Commissioner Allison Clements Statement
February 28, 2022
Docket No. ER22-682-000
I dissent because it would be more appropriate to reject Duke Energy Progress (DEP)’s proposed rate without prejudice, rather than accepting, suspending, and setting the rate for hearing.
This case raises an important issue regarding how rates may be calculated as system resource mix and demand-side usage patterns change. Here, in response to a customer’s current and planned use of energy storage and other demand-side resources, DEP has proposed a rate formula that depends upon that customer’s demand both at coincident peak and non-coincident peak times throughout the year.
I agree with the majority that DEP has failed to demonstrate that its proposed rate is just and reasonable,[1] and I also agree with the majority that DEP has put forward evidence that its currently effective rate may fail to appropriately align costs with beneficiaries given the changing operational conditions on DEP’s system.[2] But I would reject the proposed rate modification without prejudice rather than accept and suspend it because, in the face of demonstrably inadequate evidence put forward by DEP, the Majority Order sets too low a bar for the filing party’s proposed rate to become effective as the hearing process moves forward.[3] At minimum, a five-month suspension period is warranted in this case to reduce the risk that North Carolina Eastern Municipal Power Agency (NCEMPA) is unable to recover refunds in the event the Commission ultimately finds that the proposed rate is not just and reasonable or unduly discriminatory.
There are two critical deficiencies in DEP’s proposal. First, DEP has failed to demonstrate how its rate proposal “reflects [its] transmission planning.”[4] DEP’s arguments regarding the lack of value to its system of NCEMPA’s demand-side measures are at odds with the rate it has proposed, as well as the structure of the Restated Full Requirements Power Purchase Agreement (Amended FRPPA). DEP implausibly asserts that it derives “little if any system benefit” from the demand-side tools and resources deployed by NCEMPA because “DEP cannot rely upon them,”[5] while proposing a rate that is inconsistent with this assertion. DEP does not explain how it will be able to rely on NCEMPA’s use of demand-side resources if NCEMPA uses them to reduce both the coincident peaks of the system and NCEMPA’s non-coincident peaks,[6] yet under its proposed rate such usage would reduce NCEMPA’s capacity charges.[7]
While hypothetically possible that DEP’s cost of service to NCEMPA customers depends on both their usage at coincident peak and non-coincident peak times,[8] DEP has thus far failed to demonstrate this to be the case. A coherent theory as to how the proposed charge relates to DEP’s costs is important because without this, NCEMPA has little assurance that DEP will not seek and receive approval for another rate change as soon as NCEMPA members make demand-side investments that respond to the new rate. Were the Commission to approve DEP’s proposed rate such that NCEMPA begins reducing both its coincident peaks and non-coincident peaks in response, will DEP not subsequently assert that these demand reductions cause NCEMPA to pay less than its fair share of serving the system, as the logic of DEP’s pleadings suggests? If not, why not?
Second, DEP fails to adequately “explain[] why, if customer [non-coincident peak] demands truly are a capacity-cost driver for DEP, they are not the basis for allocating demand-related capacity costs to all DEP customers.”[9] While different capacity rates may be appropriate for different customers where such customers are truly differently situated, DEP has not (1) provided a rational theory as to how its costs to serve NCEMPA depend both on reducing coincident peaks and non-coincident peaks, while its costs of serving other customers do not, and (2) put forth adequate comparative evidence to support such a theory demonstrating NCEMPA to be differently situated from its other customers with respect to the drivers of transmission system planning costs. As the Majority Order notes, different DEP customers have agreed to different rates.[10] Structural differences between NCEMPA’s contract and that of other customers are not necessarily unduly discriminatory. But this basic fact does not lessen DEP’s burden to demonstrate that the different rates between its customers are justified rather than undue. And while different wholesale customers have different variations of coincident peak rates,[11] the proposed rate is unique insofar as it positions NCEMPA as the only customer with a rate dependent on non-coincident peak usage.
Underlying both of these deficiencies in DEP’s filing is a feature of capacity planning that is underexplored in DEP’s submissions to the Commission: how the need to serve NCEMPA (or any other customers) at non-coincident peak times contributes to DEP’s costs.
As DEP describes, public utility transmission providers historically focused on planning only for a single coincident system peak because “utility analysts thought that production plant costs were driven only by system maximum peak demands.”[12] More recently, some public utility transmission providers have shifted to a 12-CP methodology based on demonstrations that, due to changes in planning practices and the resource mix, the need to address coincident peaks throughout the year is now driving system costs.[13] DEP has put forth evidence that its planning practices are evolving in response to changing system conditions and North Carolina’s public policies, averring that it must consider system constraints across a range of different times throughout the year.[14] But it does little to show that DEP must incur costs to provide capacity at NCEMPA’s non-coincident peaks, or that it achieves cost-savings from reductions to coincident peaks only if NCEMPA’s non-coincident peaks are also reduced. If NCEMPA’s non-coincident peaks occur at times when DEP otherwise has excess capacity, for example, then it is not clear how a rate that reduces NCEMPA’s charges only if NCEMPA employs demand-side measures to reduce both the coincident peaks and its non-coincident peaks would be reasonably connected to the cost of serving NCEMPA. Are there local transmission constraints or other reasons why DEP would have to invest in new capacity or retain existing capacity to serve NCEMPA that it would not otherwise need?
As the hearing process commences, I urge DEP to re-examine whether it may be able to derive some value from NCEMPA’s use of demand-side measures, both in reducing coincident system peaks and non-coincident peaks, and to put forward a clearer description of how its proposed rate reflects transmission system planning. I also urge DEP and NCEMPA to explore with greater resolve whether enhanced coordination measures may be deployed in a manner that enhances this value. Practices of other utilities and grid operators may be instructive in demonstrating how demand-side activity can be deployed and predicted in a manner that reduces costs of serving the system. To the extent that DEP fails to adopt load forecasting or other practices that would allow it to derive value from NCEMPA’s demand-side measures and this matter proceeds to a trial-type evidentiary hearing, the presiding judge should assess whether a rate premised upon such failure is just and reasonable and not unduly discriminatory.
To be clear, I adhere strongly to the view that rate suspension and hearing procedures can be an extremely valuable tool to sort out disputes of material fact. A filing party need not have fully supported its proposed rate in order for this process to be warranted, or else it would be of little use. But given the circumstances of this case and the likely consequences that initiating this hearing process creates, I believe DEP has failed to provide adequate support to warrant the Commission taking this step. While a rate may be just and reasonable and not unduly discriminatory without a precise match between charges and true system costs, and a hearing process can be used where material facts remain in dispute, a basic floor before accepting and suspending a proposed rate in this context should be that the filing party puts forward at least a general theory for how the proposed charges match costs, as supported by accompanying evidence. DEP has failed to do that here, instead principally relying on an argument that is at odds with its proposed rate.
The consequences of today’s order may be significant for NCEMPA members. With the Amended FRPPA thrown into uncertainty, NCEMPA members may find it difficult to contract with demand-side resources capable of providing value to the system, until the hearing process is resolved. And to the extent that the hearing process stretches beyond the 15-month refund period,[15] NCEMPA risks being subjected to unjust and unreasonable or unduly discriminatory charges without any recourse. Given DEP’s failure to put forward a reasonable theory justifying its proposed rate, I cannot join an order that risks these consequences.
For these reasons, I respectfully dissent.
[1] Majority Order at P 46.
[2] Id. at P 42.
[3] Rejecting DEP’s inadequately justified proposal would not curtail its ability to change the status-quo rate, to the extent that rate is demonstrated to in fact be unjust and unreasonable. DEP would retain options to (1) file a complaint under section 206 demonstrating the current rate to be unjust and unreasonable, at which point the Commission would have an obligation to fix a just and reasonable and not unduly discriminatory replacement rate; or (2) file a new rate proposal under section 205 that adequately demonstrates that the new filed rate is just and reasonable and not unduly discriminatory.
[4] PJM Interconnection, L.L.C., 169 FERC ¶ 61,041, at P 53 (2019), order on reh’g, 172 FERC ¶ 61,054, at PP 33-34 (2020).
[5] Filing, Transmittal Letter at 10. NCEMPA demand-side measures that DEP asserts it derives little if any system benefit from include “Energy Efficiency Measures,” “Demand-Side Management programs,” and “Demand Response.” Id. at 9-10.
[6] DEP witness Harold James does assert that if NCEMPA uses its demand-side resources to “address[] its non-coincident peak as well as the system coincident peak, this could reduce the capacity that DEP must install to provide [NCEMPA] with the firm-as-native load requirements service provided for under the contract.” Filing, attach. C (James Test.) at 29:14-16. But this claim is in tension with DEP’s prior claims that the reason NCEMPA’s coincident peak reductions do not deliver value is that “DEP has no rights to call on these resources or to interrupt service to NCEMPA.” Filing, Transmittal Letter at 10 (emphasis omitted). DEP offers no coherent theory as to how the demand-side resources are valuable and predictable when dispatched to address two identified peaks but offer little or no value when dispatched to address only one peak.
[7] NCEMPA has a right under the Amended FRPPA to use demand-side measures to reduce its capacity charges. DEP’s claim that NCEMPA demand-side measures offer little if any value is in tension with its decision to agree to a contract that allows such measures to reduce NCEMPA’s capacity payments. (Note that while the ability of NCEMPA to utilize battery storage technologies was disputed, the ability to use demand-side measures more generally was expressly contracted for.) See N. Carolina E. Mun. Power Agency, 172 FERC ¶ 61,249, at PP 2-3, 32-38 (2020) (holding that NCEMPA has a right under the contract to utilize battery storage resources to reduce demand, and discussing the various contractual provisions in the Amended FRPPA that permit NCEMPA to utilize demand-side measures), reh’g denied, 173 FERC ¶ 62,079, order on reh’g, 173 FERC ¶ 61,235 (2020), petition for rev. denied, Duke Energy Progress v. FERC, Nos. 20-1495, 21-1008 (D.C. Cir. 2022).
[8] With both coincident peaks and non-coincident peaks affected by NCEMPA’s use of demand-side resources as permitted under the Amended FRPPA.
[9] NCEMPA Answer at 9 (emphasis in original).
[10] Majority Order at P 45.
[11] Id.; see also Filing, attach. E. (Gann Test.) at 10-11 (noting that four of DEP’s five other customers have rates pursuant to which “capacity costs are allocated . . . through a formula rate that uses a coincident peak approach,” and explaining that the fifth customer uses a stated rate).
[12] Filing, Transmittal Letter at 18 (quoting Electric Utility Cost Allocation Manual, National Association of Regulatory Utility Commissioners, Jan. 1992, at 39).
[13] See, e.g., PJM Interconnection, L.L.C., 169 FERC ¶ 61,041, at P 55 (2019) (“Dominion’s proposed 12-CP methodology, which considers monthly peak usage in all seasons, reflects the way Dominion plans its transmission system.”).
[14] See, e.g., Filing, Transmittal Letter at 19-20, attach. D (Roberts Test.), attach. G (Snider Test.). The closest DEP comes to articulating a theory to support its proposed rate is in suggesting that “non-coincident peak is the best available proxy for the amount of demand Power Agency actually places on the system.” DEP Jan. 31 Answer at 19-20. But it leaves me scratching my head as to why this is an appropriate proxy, especially considering that its proposed rate places similar incentives for NCEMPA to reduce its contribution to non-coincident peak as the current rate creates for NCEMPA to reduce consumption at coincident peak.
[15] See 16 U.S.C. § 824e(b) (“[T]he Commission may order refunds of any amounts paid, for the period subsequent to the refund effective date through a date fifteen months after such refund effective date.”).