Avoided cost rates for qualifying facilities (QFs) are determined using methodologies like the peaker method, which calculates capacity payments based on the economic carrying cost of new combustion turbines and allocates payments during hours of greatest need identified through loss of load expectation studies, while energy payments are adjusted for intermittency through mechanisms like the Solar Integration Service Charge (SISC) to reflect the actual value provided by renewable resources.
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Technical Conference - 2025 Biennial Avoided Cost Proceeding - 5/13/2026追加:
avoided costs. Commissioners present are Floyd B. McKisik, Tommy Tucker, Don Vandervart, and John W. Ga. I'm William Broly, and I'm chairing this conference.
On August 22nd, 2025, the commission issued its order establishing bienial proceeding, required data, and scheduling public hearing in docket number E100 sub 211. This order established the 2025 bienial proceedings held by this commission pursuant to the provisions of section 210 of the public utility regulatories policies act of 1978 and the applicable federal energy regulatory commission regulations pertaining to this commission's responsibilities for determining each electricity each electric utilities avoided cost with respect to rates for purchases of power from qualifying co-generators. and small power production facilities. These proceedings are also being held pursuant to North Carolina General Statute 62-156, which requires the commission to determine the rate to be paid by electric utilities for power purchased from small power producers as defined in general North Carolina general statute 62-3 per 27A.
Pursuant to that order, Duke Energy Carolina's LLC, Duke Energy Progress LLC, together here and after referred to as Duke, Virginia Electric Power and Power Company, DBA, Dominion, North Carolina, here and after referred to as DENC or Dominion, Western Carolina University, and Appalachin State University doing business as New River Light and Power Company were made parties to this proc. proceeding here and after referred to collectively as the utilities. The public staff which represents the using and consuming public has been made a party to this case pursuant to North Carolina General Statute 62-15D.
On October 31st, 2025 and November 3rd, 2025, the utilities filed comments, data, and proposed rates as required by the commission's August 22nd, 2025 order.
The commission has issued orders allowing the following parties to intercede intervene in this proceeding.
The North Carolina Sustainable Energy Association, NCSEA, the Carolina's Clean Energy Business Association, CCEBA, or CCBA, Carolina Industrial Groups for Fair Utility Rates, SIGFUR, the Southern Alliance for Clean Energy, SACE, and Renewable Properties, LLC, Renewable Properties, the Public Staff, NCAA, Renewable Properties, Sigfer, Sace, and SIBA filed initial comments on February 5th, 2026. Renewable properties, the public staff, SACE, DENC, NCAA, CCBA, and Duke filed reply comments on or before March 20th, 2026.
On March 27th, 2026, the commission issued an order scheduling this technical conference for today, May 13, 2026 at 10:00 a.m. for commissioners to receive oral presentations from the utilities regarding the 2025 bianial determination of avoided cost rates for electric utility purchases from qualifying facilities. The order required that the utilities file names of the individuals who would appear at the technical conference and their presentation materials on or before May 6, 2026.
Additionally, the order required utilities serving at least 150,000 North Carolina retail jurisdictional customers to present additional information regarding the combustion turbine capital cost estimate, the proposed net energy benefit decrement, the analysis surrounding the solar integration service charge SISC, and the application thereof, and a request for additional information attached to the order as appendix A on May 6, 2026, Duke, DENC, Western Carolina, and New River Light and Power file the names of the individuals who would appear at this technical conference. The utilities participating in today's technical conference are and will appear in the order listed as follows: Western Carolina, New River Power and Light, Dominion, and Duke.
Depending on the length of commissioner questions, the commission may observe a 10-minute break following Dominion's presentation.
Uh that might be lengthened as we understand the Duke presentation was not received in time and uh our staff will need the opportunity to load that up for the presentation system.
Uh, as noted in the March 27th, 2026 order, each utility is limited to a presentation of no more than 30 minutes, excluding commissioner questions. The commission will adhere strictly to this time limit and therefore ask that each utility pay close attention to the time allotted. Please do not exceed that time limit. I will also be monitoring the time and will let utilities know if their time has expired. I will also note that during commissioner questions, each utility will first be asked the same set of general questions before being asked questions specific to the utility.
With that, we will begin with Western Carolina and New River Light and Power.
Please introduce your presenters and begin your presentation.
Good morning, commissioners. I'll make >> Oh, I'm sorry.
>> Thank you, Mr. Chairman and members of the commission. My name is Grace Styers with the law firm of Fox Rothschild. I serve as regulatory counsel for Western Carolina University uh and Appalachia State University doing business as New River Light and Power. Um we appreciate the opportunity to be here today. I have sitting next to me Mr. Reed Conway from Western Carolina University. Uh Mr. Matt McDad, the general manager of New Orle Power, sends his regards and regrets, but um had uh is meeting with the city of Boone City Council today um and uh is unable to be here as I had informed um commission uh in our pres uh information earlier, but we do have the most knowledgeable person to answer these questions, address these issues, which Mr. Randy Howie of Summit Utility Advisors. he uh drafted the u comments that were filed in this docket and provide the verification for those is the most knowledgeable of the avoided cost issues and will be presenting on behalf of both Western Carolina University and New River Light and Power. So with that I'll turn it over to Mr. Howie.
>> You introduce yourself for the record.
>> Thank you Bri. Um yeah my name is Randy Howie. I am from Summit Utility Advisors and I do represent uh New River Light and Power and Western Carolina University in rate matters as well as I do in the avoided cost proceedings for for this process.
We presented we handed out these slides to the commissioners and all council of record. If anyone and and staff, if anyone else would like additional paper copies of the presentations, we have them here on the corner of the desk here. You may take one.
All right.
Yeah, it's not moving. Next slide.
That could be me.
All right. Thank you. Um yeah, we are just want to give you a little overview of what the systems look like for New River Light and Power and for Western Carolina Power. Um both are distribution system only. They don't own any generation. Uh they have a wholesale power sales agreement with Carolina Power Partners for all of their um wholesale power supply needs. None of them have neither one of them have any generation. Uh they also do not own and operate transmission facilities either.
They use uh they pay for the transmission service from Duke and as well as from Brimco to get the power from their generator to their uh facility. So no generation and no transmission. They are both again just distribution facilities. So um makes them a little different from from Duke and Dominion. Just to give you an idea of the size of these facilities, New River Light and Power serves just over 9,000 customers and uh Western Carolina serves just under 4,000 customers and that's in and around uh Boone for New River Light and Power and Koi for Western Carolina Power. the these are more of a based on their size and the way they operate, they're more they operate more as a municipal utility would because they are smaller and in only in their communities and they really do focus on uh looking and meeting with the customers as as Mr. Syers uh said Matt MDAD with New River Light and Power is meeting with the town council of Boone right now for some issues that they were talking through.
So they do operate more as a municipal utility more so than they do uh an investor own.
>> Next one. Thank you.
As I said, the wholesale power supply agreement that they both have, they both purchase their power from Carolina Power Partners. Uh they both are on a 20-year agreement with them. And the main components of that agreement is they have a capacity payment, which the capacity per KW month is contractually set. and it is applied to whatever their peak their actual uh coincident peak is for each and every month. So that is set contractually. The the energy they pay for is a more pass through. It is the cost of fuel that the um energy that Carolina power partners use to generate power plus a little bit of a a variable on&m piece added to it. So the the fuel is a pass through to the customers for for both New River and for Western Carolina. And to give you an idea of the size of both of those, West uh New Riverline Poweres right around just under 50 megawws is their capacity that they buy from CPP. So relatively small and you know roughly 225,000 megawatt hours in a year. So again relatively small. And Western Carolina the same. They capacity they they purchase the maximum is about 17 megawatt hours and then their their purchase of energy is about 56,000 megawatt hours in a year. So again relatively small um utilities uh from the purchase power side. Okay. Next.
Now New River does have 28 what we qualified facilities that are solar. Um they are all distributed connect they're connected to the distribution system again no transmission facilities at all 10 of them are on New River's uh schedule PPR which is a purchase power for renewable which is for solar customers only which was developed in New River's last rate case effective back in 23. Um they have 10 of their own there. One of them is uh the size ASU does have a solar facility that's 100 me 100KW and the the other utilities the average size is about 6KW.
So they're relatively small systems as well and the amount of energy that they have purchased from those um in 2025 was just over 241,000 kilowatt hours. They also have uh 18 customers that are on New Rivers's net billing rider which was also effective in the last rate case um back in 2023 and the average system size of those customers just over 4KW. So again relatively small um and purchasing about 38 39,000 kilwatt hours from them in 2025.
Uh there is no utility scale solar at all hooked up uh with a new river light and power system.
Next, please.
So, the total purchases that they had from these qualified facilities underneath the solar uh arrangements they had, it's about 280,000 kilowatt hours. That makes up less just over, you know, onetenth of a percent of the total energy they purchased from Carolina Power Partners. So, a very small percentage. And the amount of credits that they paid in 2025 was just over $11,000. So, um, again, not a significant piece of, uh, cost for New River Light and Power, nor the energy that they intake. The next slide, please.
Now, Western Carolina Power, uh, does have five, uh, facilities that are uh, that they've purchased energy from from solar facilities. They do have one customer that's has one that's size 67KW and then the average of the other ones are about 11KW. So, again, relatively small facilities. And the annual purchases they had in 25 were just over 16,000 kilwatt hours, which you know, well below onetenth of a percent of their total purchases compared to their wholesale purchases. And their total credits um for that year were just over $700. So once again, relatively small um qualifying facilities that they're, you know, paying credits for u from the solar facilities. And Western Carolina also does not have any utility scale um solar on its system either.
Next slide.
Um and for the for these proceedings how we developed the avoided cost for the um small power supplier reimbursement was we we did it we have a formula rate that we have proposed in the past and was approved in the past and the formula rate is based on their actual costs from Carolina Power Partners. Each year when when when they come in and set their purchase power adjustment um clause for their retail rates, we also identify what is the projected cost of energy from Carolina Power Partners and that would be the only avoided cost we have in this uh for this proceeding was the energy piece of it and then we we basically use that number for the year and apply multiply that by the end number the amount of energy that they receive from these customers. So again, it's the it's the pass through energy that we receive from Carolina Power Partners is what we utilize as the avoided cost uh for the energy piece.
And we also do have the there's a a an SP demand rate which none of the c none of the um customers are on right now.
But if they were, we would take the the actual cost of demand that Western Carolina or New River pays to Carolina Power Partners and then identify what was the um KW amount during that system CP coincident peak if any and then that would be their avoided cost because it would have reduced power supply costs from Western Carolina or from New River Light and Power. So that is where we identified the avoided cost for this proceeding. Um and similar process that was used during the rate case for new river light and power developing the net billing rider and the the purchase power for renewable energy. So that uh concludes what I had prepared for you.
Happy to answer any questions that you may have right now.
>> Thank you sir. Um, I'll just go ahead and ask the questions, but I believe y'all received copies of these in advance, so you you're probably ready with answers. Uh, first, please share with us your understanding of effective system costs and provide any specific instances of those costs affecting your systems.
>> Okay. Um yeah, the I understand that the affected system costs are from uh requirements to the transmission systems that may be impacted by either generation or large upcoming on um you know given the fact that New River Light and Power and Western Carolina Power don't own and operate transmission systems. We do not have uh the need we don't look at that because they don't have those costs to look at. Um but the um the fact that they have some qualifying facilities on their system that are relatively small um we have no knowledge of those generation facilities causing any impact to the dis to the transmission facilities from of Duke or BMCO.
>> Okay. The second is if you know how uh affected system costs are passed through to your North Carolina retail customers please tell us. Yeah, we since we don't have any we didn't have anything to address.
>> In your opinion, do affected system costs have any impact on or relevance to avoided costs?
>> Uh again, since you know our our systems don't have the transmission facilities, it wasn't looked at. So I I do not have an opinion on that one.
>> I would say our transmission network upgrade cost taken into account when determining avoided cost for your system.
>> Again, >> you don't have any.
>> We don't have any. Yes sir.
>> All right. Uh please briefly describe the types of qualifying facilities currently interconnected to your systems.
>> Uh right now they are all solar facilities.
>> Okay.
>> And they're all rooftop if I'm not mistaken. Generally just >> most are rooftop. ASU does have one on a building that I think some may be ground mounted but that was the 100 100KW one.
>> Okay.
How common nationally is the wholesale costbased formula rate methodology that you apply for avoided cost rates? Uh >> I'm not sure nationally. I don't I I'm happy to look at it look up and get back to you on that one if you like.
>> All right. Uh any questions from other commissioners?
Hearing none. Thank you, sir. You're excused.
>> Thank you for your time.
>> Thank you.
>> We can only hope the rest go as well.
Uh, next would be uh Dominion.
>> Morning, Chair Broly. Commissioners, Andrea Kels with Meguire Woods here for Dominion Energy North Carolina. Um, uh, today for Dominion, we have Lisa Crabtree who's the director of strategic planning for the company and Jeff Madson who's manager of integrated strategic planning for the company.
>> Good morning.
Try to click her.
One second.
Y >> All right. Uh I'm Jeff Matson. I'd like to begin um at the beginning in 1978 to level set. Um so section 210 public utility uh regulation policy act in 1978 established u this um uh perpa structure and um the original purpose was to promote non-utility generation.
Um these non-utility generators are small power producers uh we refer to as qualified facilities or QFs and um since 1978 quite a bit has changed in addition to the the growth of renewables.
Dominion Energy is now part of uh the PJM regional um transmission organization and as such uh smaller power producers can market directly to uh PJM and do not need to uh to work only with uh our utility. And in uh 2006 um the uh uh limit to qualify as a qualifying facility was reduced to 5 megawws um reflecting that situation.
Um so while perpa is a a federal law uh there are stateby-state implementation and we recognize this bianial avoids cost proceeding is uh to set the price uh the rates within North Carolina the rates being capacity and energy for those products and um our guiding principle from the the law is that we shall not exceed the utility's avoided cost of otherwise procuring that power and we'd like to begin with highlighting some of the significant changes uh from this current proposal. Um most significant is for the energy portion of the rate. We've proposed to change our fixed price or FP schedule um from a modeled fixed price for energy to using a locationational marginal price which I'll uh jump into a little bit later.
And um would like to recognize for clarity that Dominion offers an existing LMP option, our schedule LMP. So we will have two LMP options moving forward with this proposal where their capacity payments are different.
One is based on the peaker method, the FP product or FP schedule and the LMP schedule is based on the um uh capacity auction and PJM. So it's more intended to be a market structure.
In addition to that significant change to the energy um we have changed the capacity um uh working with staff. Um we have transitioned to the pricing of the uh peaker method to use an advanced class CT as opposed to an F-class CT.
And maybe more substantially, we have revised our uh allocations for how the capacity rate is paid with the intent of more precisely targeting the hours of greatest need. So the overall theme of our our proposal uh is that we are um with the LMP and with the new capacity allocations trying to more precisely align the benefits of the energy being procured with the rate the customers will pay.
Our our next slide highlights those changes in a little more detail. Um, so I'll I'll just touch on this briefly.
Uh, the fixed price or FP schedule in gray at the top, uh, where it was a modeled energy price, we had nine buckets to account for time of day and seasonality will now be based on 8,760 hours of prices every year as the actual day ahead LMPs are realized. Um, instead of having a a a basis adjustment for the congestion and loss impact, uh, we're proposing to use the nodal price, so the the node on the system closest to the QF qualified facility.
Um, this would also eliminate the fuel hedging adjustment and we have proposed eliminating our redispatch cost adjustment for simplification.
Um I mentioned the capacity cost. We're uh focusing more on hours of greatest need.
So we have in the past had capacity payments in all seasons. Um we're now focused more on winter and summer um and less the shoulders. The LMP schedule remains but the capacity um we would like to use the similar approach and focus more on the summer and winter uh periods and and less uh broad application of capacity payment.
So since uh LMP or locationational marginal price is at the heart of our proposal for energy would like to um spend some time on that. uh you know LMP is intended to reflect the cost of making delivery and delivering electricity at a specific location on the bulk power system. It's a PJM construct that um clears the market and it sets the marginal cost of generation and then applies um adjustments for congestion and losses to a specific location or node. Um within PJM there are thousands of nodes uh and um there's two markets day ahead and real time. The day ahead market um has hourly granularity on the pricing and the real time market and the real-time operations is repriced every five minutes. Um LMPS are very transparent. They're published on PJM's website for every node for every period and um that data is available to anyone in the public.
We propose applying this um using the day ahead LMP. Um I mentioned there's day ahead and real time. the vast majority of load and generation clear in the day ahead market and the real-time market is really for balancing for um adjusting the the dispatch to account for um differences in load and system conditions.
Um but the majority of the volume is is cleared through the day ahead and that's where we would like to um price our energy and we um have proposed to use the nearest node that the qualified facility uh would connect to the system at. the the benefits of using LMP as opposed to a modeled energy price is um you know much greater precision but also um because it's it's the actual price uh as we move through time it it is accounting for you know policy changes which we're seeing uh quite a bit of of policy change world events that can have major impacts on on the cost and value of energy and even intermittent weather. So where our nine buckets were able to account for seasonality and account for usage and time of day, we didn't necessarily know which day of the week was going to be hot or cold or cloudy.
Um whereas the LMP will reflect the uh actual weather in a given hour. Um and for those reasons, we feel it most represents the actual avoided cost. It's what a generator would be paid if they were selling directly to PJM.
So then the next section is capacity. So with the energy based on LMP, the capacity is still based on the peaker method. Um and uh on the left we'll walk through our process for transitioning and translating that peaker cost to the rates that are paid for energy. So we start with the cost of advanced class CT. Uh working with staff and Duke and prior cases, we've determined a third party source is a very good uh source for the price of a CT in terms of transparency and um that's what we've used. uh there's a small adjustment for economies of scale recognizing that we put more than one CT at a site typically and um we then take that investment cost and translate it to an annual cost uh using an economic carrying cost of capital concept to get to a a annual cost for that investment and then later on the fixed on and m annual cost and uh new this year we are netting in the energy margin. So, because the advanced class CTS are intermediate resources that run more often and at better heat rates, they um lower the cost of energy to customers. And we feel that it's appropriate to include that as an adjustment so that we're not double counting the value of that energy and paying it through the capacity payment while we're also paying an energy payment. And um that net energy margin um we sourced from the PJM market monitor who's independent market monitor and has projected uh energy margins for CTS. And so we were able to do that as part of the PJMRTO to rely on that third-party source in the same spirit that we relied on the third party source for uh the CT cost. Um so we propose netting that energy margin and uh the last step is to translate that uh annual cost of capacity to a rate to be paid to c or to QFs and um we we need to do that is my understanding from the structure of perpa that we pay on the energy even though capacity is not always thought of as a tied to energy. Um, so we pay on the generation a dollar per megawatt hour rate and there's two steps to translating the annual price to that dollar per megawatt hour rate. Uh, the first is the performance adjustment factor that's been established in prior cases. Uh, which essentially grosses up the value of the CT recognizing that CTS are not available 100% of the time. Um, so that if a theoretical qualified facility was able to be available 100% of the time, it could theoretically earn the full capacity payment. Um, so we have applied that as as established and then the the second part is the allocation of the rest of that of that value. And we had, as I mentioned, a broader allocation in the past, but we've gone more focused.
We leveraged the loss of load expectation study that PJM has performed um as part of their capacity market construct. And I've highlighted here hours of day within a month um that have the highest probability of loss of load based on PJM simulations.
And those are the hours that we propose or have proposed paying for capacity. So our capacity uh cost for a year are allocated to be paid only in the hours highlighted here.
um the the summer afternoon or you know afternoon, evening and then um uh you can see in the numbers here the greatest need in the winter in the morning, early morning and also at uh early evening.
And that is our um process for uh assessing energy and capacity rates.
Were you going to comment on your appendices or these are just additional information?
>> They're additional information and available uh in responding to questions.
>> Okay, sir. Let me start with the general questions that everybody gets.
Please share with us your understanding of affected systems cost and provide any specific instances of those cost affecting your systems and also if you know how these costs are passed through to your North Carolina retail customers, please tell us.
>> Thank you, Mr. Chairman. Uh affected systems costs generally refer to costs imposed on neighboring or interconnected electric systems as the result of a new project or upgrade connecting to the grid. So set another way, when a new project or upgrade is seeking to connect to the grid, an affected system study is conducted to identify whether that project requires grid upgrades on the neighboring interconnected grid. Uh since 2022, DENC has filed quarterly reports with this commission to identify any active projects in North Carolina for which DENC is an affected system or for which a DENC system project identifies Duke Energy Progress or Duke Energy Carolas as an affected system. Um since 2022, there have only ever been two projects identified. Um and both of those were later withdrawn. and so did not actually incur affected systems costs.
Um, as far as how those affect those costs impact avoided cost or or cost ultimately to customers when affected systems costs are identified and actually incurred, those costs are assigned to the project developer.
So, and in the avoided cost construct, those would be costs that showed up for the QF side of the ledger, but therefore do not actually have any impact on the compensation the utility is paying for energy or capacity. Um, because there costs borne by that project developer that is that is not the utility. Um, and therefore they're not um passed on to retail customers through rates either.
>> Okay.
You also uh answered the second question as well. Are transmission network upgrade costs taken into account when determining avoided costs for your systems? And if not, how are transmission network upgrade costs allocated when an eligible QF with a PPA comes online?
>> Yes. So they're they're not uh considered as part of the the avoided capacity construct. U but those costs uh are are assigned to the developer.
>> Okay.
Some utility specific questions. What is the approximate current breakdown of qualifying facilities in DENC's service territory in terms of solar, hydro, swine waste, landfill gas, etc. And what is the approximate total capacity?
>> They're all solar. It's approximately 680 megawatt.
Would you please explain how the proposed energy net revenue adjustment is different than DENC's net peaker adjustment from the 2024 avoided cost proceeding excuse me 2014 >> so Jeeoff I think it's talking about the difference in the CTS you know >> the um >> why we doing the net energy Now with >> so we have asked before uh the company Dominion has asked before in our propo prior proposals to net energy margin at the time uh F-class CTS were used uh as the basis for capacity cost and F-class CTS are peers um their primary purpose in the system is to be available for capacity um as part of an RTO and and part of a wholesale power market. We saw these peakers earn positive energy margins at times, but we do recognize that they primarily were peakers um that were there to serve capacity. Uh we think it it's um a distinction that the advanced class CTS that we're now using have um lower heat rates, are more efficient, are expected to run at higher capacity factors at lower cost and um in our case earn positive energy margins or thought of differently lower the the fuel cost to customers and and therefore have an energy value in addition to the uh capacity value. Um to to kind of further that uh line of thinking, if we were to use a nuclear unit or a combined cycle unit to set the cost of capacity, um we would uh see that there's tremendous energy value to combined cycle units and nuclear units and that um it is not just a capacity resource. And so those of course are base load units. Um the advanced class falls in between as an intermediate unit unit, but we still feel is appropriate to back that out and therefore not double count paying u for energy value within the capacity rate while also paying an energy rate.
We understand Dominion is expanding the scope of projects eligible for PPAs under the Virginia Clean Energy or Clean Economy Act to include projects in North Carolina. How do these terms compare with what these facilities would receive under a negotiated or standard offer pera avoided cost contract?
So, um, you know, transitioning from our previous fixed price 10-year contract to our current proposal, which would be a 10-year contract with, uh, LMPbased or variable rates. the CE uh clean economy act PPA is a fixed price um based on an RFP and that price escalates I believe at 2 and a half% annually and it's a 20-year term.
The PPA construct includes energy and capacity as well as uh Rex or renewable energy certificates. So the environmental attributes of a solar project is included whereas um in our avoided cost uh schedules wrecks are not included.
>> What has been the interest from developers in this offtake path? And this I'm assuming is the negotiated or standard offer purple.
So, uh, we've had very little interest in recent, uh, schedule 19 rates and proceedings, um, with no new, uh, QFS in the last few proceedings. And um we have uh some interest in the uh clean energy PPA from North Carolina facilities, >> but it sounds like there's not enthusiasm in either way.
>> We have had bids for the most recent RFP where it was opened up, but there not I would not say we've seen enthusiasm for our schedule 19 rates.
>> Okay. Uh questions from commissioners.
>> No. Okay. Uh, Commissioner Vandervart, >> I think I lost you when you were talking about you gota do you have like a 2 by two matrix on you have two different methods for the avoided energy cost and two different methods for the voided capacity cost or am I if I go to avoided energy cost I understand you got a fixed price method is that the old way of doing things or you're still offering that. Yeah. So the rate schedule unfortunately is uh still uh titled schedule FP uh which was based on fixed price but we are now proposing that's an LMP base. Okay. That's something we may try to clean up.
>> Okay. So that's what I was asking you.
So in the fixed price world back when you used to do that you you tried to build up a price from an existing from existing F-class CTS. You tried to include some hedging adjustments etc. Regious bash cost adjustments and you tried to create a fixed price and and then that would be in the power purchase agreement for avoided energy.
>> Yes.
>> More or less. And then in the LMP you're basically allowing let me get this right. You're basically allowing the market as forecast a day ahead to define that cost.
>> Yeah. And so uh it is a a forecast is for the next day. Yeah, I get that.
>> All right. So, now we go over to capacity. So, I mean that that makes a lot of sense, right? because you're I mean all of the all of the if you go back to the fixed price uh way of doing things you know there's always questions of are you including all the things that are involved with integrating solar onto your system whereas and you know potentially overcharging because you're missing something and now you're going over to what is essentially the market defined number and that varies I mean as you said this is a this is a dynamic number.
>> Yes, >> you know that makes a lot of sense. Now, let me go to the capacity side and again I'm a little confused here. I understand what you're talking about using the advanced I mean I I I I just don't understand the whole peaker method versus using I think what you said a loss of load which is an ELCC type approach.
>> So yes sir. So the the loss of load approach is to um allocate that cost. So previously we >> right you use that to define what windows to provide the higher cost right I guess my question is why wouldn't you just I mean can can your system operators rely on that power being generated versus if you had an ELCC amount you could actually rely on that to avoid >> building capacity which is the idea behind avoided capac you know hence the name avoided capacity So, so explain that. Explain your thinking about why you you didn't pursue that versus or or for that matter use a market driven uh capacity uh number. So, just explain that.
>> So, um so we uh are in the the PJM RTO uh that manages the capacity market that we participate in and they do use an ELCC method. And so if a generator participates directly with PJM in the market, they are paid a dollar per megawatt day or dollar per kW month. They're paid a fixed payment for for being there for being available uh regardless of the amount of energy produced. And um PJM recognizes uh the um limited the the varying capacity values of different technologies and does apply an ELCC to technologies. So the ELCC for solar is very roughly about a tenth of the ELCC for CT. Um and uh that structure makes a lot of sense to us here at Dominion. Um and that's how we uh we apply that same logic in developing our IRP. For example, we are we are ELCC um focused. However, my understanding of perpa is that we must pay for the energy as deliver.
>> I would love if you send me >> Yeah. I'm letting them finish. Yes. I would love for you to send me that statutory site.
>> Yeah.
>> I heard you say that.
>> Yeah. not not an attorney. So, uh either requirement or our practice has been to do that. So, following that practice, um we are paying it dollar per megawatt hour. And so, what we want to do is to the best of our ability to align that payment with the true value of capacity kind of that ELCC value. So, previously we had focused on um PJM being summer peaking and paying a higher rate in the summer.
Uh we acknowledge that there's some value to having resources in the shoulder months. We paid some shoulder value, but um as PJM has transitioned to the CLC methodology, they have done these loss of load studies that show the winter mornings as the most important, the most at risk hours. And we recognize that and we are doing our best to align the payment on an hourly basis for energy with those hours of greatest need.
>> No question about that. I get that.
>> And it's not perfectly aligned.
>> Yeah.
>> It's all forward looking and and um but uh we're definitely trying to transition to and so that loss of load study is the same study that underlies the ELCC construct. saying >> no and and that's what I I heard you say that and and I guess I just don't what I also heard you say was some you know per my understanding is per provides a lot of flexibility for states to do things like this and so you know maybe later after this you can send me the site that you're that you're claiming limits you to this sort of a a bonus payment during these defined periods versus an actual how much is the utility avoiding having to pay for capacity, which is the way I understand the right the reading at least in North Carolina, but you know, you can send me that later. I just I heard you say that and I didn't understand it.
>> Thank you. Commissioner, may I offer one additional point to what Mr. Matson was discussing that based on something you said and this may not be what you were asking but you know order 872 does make clear that the com the utilities still have to offer a fixed price con um for capacity if a QF is willing to sell um pursuant to a legally enforceable obligation. So we weren't able to switch over to market for capacity. That's why we're offering it for energy not capacity. FK was very clear that you QS still gets a fixed um fixed uh price >> but that would allow so I get that wouldn't be a dynamic number but would also allow you to define a fixed value based on ELCC and pay him that. In other words, perpa doesn't provide that you have to pay a volutric uh uh capacity payment. You can also pay them a fixed capacity payment based on what you can really rely on and therefore what you can really avoid to pay and put in the ground. That's and you and I agree on that then.
>> Okay. Well, thank you very much.
>> Thank you.
>> Very helpful.
>> Yes. Unless I missed it any you made a comment. Uh the chair asked you about current breakdown of facilities. You said 680 megawws of all solar. Is that correct? Okay.
>> Approximately. Yes.
>> Is is um can you make any comments about the uh about um the what the options are for those facilities uh going forward as any of their contracts expire and they want to continue operation.
>> Yeah. So um a number of those facilities are are larger. 20 megawws was our limit in the past prior to the 2006 and um would not qualify under the new uh purple construct. So for facilities that did qualify, uh the schedule 19 rates would be open to them as offered. And um for those that did not qualify, they and those that do, they have the ability to market directly to PJM. So that that's available to anyone within our our territory. And um so those would be two options. We also have the option of the clean energy a clean economy um RFP and then um uh Dominion uh could consider other options going forward >> and and remind me of those size there was some size criteria around their um their options for selling into the market or or via one of these tariffs.
>> Yeah. So for being into tariffs, um our standard contract is 1 megawatt or less and our negotiated contract size under uh schedule 19 is 5 megawatts or less and we have many facilities uh qualified facilities currently that are 5 megawatts and also 20 megawws.
>> And commissioner guy, I just want to offer clarification that you know when Mr. Mr. Matson's talking about the 5 megawatts for under it's for Dominion.
It's for because Dominion's in PJM.
They've got a ruling that under purpose they don't have to buy from a QF sized above five megawatt. It's specific to because they're in the RTA.
>> Okay. Thank you.
>> I think that's all the questions.
>> Yes, we will. Thank you.
Take a break.
Dude's presentation arrived.
>> It has.
>> Okay, good. So, break.
>> Uh, it's ready to go right now. You want to keep on going?
>> Yeah. Yeah.
>> Thank you.
on the record and come to order. I want to correct a minor error I made. Uh we have attorneys here today representing interveners who are not questioning and not presenting but are in attendance and I'd like to allow them to identify themselves for the record.
Thank you, Mr. Chairman. Um, John Burns for CCA.
Nick versus >> Hannah Klaus for safe.
>> Justin Samowski on behalf of the North Carolina Sustainable Energy Association.
>> Good morning. Tom Felling with the public staff on behalf of the using and consuming public.
>> Thank you.
Okay, Depp and Deck Duke, good morning.
>> Good morning.
>> Please introduce yourselves.
>> Good morning, commissioners. Uh, Hayes Finley with Duke Energy. Um, Carolina's in Duke Energy Progress. And also here today is Tracy DeMarco with Meguire Woods representing the companies. Uh, and I will let the panel introduce themselves. But before that, I'd like to just thank the commission for accommodating uh our revision to the PowerPoint. We just had an updated graph. We wanted to make sure you had the most accurate information. So, thank you for the additional time to submit that.
>> Chair Bryley, commissioners, good morning. Uh, my name is Glenn Snyder.
I'm managing director of IRP and analytics for the Carolas. I have uh with me today uh Mr. Mike Quinto who's director in our our group and Miss Mora Farver and the panel uh is looking forward to uh presenting to you today and happy to be here with you.
So really a a lot of what we'll say I'll try and streamline a few of my remarks because uh they were uh very well uh presented by the Dominion witness uh and uh we have a lot of uh common ground there. So again we use the peaker methodology uh and that really I'm going to give you a history of that uh and then go into the components of it. how we delineate energy from capacity and the various aspects of energy and capacity, what's included, how it's included in the energy and capacity payments. And then Miss Farber is going to end with some discussions around our retrofitting uh process and affected systems.
As Mr. Matson said, you know, Purp's got a long history. We're going on. It's hard to hard to believe as I sit here.
It's going on 50 years of FURPA. Uh 1978 uh rulem came out in 1980 under 69.
There's been a couple of revisions over the years. 2005 Energy Policy Act uh had some revisions and then lately FK 872 as we just heard about in the prior uh presentation also had some revisions to that. Um at the state level, you know, think about it through cooperative federalism. The federal government sets the general standard. The state has the implementation of that standard. Uh our implementation over the years has changed. When I first started doing this more than a decade and a half ago, um this was pre 589, pre951 here in North Carolina. So standard offer rates were the only way in which QFs really came on to the system. And the graph we put up here on the right sort of shows that, right? um that we had at that time dropping costs uh for solar at the same time and incentives coming into play.
The technology was maturing uh and gas prices were high back then. So you had this avoided cost rates that were rising. Costs were coming down. You had long-term standard offer rates. It encouraged a lot of solar development.
Uh and you saw that spike there, you know, in the teens 20, you know, 14, 15, 16.
uh as the market started to change and North Carolina recognized that, you know, maybe the better way to bring on solar was through competitive procurement, uh most of that QF development under standard offer rates after House Bill 589 and then subsequently House Bill 951 uh had migrated away from taking standard offer and moving over to the longer term uh purchase power contracts and you get it through a competitive instead a fixed price. It's competitively procured relative to, you know, their their bids, and everybody doesn't get the same fixed price. Uh, as as was said by the Dominion witness, uh, in exchange in those long-term contracts, you also get, uh, dispatchability rights on the solar. you get environmental attributes over the life of the contract where you do not get those in a standard offer contract which is not allowed under uh perk principles for your fixed price rate. Um you know the the same principle I'll just quickly reiterate it's an indifference price. You want to make sure that you're setting an avoided cost rate that but for we often use that term that but for the QF customers would have paid the same amount for the energy and capacity taking it from traditional resources on the utility. So it's uh it's an indifference price that leaves the customer paying the same whether they take it from the QFS or the QF doesn't show up and they take it from the utility. Um so under the peaker method and we've already heard about this we'll break it into capacity and energy the energy gets reduced for solar again this is a technology agnostic rate because it does apply to any QF so it applies to co-generators it applies to other renewables biomass um solar however gets a deduct to their energy rate for their intermittency that's specific to solar and it reduces the energy a solar provider gets but for that deduct the same standard offer rate applies across all qualifying facilities. Next slide.
So, we've got an example uh on the energy. What I'm going to do is I'm going to talk about the the energy components in the SISC and I'll pass it over to Mr. Quinto to talk about uh capacity and the capacity component of the rate. Um so what we've shown here is uh a QF is only compensated when it delivers its value at the value it delivers right and so if you you know see the graph on on the right are energy rates um much like dominions are broken into seasonal and then by season time of day buckets. So you have off- peak on peak and premium peak in in the summer and in the winter and then you have on and off peak in the shoulder months.
that give you uh varying uh price buckets. Uh what we show here is you can see that throughout the day our load is the highest in the winter in the early morning hours and then again in the late evening hours. So that's when the avoided cost rates are higher. In the morning we even have a a premium peak where loads are the very highest. So your marginal costs are the highest.
what you avoid by having generation during those times is greater than what you avoid if you have it either at night or in the middle of the day. And you know what we would see is a similar thing in the summer. Actually, if you saw the rates we just filed, um because of all the solar we already have on the system and project to have on the system, even in the summer, our middle of the day is off peak because our load is net of solar that's already on the system is fairly low. So, we're accounting for the fact that existing solar reduces just like in this graph in the winter, you're off peak in the middle of the day. And so, you're not getting as much on a dollar per megawatt hour as you are if you're available during those early morning or late afternoon hours. And it's it's a different type of a you know, you've heard of the duck curve. you see a different type of duck curve but peak hours may not start until four five six o'clock it it now because we have all the solar 12 years ago when I was doing this peak would have started at noon or 11:00 but because of all the solar those hours have shifted and so we now we now pay less so time different energy what does it do yes we we avoid uh primarily fuel we also avoid vom reagent costs, you know, sulfur, limestone, things of that, variable costs associated with operating dispatchable generators. But the biggest bucket that you're avoiding is the fuel costs. So all of the the solar and other QFs that are providing energy to the system, but for them providing energy, we would have been burning gas, you know, in the near term, a little bit of coal. Longer term that's going away, but predominantly that would have been gas. So we you know I just wanted to highlight that it does provide well it doesn't and Mr. Quinto will get into it doesn't provide we don't compensate very much at all for avoiding capacity. What it does do is it reduces dependency on natural gas uh which helps with gas availability and gas needs in the state. So I put a simple example uh in the upper right corner that says 100 megawws of solar produces roughly 200,000 megawatt hours of generation. If you use a average heat rate of eight for a marginal gas unit, some CC, some CT, you know, each 100 megawatts is 1.6 BCF less gas that but for the solar would have been consumed, burned and paid for by the using consuming public. So the solar really does produce more of an energy value uh relative to the capacity value and the biggest chunk of that energy value is for um the the avoided fuel and it does have some other smaller parts to it. Uh notwithstanding that we do recognize that solar has intermittency involved uh both at the hourto- hour level, day-to-day uh season to season, but also sub hourly. And so the you know we started asking these questions. I remember asking some of these same questions that the commission put before us today back in 2016 like how are we going to capture the subhourly intermittency and some of the costs that that produces and then we put our heads together we hired a strappe consulting uh we engaged in a in an SISC uh study to say what is that subhourly and hourly ramp intermittency that solar creates and should we reduce the energy value produced by solar based on the unique intermittency characteristics of of that particular QF technology. Um that was uh a very at the time a very controversial uh issue. Uh we spent hours and hours uh in front of the commission. It was a huge study that was in front of the commission.
uh the commission took a big interest in it and then had us engage in the next filing with a technical review committee where we brought in Brattle, three national labs, some of the interveners here today had their experts on that on that review committee. And so we had a a very deep dive, a lot of time, effort, uh resources at at all by all parties including the commission uh to review that that solar integration service charge to say, hey, how do we account for that intermittency on the system?
And that's on the this bottom graph here where you're seeing a little bit of that. It's not really, it's hard to see where it's up to scale, but those little pertibations over a smooth um a smooth load cause you to need to carry extra load following services. And so you're on a less efficient part of your heat rate curve with your power plants. And there's there's a slight cost to that.
And what that study showed is the more solar you add, the the higher that cost would go up. Um but it the rate at which it goes up sort of slows down because you get geographic diversity. So you know nominally it goes up but as a percentage of the system it doesn't go up that fast as you get more geographic diversity. The other couple of key takeaways I don't have on the slide but just a sort of a speaker note is it's very much dependent upon the cost of that intermittency. Two things one is what is the cost of natural gas because it's a suboptimal utilization of gas. So if gas was really really cheap that sub-optimal utilization of gas doesn't cost that much. If gas was really expensive then that suboptimal utilization of gas gets more expensive.
And then the second one that many of the interveners uh here and the public staff have raised and and we don't disagree with is it's also a function of the composite of your system. So as your system adds more and more storage resources in particular the cost of that load following intermittency and the amount of an the cost of carrying ancillaries drops precipitously. Um battery storage is capable of instantaneously almost accepting or injecting little pertibations even as it's in its ramp up and ramp down. it slows or increases its ramp in or slows or decreases its ramp out and so it can deal with these pertibations with little variable costs and and can actually provide those ancillaries rather than natural gas providing those ancillary services. So two things that that I would uh remind the commission is is just how much is that how is the system changing over time and how are we going to incorporate that in our SISC and what is the cost of gas. So those are sort of the two big things uh that that drive uh the cost on that. Um again I think uh you know we've hit most of the points on on this. You can see where that top right corner uh where solar comes on. I was mentioning that in in the winter uh that load dips. It looks like hey maybe I'm ramping down and ramping back up. the the difference between the dark blue line and the light blue line that you're seeing on that slide, that's the total number of megawatt hours that's being saved from the solar, which is represented in the green below. That's a bunch of megawatt hours that are no longer being generated by natural gas. However, that doesn't mean you're necessarily ramping units up and down. That dip might be used, those units may stay flat along that, but now you're charging batteries. So on certain days, what solar is going to help you do is it's going to help you make sure you've got enough energy on the system to meet the next morning's peak by having your batteries charged that but for the solar you might have struggled with the energy sufficiency to have the battery charged. So there are some tangential benefits uh from solar that that often are are overlooked. Um and with that I'll I think I'll pass it over uh to Mr. Quinto.
>> Thank you.
>> Thanks Glen. Good morning commission. Uh the second component of avoided cost as Mr. Schneider uh mentioned is the uh compensation to QFS through the capacity payment. Uh the capacity value uh is comprised of the fixed cost components related to incremental marginal capacity on the system. Uh that capacity payment um is uh the capacity payment periods when that capacity payment gets paid uh is determined based on loss of load expectation uh risk from resource adequacy studies. So the table that you see in the top right uh is an example for D. So for hours ending 5 through 9 uh in the months of December through February is when these capacity payment periods um are. Uh below that you'll see heat map. This is a loss of load probability from our 2023 resource adequacy study. Uh it shows when the system has the most loss of load risk uh with months across the top 1 through 12 January through December and hours uh down the left side hours ending one through hours ending 24. Uh you can see that the majority of this loss of load risk occurs in the winter or exclusively in the winter for our system and then for uh overwhelmingly in the winter mornings. So we correlate that capacity payment period to our resource adequacy study and our loss of load probability.
Uh this is driven by system peak conditions uh where weather sensitive load drives up uh the probability for loss um loss of load expectation in those hours. Our resource adequacy studies where this is derived from is composed of um over 40 years of real weather data that's used to um uh along with outage data uh to determine when we have the most system uh risk that incorporates uh potential extreme weather conditions uh over extended days and also considers the resource mix and um resources being able to generate such as uh if cloud cover were be um to happen for days at a time um and limiting the amount of solar generation in that time frame. Um so that is how we determine the capacity payment hours over which when QFS are uh compensated for their capacity value to the system.
Uh in determining that capacity value uh we use the peaker methodology again uh consistent with kind of how Dominion described using the economic carrying cost of a new CT. Uh the CT represents the lowest capacity uh lowest capital cost for a capacity resource. Um and it's uh spread out over the life of its asset. That's how we come up with that economic carrying charge. Uh the capacity value also includes the fixed costs related to operating and maintaining uh that peaker. Uh the companies did highlight in their filings that uh we had two key component updates to our capacity value calculation. The first one is a transition of our data source. So, in the past, we had been using an EIA um uh installed cost for the new peaker. Uh we've transitioned over to the 2025 uh cone uh report for PJM. Cone being cost of new entrant. Uh this is a publicly available uh data set that allows us to um use that for the installed capital cost for the peaker resource itself. We've also updated our capacity resource to the advanced class CT consistent with uh what Dominion has done. Uh this advanced class CT aligns to our generic representation of the next peaking resource in our IRP as well. Um as I'll mention in some following slides, this transition to the uh advanced class CT does have an impact when we talk about the net energy benefit decrement or um the net energy value as uh Dominion described it.
Uh one of the considerations the commission had in this technical conference was the ability for solar to provide reliable capacity for the system. Uh so as discussed those capacity payment periods uh when QFS receive uh capacity payments uh are based on generating uh during those capacity payment hours. um to receive a full capacity payment for a year, a facility would effectively have to generate in all of those hours December through February um at 100 effectively 100% output to receive that full annual economic carrying charge of the peaker. So with respect to solar, we can see on the bottom right that the uh generic solar profile is not well correlated with these capacity payment hours. Um looking at that uh graph in the bottom right, the blue line representing a generic solar uh output. Uh you can see in the winter it's not even getting to 100% output um on an average day. Um and then very little uh portion of that actually showing up during those capacity payment hours.
Um so what we uh see when we overlay this generic uh solar profile over the course of an entire year um approximately 6% of a QS total revenue would come from this capacity payment with the overwhelming majority coming from their energy payment. As you can see in the table uh on the top right, a 100 megawatt uh solar facility, for instance, uh would get uh roughly $9.5 million uh in payment for its energy across the entire year with just 600,000 of that um uh revenue coming from generation in that in those capacity payment periods. Uh that's about 6% for a uh just a generic facility that can operate at 100 megawatts across the entire year. Um you can see just below that their compensation would be roughly 41 million from energy payments and almost 10 million uh from capacity payments close to uh 25% of their total revenue. So a significantly smaller amount of uh solar QF's revenue coming from the ability to provide capacity to the system.
um this low solar generation in these capacity payment periods uh effectively reflects our ELCC or capacity value for solar. Uh so ELCC effective c effective load carrying capability is the ability for a resource to provide reliability to the system. uh we calculate those ELCC's based on loss of load expectation calculations consistent with our resource adequacy studies uh as previously discussed and that generic solar profile or the profile that we would expect out of a solar resource um the major component of its ELCC is that it doesn't generate in those hours um so in our planning process in our IRP's development uh solar uh capacity value is effectively 2 to 3% of its name plate capacity so For uh the example in the bottom left here, a 100 megawatt solar facility would only receive roughly two to three um megawatts of firm capacity contribution in our planning process or effectively 2 to three equivalent megawatts of a combustion turbine. So certainly not on a 1:1 basis.
Uh finally the last uh component with respect to avoided capacity value is um the commission asked us to discuss our net energy benefit decrement. Uh so as previously discussed uh these peers uh can provide both capacity and energy value to the system. Avoided cost seek to compensate QFs through energy and capacity value separately. uh and so that capacity value is intended to compensate only for its marginal capacity value to the system. Therefore, our process for net energy benefit decrement uh then removes the energy value that a um a peaking resource or resource um is able to provide to the system. So uh the rationale was already discussed a little bit. I'll touch on a high level. Uh today our existing fleet is uh from Peaking Resources is largely uh F-class CTS. They're an older legacy unit. Uh they have roughly a 105 heat rate. Um the advanced class CTS are much more efficient. Uh they can operate at a 9,000 to 95 heat rate. Uh so they are utilized on the system more often when introduced. they provide um by providing more efficiency when generating uh they provide value to the system on that um 8760 across the entire year um from its energy output.
Uh so to calculate this um benefit that having a new peaking resource that's much more efficient on the system uh we do successive u model runs one with and one without uh this new peaking resource. We look at the production cost of the system between the two and that delta in production cost is the value that this uh new peaking resource provides to the system and which becomes our decrement to the capacity. Uh the high level results result in about a 12 to 16% uh reduction in the capacity payment that we would uh that reflects the installed cost of the CT. um that installed cost gets reduced by that 12 to 16% to become our effective net capacity uh payment to QFS when they generate in those capacity payment periods. So in summary from a capacity standpoint without the net energy benefit decrement or this NEBD uh the capacity rate would overstate the value of capacity uh to the system by co-mingling or including energy capacity value. Um and this methodology for reducing the capacity value uh prevents that uh conflating uh energy and capacity value by isolating that pure marginal uh capacity value as appropriate. Um again similar to the net cone process that you may have be familiar with in other jurisdiction.
Cone being cost of new entrant or the installed cost of a new resource. That net part is removing the energy benefit.
Um that's effectively the same thing that we're doing here in our avoided cost filings. And with that I will uh pass it over to more.
>> Thank you. And I'm here to address some specific questions about um a proposal in our avoided cost filing about expiring QFs. And so um we held a stakeholder process um including uh groups such as the public staff and CCBA and after those stakeholder discussions included in our avoided cost filing an option for expiring QFs that are adding energy storage to their facility. And so this would be a limited time option um to execute a 10-year HERPA PPA and they would commit to retrofit their facility with this battery storage. um the companies would have the ability to change which hours the capacity payment is assigned to over the course of that 10-year term. And this is really to align with system needs in case that changes over time. We're not necessarily locked into those exact hours for the whole future. Um we're also seeking an amount of storage that would be at least 20% times four hours of that facility size. The idea was really just to avoid gaming that someone's not, you know, adding a laptop battery to their existing solar facility just to get a 10-year rate. Um, these facilities would not be allowed to grid charge and they still have an interconnection review that's required. Um, they may qualify as a material modification and this would u require additional study and we have seen seen interest from developers on this um you know during the stakeholder period and um and comments on our avoided cost docket. CCA has been supportive of this offering.
Um, thus far there have been about 15 sites that have inquired with DEEC and D. And in the interconnection queue, we had about seven, I believe, um, QFS that are seeking to add storage to their existing facility. And we also had a stakeholder um, ask if we could change the requirement from DC connected storage. Would they would we allow AC connected storage? And after review, we do think that that is a a worthwhile modification. still ensuring no grid charging but AC connected storage can be allowed. So we are seeing some interest in um this offering and the next avoided cost filing would update the commission on how much participation we've seen and if we recommend continuing this option or not.
>> I don't think our summaries I I'll go quickly anyway. I wasn't going to read off that deck. I think you have it in hard copy. Um, I think what we really wanted to leave you with is when we reviewed uh the questions that came in uh that was the impetus for this technical conference. We wanted to make sure that we we covered those. And and really from our perspective given this 10-year history, the extensive uh reviews we've gone through in terms of uh the decrements, how we apply capacity rates, how we account for ramp and intermittency, for example, that we have we have accurately arrived at that indifference price for customers that says the rates that are in the QF avoided cost rate in this proceeding accurately reflect the rates that customers would otherwise have incurred if they would have bought energy and capacity from the utility. So, as Mike pointed out, for example, solar gets a very small, but if I have a um biomass or a co-generator who can generate in those winter morning hours, they get a very big payment. So certain QFs can avoid capacity, other ones can't. And they get paid appropriately and that means the customer is only paying a little bit solar. They're going to pay a lot more for capacity from a biomass facility or a co-generator. When it comes to energy, I showed where the energy rates are now sort of the lowest during the daylight hours just because of the saturation of solar and it then gets further reduced because of the SISC. Um, so again, uh, if you, as Miss Farmer said, if you have a battery, you may say, "Hey, maybe I better take that lowcost energy, put it in the battery, and start avoiding capacity or higher cost. If you don't, you're going to get stuck with the lower cost, and you're going to get an SIS charge." So really to have in perpa a technology indifferent rate that compensates at that but for indifference price has been this strive over the last decade through subsequent proceedings and uh I think we've we've arrived at that uh here in the methodologies we proposed today.
>> Well thank you and you brought it in right on time.
Okay. So, let me go through the general questions. Uh, please share with us your understanding of affected systems cost and provide any specific instances of those costs affecting your systems.
>> Yes, we did um put together a little additional information on this. So, as the affected system operator, Duke Energy must reimburse our interconnecting customers for the actual system costs of any affected system network upgrades on our system. um the interconnecting customer will initially fund those upgrades and then once the project reaches um completion the COOD um then they will be reimbursed plus BK interest rate and FIRK allows the affected system operator a period of 20 years to make this repayment. Um but after reimbursement then Duke Energy would roll those costs into the FK jurisdictional transmission rates and those are consistent with commission policy and into bundled retail rates for North Carolina and South Carolina.
Um I can also say that we the evidence that we were able to collect quickly is that affected system costs seem to be pretty dimminimous. um we don't have a lot of evidence of very large affected system costs as Duke Energy, Carolina's or Progress being the affected system operator. Um and conversely, um it it appears that's the same in the other direction as well when there are generators on our system that may be affecting our neighbors and the neighbor is the affected system. Um it appears that the the numbers are quite small. Um it looked like in the past I think 10 years from from 2018 um it was around $12 million was the estimate that we were able to quickly put together. So um it does not seem to be happening very often that we have uh very much in the way of affected system network upgrades.
>> Okay. And and those were not part of the avoided cost calculation. Um they they don't affect the rate that we pay.
Right. So QFs bear those as Dominion said they bear those. Uh if if they put a QF in here and it affects Dominion North or South Carolina, the QF bears that cost. Ultimately, Dominion uh would reimburse them, but it doesn't affect what North Carolina is is avoiding or the cost to a North Carolina retail customer and debt and depth. So they are not considered as part of consistent with Dominion's comments, part of our our avoiding cost calculations.
Okay. In your opinion, do affected systems costs have any impact on the re or on or relevance to avoided costs? No, they do not.
>> Are transmission network upgrades cost taken into account when determining avoided costs for your systems?
>> No.
uh how are transmission network upgrade costs allocated when an eligible QF with a PPA comes online?
Um so the QFS are studied in the interconnection cluster just like any other generator and we have a combined cluster process that is both state and fj jurisdictional projects. And so if a network upgrade is identified then the study will uh calculate the contribution of the projects that are all contributing to that network upgrade.
And there's an allocation mechanism um in our interconnection procedures for how the cost of that network upgrade would be shared among the projects that are contributing to the network upgrade.
>> Okay.
What are the approximate current breakdown of qualifying facilities in North Carolina in terms of solar, hydro, swine waste, landfill gas, etc. We I'm sorry. We did not have that question in advance, but I can give you a pretty good ballpark answer. We have, you know, a couple thousand solar PPA.
So, it's the vast majority is solar, over three gigawatts of solar PPA on the system. We may have 20 or 30 biomass and small hydro, much smaller. you're you're talking, you know, 100 megawatts, not 3 gigawatts. So, that's just general perspective. I'm sorry uh we did not uh have that uh exact numbers coming in, but that that's just a general uh ballpark of the the mix of QFs on the on the system.
>> Okay. So, we got some more Ed Lib to do.
Um could you please explain the history of the peaker methods implementation in North Carolina?
I think I've been doing this since 2012 and we've used the peaker method, you know, for the last 15 years to my knowledge. You know, just as a real quick ad adlib, it's the peaker method and avoided cost, but the peaker method is essentially renamed the utility cost test. When you go into the EE and DSM docket, they look at the avoided value of a peaker for the capacity value of E and DSM and then they take the load shape of the EE or DSM with and without to get the energy. So you're effectively running a peaker method there. Um in IRP space I think uh the Dominion witness did a great job of saying you know even in IRP we would build nothing but peers because it's the cheapest resource except other resources like nuclear or combined cycles create system energy benefits that offset the the incremental higher capital costs to build those resources.
So in essence before you build a combined cycle or a nuclear plant it has passed the peaker test. It's a more economic option to spend the higher capital because you're generating energy savings on the system that offset that.
So the peaker method in my mind uh has been in some name, shape or form underpinning avoided cost and resource planning concepts for decades and is widely used uh around the country in such a manner.
>> Uh Miss Miss Farber, this is specifically for you. Duke previously stated that five-year avoided cost terms are not commonly used to finance large solar facilities in our state. Does that still remain the case?
>> Um I would say yes. We are not seeing as many um standard offer or negotiated offer five-year uh purpose facilities these days, but we do offer our solar and solar paired with storage RFP and that has a longer term um and also has additional benefits as those are controllable PPAs. Um so we are not seeing as much participation for those shorter term PPAs. That's right.
>> Are there larger solar facilities being financed in South Carolina as QFs?
Um, South Carolina offers a 10-year avoided cost rate and so we have seen a little bit more participation for those um, standard offer negotiated QF contracts in South Carolina. But again, our RFP allows for participation in both North and South Carolina. And so we've seen a lot of facilities in both states um, participating in those past RFP cycles.
>> Okay. Uh in your April 15, 2025 filing, Duke stated that approximately uh 1,900 megawws of solar Qfs are eligible for retrofit PPA renewal within 60 months. Has this number changed?
>> Um subject to check. Um I don't believe so.
I I think it would only change in the sense of where are you counting your 60 months off of. Okay. Um and so how that date shifts. So it might change marginally.
>> All right. Um would you please explain the operational control Duke intends to have over battery systems for solar QFs which renew their PPAs under their limited time offering?
>> So under this um 10-year construct, the facility would control their own dispatch. So, of course, we have safety protections as we do and communications requirements as we do with any facility on our system. But Duke would not dispatch the storage. Instead, the price signal for that facility is really based off of the avoided cost time buckets and those capacity hours. And so they would maximize you know their um revenue by charging the storage off of the colllocated solar likely at times when the solar price is cheap and then having that energy go onto the system during those capacity hours so that they can um reap the higher value and this is aligned with the system needs. Um, it also mentioned these contracts will have an ability for Duke to change which hours are those high-capacity hours in case we see a future change on our system. You know, in case these hours don't stay the same for the full 10 years of the contract, we want to be able to have some ability to improve and shift. And so, um, we could change which hours are assigned that high capacity value if needed. Well, if you're not dispatching it, what does operational control mean?
>> Um, the operational control is really more in terms of system emergency. And so we would not be sending a dispatch signal to the storage specifically. It would really be about if there's um an emergency or um some event came up on the system in which we needed to stop energy production to the system. It's um that operational control would really be more for emergency situations.
>> I'm I'm still not quite sure where we are. Is that operational control meaning you would draw power from the battery or that you would stop drawing power from the QF?
>> Um, essentially we would disconnect it from the system if there were an emergency event. So we're not going to, you know, it's as a dimmer switch. We're not going to move the dimmer switch.
It's more of an onoff switch for this type of contract. This is very different from our RFP solar paired with storage in which we do have full dispatch of the solar and battery.
>> Okay. Thank you. Can you explain the methodology underlying Duke's solar integration service charge including how it was originally developed and how it has involved across po uh prior avoided cost proceedings?
Yeah, that was um I think in uh 2018 as I said was the first evolution of that, you know, contemplated before that but officially studied and introduced in the 28 proceeding. Um and then it evolved through subsequent uh further deep dive uh proceedings before this commission with a very extensive technical review committee that looked into it. And it really did look at what are the operating reserve needs and how do they grow commensurate with growth in solar.
So you the objective function in the study was I want to keep real time reliability equivalent as I add more and more solar onto the system. To do that, you have to increment up the amount of real-time operating reserves that the system has available to respond to intermittency to keep that equivalency of a of a smooth load shape. And and so that had been studied, you know, in depth. It uses a very uh sophisticated subhourly stochastic analysis, 43 years of weather data.
uh several I'm not sure if it's exactly 43 years but several years of solar radiance data load all correlated weather correlated it runs through stochastic analysis and and so that that study uh innovative at the time now being pretty widely accepted uh in in other jurisdictions is my understanding has become pretty popular um has has really had a deep a deep history for going on eight years now uh with uh you know just an you know an incredible uh effort in terms of the the amount of uh FTE hours if you will uh expense and time of this commission and and parties here uh I think we spent hours uh in a hearing on that and that was following you know weeks and weeks of stakeholder meetings and analyst runs and draft reviews uh of that study report. So it's been a it's been a a deep dive evolution uh on that over over the last eight years.
>> Has any party proposed an alternative methodology for the SISC calculation?
>> Not to my knowledge.
>> So there were some additional questions I believe came out with the original order that we have as appendix A. There were seven of those.
Y'all have your answers for those with you?
>> Yeah, those seven we tried to I what you'll see on the slide deck is we said which which of those seven questions was being addressed in each of those slides.
So those slides were intentionally developed to address each of those seven questions. But if if there's additional questions or or color you would like on those seven questions, uh we'd be happy happy to provide it.
I think the easiest way for us to do that, let me go ahead and reread these and then if any of the commissioners have questions that they didn't feel were answered in your presentation, let's do it that way cuz I I mean there's >> that's fine.
>> There's a lot of these showing on.
>> All right. First, for a representative solar qualifying facility, given that the loss of load risk has essentially shifted to winter months, what is the expected share of total revenue attributable to avoided capacity payments versus avoided energy payments over the contract term?
>> Yes. Uh, Commissioner. Yep. So, on slide seven, we highlight, you know, the uh shift to winter uh load risk, addressing that portion of the question. And then on slide eight uh we include uh the uh representation of a 100 megawatt solar facility with its energy payment and its capacity payment based on its generation profile. Um so roughly 6% of their projected re revenue would come from that capacity payment.
>> Okay.
uh regarding the proposal to offer existing operational let's see were there this is the uh expiring purchase power agreements with limited time option for the 10-year PPA with additional terms. Uh were there any on the ground implementation challenges identified during stakehold?
>> Um one of the topics that was discussed that I mentioned on here is just the interconnection review process.
>> Okay.
Uh were the developers under these expiring PPAs expressed sufficient interest in the offering?
>> Yep. Um so CCA was supportive of this and um we have 15 sites that have approached us so far to utilize this.
>> What reporting requirements, if any, uh would be helpful for the commission to monitor implementation?
Um the plan right now is that in our next avoided cost filing we would update the commission on utilization of this offering um and make a recommendation then about whether it should be continued.
>> Okay.
Um, with respect to the avoided capacity component and given that serve v serve modeling indicates that winter morning hours drive essentially all loss of load risk, does the proposed methodology explicitly account for the effective load carrying capacity of standalone solar during those winter AM hours? And please explain whether capacity credits are scaled to dependable contribution and if so, how that scaling is implemented. mathematically.
>> Uh yes, Commissioner. The uh what I highlighted on slide eight was the overlay that we have of that solar profile. Um and the amount of solar generation that would then receive those capacity payments effectively represents this ELCC um of solar or that capacity value. Um so the limited generation that uh appears in those capacity hours is similar to the uh solar that is also available on the system during those loss of load risk um hours in our resource adequacy study. Um so they are essentially one and the same.
>> Okay. Regarding the avoided capacity proxy, does 1 megawatt of incremental solar generation allow the companies to defer or avoid one megawatt of combustion turbine capacity additions under current winter peaking conditions.
This one is also on slide eight uh where I discussed in our planning process uh >> uh taking that ELCC that we calculate through our own ELCC studies and and working with uh the power gem the uh the serum modeling uh consultant uh calculate what that capacity value is.
It's effectively 2 to 3% of the name plate capacity of solar gets uh attributed as firm capacity. So a 100 megawatt solar facility would only cont uh contribute 2 to 3 megawatts of firm capacity to our system um in our planning process. So any solar that would be on our system projected to come onto our system over the coming years or out further into the future is only credited with a very small portion of firm capacity and the rest of that having to be made up in our planning process by other firm capacity resources.
Uh with respect to avoided energy component derived from production cost modeling, how are incremental cycling ramping inefficiencies, startup shutdown impacts and maintenance burdens on the thermal fleet captured?
Yeah, we touched on that on slides I think five and six where we talked about um the solar integration service charge.
some of that there is uh start costs in the model both in in encompass and in servum start uh ramp costs uh ancillary service costs that capture that uh that cost and uh it's it is captured in the energy rate uh both as we talked about in reduced uh uh energy value that gets attributed to uh having to have more of those costs on the system if you're having to follow load more.
And has the avoided cost analysis examined multi-day, low solar or extreme winter events in which dispatchable resources must operate continuously to maintain reliability?
And if so, how are those operational realities reflected in both the avoided energy and avoided capacity components?
So yes, it does incorporate that in in energy as you can see in our our rate schedules. For example, uh you you take into account not only the dal pattern of solar it being available less hours in the day but there's a higher probability of cloud cover etc. That that goes into our solar profile that goes into our base modeling. you have longer days in the summer. In the um the loss of load probability, loss of load expectation model that uh witness quinto uh was discussing. It has those uh several years of actual solar output that reflects the arradiance not only from the dal pattern but the radiance uh variations that can uh come through cloud cover and that's all correlated uh in the analysis when calculating the the loss load risk. Okay. And then the last one was taking into account ELCC integration impacts and winter reliability dynamics. Do the companies believe the proposed avoided cost rates, both energy and capacity, fully reflect the incremental cost the utility would otherwise incur? And if so, please identify specific modeling elements that demonstrate that conclusion.
>> Yes, I I think um you know what we've demonstrated, Mr. Quinto did a nice job of just explaining, for example, that only two to three megawws of of solar is being credited. So in our in modeling that we do, the value that's attributed to solar is is almost exclusively the energy value uh that's attributed. So we're not we're not in our modeling assuming solar defers capacity and then in reality having to go out and purchase capacity that was assumed to be deferred. We are not crediting solar uh with capacity. That's on the capacity side. uh on the energy side whether it's in avoided cost rates or in our IRP modeling we take into account uh all the variables that were in your question in terms of the ramp rates the intermittency the coincidence uh with high load low load periods uh recognize you know those costs in the in the energy value that's contributed uh as appropriate uh for solar so we capture it both on the energy and on the on the capacity side and and are not over ascribing uh value a as a result of of those uh characteristics and so on.
>> Thank you sir. Are there any other questions from commissioners?
Commissioner McKissy.
>> Um just a couple of questions and uh Mr. Snder, I think you touched upon it in your original comments talking about the solar integration service charge and you talked about the involvements of a strappy and brattle group and three national labs of public staff and other stakeholders. But can you get into more detail about the time frame over which those discussions occurred, the level of specificity that occurred during those discussions and how um the recommendations came forth as they did and whether that was a more or less a consensus at the time.
Yeah, I'll give my first shot at that and then if Quentto wants to jump in on any of that, but uh being the grayest hair on the table here, I probably have the the longest memory on this one. Um you know, like I said, it was in the original filing, we did not have the technical review committee, but it was because of the uh climate at the time and the innovative nature of a solar integration service charge. sort of standard hat now, but back then it was a novel idea to have a separate technology specific deduction in the energy value. Um there were hundreds of data requests asked of Estra and the company. Uh there was lots of technical debate amongst interveners, the public staff, the company, the company's consultant. Um it was a very complex proceeding. The commission I think saw some compelling arguments on all sides uh and uh mandated in that order that the next time you come forward do this with a broader oversight of this technical review committee that uh Brad sort of chaired with the company its consultant uh national labs and experts brought in from the interveners all uh opining on that. uh there were multiple several hour meetings uh in between uh development of that study where issues and technical results were looked at, evaluated, discussed. Um at the end of the day it was maybe I wouldn't characterize as 100% but consensus but there was a lot of consensus uh developed I in that technical review committee process that led to the next filing of the solar integration service charge and the subsequent uh avoided cost filing after the 2018 filing. So, uh I do recall sitting in in multiple multi-hour meetings uh and having a lot of technical experts uh from around the country uh debating uh a lot of sticky issues and a lot of this is high level math and a lot of it is just conceptual.
It's just the right framework and approach to that concept. And so you can imagine with you know multiple PhD types and national labs in the room there's a lot of opinions to work through but it was a it was a very intensive process.
Um I think it led to a constructive outcome. I I knew just uh you know the amount of time and effort uh was was extensive and so it um you have to approach those things very carefully because it was very uh it was good to come with those outcomes but it came at a pretty high cost. It took the time of the public staff, a significant amount of time and effort. Took many resources within the utility and the interveners at at fairly great expense uh to to come up with this. So, it's something that, you know, in hindsight I I think was was very good, but it came at I don't want to underestimate the the toll it took on everybody to to get to that result.
>> And and you talk about the time it took.
Could you be a little bit more specific over in terms of what that time frame looked like knowing that it's impossible to determine the number of hours since it was an exhaustive process but the number of of months that it would have taken to have uh gone through that?
Yeah, it was I think >> o over a year.
>> The uh >> gone.
>> Yeah, this uh the we were ordered to do this for uh sub 175. Uh the technical review committee uh began meeting in March of 2021 and issued their report in August of 2021 uh just prior to us filing our avoided cost filing for 175 in November of 2021. Um so it was a monthsl long process for this technical review committee to meet to talk about the methodology to understand the perspectives of all the stakeholders involved from national labs to solar developers and the public staff and the the companies themselves um to develop this methodology. The report is fairly comprehensive in terms of all the items they discussed. uh it includes comments from um stakeholders that specifically had um uh comments on the report uh as well. Uh so very in-depth process, a lot of manhour as as Mr. Schneider mentioned um and reports to uh you know document what was discussed and what was determined in that uh review.
>> And I guess a followup is this. I I understand that that based upon what the public staff has indicated as well as some of the stakeholders and other groups uh and even Duke you're looking at potentially revisiting kind of an assemblage of that type of group to move forward in terms of recommendations beginning I guess looking at next year's cycle for avoided cost. Is that correct?
>> Yeah. I I want to be clear we're not recommending reconvening a technical review committee. Well, maybe you could be more specific about what you do in >> we are, you know, thinking about re-engaging um the consultant who's no longer a STRA um power gem uh to basically update the approach and the process that the technical review committee agreed upon.
Uh again, in hindsight, you know, we didn't know where these were going to go. We didn't back then in 2018, you know, you thought solar was going to go through the roof. You weren't projecting the amount of storage you had on the system and you thought gas prices were going to be really high. So, it's like how high can this, you know, solar integration ser, you know, charge go. I think we're still adding solar to the system, maybe not at the rate we thought we were back then. Um, gas prices didn't go to where we thought they were going to go back then. And now that we have storage on the system, you know, we don't see this huge upward pressure that maybe we thought. Um, so when you look at, you know, the the impact of that integration service charge, you've got to ask yourself, you know, how much effort do you refine put into refining that number? Uh, if if it's not going to be largely material, it's important, but is it, you know, moving the IRP? Is it moving avoided cost rates in a in a big material fashion? Um, you know, it's not our expectation in this environment, just knowing what inputs drive it. Um, so yes, we're committed to updating that that will get reviewed by public staff and interveners. Uh, we envision using the approach that was agreed upon in those very extensive processes. So, we're we're not envisioning a a big change in approach, but I just Commissioner Mc Mckis, I want to be very clear. We're not uh we're not looking to go back down the path of getting national labs involved in all of that this time next time around.
>> Thank you for that clarity and knowing that that's still going to be a pretty timeintensive process uh what you're proposing and and what's how long do you think it would take before those recommendations come forth knowing that we have deadlines for next year as well? Yeah, I think at this time um subject to check, you know, we we believe they'll be ready in time for the next avoided cost filing is, uh our current plan for updating the SISC.
>> All right. And of course you mentioned the impact of battery storage and of course in the recommendation that's coming forth at this time is that these existing facilities if they're willing to put in the additional storage that's been identified that that that would be qualifying them to get these new 10-year contracts. Now, I guess the question I have in my mind is what impact do you think that proposed storage at the level has been recommended this time would have upon the system and and how that would benefit Duke at this time?
>> Yeah, I think I think it's a good thing to give the option to that. Uh, you know, I want to put it in perspective though, right? um 40,000 megawws, you know, by the time we get out in time system. Um we're talking approaching 10 gigs of solar, 5 gigs of storage.
The program Miss Farber talked about what I think you said 12 to 15 participants expressed interest in adding a battery.
>> Yes. So far there've been 15 participants. So it's relatively modest.
>> It's going to be a relatively modest amount of storage uh for these that are Most of the storage on the system is charged by the system or the solar, you know, coming off the system, putting back utility dispatch rights. This is unique for legacy QFs where they they are just going to charge. I think it's a good thing because it's going to move uh the one slide I showed without storage, you can see solar continues to come in in hours that as both I and Mr. Quento showed are not aligned with our capacity needs or our highest energy period. You put a battery in, you're going to take the portion of your solar that you would otherwise have put to the grid. You're going to put it in the battery. Then you're going to, as Miss Farber said, you're going to dispatch that battery economically at the most valuable times.
And so it's going to shift that solar production into times that have more value. Um, so even though we don't have full dispatch, given the the scale being relatively small compared to our our system, it's moving in the right direction. It's sending the right signals. It's moving energy to periods where we need it more and it's, you know, being priced appropriately. So, I think it's a it's a good thing.
>> Just to clarify, I think when Mr. Snder was talking about the impacts of storage on the avoided cost calculation, that was more of a systemwide resource planning.
And then separately we have this offering.
>> Yes, >> the existing QFs to add storage that will likely be a much smaller quantity.
But thinking about our resource plan and not only the existing standalone storage on our system, but future energy storage on the system, um that would be part of the shifting um calculation for solar integration service charge.
>> Yeah. Yeah. Yeah. Thank you for that clarity. It was the way I was interpreting it, but it's good to have that clarity in the record. And and and I guess lastly, how important is administrative simplicity and predictability u in designing perpa avoided cost methodology?
Um particularly given the diversity of technologies and operating characteristics that may qualify as QFS.
>> I would say that's been an issue in in several cases. Again, um the one graph I showed is we really don't have um standard offer rates being taken very much. It's it's really the market has migrated to the longer term contracts under competitive procurement. But even in those competitive procurement that Miss Farber runs, um, you know, the standard contract gets a lot of debate and and eyes on it in the stakeholder process and then is ultimately presented to the commission and having it be in an administratively understandable, implementable has has been a whether it's in standard offer rates or in in uh procurement contracts has been an issue that's that's been pretty important.
before this commission for for over a decade.
>> And lastly, I know this uh solar integration service charge is something that this commission is seriously, you know, looking at in this particular avoided cost proceeding. Is there anything that you've not been asked by Cher Broly or by myself that you believe would be insightful that you'd like to share in terms of our uh consideration of what it costs moving forward in this particular hearing?
>> No, I I think we've we've covered a pretty broad ground on this in this hearing. I would say you know just it you can get lost in the weeds in the complex math and stochastic analysis and all that but but essentially it's you know how much operating reserves do I need additionally because of solar and then what's it cost to carry them right um and so that's what the solar integration service charge is really trying to to capture there's a couple of core drivers so you can really simplify it and I think we've done a good job uh between the conversation we've had in in hitting hitting the highlights on that.
>> Well, let me thank you collectively for your testimony this morning and more importantly for the institutional knowledge that you have from all the experience in working with these issues over the years.
>> Thank you, Commissioner.
>> Commissioner Tucker.
>> Thank you, Chair Broly. Uh folks, I I'm going just ask a couple of questions just to bring it down to my understanding.
Um, Dominion uses the peaker method. You use the peaker method. If you were to take your um, operational and weather characteristics and put those all the formulas together, the payment to the QF, would it come out the same uh, with Dominion and with Duke?
>> There there's some differences. again PJM uh they're a little further north and Dominion when they showed and you know a lot of similarities in methodology but due to system differences you get some different results when applying the methodology so their loss of load risk for example still has summer loss of load risk where we do not so they pay for some amount of capacity for contributions in the summer at this moment in time I remember back in 2012 we were 100% summer. You know, it's it's only been in the last decade that we have migrated and and for a few years we were both. We were summer and winter and then we went to all winter.
And so history could repeat itself. We, you know, not saying it's impossible for us to start seeing summer in the future if something different happens, but Dominion currently has summer. We don't, we apply the same approach, you get a different result. So there are different results, but but similar approaches.
Okay. Um, we have had uh a briefing in March, end of March. We've had a briefing um internally uh in the last week or so on avoided cost. Um and then internally and externally we I have heard um that Duke overpays the QFS for their value um at peak times that they're utilized for whatever reason that the way the method and the calculation of the payment to them for their value of being added onto the system.
Does that have any relevance to what we're discussing this morning? Do you overpay? Are you underpay?
Where does that comment uh lead us to in discussion? Is that real or not?
>> I don't believe it is. And I think it's um when you go through what we just presented today, >> right, >> I think there might have been a perception that hey, you're you've got to double pay. You got to go buy the capacity because you paid solar for capacity and then it's not there at time of peak. So you go out and you build a peaker or combined cycle. Now you're paying twice.
And I think what Mr. Quinto just showed is how we do it in avoided cost and understanding that now most of it is the capacity values being attributed starting with the IRP and the IRP process which will be in front of you in a month. um less than a month on coming through uh the competitive procurements even there the IRP gives as Mr. Quenta said 2 to 3% ELCC value. So solar is getting selected for its energy value not its capacity. When it's getting selected it is it is providing energy benefits. It's reducing gas demand on the system. Uh it's part of a diversified mix. We recognize within the within the IRP uh framework that we're not getting capacity value unless there is storage on the system and then storage is providing that capacity value and even that has an ELCC equivalent so storage doesn't even get a one one it gets a reduced so you know we are taking all of that into account and I think some of it's a perception that we're not and so what I was glad to be able to do today was have our panel present to you and show that that we recognize the value but we also recognize the limitations of solar and we you know we have been for more than a decade endeavoring to pay whether it's in avoided cost space or whether it's how we value it in IRP space to pay that appropriate price for solar only for the value it creates no more no less >> okay thanks sir that's all I have Mr. here, >> Commissioner Vandervart.
>> So, I got a couple of questions. I mean, just on that issue though, you could if you were to calculate a capacity, avoided capacity using the ELCC directly, not just to develop your windows like we were talking about. And you just simply multiply that that ELCC times the name plate. uh you know have you all made that calculation because that is done some places.
>> Yeah. So I think context is really important here, right? So that's exactly how an IRP model works.
>> Sure.
>> Just what you've done. IRP uses generic CT, generic CC, generic solar, you know, generic battery.
When you get into execution like QFS, they're they're getting making real projects. They're getting commercial payments. They're taking out debt. This is each solar project it sells for example has a different ELCC. Some solar is dual axis tracking bfacial with a 1.5 DCAC over panel ratio. Other solar is fixed tilt 1.2 no bfacial. So that one would have this ELCC, this one would have that ELCC. Well, oh, I've got a different shade of gray. mine, you know, I got white rock under mine. I get better reflective than that guy with gray rock. So, I want a different ELCC.
So, the beauty of the way as presented is here's when it's valuable. You figure out the technology. If you can make it run in the nighttime, I'll pay you for it. But if it doesn't, I won't. So, and if you're a solar QF, you you don't get it. But if you're a a hydro or a co-generator and you can, you do get it.
So it makes the commercial implementation on a financial contractual basis much more straightforward than it would be to try and implement an ELCC in a commercial environment where there's contractual payments involved.
>> But those those differences you're talking about PR mining when we're talking about a 1 to 2% ELCC anyway.
Just for just for back of the envelope, if you did calculate that out, how would that compare with the methodology that you're using, the peaker method, where you're paying for a volutric amount of electricity at at a rate that's five times the energy rate.
>> So, I'm just trying to get, you know, ballpark.
>> Yeah. I think what Mr. Quinto was showing is um the solar gets a dimminimous fraction of that capacity value which is what they would generally it'd be generally aligned with if we just paid them on an ELCC. If I give you that out of all that you know 41 what was your number there on total revenues if I was round the clock?
>> Yeah 41 million for >> 41 million of total revenues for an aroundthe-clock generator. Solar's getting 600,000, not even one million.
So, it's just a tiny percent of the total revenue that Solar's getting paid and that equals a tiny percent of the ELCC. So, the two align. We're not paying them as though they're a a dispatchable full capacity. We're giving them a fraction in this structure that lines up with the ELCC value that's used in IRP space. You're only you're only giving them a a little bit of money because they only generate a little bit during that period.
>> That's right.
>> You're giving them a very high rate, a five times energy avoided energy rate.
And I and we're talking 1,900 legacy megawws, right? And so all I'm asking is what is there a difference that's if you multiply it by 1900 that would save the rateayer any money? I mean, I get it. It's easier to do it this way. My question is is have you calculated out and do you have an idea of if it's higher, lower, same?
Have you actually calculated?
>> If we took the ELCC of solar, multiplied it times the carry cost of a peaker, would it generate about the same costrevenue as this? I think we're in the same ballpark. I we didn't do the exact math to say am I >> 10% more? Is it should 600,000 be 660 or 540? But it's out of the 40 million it's not going to be 600,000 should have been 8 million or zero. So it is a relatively small number to start with and it might be a small difference of that small number in the first place.
>> I I mean I ran it and it is it's not insignificant. Um and you know again you're using the same advanced class CT as your avoided cost, right? If you use that, it it'll it'll make a difference.
>> Net of net of the net energy benefit.
>> Yeah. Let me move to to one other thing before I go to the avoided energy costs and that's where you use your SCSI. Have you ever looked at the Dominion folks?
They allow the they use a market type driven cost for that. How do those compare? because as we discussed with them there is you know I don't agree that SE SI captures everything but the market certainly captures it all right in a in a pretty large market like that have you ever calc you know taken a look at what those numbers might the range of those numbers versus the number that you're actually building up you're building up using a um this combined cycle uh and then you're discounting it by the SCSI which is a pretty small number right now and You're so that's how you're getting to your rate. He's letting the rate Well, you can average it. You can let it float.
>> I'm just trying to get again what's the, you know, are they are they close? Are they different?
>> The big difference and and I wanted to clear up one thing on that. It it that when it comes to energy, it it has nothing to do with the H frame. It is it is the marginal energy on the system, right? And so the difference in the five-year rate is we're saying here's a projected value of of five years with five years of of market. And this was also a big issue over the last decade is how do you come up with your future fuel prices. So we used take five years of market gas prices. We run it through the IRP models and we say what's the marginal cost of energy with that five-year projection and you average and fix that rate on a levelized basis. The Dominion approach, which has been enabled by FR 872 in 2020, says rather than paying a fixed payment based on a five-year projection, there's two big things. It's it's market, but it's as available in real time. So, I'm no longer on the energy side. And and I think their council correctly said in in 8 in 872 you you are obligated to pay fixed capacity but since 2020 you can now pay floating energy essentially but you still have to pay fixed capacity. the floating energy.
Um the biggest thing is is your projection like right now with five years of natural gas is I don't know 350 Henry hub 370 something like that. You know am I going to see real time gas prices come in at 250 or $5. So you're one's a a fixed price one's a variable and gas can change every day. So the Dominion approach is going to be really good for customers on $2 gas, but you're going to pay the QF on that $50 constrained zone 5 day. You're going to pay the QF $500 a megawatt hour because it's going to be floating, right? So it's a fix for float. Probably the biggest difference between Dominion and us that would present a challenge for us is they're in a market with a with a published liquid LMP prices. ours would have to be internally calculated based on on marginal cost. Uh and there's just an administrative difference to pointing to uh market LMPPS versus internally calculated marginal cost which we do use in other proceedings for other pricing mechanisms. So going and we wouldn't be locationational based our we don't do marginal cost by nodes on our system. Um where the Dominion witness was saying they would align it with the closest PJM node. Ours would be a system average marginal cost and it's something we could could consider post872.
Um but we would have to overcome those those barriers of are we going to do a long run average price or do we want to do a floating price that's then pegged to a internal marginal cost >> and I'm not asking to change I'm I'm asking you simply if you look at their actual numbers how do they compare you know anytime you put together a using a modeling approach to try to establish a number you know it's always good to look at another a totally different way of arriving at the value of that number and the and I'm not saying use what the do what the union does in terms of their avoided cost but look at the data that that he's looking at and just try to I know I get you it's it's dynamic but it is the real cost for avoided energy the real deal so take however long an averaging period you want how does that compare with your number that you construct and then subtract that small SCSI from to come with a number that you put in a in a in a in a contract for 10 years, right?
>> Right.
>> How does that compare? Have you done that?
>> Um I think this is the first time they're doing it's forward looking, so it's going to be it's really will there's no history with this to to do it. They're just proposing this. They used to use the same method we did. So this is the first time they've went to a floating price, >> but you can get the price. You and I Yeah, we go get the historic >> go backwards, right? You can go backwards. And I guess what I'm saying is look back a year. look back two years. How does that compare with the 10-year number that you know you're looking at? That's all just as a kind of a check on the SCSI as as much work as went into the SEI. You know, I grant that >> the real number now, you know, I'm not arguing about how practical it is to use the Dominion. Uh I'm just simply how does that compare? Is that a D, you know, are we are we in the right ballpark or is it something different? I guess have you done that? We have in the past we have sort of looked at that and we've considered it and what we found in the past when we looked at it it's whenever you it's more dependent not on that methodological difference as much as when you snap the chalk line.
>> How about this and let's let's just move on. How about if you send me a one-year number out there and a two-year number and compare it to your proposed avoided energy cost with with the SEIC discount.
Does that make sense?
I think so. I might need to clarify a little bit after, but yeah.
>> Does that make sense to you, Mr. Quenton?
Or >> five fiveyear rate or a 10ear rate?
>> Okay. Give me a one year, two year, fiveyear just just to give you a I mean averaging time that matters. I don't think after we go to two to five is going to change a lot. But my point is I just want to see what the actual number average however you like to compare to the number you construct. That's all.
Okay?
>> No big deal. So >> we'll figure something out, >> right? You can always ask. Um, so we go around the state and we get a lot of people come up to us and say, you know, why aren't, which is I think you pointed out right at the beginning, why are we just building more solar because it's the cheapest power on the grid. So why don't we just keep building solar?
Um, I'll let you ask that answer that.
>> Uh, Commissioner, that's not really the topic we're on today. exactly the topic we're going to get to.
>> Commissioner, no, we're not going to talk about how much solar. We're going to talk about avoided cost. That's what we're dealing with today.
All right, I'll start a little bit later. Let's try this.
We've got two deserted islands, want to develop them in a res as resorts.
One person goes to the island A and he's been told solar is really cheap. He just builds nothing but solar.
The other guy builds so uh nothing but gas. He just puts gas in in the ground.
Okay. The first year the the investments are zero in island A. And so he's figuring out now I got to go add some battery. So he adds battery and that improves things a little bit, but the lights still go out at night. And so finally he adds gas.
So and now everything's fine. Now, which system can sell electricity for less? It's going to be the pure gas system, right?
>> Commissioner, I want to ask you again.
Can we stick to avoided cost?
>> I'm I've just set the foundation. I'm going to go to avoided cost right now.
>> Okay. I'll give you just I'll give you a little leeway.
>> Thank you. So, let's go to your let's go to your uh your deal, your 10-year deal. In that case, you are giving the same the deal is you get a 10-year rate, but we're going to give you and we're going to give you the same avoided cost, the same avoided uh energy cost, same avoided capacity cost for 10 years as long as you have this battery component. Is that right? Do I have that right? Um yes that's the proposed offering for adding storage to an existing facility.
>> So in that case you are including or you're not but you're implicitly requiring the QF to include in his business model the cost of firming backup the batteries. He's going to he's going to eat that, right? He's the one who's going to have to pay for those batteries over the 10-year contract. Is that right?
um they will pay for the construction of the batteries on their facility. Is that what you mean?
>> No, I mean they're to for them to stay in business, they've got to calculate out that the amount of money they're going to make over their 10-year contract is going to pay for their operation and for their investments in the batteries. Is that right?
>> Sure. They'll they'll evaluate their business opportunity. So in that case the cost of firming although it's only partial you've you've told them to take that into account >> essentially because that's the deal.
>> So when you say firming um if you mean in terms of if they would like to avoid the solar integration service charge that is one way that they can operate their battery that is added to the solar facility.
>> Well they're also going to get paid more for generating during the the peak area hours right. But I'm just saying >> by shifting the energy the capacity hours. All I'm saying is is that in their business model, they've got to include the cost of those batteries.
>> Uh yes, they would include the cost of constructing their batteries in their business.
>> Okay. And now and and typically, do you include the cost of firming when you're looking at your solar when when we when people say, you know, it's cheaper than anything else, you're not including that that firming. Is that right?
No, we're we're not we're not including but we're not charge we're not valuing it based on I think it's a double negative going on here, right? So when we say does it make sense, we're not assuming it provides we recognize that the solar itself is not going to avoid capacity in avoided cost and in IRP. So to Mr. Quento's slide and and some of mine is so we're we're not including the value we're only including the value predominantly of the energy that it provides and we say is should we select solar or should solar elect to be a a QF they're getting paid largely for just the energy and that's how we value it in IRP as well. So that and so that's where I get to the point of the avoided energy and the avoided energy you have that SESI discount but it doesn't include the cost of firming that the rest of the system has to provide. So in other words am I right about that? I don't think you do >> yet. No it it is it is simply to say what's the extra cost for intermittency >> for the inter hour. Yeah.
>> All that stuff. And so what I'm saying is over here your QF guy who's going to sign up for the 20% BS bees, they're going to be eating that firming charge even though it's only partial, but they're they're eating that, right? But when you when you're looking at the avoided cost, generally you don't take that firming uh into account. Is that safe to say?
>> Yeah. When we look at the avoided cost, we just say what's the value at in each hour and if it provides it, it gets it.
If it doesn't, it doesn't. So, it's not really including or not including the firming cost. It's simply saying if you can firm, you get more money. If you can't firm, you don't. And so, you if you can, like Mr. Quinto slide showed, you can be more expensive and and make a business case. You can have a $ 38 million a year facility as long as you can produce in every hour and you're going to be able to make money. If your solar costs 38 million, you're not going to sign up for avoided cost rates because what he showed is you're only going to make nine million in revenues.
So it it's more of you providing the value. If you're not providing the value, you're probably not going to sign up for our rate. So, you know, each QF is going to sign up based on how much of that value they can create. And someone that can firm can spend a lot more.
someone who can't firm can spend a lot less because we're only paying for value you create.
>> Okay. Thanks very much. That's all.
>> Thank you, Commissioner Ga.
>> Thank you, Chair. Just a couple of questions. Uh I think you kind of touched on this, but remind this commission when in your proposed tariffs when the SA SISC does and does not apply because I think it comes for particular types of resources, right?
It's solar only and all solar gets charged in SISC. They have an ability uh which no one has elected to do yet which is if you install a battery not just to move energy but if you then use that battery also to smooth out pertabbations and subhourly and get back to a smooth load shape you can forego the SISC. We haven't seen anyone elect to do that.
They just elect to pay the S take a reduced energy payment. So it's and it's only it's for solar specific.
>> Okay. Okay. Thank you. Um c can you remind and you may have touched on this but reminds commission as to when you get into the capacity payment side of things um uh and this might be your construct or more so pera but why capacity is paid on a megawatt hour basis versus say a megawatt day or something along those lines.
>> Yeah. And I think that you know being a this isn't a solar rate right? We tend to think of it like that because solar dominates the QF market. It's a technology agnostic rate.
>> So what you try and do is you you spread capacity value over when it creates that value and therefore different technologies like maybe hydro can't even get all of it because it doesn't run the small hydro facility can't run the whole period. So maybe it gets 50% of the capacity value. Maybe I've got a co-generator that has a questionable outage rate and it can only produce some of the time. It gets its proportional.
Solar gets its proportional, which as Mr. Quinto showed is a tiny percentage.
So, it's a rate structure that is administratively um applicable to all QFs without having to have a solar specific rate sitting over on the side. And then you start getting into if you had a solar specific rate because we looked at that years and years ago, you start getting into who's solar because there are and it does well small differences. It makes a lot when it's revenue based. It might not in big IRP space, but you know what what type of solar is my solar? Is it tracking? Is it not tracking? Is it heavily over panled? Not is it bfacial? Is it not?
and and so it becomes difficult to have a a solar specific rate that drives revenues if that solar doesn't match your solar. So getting into a specific rate presents administrative and and and sort of regulatory, legal, financial challenges as opposed to a more general applicable rate. So the reason it's spread is so that it can apply to any QF and it's you create value, you get paid for it, you don't, you don't. and it's technology agnostic when it comes to capacity.
>> Okay. Well, one more question. Um are are uh and I want to be clear. I am I'm going to I'm going to say these words and then not say them again. Um, I'm not uh bringing up net metering here, but are retail customers, for example, residential or business customers, are they able to utilize avoided cost rates, say if they install rooftop solar, if they want to sell the entire output of their facility to the to the Duke system.
I think at one time this was known as a sell all sort of arrangement. I'm just curious if that is still uh something allowable. We'd have to double check. I do believe schedule PP allows for that.
I'm afraid I'm misspeaking. So perhaps I >> we'd have to get back to you.
>> Okay. I'm not sure.
>> If you did some late file, that'd be great. But yeah.
>> Okay. That's all I've got.
>> At this point, I think our job here is done and we are adjourned. Thank you.
>> Thank you, commissioners.
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