R Street Comments on FERC NOI the Implementation of Dynamic Transmission Line Ratings
FEDERAL ENERGY REGULATORY COMMISSION
Implementation of Dynamic Line Ratings
Docket No. AD22-5-000
Comments of the R Street Institute
On Feb. 24, 2022, the Federal Energy Regulatory Commission (Commission or FERC) published a Notice of Inquiry (NOI) on the implementation of dynamic line ratings (DLRs).  Line ratings are determined by ambient weather conditions, including temperature, solar radiation, cloud cover, precipitation and wind speed and direction. DLRs can increase the capacity, efficiency and/or reliability of transmission facilities by accounting for real-time weather conditions. Existing, common practices use static or seasonal line ratings based on infrequent potential weather conditions, resulting in overly conservative assumptions relative to most real-time weather conditions.
The NOI supplements Order No. 881, which FERC issued in December 2021 to require transmission providers to use ambient-adjusted ratings (AARs), though the order did not require DLR implementation based on the record.  AARs only account for ambient air temperature and the presence, not intensity, of solar heating. Thus, the NOI examines the merits of accounting for additional conditions like the intensity of solar heating, cloud cover, precipitation, wind speed and direction, and transmission line conditions including tension or sag.
These comments provide the overarching view of the R Street Institute, including a strategic take on next steps for the Commission. They also provide responses to some of the specific questions posed by the Commission.
Summary of R Street Position
The R Street Institute (RSI) applauds the Commission for investigating this matter. Order No. 881 captures key determinants of transmission line transfer capability but, by itself, will not result in accurate line ratings. Wind speed and direction alone often have greater effect on transfer capability than AARs.  As such, the status quo after Order 881 implementation will result in improved, though still chronically understated, line ratings that increase wholesale rates from unnecessary congestion, inefficient transmission and generation investment decisions, and generation curtailments.
The opacity and dearth of transmission system information and independent oversight outside of regional transmission organizations (RTOs) is the primary evidentiary obstacle for determining whether DLR implementation is required for just and reasonable wholesale rates. Ironically, prolific use of DLRs is clearly advantageous in RTOs because of RTO transparency, yet the DLR proposition is perhaps greater in non-RTO regions given the deficiencies in congestion management practices outside RTOs. Strategically, this means that FERC DLR policy must account for institutional constraints outside of RTOs and any reforms that alter these constraints.
RSI contends that its original position noted in this NOI of requiring DLRs by default, with exceptions granted when justified by cost-benefit analyses, is advantageous on technical, legal and implementation grounds compared to the alternative of targeted DLR implementation. There are several points that support this:
- Unlike AARs, the prudence of DLRs may have line-specific considerations, but nevertheless the economics of DLRs are favorable in most cases and thus better suited for an opt-out rather than opt-in approach. Requiring utilities to demonstrate why DLR would not pass a cost-benefit test on a specific line would result in greater compliance and administrative efficiency.
- The determination for default DLRs can be predicated on a general demonstration that DLRs are “good utility practice” in most cases; it does not necessitate line-specific criteria as the targeted approach would, which may not be readily available in all regions. Importantly, a general determination can be made where data is readily available and extended to non-RTO regions that fail to provide data demonstrating otherwise. FERC can justify a general finding on the premise that it is using the best data utilities make available and there is no principle or theory that supports why non-RTO utilities should be treated differently.
- A policy of targeted DLR implementation requires granular, independent oversight that is lacking outside RTOs under the institutional status quo. Compliance would be poor without independent initial and periodic reevaluations of specific lines or a reporting mechanism for enforcement. Justifying DLR requirements based on limited cases may introduce legal risk by undermining the external validity of the determination to areas lacking data availability (e.g., line-specific congestion data outside RTOs).
If the Commission opts for the targeted DR approach, it may need to require congestion reporting that is more transparent, frequent and granular; use alternative congestion metrics; or overhaul the institutional framework outside RTOs in parallel with this proceeding. Parallel institutional reforms could establish independent institutions that monitor, report and enhance the transparency of the transmission system outside RTO regions, such as those that may result from RM21-17-000 and related proceedings. In particular, the use of an independent transmission monitor (ITM) outside RTOs would prove illuminating for objective DLR assessment. An ITM could also provide ongoing oversight and enforcement functions if granted a referral mechanism akin to those of independent market monitors, which is crucial if DLR implementation requires line-by-line evaluation.
Between Order 881 and a potential DLR requirement, the Commission may set a precedent for grid-enhancing technologies (GETs) policy using direct or de facto technology-forcing instruments. Common economic policy theory suggests a performance incentive-based approach would outperform technology forcing; most applications, however, exist in competitive marketplaces where marginal or moderate shifts in incentives suffice.  Under cost-of-service regulation, the staggering depths of transmission owners’ (TOs) perverse financial incentives for GETs may render technology-specifying policy instruments the economically efficient option, especially given the lessons of implementation problems with performance-based ratemaking at the retail level (e.g., gaming baselines).  Key considerations for other GETs is the extent to which their application constitutes a general or circumstantial best practice, as technology-forcing is harder to administer on a case-by-case basis.
Responses to Select Commission Questions
(Q1) As a threshold matter, even for transmission lines that incorporate AARs, is there a need to further increase the accuracy of transmission lines ratings through the implementation of DLRs to ensure just and reasonable wholesale rates? Why or why not? If yes, please explain whether a requirement by the Commission to adopt DLRs is needed.
DLRs provide marginal benefits far in excess of marginal costs above AARs in a great number of applications. An early pilot found line capacities above AARs by 8-12 percent for 138 kV lines and 6-14 percent for 345 kV lines roughly 90 percent of the time.  This month, PPL reported that implementing DLRs on two 230 kV lines in addition to AARs would cost less than $1 million and boost capacity 10-30 percent on lines with $23.5 million in annual congestion costs projected in 2025.  Studies indicate that even a 10 percent increase in line ratings could eliminate most congestion, and U.S. wide congestion sits in the neighborhood of $6 billion annually.  Various GETs studies could be disaggregated to ascertain the specific marginal cost and benefits of DLRs above AARs if needed. 
At bare minimum, accounting for certain weather conditions beyond what AARs capture are a general best practice in line ratings. For example, adjusting line ratings to account for wind speed and direction should constitute good utility practice. In fact, wind speed and direction alone often have a greater effect on transfer capability than AARs. 
DLRs have been technically feasible for long enough to demonstrate that these practices will not be implemented consistent with good utility practice under the status quo regulatory framework. DLRs have been successfully demonstrated on a commercial basis for roughly a decade.  A Commission requirement is necessary to propel adoption because the parties responsible for making the decision generally have a financial motive to avoid adopting DLRs and other GETs.  Specifically, the perverse incentive under the cost-of-service paradigm encourages TOs to spend capital less efficiently in order to maximize rate base, which will always deprioritize DLRs given their mass capital savings relative to conventional transmission expansion. Further, some TOs also own generation, often through an affiliate that benefits financially from artificially high congestion.
(Q2) What, if any, barriers to DLR implementation exist today? Are potential requirements to implement DLRs necessary to address these existing barriers? Why or why not?
There are no prohibitive technical barriers to DLR adoption. They have demonstrated commercial readiness and the ability to integrate into transmission system operations without requiring operator intervention.  However, proper implementation requires robust and granular monitoring along an entire line.
The core barrier to DLR implementation is the misaligned financial motive of TOs to adopt economical DLRs. This leaves the Commission with two general policy options. First, it can fundamentally alter financial incentives of TOs to align with economical GETs adoption, including DLRs. Performance-based rates provide one such option, however historical and recent retail level experience with this approach has not yielded consistently favorable results (e.g., utilities game baseline measures).  This decision, however, is largely beyond the scope of this proceeding.
The second option is for the Commission to impose requirements that result in the economical adoption of DLRs. Requirements have options between policy instruments and implementation techniques within each instrument. Policy instruments include performance standards and technology-forcing requirements. Of particular interest in this proceeding are technology-forcing requirements implemented uniformly or under specific conditions. Order No. 881 used a uniform requirement, which was appropriate because AARs have benefits exceeding costs in every application. Although DLRs appear to provide positive net benefits in the vast majority of cases, whether benefits exceed costs still depends on line-specific conditions. Criteria-based DLR requirements could account for these differentiated conditions and likely achieve higher net benefits system-wide and for specific applications.
A secondary barrier are institutional deficiencies in transmission oversight. At minimum, this function is important to monitor DLR implementation for rating accuracy verification. It could also serve to identify where DLR is economical, if relevant. The granularity and quality of transmission asset oversight varies by RTO, as indicated by the differences reported by independent market monitors (IMM). The deficiency is correctable within RTOs by modifying the role of the IMM or creating a new entity with such abilities.
Outside RTOs, there is no existing institution that could adapt to this role. Line-specific DLR assessments would require congestion reporting that is transparent, frequent and granular. Currently, these regions are opaque to the point that alternative metrics are often used to estimate utility-wide congestion— any granular scale approaching a nodal level remains inaccessible.
Potential overhauls to the institutional framework outside RTOs in parallel with this proceeding could be transformative for DLRs. RM21-17-000 and related proceedings may help establish independent institutions that monitor, report and enhance the transparency of the transmission system outside RTO regions. In particular, the use of an independent transmission monitor (ITM) outside RTOs would prove illuminating for objective DLR assessment. An ITM could also provide ongoing oversight and enforcement functions if granted a referral mechanism akin to those of independent market monitors, which is crucial if DLR implementation requires line-by-line evaluation.
(Q3) If the Commission were to require DLR implementation, should it require the implementation only on certain transmission lines, and, if so, what set of criteria should be considered to identify transmission lines for DLR implementation? Examples of such criteria could include congestion, curtailment levels, voltage levels, infrastructure, and/or geography/terrain. Explain why such criteria would identify the set of transmission lines on which DLRs need to be implemented in order to produce just and reasonable wholesale rates.
RSI contends that its original position noted in this NOI of requiring DLRs by default, with exceptions granted when justified by cost-benefit analyses. This is advantageous on technical, legal and implementation grounds compared to the alternative of targeted DLR implementation. There are several points that support this claim:
- Unlike AARs, the prudence of DLRs may have line-specific considerations, but nevertheless the economics of DLRs are favorable in most cases and thus better suited for an opt-out rather than opt-in approach. Requiring utilities to demonstrate why DLR would not pass a cost-benefit test on a specific line would result in greater compliance and administrative.
- The determination for default DLRs can be predicated on a general demonstration that DLRs are “good utility practice” in most cases; it does not necessitate line-specific criteria as the targeted approach would, which may not be readily available in all regions. Existing regional studies are sufficient in scale and generalizability to other regions to support a general determination based on where data is readily available and extended to non-RTO regions that fail to provide data demonstrating otherwise. FERC can justify a general finding on the premise that it is using the best data utilities make available and there is no principle or theory that supports why non-RTO utilities should be treated differently.
- A policy of targeted DLR implementation requires granular, independent oversight that is lacking outside RTOs under the institutional status quo. Compliance would be poor without independent initial and periodic reevaluations of specific lines or a reporting mechanism for enforcement. Justifying DLR requirements based on limited cases may introduce legal risk by undermining the external validity of the determination to areas lacking data availability (e.g., line specific congestion data outside RTOs).
The Commission should establish clear rules for exemptions to minimize abuse and litigation. A justifiable rationale for exemption includes existing or expected future congestion that does not warrant the expense of implementing DLR. In all cases, the cost of DLR must be estimated relative to congestion savings and any additional benefits the Commission may specify it is prudent to exempt projects that are already certificated and under construction that will alleviate congestion that would otherwise justify a DLR.
If the Commission opts for the targeted DLR approach, the Watt Coalition criteria are reasonable with one exception. The proposed generation curtailment threshold of 10 percent is large in this context. A preferable level is 3-5 percent. A 5 percent curtailment threshold has been used as a viability assessment in GETs analyses already.  RSI stresses that the targeted DLR approach must be accompanied by granular, independent transmission oversight and enforcement reforms in regions outside RTOs.
An alternative variant of the DLR default or targeted DLR approach is to require line ratings adjustments that account for some, but not all, weather conditions encompassed by DLRs. Wind speed and direction should be the top priority based on the magnitude of effect. Solar intensity also warrants close consideration.
(Q5) If the Commission were to require DLR implementation based on certain criteria, should the criteria be regularly reevaluated to ensure such criteria continue to ensure accurate transmission line ratings, and, if so, at what interval(s)? How should such regular reevaluations work practically?
Annually, RTOs, IMMs and/or ITMs should identify the costliest transmission constraints. They should identify whether the congestion is temporary or continual based on a specified threshold, such as that used to define narrowly constrained areas. If continual, they should detail the conditions that would have to change to alleviate chronic congestion and any pending congestion relief projects. If suitable to these conditions, a crude and formulaic net benefits assessment of DLRs and perhaps other GETs could be included.
If DLRs passed the crude test in the routine analysis, it could trigger a more intensive and specific net benefits assessment. If these results came back favorable, it could trigger an actionable referral to ensure economical DLR adoption is evaluated either by the Commission or an independent regional transmission oversight body. The IMM or ITM should also be responsible for reporting the accuracy of line ratings where DLRs have been implemented.
(Q6) If such criteria included the magnitude of congestion on a transmission line, what metrics exist that assess the magnitude of congestion in both or either RTO/ISO and/or non-RTO/ISO regions? For any congestion metrics suggested, what data sources are available?
Congestion is readily transparent in RTOs. It constitutes the bulk of price differences in locational marginal pricing—the core concept in modern power systems—that for purposes beyond this proceeding is not yet employed as standard practice in some regions. Adjustments to reporting may help identify total congestion levels at the line-specific levels that highlight DLR-avoided costs, as noted in previous responses. For example, RTOs and IMMs vary in their technical criteria for determining the chronically congested areas used for market power mitigation thresholds, which could be altered with improved consistency across regions for GET analysis.
Congestion measures outside of RTOs are a severe deficiency for many reasons, including assessing the avoided costs of DLRs. There are a variety of indirect measures of congestion:
- Transmission loading relief (TLRs). TLRs are a procedure for mitigating transmission security limit violations, which are publicly logged whenever a TLR Level 2 is invoked.  TLRs will understate congestion frequency and duration overall, thus serving as a floor of indirect congestion. There is no known way to attribute an economic value to TLRs, however, which inhibits any direct estimate of DLR-avoided cost.
- Bilateral contract terms and available transfer capacity (ATC). ATC reporting is intended to provide third parties with information on transmission service availability.  ATC and related measures may indicate denials of service from chronic congestion. Elevated prices in power purchase agreements may also indicate this problem, such as regional or subregional outliers reported in electric quarterly reporting data. Export constraints may warrant particular scrutiny as non-RTO regions are flush with generation capacity, where transmission constraints inhibit sales into RTOs.
- Generation curtailment. As noted previously, curtailment exceeding 5 percent should indicate a significant likelihood of chronic congestion at a fairly granular, if not line-specific, level. Curtailment is best used in conjunction with other metrics to help decipher when curtailment is caused by congestion or to avoid overgeneration events given the minimum generation constraints of other resources.
- Various transmission infrastructure planning metrics. Utilities employ a variety of transmission metrics per Order 1000 and other Commission requirements to assess the cost-effectiveness of transmission development. Embedded in these load flow analyses are various indirect congestion measures. One example is load-weighted transmission investment.  These often incorporate historical indicators of congestion as well as projections of future patterns to inform transmission expansion planning.
- Retail indicators of congestion. A staple of utility retail practice outside RTOs is to report system lambda hourly.  Any dispatch above lambda may indicate import constraints. Curtailment below system lambda may indicate export constraints. Utilities also report fuel and purchase costs, often in automatic retail rate adjustment mechanisms, at the retail level. Elevated fuel and purchase costs often reflect exceptional dispatch that departs from the underlying system baseline for purposes of navigating transmission constraints.
Given the limitations of these indirect congestion measures, the Commission may use multiple indicators simultaneously to increase the correlation with congestion. For example, a screen consisting of TLR frequency, ATC magnitude and generation curtailment frequency exceeding certain levels in a given area would provide evidence of chronic congestion on a particular flow path. The Commission may use these as proxies associated with congestion levels that support favorable DLR economics, or use them as the basis to collect further information. If necessary to make DLR requirements actionable, the Commission could issue an information request of utilities outside of RTOs. Regardless, regions outside RTOs would require an overhaul of congestion reporting and independent review to enact ongoing DLR reassessments.
(Q8) What are the differences, if any, between RTOs/ISOs and non-RTO/ISO transmission providers that the Commission should account for when considering any DLR requirements?
Key differences between RTO and non-RTO regions include congestion transparency and congestion management practices. RTO/ISOs produce transparent locational energy prices. The predominate driver of differences between locational prices is congestion. Utilities in non-RTO areas have their own internal, less transparent manner of dispatching generation and making purchases and sales that can mask congestion costs. These congestion management practices are less efficient than RTO systems spatially and temporally, and thus may result in marginal generation costs in excess of comparable conditions in RTOs.  This may be reflected, for example, in elevated fuel and bilateral purchase agreements. Accounting for differences in congestion management practices may be informative for any indirect congestion metrics used outside RTOs regions.
(Q9) If the Commission were to require DLR implementation based on certain criteria, should it require that new transmission lines be evaluated to determine whether they must implement DLRs? Are there any characteristics of new transmission lines that warrant different criteria?
DLRs should be included in standard expectations for all new transmission facilities, at least above a relatively low cost, voltage or capacity expansion threshold. This is because DLR inclusion can affect the optimality of conventional transmission expansion. DLRs and other GETs are often complementary to conventional transmission expansion and occasionally imperfect substitutes.
(Q10) If the Commission were to require DLR implementation, how should that requirement be considered in regional transmission planning and interconnection processes?
Regional planning and other system assessments will have to account for expected variability in line ratings. Planning and interconnection processes can use general proxies of transfer limit increases that are coincident with periods that face binding constraints. These should be based on expected conditions, not the lowest ratings values under infrequent conditions. Otherwise, it would effectively result in static line rating inputs despite DLRs being used in practice. For example, a line carrying generation produced by wind should be assumed at a “high” wind speed rating when evaluating transfer capability. Planning tools and procedures employ more sophisticated techniques, per software capabilities, to account for the distribution of ratings by time and location associated with DLRs.
(Q11) If the Commission were to require DLR implementation based on certain criteria, what transparency measures should the Commission require? For example, should the Commission consider requiring transmission providers to submit informational reports that show which transmission lines meet any determined criteria for DLR implementation? And/or should the Commission require transmission providers to post the same on their Open Access Same-Time Information System websites?
This would be critical under the targeted DLR approach. Ideally the Commission would require congestion reporting on at least an hourly rate and include continuous spatial reporting along a line, not just a few point estimates, to develop an accurate basis of DLR-avoided costs. Economic costs, not merely engineering statistics, would be necessary. Transparency may also require reporting in a usable data format to enable third party verification. Requiring explanations that distinguish chronic and episodic congestion as well as deviations from historical congestion patterns would inform DLR prudency.
More transparency would be beneficial but not imperative under the default DLR approach. The burden would be on the utility to demonstrate that congestion avoided costs are too low to justify DLR.
(Q12) For any DLR requirement criteria you identified in response to question Q3 above, please explain and, if possible, quantify the potential annual gross market benefits that would be expected to result from such a requirement.
Approximate regional DLR net benefits assessments should be done for all lines and especially those that are chronically congested. Even rough estimates are informative. For example, the Southwest Power Pool (SPP) had net congestion costs of $442 million in 2020.  Assuming a 10 percent ratings improvement for the top ten constraints, each active about 10 percent of the time, shadow prices of roughly $10/megawatt-hour indicate annual benefits of $360,000 – $450,000 per constraint, or $3.6 million to $4.5 million for all ten. This would exceed the DLR implementation costs of roughly $2 million provided by SPP. The State of the Market Report for the Midcontinent Independent System Operator provides a useful replicable example of benefits estimates of hypothetical and actual line ratings improvements. Such analyses clearly inform determinations of line-specific prudence and prioritization for DLR implementation. 
RSI respectfully requests the Commission consider the comments contained herein.
/s/ Devin Hartman
Director, Energy and Environmental Policy
R Street Institute
1212 New York Ave. N.W., Suite 900
Washington, D.C. 20005
April 25, 2022
 Federal Energy Regulatory Commission, Implementation of Dynamic Line Ratings, Notice of Inquiry, Docket No. AD22-5-000, Feb. 24, 2022. https://www.govinfo.gov/content/pkg/FR-2022-02-24/pdf/2022-03911.pdf.
 Federal Energy Regulatory Commission, Managing Transmission Line Ratings, Final Rule, Docket No. RM20-16-000, Order No. 881, Dec. 16, 2021. https://www.wrightlaw.com/62D00A/assets/files/documents/W0284102.PDF.
 Americans for a Clean Energy Grid, “Dynamic Line Ratings,” August 2014, p. 3. https://cleanenergygrid.org/wp-content/uploads/2014/08/Dynamic-Line-Ratings.pdf.
 See e.g., Margaret Taylor et al., “Confronting Regulatory Cost and Quality Expectations: An Exploration of Technical Change in Minimum Efficiency Performance Standards,” Resources for the Future, October 2015. https://media.rff.org/documents/RFF-DP-15-50.pdf.
 See e.g., “Profiles on Electricity Issues: Performance-Based Regulation,” Electricity Consumers Resource Council, August 2000. https://elcon.org/wp-content/uploads/pbr_profile1.pdf.
 See, e.g., “Oncor’s Pioneering Transmission Dynamic Line Rating (DLR) Demonstration Lays Foundation for Follow-On Deployments,” U.S. Department of Energy, May 20, 2014, p. 1. https://www.energy.gov/sites/prod/files/2016/12/f34/Oncor_DLR_Case_Study_05-20-14_FINAL.pdf.
 Horst Lehmann and Eric Rosenberger, “Dynamic Line Ratings with Sensors,” Reliability First Presentation, April 4, 2022, pp. 114-115. https://rfirst.org/KnowledgeCenter/Workshops/KC%20%20Workshops%20Library/2022-04-04%20Facility%20Ratings%20Presentation.pdf.
 T. Bruce Tsuchida, “Managing Transmission Line Ratings,” FERC Technical Conference, Sep. 10-11, 2019, p. 7. https://www.brattle.com/wp-content/uploads/2021/05/17919_managing_transmission_line_ratings.pdf.
 See, e.g., T. Bruce Tsuchida et al., “Unlocking the Queue with Grid-Enhancing Technologies,” Case Study of the Southwest Power Pool, Feb. 1, 2021. https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf.
 Americans for a Clean Energy Grid, 2014, p. 3. https://cleanenergygrid.org/wp-content/uploads/2014/08/Dynamic-Line-Ratings.pdf.
 U.S. Department of Energy, 2014. https://www.energy.gov/sites/prod/files/2016/12/f34/Oncor_DLR_Case_Study_05-20-14_FINAL.pdf.
 Comments of the R Street Institute before the Federal Energy Regulatory Commission, Post-Workshop Comments on Grid-Enhancing Technologies, Docket No. AD19-19-000, Feb. 14, 2020, p. 1. https://www.rstreet.org/wp-content/uploads/2020/02/FINAL-Hartman-GETs_Post-Workshop_Comments.pdf.
 U.S. Department of Energy, 2014. https://www.energy.gov/sites/prod/files/2016/12/f34/Oncor_DLR_Case_Study_05-20-14_FINAL.pdf.
 Electricity Consumers Resource Council, 2000. https://elcon.org/wp-content/uploads/pbr_profile1.pdf.
 See, e.g., T. Bruce Tsuchida et al., 2021, p. 7. https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf.
 See. e.g., “Transmission Loading Relief (TLR) Procedure,” North American Electric Reliability Corporation, last accessed April 19, 2022. https://www.nerc.com/pa/rrm/TLR/Pages/default.aspx.
 “FERC Issues Proposed Rulemaking on Transmission Line Ratings,” Troutman Pepper, Dec. 11, 2020. https://www.jdsupra.com/legalnews/ferc-issues-proposed-rulemaking-on-24323.
 “Annual U.S. Transmission Data Review,” U.S. Department of Energy, March 2018, p. 12. https://www.energy.gov/sites/prod/files/2018/03/f49/2018%20Transmission%20Data%20Review%20FINAL.pdf.
 See, e.g., Testimony of Rachel S. Wilson on Behalf of Sierra Club, “Application by Duke Energy Progress, LLC, for Adjustment of Rates and Charges Applicable to Electric Utility Service in North Carolina,” State of North Carolina Utilities Commission, Docket No. E-2, SUB 1219, April 13, 2020. https://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=e6409bfe-c4d3-40f8-aaec-4a35c2567663.
 See e.g., Devin Hartman, “Wholesale Electricity Markets in the Technological Age,” R Street Policy Study No. 67, August 2016. https://www.rstreet.org/wp-content/uploads/2018/04/67-1.pdf.
 “State of the Market 2020,” Southwest Power Pool Market Monitoring Unit, Aug. 12, 2021, p. 5. https://www.spp.org/documents/65161/2020%20annual%20state%20of%20the%20market%20report.pdf.
 Potomac Economics, “2020 State of the Market Report for the MISO Electricity Markets,” May 7, 2021, pp. 64-67. https://www.potomaceconomics.com/wp-content/uploads/2021/05/2020-MISO-SOM_Report_Body_Compiled_Final_rev-6-1-21.pdf.