net metering policy. NET METERING BACKGROUND - If a rooftop solar system generates more electricity per month, on average, than that customer uses the current state policy is to compensate solar customers for the net generation of electricity at the same retail rate (about $0.10/kWh for PSCo customers) that the utility charges. Per Colorado law, residents are allowed to size their systems up to 120% of their average annual electric usage per year, but not every customer has a system that will produce more electricity than they consume. Net metering is important to customers who invest in solar because it plays an integral part in their ability to earn a return on their investment. Colorado is one of twenty-seven states that use the retail rate for payment toward residential solar customers. 1 However, only investor owned utilities use the retail rate in Colorado. The other types of electric utilities in Colorado, rural electric associations (cooperatives), and municipal electric utilities (munis) are not governed by the Colorado PUC, and for the most part, can decide their own net metering policy. The debate between the solar industry/customers and the investor owned utilities centers on the differing views on costs versus benefits of these distributed solar resources on the grid. The value of these costs and benefits differs depending on whether you are a solar customer, non-solar customer, the utility, or society as a whole. The utilities and some others take the side that net metering at the full retail rate carries an unfair incentive to solar customers resulting in an unfair cost shift to other customers. The solar industry and other solar supporters argue that the full benefits of distributed generation at current penetrations are not properly accounted for and outweigh the costs to non-solar customers. The debate in Colorado was sparked by PSCo s claim in their testimony supporting their 2014 Renewable Energy Standard Compliance Plan (Proceeding No. 13A-0836E) that net metering at full retail rate constitutes an incentive, and that their solar customers are not paying their fair share to use the utility s electric grid, and correspondingly, the non-solar customers are paying more than their fair share. However, various pro-solar parties argued the existence or size of this incentive/cost shift claimed by PSCo and countered that the full value of the distributed generation was not taken into account, and would more than offset any claimed incentive or cost shift. In full disclosure, I represent one of the parties in this proceeding that disputed this claim, the Colorado Solar Energy Industries Association United_States

2 Multiple motions to defer or sever the net metering issue from the 2014 RES Compliance Plan proceeding were filed, but it wasn t until the Colorado Energy Office filed a motion asking the Commission to sever the net metering issue, that the PUC listened. On February 27 th, 2014, the Commission issued Decision No. C I granting the CEO Motion to Sever, thus setting the stage for the yearlong proceeding that considered net metering and retail distributed generation. Decision No. C , issued March 18, 2014 opened Proceeding No. 14M-0235E to consider net metering and the potential impacts of retail distributed generation expansion in Colorado. The proceeding started with a series of presentations designed to guide the Commission on what it should do. The Commissioner s Informational Meeting on April 9 th included presentations from Staff of the Colorado Public Utilities Commission (Staff); the Colorado Office of Consumer Counsel (OCC); the Colorado Energy Office (CEO); Public Service Company of Colorado (PSCo); Black Hills/Colorado Electric Utility Company, LP (Black Hills); the Vote Solar Initiative (Vote Solar), Rick Gilliam and Kevin Fox on behalf of the on-site solar industry; Western Resource Advocates (WRA); Ms. Karey Christ-Janer; and CRES Boulder County s Ms. Leslie Glustrom. PSCO presented the idea of a separate adjudicatory process to hash out the differences for each utility, and the joint solar parties asked for an independent study to develop a standard method for determining the costs and benefits of retail distributed generation before any other Commission action is taken on net metering. Following the initial presentations, many parties filed comments, and this led to the Commission ordering a round of initial legal briefs on such topics as: interconnection policy, offering net metering to customers when the utility is not in compliance with the renewable energy standard, issues of REC ownership, legality of separate rate classes for solar customers, and the utility s ability to deduct fixed costs from the full retail rate offset. Initial briefs were due on July 31, 2014, and replies due August 29 th, As could be expected, the briefs returned a range of interpretations of the questions presented. The Commission also ordered a series of 3 panels: Costs, Benefits, and other state s examples, and eventually added a fourth panel addressing issues related to on-site storage; distribution system design; panel orientation and sizing of photovoltaic systems; grid parity and the need for incentives to install retail distributed generation in the future; and a minimum bill concept. The rest of this article gives a synopsis of the four panel discussions held at the Colorado PUC. PANEL I COSTS - July 24, 2014 All four panels took place at the Colorado PUC (1560 Broadway, suite 250, Denver, CO). The first panel happened on July 24, 2014, and it was probably the least controversial. In other words, there was broad agreement on the costs of net metering for RDG. The two sides still differed in that PSCo, through it s presentation by Alice Jackson, VP of Rates and Regulatory Affairs, reiterated that the Company wanted the costs of net metering declared an incentive, and tracked in the Renewable Energy Standard Adjustment (RESA) fund. Specifically, PSCo wanted net metering payments above the avoided cost to be included in the RESA because all customers pay into that fund and it is limited to 2% of the customer s total monthly bill. This would have the effect of adding more cost to the RESA, and less ability to use the RESA funding for other renewable energy incremental costs. Whereas, the solar industry, represented by TJ Slocum, a founding member of COSEIA, and Mr. Thomas Beach, a consultant with Crossborder Energy, pointed out that the solar penetration, and therefore costs, are still low, and that the costs of RDG in terms of levelized cost of energy (LCOE) are coming down for residential, commercial, and utility scale solar and are most likely going to achieve grid parity between 2015 and The joint solar parties compared the cost shifting to that of demand

3 side management (DSM) programs. They pointed out that DSM shifts about 10 times the cost from participants to non-participants than solar does. Basically, PSCo says the annual costs are around $16 million and the joint solar parties calculated around $7 million. The last speaker for the first panel, Kent Singer, represented the Colorado Rural Electric Cooperative Association, and said that the co-ops support the basic concept of net metering. He noted that there are 22 separate electric distribution co-ops in Colorado, each with their own elected boards of directors and their own policy toward net metering. Some pay full retail rate and some call it a subsidy and only pay avoided costs, and some use another form of calculation. He said there are about 3,000 net metered customers in the 22 coops. Some co-ops have rebates or other incentive programs on top of net metering, but most do not. PANEL II BENEFITS - October 1 st, 2014 The second panel was the one most participants were waiting for - presentations on the benefits of rooftop solar. On October 1st, six panelists talked about the benefits of RDG and net metering. The first panelist was Dr. Bryan Hannegan, the Associate Laboratory Director of Energy Systems Integration at NREL. He said that the benefits depend on a number of factors: It depends on whether the sun is shining, or not; it depends on what the condition of the grid is, and what it might need; it depends on the load that that grid is serving, and, at that particular point in time, what is required for system stability or reliability purposes. 2 He said one category of benefits is the energy displacement value typically not burning gas from a gas turbine. The second class of benefits has to do with the environmental and health value of reducing harmful emissions, and the reduction of a carbon tax, or other environmental regulation costs. There are also benefits of meeting a state RES compliance, general environmental benefits of reduced water use, and avoided land use impacts. When asked by Chairman Epel about grid parity and when it will happen with rooftop solar, Dr. Hannegan answered by pointing out that the question shouldn t be when will rooftop solar cross over grid parity, but where do we cross over value parity. He likened solar investment to investment in cell phones. People pay more now for cell phones, but they certainly cost more than the old phone system, but we choose it because it gives us so much more value. The next presenters were Tom Beach, the same Crossborder Energy consultant from Panel I, and Rick Gilliam, the Program Director of Distributed Generation Regulatory Policy for Vote Solar. Mr. Beach pointed out that the States of Vermont, Nevada and Mississippi had found that net metering was cost effective. He said you need to do a long term, life cycle analysis of benefits, and costs, because solar is a 25 to 30 year investment. Second, the analysis of benefits should consider the full, broad range, even if some are difficult to analyze. And the comparison of benefits to costs should happen from a variety of perspectives. For example, the Nevada study used five different perspectives ratepayer, solar participant, non-participant, total resource cost, and the societal perspective. The Crossborder Energy Study found benefits of 18c/kWh, and so based on 140 MW of DGS examined in the study, the benefits for residential customers were about $12 million a year (see p. 34). And, if that calculation is extrapolated to the now double the size of solar (240 MW) the benefits also double to $24 million per year. This gives a benefit/cost ratio of 1.5-to-1 in Colorado. He went on to describe how the Crossborder Energy analysis was different than the PSCO study, and how the PSCo study was flawed in many ways. 2 Transcript of Panel II December 1, Bryan Hannegan: p. 7, lines 4-9.

4 Rick Gilliam pointed out that about 55% of the initial 59 MW on the PSCo system and around 44% of the first 140 MW of DGS in Colorado came from commercial systems, and not residential, and commercial customers are likely to have benefits that far exceed the costs, so the more commercial megawatts that are part of the mix, the better the overall comprehensive net metering cost and benefit analysis will look. In the commercial setting, there are less exports, and greater opportunity for reducing distribution costs. PSCo had the final presentation on benefits. Alice Jackson was back along with Kelly Bloch who is their Senior Director of Electric Distribution and Engineering. They focused their study of benefits for this panel on the residential impact of on-site solar. Kelly Bloch described the problem of solar generation coming on to the distribution network when the development was already designed, and not with solar in mind. She mentioned that when enough solar comes into a distribution network and power starts going the other way toward the substation, there are changes in design and increases in costs that will be required. She basically pointed out how the grid was necessary at all stages of a solar rooftop customer s daily load profile, and how solar doesn t provide the kinds of reliable power that the utility provides, and finally, that the grid last even longer than the expected life of the solar panels. They pass along any upgrade costs to the person installing solar in a neighborhood where they might cause a need for an upgrade to the distribution system. In essence, the PSCo presentation on benefits, focused largely on distribution costs. They did acknowledge an energy offset benefit and a potential emission benefit, but they state that the PUC governs their avoided cost methodology through the most current PUC decision, which doesn t allow PSCo to account for carbon dioxide costs. Jackson admitted that the PSCo DSG study only studied system benefits, and didn t take into account any of the potential societal benefits or the other items in the Crossborder Study. She said there might be more grid security costs, and agreed the question of benefits should be looked at from a number of perspectives. And, they state that the benefits will follow the law of diminishing returns especially with respect to offsetting generation. After the PSCo presentation was finished, Chairman Epel pointed out the disagreements on benefits come in five areas: The avoided emissions costs, the avoided capacity and O&M costs, the fixed operating and maintenance costs, the avoided distribution, and transmission upgrades, and the society adder. Both Jackson and Beach agreed. Ben Norris from Clean Power Research and representing IREC talked about having to agree on methodology and assumptions. If both sides agreed on these, they would come up with the same numbers. They ve done studies for utilities, renewable organizations, and various energy agencies, so they have developed a good idea of what the methodology should be. He noted that there hasn t been any talk about ancillary services, such as looking at integration costs on the whole solar fleet versus individually, and the fuel price hedge. Why isn t that a system benefit, he asked. Hedging refers to reducing price uncertainty, and not increases in fuel prices that are accounted for and part of the avoided energy. There are benefits of solar aggregation and long term and short term benefits. And lastly, rate design is important in this whole process. Chairman Epel worried that might have to have an adjudicated docket on the methodology that will take much longer than the study itself. Dr. Hannegan and Mr. Gilliam agreed that the general approach or methodology for determining costs and benefits are fairly well aligned but the input

5 assumptions will be the harder part to agree on. Chairman Epel thanked everyone for their input and said that there will likely be a 4 th panel. PANEL III AZ, NV, MN, AND NREL EXAMPLES December 1 st, 2014 After introductions by the three Colorado Commissioners, Commissioner Heydinger of Minnesota started off the third panel with a discussion of the State s integration cost study that showed a 40% renewable energy standard was possible by 2030 in Minnesota, with incremental costs from the transmission system, and that 50% would be much more costly. The rest of her presentation centered around the Value of Solar methodology applied in MN. She said they had a very open stakeholder process with utility and solar engineers, along with national labs and others help out in the process of determining Minnesota s Value of Solar Tariff Methodology. Next up was Commissioner Susan Bitter-Smith from the Arizona Corporation Commission. She acknowledged that each state is different, and their Commissioners are publicly elected. They had a large public debate on net metering in AZ. The investor owned utility, Arizona Public Service (APS), argued that existing solar customers should have to pay a $50 charge for access to the grid, and the solar industry countered by saying their customers were owed money. AZ had a series of stakeholder meetings hosted by APS that were not particularly productive, but it did vet many studies and get a lot of info out on the table for the Commissioners. Then there was a public hearing process, and there were many protests, but in the end the Commission held there is a value to the grid, and there is a cost shift to non-solar customers, and the final verdict was a 3/2 split of Commissioners voting in favor of a 70c/kWhr charge for prospective solar customers, which translates to about $5 to $7 per month. Importantly, the rule went into effect for only new solar customers and existing ones were grandfathered in with no charge. She concluded by saying next up for AZ is a full rate design conversation, and they ll see what happens there. Commissioner David Noble from Nevada was next, and he started out by stating that Nevada started a net metering program in 1997, but in , allocated $255 million for incentives to try and get 250 megawatts of distributed solar on the grid. He said that the incentives started out too high and there was a 500% to 1000% oversubscription in their solar project lottery. He noted that there were a lot of fits and stops with applications and allocations and instillations, so in 2013, the legislature switched over to performance based incentives, and mandated a net meting study using a third party consultant. The study started out with a stakeholder process set out by Commissioner Smith that included representatives from the NV Commission staff, the utilities, a lawyer from the state s AG s office and one solar representative, Jason Keyes, and then a second, Tom Beach. These stakeholders ranked requests for proposals with and independent auditor, E3 running the RFP process. They saw a ratcheting down of up front and performance based incentives, and there was a 2.5x multiplier for PV toward the NV RPS. He noted that the multiplier was a good incentive in the beginning, but ended up hurting the overall benefits of net metering, resulting in fewer systems needing to be installed to meet the RPS. He concluded by stating that the multiplier won t sunset until The final speaker was Dr. Dan Arvizu, the Director of NREL. He mentioned that there are many different factors and regional considerations that make determining net metering policy difficult. And that most of the policy work happens at the local level and not national. But, there are environmental consequences to the current 100-year-old energy utility structure and policy that served us well in the past, and now they need to change. Nationally, NREL is working on grid modernization and trying to figure out the necessary objective analysis of topics that will aid local and national energy transformation policy.

6 The third panel ended with a series of questions for each panelist and many topics were discussed, including the topic of energy storage and the idea that cost reductions in residential, and utility sized energy storage could change the renewable versus fossil fuel balance of power. PANEL IV ON-SITE STORAGE; DISTRIBUTION SYSTEM DESIGN AND ANCILLARY BENEFITS; PV SYSTEM SIZE, ORIENTATION AND LOCAITON; MINIMUM BILL DESIGN April 23, 2015 On-Site Storage- After initial words from the Commissioners, Ben Kaun of the Electric Power Research Institute (EPRI) started off the first section of Panel IV on the topic of on-site storage. Mr. Kaun is a Sr. Project Manager with EPRI, in the Energy Storage Program. EPRI is an independent, nonprofit, collaborative research organization. Storage can be a capacity resource for generation, transmission, and the distribution system, it is a flexible resource that can help balance supply and demand over seconds, minutes or hours, and can also provide dynamic voltage support. It can also act as a reliability or resiliency resource. Mr. Kaun said the lifetime net present value is a better determinant of value for distributed storage. It is also important to note that storage is an integrated system, and not just a battery. The system has some costs, but also benefits, such as energy an ancillary services, or grid operations support, etc. They also need to have benefits to the customer such as bill savings from timeof-use billing, demand charge reduction, backup services for when the grid is down. Overall, energy storage is better suited in California for different reasons, than in Colorado, and it may be a while until the utility system and pricing and costs align to the point where storage is more cost effective in CO. Next up was Ryan Hanley, Senior Director of Grid Energy at SolarCity. He started off by noting that the cost curve for storage is coming down all the time, just like the solar PV industry years ago. The trick to bringing residential storage to more people in Colorado is to align possible revenue streams through incentives or utility system changes that would benefit storage. One technical solution is the widespread use of smart inverters on solar PV systems. A large scale battery system may be cheaper, but it may not have as many uses. A 60 MW storage system hooked up to the transmission system may only run a few times a year, whereas a residential system might be used every day. Either way, a diverse portfolio of systems would be best because they all have different benefits. He also mentioned that it is harder to value avoided cost benefits, but it is possible. Sometimes you have value for adding storage on the distribution, but it doesn t change how the system operates, so it is hard to calculate the value, but there are times where the addition of a storage system will have an obvious savings where you don t have to invest in a new transformer, for example. His take away was that utilities need to start planning for distribution changes that integrate storage and PV so that it is easier to calculate costs and benefits. Sky Stansfield of the Interstate Renewable Energy Council, a nonprofit that works to improve customer access to renewable energy was up next and talked about the different groups that the costs and benefits of storage accrue to, and that it s important to stack the values in a way that s transparent and include multiple points of view. Again, she emphasized rate structures that send important price signals to customers who want to install storage systems. The two main examples are time-of-use pricing and lowering demand charges. The second area of regulatory review would be to look at developing markets for ancillary services and demand response. A critical policy to work out is to make sure that storage customers have access to interconnection that is fair and efficient.

7 Distribution System Design and Ancillary Benefits Ken Wilson of Western Resources Advocates was up first, and he used to work for Bell Labs as an engineer during their transition from analog to digital, and he sees similarities here. He said the first step the grid needs is better metering to improve and advance the distribution system management to better deal with outages and survivability. He briefly described a couple of the difficulties of having a high concentration of rooftop solar in a certain distribution system, which doesn t happen often, but might occur more in the future as solar builds out. Too many solar customers can put excess strain on the transformer in a certain location, if they are producing a lot more energy than is being used. Also, voltage issues can come up in the same instances, and a lot of these problems have to do with the geography or location of these systems to the grid system in place. And, in some instances there can be flow-back of energy to the substation, and the station needs to be able to handle that. He noted that there are a lot of cost effective solutions for all of these instances that don t have to include stopping solar installations. Many of these issues are not ready for Colorado and it would be wise to see what is happening in Hawaii, and California, and Germany. He is an advocate for integrating storage into the grid in order to alleviate some of the issues of excess solar. He told the Commission that we need a distribution planning process and load studies and to use that to better integrate storage and PV onto the grid. PSCo finally got its say with Lynn Worrell, its Senior Director of Electric Distribution Engineering up next. He noted that the Xcel system has high reliability and they need to continue that with the added pressure of distributed resources like solar and storage. He said the Company has had to add distribution transformers to account for reverse flow of electricity in high PV concentrated areas. He also mentioned smart inverters as a solution for high reverse flow times. They are also looking at Advanced Distribution Management Systems, and improving communications systems for monitoring and control of the demand and load on the distribution system. Mr. Hanley of SolarCity emphasized the smart inverter can do more than just smooth out the voltage fluctuation of the PV, but the system as a whole. Solar with storage could also help lower the lifetime strain on the system by lowering the net load on a particular transformer, and extend its useful lifetime. PV System Size, Orientation, and Location Dan Harms of the La Plata REA in Durango started off the discussion on sizing, locating, and orienting PV systems. Of their 41,000 meters, 35,000 are residential and they have about 700 rooftop systems, or about 2%, which isn t extremely high, but can create local issues. He describes a solar scenario where the customer offsets their electricity, but the REA still has to pay the wholesale demand charges, and so they only receive $20 out of the $31 they have to pay from that customer. Since there are only a few instances like that, and they have a policy to encourage solar, and it isn t much of a problem now, but they may have to look into demand charges for residential solar customers in the future. Those 2% of customers cut out about 1.2% of their annual revenue (~$500,000). Before they change their demand charges, they will probably do a cost of service study and change up their whole rate structure and include time-of-use pricing. Their time-of-use pricing actually came about because they are winter and night peaking utility and they have been able to shift 10 megawatts out of their 150 MW peak. Next up was Kent Scholl, Senior Resource Plan Analyst with Public Service, and he works on their long-term planning needs. He does his best to estimate the load that they have to meet and that includes adding in every solar customer, because they have to be provided for as well. They also say

8 they do their best to estimate the behind the meter generation during the peak system hours and give solar a generation capacity credit. He noted that residential solar peak is usually a few hours later than system peak, and is worse for solar, as a system resource, but many commercial customers have an earlier peak, and that helps. He said that only about 1% of their system peak is being met by distributed solar generation. He also noted that the incremental value of avoided generation capacity decreases over time as you add more and more intermittent, non-dispatchable generation, like rooftop solar. Right now solar penetration is around 1% of customers, but if it went up to 10% solar penetration, or around 2,200 MW more solar, only about 66 of those megawatts would be useful for peak-load reduction. Location of each solar system is very important, and west-facing solar systems should not be incentivized because he stated they do not add value to the system when you take into account the amount of sun they lose from not being oriented south. Mr. Beach was back up and added that the Commission should wait until solar penetration grows to something closer to 5%, and then reevaluate net metering. Right now the system needs it and the state incentives are low and the ITC may be going away in a year or so. It would be best to wait until the solar market is off of other incentives and has a change to grow organically, and then do a comprehensive analysis of net metering, using what was learned here. Solar with storage and smart inverters could make the capacity values line up even better. Instead of 30%, storage could allow solar capacity to offset peak load up to 80 or 100%, depending on how much storage there is on the system. Minimum Bill Design The first speaker on this topic is an economist, and Senior Advisor for the Regulatory Assistance Project (RAP), Jim Lazar. He said customers should be able to connect to the grid for what it costs. Also, customers should pay for grid services and power supply in proportion to how much they use, and when they use it. Finally, customers that put power on the grid should be fairly and fully compensated for the value of the power they supply, which may be a different character of power than grid power in rate design. When designing a minimum bill rate, one should first determine what the customer specific costs are, and then set the bill amount to ensure you are recovering that minimum portion of revenue specific to those customers. Mr. Lazar is in favor of a conventional rate design that recovers a customer s specific costs. However, a minimum bill rate can avoid the collection of a lot of revenue requirements in fixed charges, and the minimum bill rate can be charged to the few customers that have smaller or zero usage. Marc Kolb of SolarCity was up next. He is here to give the solar industry s side of a minimum bill and its potential impacts on the industry. He started out by saying that if the Company did an exhaustive examination of the long term costs and benefits, it may find that the benefits exceed or at least equal the costs, and therefore, there is no need for additional reform of fixed cost recovery. A minimum bill is basically an assurance that all customers are paying their share for fixed costs that can t be avoided. He showed a calculation that leads to around $6/month as a fixed charge/minimum bill added to the $7.63 fixed charges for the average customer s bill and you get $ He noted that this addition to the minimum bill does affect solar customers without a large enough system to provide for their energy use, but it doesn t affect customers that have a larger sized system as much. The last speaker of the day was Alice Jackson, the VP of Rates and Regulatory Affairs for PSCo. She said that they have been working hard to figure out how to eliminate the cost shifting and make the payments ads transparent as possible. Even using a minimum bill system doesn t totally eliminate the cost shifting, but it s a better solution for now. Ideally, they would want to move residential customers to a three-part rate meaning adding a demand meter and billing for that as well as fixed charges and the

9 energy rate, but that would entail a large upfront cost to install demand meters. The bottom line is that $35.03 is what they came up with for their minimum bill, where they tried to add in all fixed charges that weren t being covered by solar customers. PSCo stated that if the Commission decided to go with $15 instead of $35, then the extra $20 should be taken into account through a corresponding charge to the RESA as a subsidy for solar. Chairman Epel didn t seem to think that a $22 difference was that substantial. He expected it to be larger, and thinks there is something there that can be worked out. Mr. Kolb pointed out that the $35 is actually a fixed charge and not a minimum bill. Mr. Lazar said that the inclusion of a $35 minimum bill looks like they are taking distribution network costs and converting them to a fixed charge, which is a big step in ratemaking. Further, there is no real issue of a cost-shift. The Company already has a rate design that recovers costs in a structured fashion already. Cost shifting may be happening, but it happens between customers in similar classes all of the time. It costs more to provide electricity to a sprawling ranchette than an apartment complex, for instance. Chairman Epel ended the proceeding by saying that the burden is on this Commission to decide what the next step is. The final step in the PUC process was taking in a final set of comments on any of the issues in the 4 th Panel or throughout the process. These comments were due May 22 nd, 2015, and then reply comments were due a week later. Numerous parties filed comments including: Staff of the PUC, the Office of Consumer Counsel, WRA, COSEIA, SEIA, and TASC, IREC, Vote Solar, the City and County of Denver, the Colorado Energy Office, and PSCo. The comments fairly well summarized the process. Those groups in favor of solar, stated that nothing needs to be done yet, and there is no proof that a cost-shifting is taking place. On the other side, you have PSCo and the OCC, who state that this costshifting needs to be dealt with as soon as possible, because it results in an unfair system for non solar customers. Now, it s up to the Commission to sift through all of the presentations, briefs, and comments and figure out what to do next. Regarding what to expect next, your guess is as good as mine.