170 FERC ¶ 61,129

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM16-17-001; Order No. 860-A]

Data Collection for Analytics and Surveillance and Market-Based Rate Purposes

(Issued February 20, 2020)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on Rehearing and Clarification.

SUMMARY: The Federal Energy Regulatory Commission addresses requests for 

rehearing and clarification and affirms its determinations in Order No. 860, which 

amends its regulations governing market-based rates for public utilities.

DATES: The final rule will become effective October 1, 2020.

FOR FURTHER INFORMATION CONTACT:

Regine Baus (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8757

Regine.Baus@ferc.gov

Byron Corum (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6555

Byron.Corum@ferc.gov
Docket No. RM16-17-001 - 2 -

SUPPLEMENTAL INFORMATION:
170 FERC ¶ 61,129

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman;

 Richard Glick and Bernard L. McNamee.

Data Collection for Analytics and Surveillance and 

Market-Based Rate Purposes

Docket No. RM16-17-001

ORDER NO. 860-A 

ORDER ON REHEARING AND CLARIFICATION

(Issued February 20, 2020)

I. Introduction

On July 18, 2019, the Commission issued Order No. 860,1 which revised certain 

aspects of the substance and format of information submitted for market-based rate 

purposes by Sellers.

2

 Specifically, the Commission adopted the approach to data 

collection proposed in the Notice of Proposed Rulemaking issued in July 2016, i.e., to 

collect market-based rate information in a relational database.3

 However, the 

Commission declined to adopt the proposal to require Sellers and entities, other than 

 1 Data Collection for Analytics & Surveillance and Market-Based Rate Purposes, 

Order No. 860, 168 FERC ¶ 61,039 (2019).

2 A Seller is defined as any person that has authorization to or seeks authorization 

to engage in sales for resale of electric energy, capacity or ancillary services at marketbased rates under section 205 of the Federal Power Act (FPA). 18 CFR 35.36(a)(1); 

16 U.S.C. 824d.

3 Data Collection for Analytics & Surveillance and Market-Based Rate Purposes, 

Notice of Proposed Rulemaking, 156 FERC ¶ 61,045 (2016) (NOPR).
Docket No. RM16-17-001 - 2 -

those described in FPA section 201(f),4 that trade virtual products5 or that hold financial

transmission rights (FTR)6 (Virtual/FTR Participants) to report certain information about 

their legal and financial connections to other entities (Connected Entity Information). In 

this order, we address requests for rehearing and clarification of Order No. 860.7

Six requests for rehearing and/or clarification were filed.8 The requests for 

rehearing and clarification concern the following subjects: (1) ownership information, 

 4 16 U.S.C. 824(f).

5 Virtual trading involves sales or purchases in the day-ahead market of a Regional 

Transmission Organization (RTO) or Independent System Operator (ISO) that do not go 

to physical delivery. By making virtual energy sales or purchases in the day-ahead 

market and settling these positions in the real-time market, any market participant can 

arbitrage price differences between the two markets. See Market-Based Rates for 

Wholesale Sales of Elec. Energy, Capacity & Ancillary Servs. by Pub. Utils., Order 

No. 697, 119 FERC ¶ 61,295, at P 921 n.1047, clarified, 121 FERC ¶ 61,260 (2007), 

order on reh’g, Order No. 697-A, 123 FERC ¶ 61,055, clarified, 124 FERC ¶ 61,055, 

order on reh’g, Order No. 697-B, 125 FERC ¶ 61,326 (2008), order on reh’g, Order 

No. 697-C, 127 FERC ¶ 61,284 (2009), order on reh’g, Order No. 697-D, 130 FERC 

¶ 61,206 (2010), aff’d sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 

(9th Cir. 2011).

6 The term “FTR,” as used in the NOPR and Order No. 860, was intended to cover 

not only Financial Transmission Rights, a term used by PJM Interconnection, L.L.C. 

(PJM), ISO New England Inc., and Midcontinent Independent System Operator, Inc., but 

also Transmission Congestion Contracts in New York Independent System Operator, 

Inc., Transmission Congestion Rights in Southwest Power Pool, Inc., and Congestion 

Revenue Rights in California Independent System Operator Corp. Order No. 860, 

168 FERC ¶ 61,039 at P 2 n.6.

7 Order No. 860 will become effective October 1, 2020.

8 The requests for rehearing and/or clarification were filed by the following 

entities: (1) Edison Electric Institute (EEI); (2) Fund Management Parties (FMP), which 

includes Ares EIF Management, LLC, for itself and its public utility affiliates, Monolith 

Energy Trading LLC, as the sole owner of Solios Power LLC, for itself and its public 
Docket No. RM16-17-001 - 3 -

including ultimate upstream affiliates;9 (2) passive owners; (3) Connected Entity 

proposal; (4) implementation and components of the Data Dictionary; (5) public access; 

and (6) due diligence requirements. 

We deny the requests for rehearing, and grant in part and deny in part the requests 

for clarification, as discussed below.

II. Discussion

A. Substantive Changes to Market-Based Rate Requirements

1. Ownership Information

a. Final Rule

In Order No. 860, the Commission adopted the proposal to require that, as part of 

their market-based rate applications or baselines submissions, Sellers must identify 

through the relational database their ultimate upstream affiliate(s). The Commission 

explained that, because this is a characteristic the Commission will rely upon in granting 

 

utility affiliates and affiliates the engage in trading of virtual and/or financial 

transmission products, Southwest Generation Operating Company, for itself and its 

public utility affiliates, and Star West Generation LLF, for itself and its public utility 

affiliates; (3) Office of the People’s Counsel for the District of Columbia, Delaware 

Division of the Public Advocate, Citizens Utility Board of Illinois, and West Virginia 

Consumer Advocate Division (collectively, Joint Advocates); (4) NRG Energy, Inc. and 

Vistra Energy Corp. (together, NRG/Vistra); (5) Starwood Energy Group Global, L.L.C. 

(Starwood); and (6) Transmission Access Policy Study Group (TAPS).

9 “Ultimate upstream affiliate” is defined in the final rule as “the furthest upstream 

affiliate(s) in the ownership chain – i.e., each of the upstream affiliate(s) of a Seller, who 

itself does not have 10 percent or more of its outstanding voting securities owned, held or 

controlled, with power to vote, by any person (including an individual or company).” 

Order No. 860, 168 FERC ¶ 61,039 at P 5 n.10.
Docket No. RM16-17-001 - 4 -

market-based rate authority, Sellers must also inform the Commission when they have a 

new ultimate upstream affiliate as part of their change in status reporting obligations. In 

addition, the Commission required that any new ultimate upstream affiliate information 

must also be submitted into the relational database on a monthly basis.10

b. Request for Clarification

NRG/Vistra seeks clarification solely with respect to implementation issues 

relating to identifying and reporting a Seller’s ultimate upstream affiliate(s) where 

holdings of publicly traded voting securities are involved.11 NRG/Vistra first argues that 

an investor should not be considered a Seller’s ultimate upstream affiliate based solely on 

holdings of publicly traded securities. According to NRG/Vistra, where publicly traded 

securities are involved, applying the ultimate upstream affiliate definition will yield false 

positives and fail to recognize the control exercised by the publicly traded entity. In this 

regard, NRG/Vistra asserts that the Commission has granted financial institutions blanket 

authorizations under FPA section 203(a)(2) to acquire 10 percent or more of the voting 

securities of public utilities based on its understanding that these institutions are acquiring 

such interests “in the ordinary course of business and as a passive investor (i.e., not to 

gain control of the [public u]tilities),” and that their holdings of such securities will “not 

convey control of day-to-day operations of jurisdictional facilities.”12

 10 Order No. 860, 168 FERC ¶ 61,039 at P 121.

11 NRG/Vistra Request at 4.

12 Id. at 4-5 (quoting Morgan Stanley, 121 FERC ¶ 61,060, at P 9 (2007), order on 
Docket No. RM16-17-001 - 5 -

As an example, NRG/Vistra states that the Vanguard Group, Inc. (Vanguard) has 

reported that it, together with certain related entities, owns more than 10 percent of the 

shares of NRG’s common stock. NRG/Vistra maintains that, although these shares are 

voting securities, there is no reason to regard Vanguard as “controlling” NRG or its Seller 

subsidiaries in any respect relevant to the Commission’s analysis and monitoring of 

Sellers as Vanguard has reported its holdings of NRG’s common stock to the Securities 

and Exchange Commission (SEC) through Schedule 13G filings. NRG/Vistra explains 

that the Commission has recognized that, in order to file a Schedule 13G, an investor must 

certify that the securities were not acquired for the purpose, or with the effect, of changing 

or influencing control over the issuer. NRG/Vistra also states that Vanguard has obtained 

a blanket section 203(a)(2) authorization similar to the other section 203(a)(2) blanket 

authorizations in recognition that it is acquiring the shares of entities like NRG on behalf 

of investors in its managed funds exclusively for investment purposes, not for the purpose 

of managing, controlling, or entering into business transactions with portfolio companies. 

NRG/Vistra argues that, if NRG’s Seller subsidiaries were to identify Vanguard as their 

ultimate upstream affiliate, it would inaccurately suggest that they are under common 

control with other Sellers in which Vanguard and its affiliates might also own 10 percent

voting interests. NRG/Vistra adds that NRG itself would not appear in the relational 

database in this case.

13

 

clarification, 122 FERC ¶ 61,094 (2008)).

13 Id. at 5-6.
Docket No. RM16-17-001 - 6 -

Accordingly, NRG/Vistra requests that the Commission clarify that an investor (or 

investor group) will not be considered a Seller’s ultimate upstream affiliate based solely 

on holdings of publicly traded securities. NRG/Vistra explains, in other words, where the 

voting securities of a Seller’s upstream owner are publicly traded, the exercise of tracing 

upstream ownership will stop at the publicly traded entity unless the facts and 

circumstances suggest that a holder of 10 percent or more of the publicly traded voting 

securities has an intent and ability to exercise control over the publicly traded entity and 

its subsidiaries. NRG/Vistra posits that the Commission could find that, unless the 

publicly traded entity states otherwise, the Commission will presume that any holder of 

10 percent or more of the entity’s securities does not have an intent and ability to exercise 

control over the publicly traded entity and its subsidiaries. NRG/Vistra adds that, if such 

facts and circumstances change, the publicly traded company could commit to notify the 

Commission within 30 days upon notice of that change. NRG/Vistra contends that, at 

minimum, investors that have made Schedule 13G filings with the SEC or that have 

obtained blanket FPA section 203 authorizations should not be considered ultimate 

upstream affiliates because such investors have affirmatively represented that they do not 

hold the securities for control purposes.14

However, if the Commission does not grant this clarification, NRG/Vistra requests 

that, where there is a change resulting from trading publicly traded securities, the change 

be deemed to occur when the Seller had actual or constructive notice of the change. 

 14 Id. at 6-7.
Docket No. RM16-17-001 - 7 -

NRG/Vistra argues that the Commission has acknowledged the difficulty of tracking 

secondary market transactions and that, as a general matter, publicly traded companies 

rely on after-the-fact investor filings with the SEC, including (but not limited to) 

Schedule 13D and 13G filings, for information about when a given investor or investor 

group has acquired significant holdings of their shares.15 NRG/Vistra maintains that, 

where Schedule 13D and 13G filings are made, the Seller will receive actual or 

constructive notice that an investor has acquired 10 percent or more of its publicly traded 

parent company’s shares within 10 days after the end of the month of the underlying 

trades. NRG/Vistra posits that, by granting its request, Sellers will have a more 

reasonable amount of time to make its submission to update the database, which would 

lessen the burden on Sellers and reduce the chance of inaccurate submissions that would 

later have to be corrected.16

c. Commission Determination

We deny NRG/Vistra’s request that the Commission clarify that an investor will 

not be considered a Seller’s ultimate upstream affiliate based solely on holdings of 

publicly traded securities. This determination is consistent with current Commission 

 15 Id. at 7-8 (quoting FPA Section 203 Supplemental Policy Statement, 120 FERC 

¶ 61,060, at P 36 (2007), on clarification and reconsideration, 122 FERC ¶ 61,157 

(2008)).

16 Id. at 8-9.
Docket No. RM16-17-001 - 8 -

requirements, i.e., that Sellers must identify all upstream owners.

17 When the final rule 

takes effect, this determination will also be consistent with the requirement to report all 

ultimate upstream affiliates.

18 

More importantly, however, this determination is consistent with the affiliate 

definition in § 35.36(a)(9).

19 Among other things, the affiliate definition provides that an 

affiliate of a specified company means “any person that directly or indirectly owns, 

controls, or holds with power to vote, ten percent or more of the outstanding voting 

securities of the specified company.”20 The Commission established in the final rule that 

the definition of ultimate upstream affiliate “means the furthest upstream affiliate(s) in 

the ownership chain” including “any entity described in § 35.36(a)(9)(i).”21 There is no 

exemption under either of these definitions for entities that hold publicly traded 

securities. Rather, to exempt these entities from this definition would require a change to 

the affiliate definition in § 35.36(a)(9)(i) because the determining criterion is voting 

securities. Neither the NOPR nor the final rule proposed or considered any change to the 

 17 Order No. 697-A, 123 FERC ¶ 61,055 at P 181 n.258.

18 When Order No. 860 becomes effective, Sellers generally will only need to 

identify a subset of their upstream affiliates, the ultimate upstream affiliate(s). Order 

No. 860, 168 FERC ¶ 61,039 at P 5 n.10.

19 18 CFR 35.36(a)(9).

20 18 CFR 35.36(a)(9)(i).

21 18 CFR 35.36(a)(10).
Docket No. RM16-17-001 - 9 -

substance of the affiliate definition. For this reason, we also find NRG/Vistra’s request to 

be outside of the scope of this rulemaking as it is not a logical outgrowth of the NOPR or 

final rule.

22 

In addition, once the relational database is implemented, consistent and complete 

information on ultimate upstream affiliates will be crucial for database integrity and 

accuracy, given that the information in the database may affect a multitude of filers. 

Therefore, to ensure the relational database functions as intended, it would not be 

appropriate for the Commission to sever the chain of affiliation with respect to holders of 

publicly traded securities and preemptively find that they are not ultimate upstream 

affiliates. NRG/Vistra alternatively requests that the Commission stop tracing upstream 

ownership at publicly traded entities unless the facts and circumstances indicate that a 

holder of 10 percent or more of the securities has an intent and ability to exercise control 

over the publicly traded entity. We decline to adopt this subjective approach, given that 

it is critical that ultimate upstream affiliates be consistently reported to the database. 

We also deny NRG/Vistra’s alternative request to allow publicly traded Sellers or 

the Seller subsidiaries of publicly traded companies extra time to file updates to the 

relational database. Although we appreciate that tracking trading in a publicly traded 

ultimate upstream affiliate may be difficult, the requirement to identify upstream 

 22 In determining whether a proposal is a logical outgrowth of a NOPR, the issue is 

whether interested parties “ex ante, should have anticipated that such a requirement might 

be imposed.” Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 

(D.C. Cir. 1983).
Docket No. RM16-17-001 - 10 -

affiliates is not a new requirement. Currently, a Seller owned by a publicly traded 

company, like a Seller with any other type of owner, must timely report to the 

Commission any changes in the conditions the Commission relied upon when granting it 

market-based rate authority, which typically include any changes in ownership such as 

new affiliations. These reports must be made within 30 days of the date of that change.23 

When Order No. 860 takes effect, Sellers will continue to have at least 15 days to 

incorporate, in their monthly database submissions, any relevant changes to their ultimate 

upstream affiliate(s).24 Given that Sellers will still have at least 30 days to submit their 

notice of change in status filings, we do not believe that Sellers potentially having as few 

as 15 days to make their database submissions is a significant change from current 

practice such that Sellers with publicly traded ultimate upstream affiliates will necessarily 

require additional time to report changes regarding their ultimate upstream affiliates. 

In addition, granting this alternative request would affect the timing of quarterly 

notice of change in status filings, as certain ownership changes could be reported 

approximately 75 days after the relevant transaction occurs.25 This could result in Sellers 

 23 18 CFR 35.42.

24 Because monthly database updates will be due on the 15th of the month 

following the change, updates will be due between 15 and 45 days after the relevant 

change occurs (e.g., in April, Sellers have 15 days to make the monthly database update 

if the change occurred on March 31, but 45 days if it occurred on March 1).

25 That is, if the reportable transaction occurs on March 1, the relevant SEC filings 

that serve as notice to a Seller are made by April 10, according to NRG/Vistra, and the 

monthly database updates would be due on May 15.
Docket No. RM16-17-001 - 11 -

not having the most up-to-date information in their notice of change in status filings and 

triennial filings. Consequently, we deny NRG/Vistra’s alternative request.

2. Passive Owners

a. Final Rule

In Order No. 860, the Commission adopted the proposal to require Sellers to make 

an affirmation, in lieu of a demonstration, in their market-based rate narratives 

concerning their passive owners. The Commission explained that such a demonstration 

is unnecessary, given that the Commission does not make a finding of passivity in its 

orders granting market-based rate authority and that removing this demonstration will 

ease the burden on filers.26 

The Commission also clarified the nature of the proposed affirmation regarding 

passive owners. Specifically, “[w]ith respect to any owners that a Seller represents to be 

passive, the Seller must identify such owner(s), and affirm in its narrative that the 

ownership interests consist solely of passive rights that are necessary to protect the 

passive investors’ or owners’ investments and do not confer control.”27 The Commission 

also clarified that it will continue to require change in status filings when passive interests 

arise in a Seller that has received market-based rate authority, so that the Seller can make 

 26 Order No. 860, 168 FERC ¶ 61,039 at P 137.

27 Id. P 138 (citing AES Creative Res., L.P., 129 FERC ¶ 61,239 (2009) (AES 

Creative)). The Commission added that it expects that this affirmation will be included 

in the narrative of initial market-based rate applications and in any other market-based 

rate filing (e.g., triennial update or change in status notification) in which the Seller is 

making a passive ownership representation. Id. n.206.
Docket No. RM16-17-001 - 12 -

the necessary affirmations. However, the Commission provided that, in this context, a

Seller only needs to make a change in status filing to report and affirm the status of new 

passive owners as passive and need not submit any additional information into the 

relational database.28

In addition, the Commission clarified that it is not changing existing policy 

regarding the definition of a passive investor and that specific clarifications on that policy 

are beyond the scope of this proceeding. The Commission explained that, in most 

circumstances, a determination as to passivity is fact-specific and that, if a Seller is

uncertain whether an investment is passive, it may file a petition for declaratory order.29 

Indeed, the Commission emphasized that nothing in Order No. 860 is intended to 

overturn the Commission’s case-specific determinations as to passivity and an entity’s 

reporting obligations under previously issued declaratory orders.30

As to obligations regarding the relational database, the Commission concluded 

that passive owners need not be reported in the database as ultimate upstream affiliates. 

The Commission also did not require that a Seller report the identity of its passive owners 

in the database. Further, the Commission clarified that, if a Seller can make the requisite 

affirmation regarding passive ownership, it would not need to list the assets associated

 28 Id. P 139.

29 Id. P 140. The Commission also declined to extend any safe harbor to 

affirmations made in good faith. Id. n.207.

30 Id. P 140.
Docket No. RM16-17-001 - 13 -

with any such passive owner in its asset appendix.31 The Commission stated, however, in 

footnote 209 of the final rule that “Sellers should provide the identity of new passive 

owner(s) in their narratives when making their passive affirmation.”32

b. Requests for Clarification and/or Rehearing

FMP requests clarification or, in the alternative, rehearing with respect to footnote 

209 of the final rule. As background, FMP explains that many entities subject to the final 

rule are owned by or associated with one or more passive, non-managing owners. FMP 

states that the Commission has recognized the widespread nature of the passive 

ownership of public utilities and notes that the final rule referred to several instances 

where the Commission treatment of non-voting ownership interests indicated that they 

are outside the scope of the jurisdiction of the FPA.33

FMP asserts that footnote 209 is inconsistent with paragraphs 140 and 141 of the 

final rule, which state that Commission treatment of passive ownership is not being 

changed and that a passive owner need not be identified in the filing materials that are 

established and described in the final rule. FMP contends, however, that footnote 209 

substantially changes the Commission’s existing policy.34

 31 Id. P 141.

32 Id. n.209 (emphasis added).

33 FMP Request at 1-2 (citing Starwood Energy Grp. Global, L.L.C., 153 FERC 

¶ 61,332, at P 21 (2015) (Starwood); AES Creative, 129 FERC ¶ 61,239).

34 Id. at 2-3.
Docket No. RM16-17-001 - 14 -

FMP argues next that footnote 209 is inconsistent with Commission precedent. 

FMP contends that nowhere in Starwood, for example, does the Commission require the 

submission of the identities of passive owners; FMP asserts that Starwood instead states 

that public utilities submitting market-based rate materials to the Commission “do not 

need to identify the [passive investors] in any future section 205 market-based rate 

application, updated market power analysis, or notice of change in status.”35

FMP contends that footnote 209 also substantively contradicts other recent, 

controlling precedent on this issue. FMP asserts that, “in Ad Hoc Renewable Energy 

Financing Group,[

36] the Commission referenced and confirmed without deviation 

exactly the conclusions stated in AES Creative and Starwood with respect to passive 

ownership . . . .”37 However, FMP argues that the final rule does not explain footnote 

209’s departure from this precedent.38

In addition, FMP argues that footnote 209’s use of the word “new” in the context 

of “new passive owners” is unclear. FMP contends that Starwood expressly addresses 

the concept of new passive investors and applies to future passive investors, as long as 

 35 Id. at 3 (quoting Starwood, 153 FERC ¶ 61,332 at P 21).

36 161 FERC ¶ 61,010 (2017) (Ad Hoc).

37 FMP Request at 3.

38 Id.
Docket No. RM16-17-001 - 15 -

the investment is actually passive.39 Lastly, FMP asserts that the NOPR did not give

notice that the Commission was considering a substantial change to Starwood, 

AES Creative, and Ad Hoc along the lines of footnote 209.40

If the Commission does not clarify that footnote 209 does not apply to a passive 

investment that is consistent with Starwood, AES Creative, or Ad Hoc, FMP requests that 

the Commission grant rehearing of footnote 209 on the grounds that: (1) the legal 

standard applied in footnote 209 is contrary to the facts present in the other provisions of 

the final rule and Commission precedent relied on in the final rule; (2) footnote 209 lacks 

adequate support and does not represent reasoned decision-making because it

misrepresents the Commission’s holdings in paragraphs 140 and 141 of the final rule; 

(3) footnote 209 lacks adequate support and does not represent reasoned decision-making 

because the Commission failed to examine the specific Commission orders on which the 

Commission relied on in the final rule and to apply its own precedent in a consistent 

fashion; and (4) footnote 209 departed from the Commission’s precedent without notice 

in the NOPR such that the departure was arbitrary, capricious, or otherwise unlawful and 

in violation of FMP’s rights.41

 39 Id. (citing Starwood, 153 FERC ¶ 61,332 at PP 14, 16-19).

40 Id. at 4.

41 Id. at 4-5.
Docket No. RM16-17-001 - 16 -

Starwood also requests clarification with respect to footnote 209 of the final rule 

and incorporates the entirety of FMP’s pleading as part of its own request. Starwood 

argues that footnote 209 is inconsistent with prior Commission precedent, including 

Starwood’s own 2015 declaratory order.42 Starwood contends that one of the primary 

reasons it sought a declaratory order was to obtain a definitive ruling from the 

Commission that it did not need to disclose the identity of its passive owners. Starwood 

argues that other similarly situated private equity funds and fund managers have relied on 

Starwood since that time. Starwood requests that the Commission clarify that nothing in 

the final rule, specifically footnote 209, will change existing Commission precedent, 

which Starwood argues clearly provides that parties do not need to disclose the identity of 

their passive owners.43

TAPS requests clarification regarding the affirmation a Seller must make if it has 

passive owners. According to TAPS, the classification of owners as active or passive is 

critical to the Commission’s analysis of whether to grant market-based rate authority to a 

Seller. TAPS explains that the classification determines affiliation, which triggers 

several market-based rate reporting requirements, and that the Commission required in 

Order No. 816 that Sellers need not include in their asset appendices entities or facilities 

 42 Starwood Request at 1-2 (citing Starwood, 153 FERC ¶ 61,332).

43 Id. at 2.
Docket No. RM16-17-001 - 17 -

if they have claimed and demonstrated that the relationship with those entities or facilities 

is passive.44

TAPS explains that, with respect to the relational database, distinguishing between 

passive owners and affiliates takes on greater importance. TAPS contends that failing to 

do so will substantially frustrate the Commission’s ability to regulate the exercise of 

market power and ensure just and reasonable rates.45

TAPS contends that the generalized affirmation requirement described in Order 

No. 860 is much less specific than what was proposed in the NOPR.46 TAPS thus 

requests that the Commission clarify that, for each owner that a Seller identifies as 

passive, the Seller must specifically (1) affirm whether each passive owner owns a 

separate class of non-voting securities, has limited consent rights, does not exercise 

day-to-day control over the company, and cannot remove the manager without cause; and 

(2) provide information sufficient to show that the Seller performed the requisite 

 44 TAPS Request at 6-7 (citing Refinements to Policies & Procedures for MarketBased Rates for Wholesale Sales of Elec. Energy, Capacity & Ancillary Servs. by Pub. 

Utils., Order No. 816, 153 FERC ¶ 61,065, at P 284 (2015), order on reh’g and 

clarification Order No. 816-A, 155 FERC ¶ 61,188 (2016)).

45 Id. at 7-8.

46 Id. at 8 (quoting NOPR, 156 FERC ¶ 61,045 at P 26 (“[W]e also propose . . . 

that with respect to any owners than [a Seller] represents to be passive, the [Seller] affirm 

in its ownership narrative that its passive owner(s) own a separate class of securities, 

have limited consent rights, do not exercise day-to-day control over the company, and 

cannot remove the manager without cause.”)).
Docket No. RM16-17-001 - 18 -

investigation for these affirmations.

47 According to TAPS, this clarification will allow 

the Commission to ensure that Sellers are complying with the Commission’s existing 

policy regarding the definition of a passive investor and impose little, if any, additional 

burden on Sellers as they must already identify and investigate each of these four 

attributes of the ownership interests to make the affirmation.48

TAPS adds that requiring Sellers to include this basic information in their marketbased rate filings is consistent with existing Commission practice and does not require a 

determination as to passivity. TAPS references the EquiPower Resources Management, 

LLC proceeding, in which Commission staff issued a letter with several questions 

regarding the passive nature of the ownership interests involved in the application for 

market-based rate authorization.49 TAPS states that the Commission then granted the 

application by letter order without making any determination as to the passive ownership 

interests. TAPS points out that these questions concern the same matters as the NOPR’s 

proposed affirmation requirement. TAPS asks that the Commission make clear that a 

“narrative that the ownership interests consist solely of passive rights that are necessary 

 47 Id. at 8-9.

48 Id. at 10.

49 EquiPower Res. Mgmt., LLC, Docket No. ER10-1089-000 (June 16, 2010) 

(deficiency letter).
Docket No. RM16-17-001 - 19 -

to protect the passive investors’ or owners’ investments and do not confer control” 

include responses to these questions.50

If the Commission does not grant this clarification, TAPS requests rehearing of the 

Commission’s decision to allow Sellers to make an affirmation instead of a 

demonstration regarding passive ownership interests.51 TAPS asserts that this vague 

affirmation requirement is contrary to the Commission’s obligations under the FPA and 

represents an unexplained departure from the Commission’s prior requirement in Order

No. 81652 that Sellers demonstrate passivity. According to TAPS, although the 

Commission stated that a demonstration is unnecessary given that the Commission makes 

no findings as to passivity in its orders granting market-based rate authority, the 

Commission did not explain the departure from the requirement in Order No. 816 that 

Sellers demonstrate passivity before excluding certain information from asset appendix 

entries.53 TAPS contends that the Commission’s statement that it is not changing the 

 50 TAPS Request at 10-12.

51 Id. at 13 (quoting Order No. 860,168 FERC ¶ 61,039 at P 137).

52 See Order No. 816, 153 FERC ¶ 61,065 at P 284.

53 TAPS Request at 13-14 (citing Order No. 860, 168 FERC ¶ 61,039 at P 284). 

TAPS also points out that the final rule did not cite to Order No. 816 at all in its 

discussion of passive ownership. Id. n.9.
Docket No. RM16-17-001 - 20 -

substantive standards governing a determination of passivity, or the timing of such a 

determination, does not justify a change in Sellers’ reporting obligations.54

c. Commission Determination

We deny clarification and rehearing with respect to the Commission’s directive in 

footnote 209 of the final rule that “Sellers should provide the identity of new passive 

owner(s) in their narratives when making their passive affirmation.”55 FMP and 

Starwood argue that this directive is inconsistent with provisions in the final rule as well 

as Commission precedent. FMP and Starwood also contend that footnote 209 represents 

a departure from Commission precedent and the NOPR did not provide notice of this 

change. We disagree for the reasons discussed below.

FMP and Starwood misread the Commission’s discussion of passive ownership in 

the final rule, including the clarification regarding new passive owners in footnote 209. 

The only substantive change the Commission made regarding passive interests in the 

final rule was to require Sellers to make an affirmation, in lieu of a demonstration, in 

their market-based rate narratives concerning their passive ownership interests.56 The 

Commission concluded that such a demonstration was unnecessary because it makes no 

findings regarding passivity in its orders granting market-based rate authority and thus an 

 54 Id. at 13-14.

55 Order No. 860, 168 FERC ¶ 61,039 at P 141 n.209.

56 Id. P 137.
Docket No. RM16-17-001 - 21 -

affirmation would reduce the burden on filers.57 In addressing a comment in the final 

rule, the Commission noted that “passive owners need not be reported in the database”58

and, in footnote 209, it only clarified that Sellers should provide the identities of the 

owners they are claiming to be passive in their transmittal letters. It is not inconsistent to 

say that passive owners need to be identified in the narrative but do not need to be 

reported in the database. Moreover, providing the names of such owners is consistent 

with current practice.59 The use of “new” in footnote 209 means Sellers will only need to 

make the affirmation for, and provide the identify of, passive owners whom they have not 

previously identified to the Commission in a market-based rate proceeding.60

In addition, we disagree with FMP and Starwood that footnote 209 is inconsistent 

with Commission precedent. In the final rule, the Commission expressly provided that 

nothing in the final rule would impact, let alone overturn, the Commission’s case-specific 

determinations as to passivity and an entity’s reporting obligations under previously 

issued declaratory orders.61 Consistent with current Commission policy, Sellers must 

 57 Id.

58 Id. P 141.

59 Order No. 697-A, 123 FERC ¶ 61,055 at n.258.

60 In other words, this requirement will not apply to those Sellers who have made a 

passive demonstration prior to the effective date of the final rule.

61 Order No. 860, 168 FERC ¶ 61,039 at P 140 (“Nothing in this [F]inal [R]ule is 

intended to overturn the Commission’s case-specific determinations as to passivity and 

an entity’s reporting obligations under previously issued declaratory orders.”).
Docket No. RM16-17-001 - 22 -

continue to disclose new passive owners should the Seller acquire them unless those 

Sellers received case-specific determinations as to passivity and reporting obligations 

under a declaratory order. Thus, the entities that are the subject of the AES Creative, 

Starwood, and Ad Hoc declaratory orders may continue to rely on the determinations as 

to passivity in those orders as well as the associated reporting obligations. However, to 

the extent that entities not subject to those orders have relied on those orders for reporting 

obligations, we clarify that those entities must comply with the Commission’s current 

policy described above and, when the final rule takes effect, as articulated in the final 

rule. 

For these reasons, we also disagree with FMP and Starwood that the NOPR 

provided insufficient notice of a change in filing requirements regarding passive 

ownership. The Commission changed no aspect of its policy on passive owners except 

for reducing a Seller’s burden from a demonstration to simple affirmation. What FMP 

and Starwood characterize as a change to Commission policy in footnote 209 is only an 

explanation regarding existing policy, which will remain unchanged when the final rule 

takes effect. 

We also deny clarification with respect to TAPS’s request that the affirmation: 

(1) affirm whether each passive owner owns a separate class of non-voting securities, has 

limited consent rights, does not exercise day-to-day control over the company, and cannot 

remove the manager without cause; and (2) provide sufficient information to show that a 

Seller performed an investigation for the affirmation. Likewise, we deny TAPS’s
Docket No. RM16-17-001 - 23 -

alternative request for rehearing on the Commission’s decision to allow Sellers to make 

an affirmation instead of a demonstration regarding passive ownership interests.

Although we agree with TAPS that, for the relational database to function 

correctly and as intended, owners must be properly classified as passive, we decline to 

grant rehearing to require, as TAPS requests, that the affirmation specifically affirm each 

of the four attributes of passivity identified in the NOPR and for each Seller to provide 

sufficient information to show that the Seller performed the requisite investigation for the 

affirmation. First, Order No. 860’s requirement that a Seller identify passive owners and 

affirm in its narrative that the ownership interests consist solely of passive rights that are 

necessary to protect the passive investors’ or owners’ investments and do not confer 

control is taken from AES Creative’s requirements for passive ownership interests.62 As 

contemplated in AES Creative, passive owners cannot hold voting securities, have more 

than limited consent/veto rights, or allow day-to-day control over a company.63 In 

addition, the Commission clarified in Order No. 860 that “absent a Commission order to 

the contrary, an owner who can remove the manager without cause is not considered 

passive.”64 Thus, we reiterate here that unless the Commission specifically finds 

otherwise in a particular case, a Seller will not be able to make the passive affirmation 

where the owner can remove the manager without cause. Given that Sellers cannot make 

 62 Order No. 860, 168 FERC ¶ 61,039 at P 138 & n.206.

63 See AES Creative, 129 FERC ¶ 61,239 at PP 25-26.

64 Order No. 860, 168 FERC ¶ 61,039 at P 140.
Docket No. RM16-17-001 - 24 -

the requisite affirmation unless they can affirm that the ownership interests meet the AES 

Creative requirements and do not allow an owner to remove the manager without cause,

we decline to require the specificity that TAPS requests. 

Similarly, we deny clarification with respect to the information to be provided in 

the affirmation. Prior to the final rule, Sellers were required to make a demonstration 

regarding passive ownership, even though the Commission made no findings with respect 

to whether these ownership interests were truly passive. Accordingly, in the final rule, 

the Commission chose to reduce the filing requirements associated with making passive 

ownership representations. To require Sellers to show that they have sufficient 

information to make the affirmation would be to effectively continue the demonstration 

requirement. As explained, Sellers cannot affirm that their ownership interests consist 

solely of passive rights that are necessary to protect the passive investors’ or owners’ 

investments and do not confer control unless they have verified that those ownership 

interests meet the requirements of AES Creative. These Sellers must also abide by a duty 

of candor when making any filings with the Commission.65 For these reasons, we also 

deny TAPS’s alternative request for rehearing.

B. Connected Entity Information

1. Final Rule

In Order No. 860, the Commission declined to adopt the proposal to require 

Sellers and Virtual/FTR Participants to submit Connected Entity Information. The 

 65 18 CFR 35.41(b).
Docket No. RM16-17-001 - 25 -

Commission acknowledged commenters’ concerns about the difficulties and burdens 

associated with this aspect of the NOPR and, accordingly, transferred the record to 

Docket No. AD19-17-000 for possible consideration in the future as the Commission 

may deem appropriate. However, the Commission noted that the determination in the 

final rule to collect market-based rate information in a relational database will provide 

value to both the Commission’s market-based rate and analytics and surveillance 

programs.66

2. Request for Clarification and/or Rehearing

Joint Advocates request limited rehearing of the final rule and argue that the 

Commission erred: (1) by not applying the requirement to collect Connected Entity 

Information from Sellers and Virtual/FTR Participants; and (2) in failing to require 

Virtual/FTR Participants to abide by a duty of candor.

Joint Advocates first contend that the finding in the final rule that the Connected 

Entity reporting requirements are unduly burdensome is unsupported by the evidence and 

conclusory in nature. Joint Advocates argue that, although the final rule acknowledges 

that the Connected Entity Information proposal was among the most commented on, it 

says nothing more than there were many concerns raised about the difficulties and burden 

associated with the proposal. Joint Advocates contend that this statement alone does not 

support why the Commission failed to act on the proposal or why the proposal’s benefits 

 66 Order No. 860, 168 FERC ¶ 61,039 at P 184.
Docket No. RM16-17-001 - 26 -

are outweighed by any burden. Joint Advocates assert that the final rule instead ignores 

the record except for a cursory statement about supporting comments.67 

Joint Advocates argue that the final rule focuses solely on comments regarding the 

proposal’s alleged burdens but takes that evidence out of context. Joint Advocates 

contend, for example, that AVANGRID, Inc.’s (AVANGRID) and EEI’s comments were 

critical of the burden imposed by the whole NOPR and that it is not reasoned decisionmaking to refer to these criticisms as if they apply only to the collection of Connected 

Entity Information.68 Joint Advocates explain that the final rule references only one 

other set of comments, i.e., Berkshire Hathaway Energy Company’s (Berkshire) 

comments, and that these comments note concerns with the previous Connected Entity

proposal;

69 however, Joint Advocates argue that Berkshire does not ask the Commission 

to wholly set aside the Connected Entity proposal but rather raises issues specific to its 

own business model. Joint Advocates argue thus that Berkshire’s comments do not 

support the final rule’s decision to set aside the Connected Entity proposal.70

 67 Joint Advocates Request at 8-9.

68 Id. at 9-10.

69 See Collection of Connected Entity Data from Reg’l Transmission Orgs. and 

Indep. Sys. Operators, Notice of Proposed Rulemaking, 152 FERC ¶ 61,219 (2015) 

(Connected Entity NOPR); Collection of Connected Entity Data from Reg’l Transmission 

Orgs. and Indep. Sys. Operators, Withdrawal of Proposed Rulemaking and Termination 

of Rulemaking Proceeding, 156 FERC ¶ 61,046 (2016). 

70 Joint Advocates Request at 10-11.
Docket No. RM16-17-001 - 27 -

Joint Advocates next assert that the final rule’s preferential treatment for 

Virtual/FTR Participants is discriminatory in both intent and application. Joint Advocates 

assert that the Commission has long recognized that virtual products, transactions 

involving such products and that, accordingly, sellers of such products, i.e., Virtual/FTR 

Participants, are subject to the Commission’s jurisdiction.71 Joint Advocates also point 

out that Virtual/FTR Participants are similarly situated with other market Sellers in that 

they are capable of affecting Commission-jurisdictional market prices. Joint Advocates 

contend that, even if the Commission adopted the Connected Entity proposal, the overall 

reporting requirements would still be significantly less than those for Sellers and that, 

without the Connected Entity requirements, Virtual/FTR Participants, unlike Sellers, have 

no duty of candor under the Commission’s regulations. According to Joint Advocates, the 

failure to adopt the Connected Entity proposal maintains a two-tiered regulatory scheme 

that is both unjust and unduly preferential and violates section 206 of the FPA. Joint 

Advocates argue that the appropriate remedy is to adopt the Connected Entity proposal 

and subject Virtual/FTR Participants to similar oversight as Sellers.72

Lastly, Joint Advocates assert that the final rule deprives the Commission of 

important tools to address and combat market manipulation and fraud. Joint Advocates 

echo the concerns in the dissent, including with respect to the GreenHat Energy, LLC’s 

 71 Id. at 11.

72 Id. at 12.
Docket No. RM16-17-001 - 28 -

default on its FTRs in the PJM market, and note the harm that could result from recidivist 

persons that commit fraud is real.73 

Joint Advocates request in the alternative that the Commission accept their 

comments in the record of Docket No. AD19-17-000. Joint Advocates also ask that the 

Commission expediently implement the Connected Entity proposal and any additional 

reforms offered in Docket No. AD19-17-000 given the clear potential for future market 

manipulation, fraud, and default.74

3. Commission Determination

As discussed below, we deny Joint Advocates’ request for rehearing. We disagree 

with Joint Advocates’ characterization of the Commission’s determination in the final 

rule. The Commission did not state that the Connected Entity reporting requirements are 

“unduly burdensome,” rather the Commission stated that it “appreciate[s] the concerns 

raised about the difficulties of and burdens imposed by”75 the Connected Entity proposal. 

Further, we disagree with Joint Advocates’ assertion that the final rule takes evidence 

regarding the burden of the Connected Entity proposal out of context. We acknowledge 

that AVANGRID’s and EEI’s comments expressed concerns about the burdens 

associated with both the market-based rate and Connected Entity proposals. However, 

 73 Id. at 13-14.

74 Id. at 3.

75 Order No. 860, 168 FERC ¶ 61,039 at P 184.
Docket No. RM16-17-001 - 29 -

the final rule elsewhere addressed commenters’ concerns with the market-based rate 

proposal and made adjustments, clarifications, and determinations as needed.

76 

Regarding the Connected Entity proposal, the final rule did not detail all of the 

commenters’ concerns. For example, commenters expressed concerns with the proposal, 

specifically with the proposed definition of “trader,”77 the scope of the proposal,78 and 

other aspects of the Connected Entity proposal.79 Ultimately, in the final rule, the

Commission noted AVANGRID’s, EEI’s, and Berkshire’s concerns while also noting

that some commenters supported the Connected Entity proposal. After consideration of 

all of the comments, the Commission transferred the record to Docket No. AD19-17-000 

“for possible consideration in the future as the Commission may deem appropriate.”80 In 

doing so, the Commission acknowledged that it could explore the Connected Entity 

 76 For example, in response to commenters’ concerns, the Commission decided to 

not adopt the requirement for Sellers to identify their relationships with foreign 

governments. Id. P 146.

77 Berkshire at 13-17, EEI at 11-15; International Energy Credit Association at 5-12; 

AVANGRID at 11-12; NextEra Energy, Inc. at 4-6; Manitoba Hydro at 3; Power Trading 

Institute at 5-6; Financial Institutions Energy Group 10-11.

78 AVANGRID at 14-17; International Energy Credit Association at 22-23; 

Financial Institutions Energy Group at 4-13; Commercial Energy Working Group 

at 20-22.

79 See International Energy Credit Association at 17-19; Power Trading Institute 

at 5 (opposing the requirement for Sellers to obtain LEIs); Berkshire at 4-8; NextEra 

Energy, Inc. at 3-4 (opposing the requirements to disclose certain affiliates that would fall 

within the definition of “connected entities”).

80 Order No. 860, 168 FERC ¶ 61,039 at P 184.
Docket No. RM16-17-001 - 30 -

proposal in the future. Accordingly, we accept Joint Advocates’ alternative request and 

place their instant comments in the record of Docket No. AD19-17-000 for consideration 

in the future as the Commission may deem appropriate. 

C. Implementation & Data Dictionary

1. Final Rule

In the final rule, the Commission revised the previous implementation schedule in 

the NOPR based on concerns regarding feasibility. The Commission explained that 

initially, after the final rule’s issuance, documentation for the relational database will be 

posted to the Commission’s website, including the extensible markup language document 

(XML), XML Schema Definition document (XSD), the Data Dictionary, and a test 

environment user guide as well as a basic relational database test environment. 

Additionally, the Commission stated that it intends to add to the new test environment 

features on a prioritized, scheduled basis until complete. The Commission stated that it 

would inform the public when releases will be made publicly available.81 

The Commission stated that, during the development and testing phase, it would 

encourage feedback from outside testers and that, to facilitate this feedback, Commission 

staff will conduct outreach with submitters and external software developers, making any 

necessary corrections to available requirements and/or documentation.82 In addition, the 

Commission explained that, in spring 2020, a user guide and a list of frequently asked 

 81 Id. PP 308-309.

82 Id. P 310.
Docket No. RM16-17-001 - 31 -

questions regarding the process for preparing and submitting information into the 

relational database will be available on its website.83

The Commission also explained that, in fall 2020, submitters will be required to 

obtain FERC generated IDs (GID)84 for any reportable entity85 that does not have a CID

or LEI,

86 as well as the Commission-issued “Asset Identification” (Asset ID) number87

for any reportable generation asset without a Plant Code, Generator ID, and Unit Code 

information from the Energy Information Agency (EIA) Form EIA-860 database 

 83 Id. P 311.

84 The GID is a new form of identification that was created alongside the final rule 

to serve as an identifier for reportable entities that do not have a Company Identifier 

(CID) or Legal Entity Identifier (LEI). The Commission explained that the system will 

allow Sellers to obtain unique GIDs for their affiliates and that additional information on 

the mechanics of this process will be made available on the Commission’s website prior 

to the final rule’s October 1, 2020 effective date. The Commission required affiliates to 

be identified using their CID if they have one, but if they do not, the Seller must use the 

LEI for the affiliate if available. If the affiliate has neither, the Commission required that 

the GID must be provided. Id. P 24 n.42.

85 Reportable entities are any companies or natural persons that a Seller needs to 

identify in its database submissions.

86 LEI is a unique 20-digit alpha-numeric code assigned to a single entity. They 

are issued by the Local Operating Units of the Global LEI System. Id. P 18 n.30.

87 Id. P 64. The Commission added that, when creating the Asset ID, Sellers will 

be required to provide basic information about the generator, such as its plant name, 

nameplate capacity, and month and year it began commercial operation (if known). Id.

n.108.
Docket No. RM16-17-001 - 32 -

(collectively, EIA Code). 88 The Commission stated that more information on 

discovering or obtaining these IDs will be published on the Commission’s website.89 

The Commission explained that, after all necessary IDs are acquired, submitters 

must then submit their baseline submissions into the relational database by close of 

business on February 1, 2021.90

The Commission stated that, to the extent that the Commission finds that technical 

workshops would be helpful after publication of the final rule, it will provide for those 

workshops.91 In addition, the Commission explained that, if necessary, requests for an 

extension to the initial submission deadlines may be submitted similar to the way in 

which a current request for extension of time would be submitted to the Commission for 

consideration.92

The Commission determined that it would post the Data Dictionary and supporting 

documentation to the Commission’s website.93 The Commission also concluded that 

there was no need for additional notice and opportunity for comment on the Data 

 88 Id. PP 64, 313. 

89 Id. P 313.

90 Id. P 312.

91 Id. P 317.

92 Id. P 318 & n.398 (citing 18 CFR 385.212).

93 Id. P 209.
Docket No. RM16-17-001 - 33 -

Dictionary, but the Commission noted that Sellers may reach out to Commission staff for 

further information.94

2. Request for Clarification and/or Rehearing

EEI requests clarification regarding several implementation issues.95 First, EEI 

argues that the implementation timeline should be extended to reflect the scope of the 

data required to be submitted and implementation challenges. EEI suggests that the 

Commission has adopted an unreasonably short timeline for implementing the final rule,

considering the numerous questions as to implementation.96 EEI argues that unexpected 

delays could impact compliance with the final rule and that, while the Commission has 

posted information regarding the XML, XSD, and Data Dictionary, it should also provide 

clarity as to when the other tools mentioned in the final rule will be available to users if 

such information is known.97

According to EEI, the scope and breadth of the data gathering effort will be 

extensive in most cases because the data to be gathered is nuanced and requires judgment 

to determine whether the data falls within the final rule’s scope. EEI notes that the 

Commission now requests data on: (1) the contents of market-based rate tariffs and 

certain power purchase agreements (PPAs); (2) IDs associated with counterparties to 

 94 Id. P 212.

95 EEI Request at 4.

96 Id.

97 Id. at 4-5 (quoting Order No. 860, 168 FERC ¶ 61,039 at PP 309-310).
Docket No. RM16-17-001 - 34 -

those PPAs; (3) dates related to the various elements of the market-based rate tariffs and 

PPAs; (4) certain generation; and (5) certain affiliates. EEI points out that the breadth of 

this data is greater than what is collected today for asset appendices and that it may be 

difficult to identify who may hold this information, given that ultimate upstream owners 

often restrict the flow of data among affiliates.98

In addition, EEI explains that one of the first tasks of each Seller will be to 

determine for which generating assets it lacks EIA Codes and for which affiliates and 

counterparties, if any, it lacks a CID or LEI. EEI points out that in both cases the 

Commission must first generate data. EEI explains that requests for GIDs and Asset IDs 

are to be submitted in Fall 2020 and that given the compliance deadline and the fact that 

the Commission must first compile requests, this date occurs too late in the process to 

meet the Commission’s current implementation date. EEI also submits that the 

Commission first must post a CID list that is kept up-to-date so Sellers can know whether 

to request an GID.99 EEI posits, however, that the Commission must recognize that it 

will take time for Sellers to determine the set of PPAs that require GIDs because no list 

of PPAs under which the Seller is a long-term Seller likely exists and, if a Seller’s 

Electric Quarterly Report (EQR) contains such a list, it must be sorted by long-term sales 

 98 Id. at 10-11.

99 Id. at 11.
Docket No. RM16-17-001 - 35 -

of energy or capacity. EEI provides that only then can the CID list be checked to 

determine the need for an GID.100

EEI maintains that another issue that will affect the implementation timeframe is 

the need for internal compliance personnel and compliance programs to determine 

ongoing compliance. EEI suggests that such personnel will be spread over many 

departments and training will be required to establish reporting obligations and on the use 

of data collection software if data entry is not centralized.101

EEI contends that the data entry task will be substantial for some reporting entities 

and should be considered in estimating compliance time.102 EEI suggests that, because 

the data entry and data gathering tasks are potential sources of human error, some level of 

review may be necessary post-data collection to ensure that obvious errors or omissions 

have not occurred. 

EEI next contends that technical conferences are needed to refine the Data 

Dictionary and clarify the data that must be collected. For example, EEI references the 

Commission’s guidance in the final rule regarding reporting the number of megawatts 

associated with full and partial requirements sales agreements, i.e., “[f]or a full 

requirements contract, the amount should equal the buyer’s most recent historical annual 

 100 Id. at 11-12.

101 Id. at 12.

102 Id. at 13.
Docket No. RM16-17-001 - 36 -

peak load” and “for a partial requirements contract, the amount should equal the portion 

of the buyer’s requirements served by the seller multiplied by the buyer’s annual peak 

load.”103 EEI argues that this guidance raises several questions, and entities will have 

difficulty knowing what data to gather and report. Each entity may interpret the data 

requirements differently without Commission clarification.

104 

EEI also questions the need for many of the date fields in the Data Dictionary. For 

example, EEI argues that the need for a field on “relationship_start_date” in the 

“entities_to_entities” table is unclear. EEI contends that, unless the Commission explains 

the need for retroactive dates in this field, as well as in other fields such as the 

“cat_status_effective_date” field in the category status table, it should allow the Sellers to 

use the date of the baseline filing and not seek historical dates. EEI asserts that if the 

Commission does not accept this alternative, it should allow discussion during the 

technical conference on how this burden can be reduced. In addition, EEI states that both 

outside vendors and in-house personnel will build data collection software for the final 

rule. EEI argues however that the Data Dictionary in and of itself does not allow 

software developers to understand what is needed in the software. EEI references several 

tables, including “mbr_authorization,” “mbr_category_status,” and 

“entities_to_genassets,” which could each be populated in different ways. EEI thus 

maintains that, for the software to have the functionality needed to meet the 

 103 Id. (quoting Order No. 860, 168 FERC ¶ 61,039 at P 94).

104 Id. at 6-7.
Docket No. RM16-17-001 - 37 -

Commission’s needs, Commission staff and Sellers must explain to software developers 

how each table in the Data Dictionary will work. 

Similarly, EEI suggests that software developers will need time to understand how 

each table may be used by a variety of customers before they can begin coding. EEI 

maintains that, because Sellers will require new data collection software to convert the 

collected data into an XML format, technical conferences will be useful for providing 

feedback about how long this process will take. EEI suggests that developing new 

software can take between six months to more than a year and that the relational database 

is more complicated than past Commission endeavors because some entities will not have 

a vendor in place. EEI submits that most Sellers will need time to contract to develop 

software, the process of which will likely take several months.105

EEI further provides comments on specific fields, such as the “PPA Agreement ID”

field in the PPA table. EEI requests that the Commission verify that the identifier for each 

PPA should be the one used in EQR Field 20 only if the Seller is making a sale and that, 

where the Seller is purchasing long-term, it does not need to check to see: (1) if the Seller 

files EQRs; and (2) review the EQR of that Seller and find its identifier in its Field 20.106 

In regards to operating reserves, EEI requests that the Commission clarify that it is only 

seeking information as to Sellers who receive a Seller-specific order as to permit sales of 

 105 Id. at 12-13.

106 Id. at 15.
Docket No. RM16-17-001 - 38 -

operating reserves in a non-ISO/RTO balancing authority area in which it would otherwise 

be prohibited from selling under the model tariff wording.107

Lastly, EEI seeks clarification that Commission staff can make changes to the 

Data Dictionary fields as appropriate to reflect the outcome of the technical 

conference.108 

3. Commission Determination

We grant EEI’s request for clarification in part and deny it in part. First, we deny 

EEI’s request to extend the implementation timeline and disagree with EEI’s assessment 

that the scope and breadth of the data gathering effort will be extensive. As noted in the 

final rule, Sellers already collect most of the information required to be submitted under 

the final rule, either as part of the narratives in their market-based rate filings, asset 

appendices, EQRs, or as part of their market-based rate tariffs.109 For example, Sellers 

should already have available a list of long-term PPAs in which they are the seller 

because such sales are reported in EQRs. The final rule merely alters the manner in 

which Sellers will provide this data to the Commission. Additionally, the current 

implementation timeline provides Sellers with over 18 months to gather any new data 

 107 Id. at 17.

108 Id.

109 Order No. 860, 168 FERC ¶ 61,039 at PP 88, 90, 97, 105, 122, and 158.
Docket No. RM16-17-001 - 39 -

that they may be required to submit into the database.110 We find this to be enough time 

to gather any necessary information. 

In response to EEI’s concerns that Sellers and vendors will not have enough time 

to become familiar with the submission process, we note that on January 10, 2020, the 

Commission provided, on its website,111 updated versions of the Data Dictionary, XML,

XSD, and a frequently asked questions document, as well as provided access to a test 

environment for the relational database.112 We expect that these items should provide 

Sellers, vendors, and other interested parties with a reasonable level of clarity on what 

Sellers will be required to submit and aid in the creation of tools to make those 

submissions. In regard to EEI’s concerns that Sellers may not have enough time to 

determine for which affiliates or counterparties it needs to obtain a GID and which 

generating assets need Asset IDs, we note that the test environment (and the future portal 

for the relational database) should address these concerns. Sellers will find within the 

test environment tools to search for existing CIDs, LEIs, and GIDs, as well as the 

 110 Submitters have until close of business February 1, 2021 to make their initial 

baseline submissions.

111 This information can be found at https://www.ferc.gov/industries/electric/geninfo/mbr/important-orders/OrderNo860.asp.

112 This test environment, and eventually the relational database, can be found at

https://mbrweb.ferc.gov/.
Docket No. RM16-17-001 - 40 -

mechanism to create GIDs and Asset IDs.113 Further, because the EIA Codes will be 

pulled from EIA, Sellers may also review the most recent EIA-860 table to discover 

whether they need to create an Asset ID for any generation asset.114 Sellers will also be 

able to make test submissions into the relational database, which will help them to 

become familiar with the submission requirements of the database and how to format the 

data required.115 

We anticipate that these items, along with the technical workshop, will provide 

interested parties with sufficient information and tools to be able to make their 

submissions. While we appreciate EEI’s argument that unexpected delays could impact 

compliance with the final rule, to date, no such delays have occurred. Nevertheless, if 

unexpected delays do occur, Sellers may seek an extension of time to make their baseline 

submissions. Further, to the extent that EEI remains concerned about human error, we 

reiterate that the Commission’s usual practice is simply to require a corrected submittal 

be made without any sanctions.116 

 113 The ability to search for EIA Codes or Asset IDs for generation assets will be 

introduced into the test environment a future update.

114 See https://www.eia.gov/electricity/data/eia860/.

115 As noted in the January 10, 2020 notice, this is a test environment and all 

submissions into the database, specifically, XMLs and all created GIDs and Asset IDs, 

will not be part of the official record and will be cleared from the database before it 

officially goes live. 

116 Order No. 860, 168 FERC ¶ 61,039 at P 293.
Docket No. RM16-17-001 - 41 -

Next, we grant EEI’s request that the Commission hold a technical workshop, and we 

note that Commission staff will be hosting a technical workshop on February 27, 2020.

117 

We expect that many of EEI’s concerns with the Data Dictionary and the data that must be 

collected will be addressed at the technical workshop. Nevertheless, we take this 

opportunity to provide some clarifications. 

We will allow the use of a January 1, 1960 default date for certain date fields, for 

dates that occur before the October 1, 2020 effective date of the final rule, when 

populating the database.118 For example, Sellers may input January 1, 1960 for date 

fields such as “relationship_start_date” in the “entities_to_entities” table if the 

relationship between the entities began before October 1, 2020 and the seller does not 

know the actual start date.119 

 117 See Notice of Technical Workshop, Docket No. RM16-17-000 (Jan. 22, 2020).

118 We will continue to require Sellers to populate the “authorization_effective_date” 

field in the “mbr_authorizations” table with the actual date that their market-based rate 

tariffs first became effective. For most Sellers this date is easily discoverable as it is in their 

market-based rate tariff. Additionally, Commission staff currently maintains, and posts on 

the Commission’s website, a document where Sellers can discover this date. See 

https://www.ferc.gov/industries/electric/gen-info/mbr/mbr-contact.xlsxError! Hyperlink 

reference not valid..

119 One field that EEI specifically inquired about is the “cat_status_effective_date” 

field in the “mbr_category_status” table. We clarify that for category statuses granted 

prior to October 1, 2020, Sellers may use the default date. For any changes to category 

statuses that occur after that date, Sellers should populate the effective date of the tariff 

that first reflects the changed status.
Docket No. RM16-17-001 - 42 -

We also verify that the “ppa_agreement_id” field in the “entities_to_ppas” table 

will be nullable and Sellers should only populate this field with the ID number in EQR 

Field 20 when they are reporting their own long-term sales. Stated another way, we do 

not expect Sellers to review the EQRs of their counterparties when preparing their 

submissions into the relational database. 

Regarding operating reserves, we clarify that we are not seeking information on 

operating reserve authority provided for in standard market-based rate tariff provisions. 

The Commission is only seeking information on Sellers who have received a sellerspecific authority to make sales of operating reserves at market-based rates.120 Further, 

for specific questions about the Data Dictionary or other implementation issues, Sellers

and other interested parties may contact Commission staff at MBRdatabase@ferc.gov.

D. Public Access

1. Final Rule

In Order No. 860, the Commission clarified that certain aspects of a Seller’s 

market-based rate filing can appear in eLibrary as either public or non-public. The 

 120 The market-based rate standard tariff includes provisions for sales of ancillary 

services, including sales of operating reserves, in designated organized markets as well as 

for third-party sales. The third-party sales of ancillary service tariff provision specifies 

that authority for sales of “Operating Reserve-Spinning and Operating ReserveSupplemental do not include sales to a public utility that is purchasing ancillary services 

to satisfy its own open access transmission tariff requirements to offer ancillary services

to its own customers, except where the Commission has granted authorization.” See

http://www.ferc.gov/industries/electric/gen-info/mbr/filings/tariff-changes/provisions.asp

(emphasis added). The Commission will only require operating reserve information 

where such specific authorization was granted. 
Docket No. RM16-17-001 - 43 -

Commission noted that a Seller, like anyone else submitting information to the 

Commission, may request privileged treatment of its filing if it contains information that 

is claimed to be exempt from the Freedom of Information Act’s mandatory disclosure 

requirements.121 The Commission stated that it did not expect that the information 

required to be submitted into the relational database will qualify for privileged treatment

and consequently declined to incorporate confidentiality safeguards in the relational 

database.

122 

2. Request for Clarification and/or Rehearing

TAPS requests that the Commission clarify that the public has a right to access the 

relational database.123 According to TAPS, in the final rule, the Commission repeatedly 

explains that its expectation is that the public will have access to the relational 

database.124 TAPS argues, however, that neither the final rule nor the amended 

regulatory text directly states that the public will have the right to access, search, and use 

information contained in the relational database. TAPS requests that the Commission 

expressly clarify that the public will have the right to do so.125

 121 See 5 U.S.C. 552.

122 Order No. 860, 168 FERC ¶ 61,039 at P 284.

123 TAPS Request at 4.

124 Id. (citing Order No. 860, 168 FERC ¶ 61,039 at PP 151, 152, 158, 234, 284).

125 Id.
Docket No. RM16-17-001 - 44 -

TAPS points out that full access to the relational database and its functions is 

critical because the relational database will be one of the only remaining sources of 

information about the potential for anticompetitive market power. TAPS explains that 

this is because the final rule eliminated the requirement to submit organizational charts 

and for each Seller to report the assets of its affiliates with market-based rate authority. 

TAPS adds that the Commission also eliminated, in a separate rulemaking, the 

requirement that Sellers in certain RTO/ISO markets submit indicative screens for 

assessing horizontal market power.126

TAPS explains that the final rule also implies that the public will have broad 

access rights through the relational database’s services function. However, TAPS argues 

that the final rule does not define services function or specify that the public will have 

access to all of the relational database’s functions. TAPS thus requests that the 

Commission clarify that the public’s right to access the relational database includes the 

ability to use all the functions available to the Commission.127

In addition, TAPS requests that the Commission clarify that the public will have 

access to the following: (1) the relational database function that generates organizational 

charts; (2) the same historical data as filers (i.e., Sellers); and (3) the full set of marketbased rate information, either through eLibrary or otherwise, including information

 126 Id.

127 Id. at 4-5.
Docket No. RM16-17-001 - 45 -

Sellers submit into the database. TAPS also asks that the Commission clarify that all of 

the historical data preserved will be publicly available.128

3. Commission Determination

As TAPS requests, we clarify that the public will be able to access the relational 

database. In this regard, we clarify that we will make available services through which 

the public will be able to access organizational charts, asset appendices, and other reports, 

as well as have access to the same historical data as Sellers, including all market-based 

rate information submitted into the database. We also clarify that the database will retain 

information submitted by Sellers and that historical data can be accessed by the public.

E. Due Diligence

1. Final Rule

With respect to the due diligence standard in § 35.41(b), the Commission stated 

that it generally will not seek to impose sanctions for inadvertent errors, misstatements, 

or omissions in the data submission process. The Commission stated its expectation that 

Sellers will apply due diligence to the retrieval and reporting of the required information 

by establishing reasonable practices and procedures to help ensure the accuracy of their 

filings and submissions, which should minimize the occurrence of any such inadvertent 

errors, misstatements, or omissions. However, the Commission explained that the 

intentional or reckless submittal of incorrect or misleading information could result in the 

Commission imposing sanctions, including civil penalties. The Commission explained

 128 Id. at 5-6.
Docket No. RM16-17-001 - 46 -

that these circumstances might include, for example, systemic or repeated failures to 

provide accurate information and a consistent failure to exercise due diligence to ensure 

the accuracy of the information submitted.

129 

The Commission declined to adopt a “safe harbor” or a “presumption of good 

faith” or “good faith reliance on others defense,” nor did the Commission decide to limit 

enforcement actions to only where there is evidence demonstrating that an entity 

intentionally submitted inaccurate or misleading information to the Commission.130

The Commission reiterated that a due diligence standard provides the Commission 

with sufficient latitude to consider all facts and circumstances related to the submission 

of inaccurate or misleading information (or omission of relevant information) in 

determining whether such submission is excusable and whether any additional remedy 

beyond correcting the submission is warranted.131

The Commission explained that establishing adequate due diligence practices and 

procedures ultimately depends on the totality of facts and circumstances and can vary 

case to case, depending upon evidence presented and whether, for example, reliance on 

third parties or affiliates is justified under the specific circumstances. The Commission 

added that most Sellers have knowledge of their affiliates’ generation portfolios because 

 129 Order No. 860, 168 FERC ¶ 61,039 at PP 291-293.

130 Id. P 294.

131 Id. P 295.
Docket No. RM16-17-001 - 47 -

Sellers must include this information in their indicative screens, so to the extent that the 

auto-generated asset appendix is clearly incongruous with the screens, the Commission 

expects that the Seller will make note of the perceived error in the transmittal letter.132

The Commission explained however that, if a Seller does not have accurate or 

complete knowledge of its affiliates’ market-based rate information, in most cases it 

should be able to rely on the information provided by its affiliates unless there is some 

indication that the information the affiliate supplies is inaccurate or incomplete.133 The 

Commission added that, although Sellers should not ignore obvious inaccuracies or 

omissions, relying on information from affiliates should be sufficient to satisfy the due 

diligence standard provided there is a reasonable basis to believe that such information 

obtained from affiliates or third parties is reliable, accurate, and complete.134

2. Request for Rehearing

TAPS requests rehearing as to whether the Commission erred by (1) failing to 

include safeguards during the relational database’s initial implementation to ensure that 

the newly adopted relational database functions as intended and at least as well as the 

pre-Order No. 860 data collection regime, and (2) failing to adequately specify the 

 132 Id. PP 295-296.

133 Id. P 297.

134 Id. P 298.
Docket No. RM16-17-001 - 48 -

Commission’s expectations for satisfying the Commission’s135 due diligence 

requirements under the new reporting regime.

According to TAPS, Order No. 860 conceded the risk of reporting errors and the 

Commission erred in declining to continue existing reporting requirements or other 

safeguards during the initial implementation of the relational database.136 TAPS 

contends that the Commission also erred in failing to specify what ongoing practices and 

procedures the Commission expects Sellers to implement to satisfy their due diligence 

obligations.137

TAPS asserts that the essential component of the relational database is identifying 

common ultimate upstream affiliates among Sellers.138 TAPS argues that the relational 

database will not work if Sellers fail to correctly identify their ultimate upstream affiliates 

and that, because of complex corporate organizational structures, the risk of such failures 

is significant, as the Commission acknowledged. TAPS maintains that the risk of error 

will increase over time as changes in ownership result in a new ultimate upstream

 135 18 CFR 35.41(b).

136 TAPS Request at 14-15 (citing Order No. 860, 168 FERC ¶ 61,039 at PP 123, 

310).

137 Id. at 15 (citing Order No. 860, 168 FERC ¶ 61,039 at P 291).

138 Id. (quoting Order No. 860, 168 FERC ¶ 61,039 at P 5).
Docket No. RM16-17-001 - 49 -

affiliate. TAPS adds that other problems that could compromise the relational database 

are likely to emerge after the database is fully developed and implemented.139

TAPS contends that the final rule’s response and solution to the problem of 

misreporting are inadequate. TAPS states that the final rule claims that the CID, LEI, 

and/or GID assigned by the relational database to each ultimate upstream affiliate will 

reduce the likelihood that Sellers attempting to report the same ultimate upstream affiliate 

inadvertently report different entities.140 TAPS argues however that the Commission 

conceded that this only remedies reporting errors where Sellers are attempting to report 

the same ultimate upstream affiliates, and that it does not address the concern that some 

Sellers will misidentify their ultimate upstream affiliates at the outset.141 According to 

TAPS, the final rule claims that this error can be identified and addressed when a Seller 

views its auto-generated asset appendix.142 However, TAPS argues that the autogenerated asset appendix may not help remedy this reporting error where there is no 

specific directive that Sellers perform an independent review of the asset appendix, retain 

the audit trail necessary to do so, or report errors for correction and/or correct such errors 

 139 Id. at 15-16.

140 Id. at 16 (quoting Order No. 860, 168 FERC ¶ 61,039 at P 51).

141 Id.

142 Id. (quoting Order No. 860, 168 FERC ¶ 61,039 at P 123).
Docket No. RM16-17-001 - 50 -

unless the errors are obvious. TAPS asserts that the final rule both fails to require such 

an audit trail and even allows Sellers to rely on other Sellers’ information for accuracy.143

TAPS argues that the Commission should implement two safeguards to address 

these concerns. First, TAPS requests that, for purposes of accuracy, the Commission 

require that baseline database submissions, if not all submissions during the first three 

years of the relational database, include the asset appendix generated without using the 

database. TAPS contends that this will enable the Commission and others to check that 

the initial implementation of the relational database does not omit relevant information 

that would have been collected and made available under the previous market-based rate 

reporting regime.144

Second, TAPS requests that the Commission articulate its expectation for what 

practices Sellers should adopt after this initial three-year period to satisfy their due 

diligence obligations under § 35.41(b). Specifically, TAPS contends that the 

Commission specify that it expects Sellers’ continued due diligence practices to include: 

(1) creating appendices of affiliated generation assets developed without reliance on the 

relational database; (2) comparing the non-relational database asset appendices against 

the ones generated by the database; and (3) retention of those comparisons for a 

reasonable time (at least six years, or two triennial market power updates). TAPS 

 143 Id. at 16-17 (quoting inter alia Order No. 860, 168 FERC ¶ 61,039 at P 298).

144 Id. at 17-18.
Docket No. RM16-17-001 - 51 -

maintains that these requirements will ensure Sellers are able to identify reporting errors, 

the Commission can check the accuracy of the database-generated asset appendixes, and 

the Commission can fulfill its statutory mandate to ensure just and reasonable rates 

during this transition.145

3. Commission Determination

We deny TAPS’s request for rehearing requesting safeguards during the initial 

implementation of the relational database and requesting that there be specific 

expectations regarding due diligence obligations moving forward. We agree with TAPS 

that, for the relational database to work as intended, common ultimate upstream affiliates 

between Sellers must be correctly identified, and we expect Sellers to exercise due 

diligence as they make their initial submissions in the relational database. As stated in 

the final rule, the Commission acknowledged that there would be some risk of reporting 

errors where there are subtle changes in ownership percentages resulting in new ultimate 

upstream affiliates that may not be universally noticed and reported by all affiliated 

Sellers.146 We also acknowledge that there will be reporting errors if, as TAPS suggests, 

Sellers misidentify their ultimate upstream affiliates at the outset. However, we believe 

these reporting errors will be minimal as the Commission’s definition for ultimate 

upstream affiliate is clear.

147

 145 Id. at 18-19 (citing Order No. 860, 168 FERC ¶ 61,039 at P 292).

146 Order No. 860, 168 FERC ¶ 61,039 at P 123.

147 See supra n.9.
Docket No. RM16-17-001 - 52 -

As such, we affirm the Commission’s due diligence findings in the final rule, and 

decline to impose the additional requirements that TAPS requests. The Commission 

explained that a due diligence standard provides the Commission with sufficient latitude 

to make case-by-case considerations and that due diligence practices and procedures 

ultimately depend on the totality of the facts and circumstances, including whether 

reliance on third-parties or affiliates for information is justified.

148 We emphasize that 

the Commission’s regulations impose a duty of candor on all Sellers to provide actual and 

factual information and to not submit false or misleading information in communications, 

or omit material information, in any communication with the Commission.149 To the 

extent that there are inaccuracies in auto-generated asset appendices, we expect that 

Sellers will note those perceived errors in their transmittal letters. We reiterate that, 

while we expect that most inadvertently erroneous or incomplete submissions will be 

promptly corrected by reporting entities without the imposition of any penalty, the 

Commission will continue to exercise its discretion based on the circumstances to 

determine whether sanctions are appropriate.150

In addition, we find that TAPS’s request for additional safeguards would both be 

burdensome and undermine the benefits of establishing the relational database. First, if 

 148 See Order No. 860, 168 FERC ¶ 61,039 at PP 295-296.

149 18 CFR 35.41(b).

150 Order No. 860, 168 FERC ¶ 61,039 at P 294.
Docket No. RM16-17-001 - 53 -

the Commission required that all baseline database submissions and all submissions 

during the first three years of the relational database include asset appendices generated 

without the database, this would, in substance, continue the pre-final rule reporting 

regime except with additional filings.151 Given that a purpose of the final rule is to 

reduce burden, this requirement would run counter to the one of the goals of the final rule

and would result in a more burdensome system for Sellers; however, the Commission and 

the public would receive little, if any, added benefit. 

Likewise, with respect to ongoing due diligence requirements, we decline to 

require that Sellers are expected to: (1) create asset appendices without relying on the 

relational database; (2) compare those asset appendices to the ones generated by the 

database; and (3) retain those comparisons for at least six years. Although characterized 

as expectations, TAPS’s request can be read as additional requirements that would be part 

of Sellers’ responsibilities under § 35.41(b). As noted above, such requirements would 

run counter to the purpose of the final rule, specifically, the goal to reduce burden on 

Sellers. We reiterate, however, that Sellers have a duty to perform due diligence to 

ensure that the information that they provide to the Commission is accurate and complete,

and we encourage Sellers to adopt due diligence practices, which could include those 

proposed by TAPS.

 151 Further, we note that Sellers will not need to submit a transmittal letter with 

their baseline database submissions. Instead, the baseline submissions will consist solely 

of the submission of information into the database as required by the final rule.
Docket No. RM16-17-001 - 54 -

III. Document Availability

In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC’s Home Page 

(http://www.ferc.gov) and in FERC’s Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

From FERC’s Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, 

TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.
Docket No. RM16-17-001 - 55 -

IV. Effective Date

The final rule will become effective October 1, 2020.

By the Commission. Commissioner Glick is dissenting in part with a separate statement

 attached.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Data Collection for Analytics and Surveillance and 

Market-Based Rate Purposes

Docket No. RM16-17-001

(Issued February 20, 2020)

GLICK, Commissioner, dissenting in part: 

I dissent in part from today’s order, because I believe that the Commission should 

have finalized a critical aspect of the notice of proposed rulemaking1 (NOPR) that would 

have required Sellers2 and entities that trade virtual products or that hold financial 

transmission rights (Virtual/FTR Participants)3 to report information regarding their legal 

and financial connections to various other entities (Connected Entity Information). 

Frankly, many aspects of this Connected Entity Information proposal should have been a 

no-brainer for this Commission. For example, the NOPR would have required 

Virtual/FTR Participants to be truthful in all communications with the Commission—not 

exactly a burdensome obligation. Nevertheless, the Commission has relegated even those 

common-sense reforms to a hollow administrative docket that has not seen any action and 

likely never will under the Commission’s current construct. As I explained in my earlier 

dissent, the Commission’s retreat from the NOPR proposal is part of a troubling pattern 

in which the majority seems indifferent to detecting and deterring market manipulation.

* * *

 1 Data Collection for Analytics and Surveillance and Market-Based Rate 

Purposes, 156 FERC ¶ 61,045 (2016) (NOPR).

2 “Seller means any person that has authorization to or seeks authorization to 

engage in sales for resale of electric energy, capacity or ancillary services at 

market-based rates under section 205 of the Federal Power Act.” 18 C.F.R. § 35.36(a)(1) 

(2018).

3 As explained in the final rule, the Commission proposed to define the term 

“Virtual/FTR Participants” as entities that buy, sell, or bid for virtual instruments or 

financial transmission or congestion rights or contracts, or hold such rights or contracts in 

organized wholesale electric markets, not including entities defined in section 201(f) of 

the FPA. Data Collection for Analytics and Surveillance and Market-Based Rate 

Purposes, 168 FERC ¶ 61,039, at P 182 (2019) (Final Rule).
Docket No. RM16-17-001 - 2 -

When it comes to detecting market manipulation, context matters. A transaction 

that seems benign when viewed in isolation may raise serious concerns when viewed 

with an understanding of the relationships between the transacting parties and/or other 

market participants.4

 Unfortunately, information regarding the legal and contractual 

relationships between market participants is not widely available and may, in some cases, 

be impossible to ascertain without the cooperation of the participants themselves. That 

lack of information can leave the Commission in the dark and unable to fully monitor 

wholesale market trading activity for potentially manipulative acts. 

That problem is particularly acute when it comes to market participants that 

transact only in virtual or FTR products. Virtual/FTR Participants are very active in 

RTO/ISO markets and surveilling their activity for potentially manipulative acts 

consumes a significant share of the Office of Enforcement’s time and resources. It may, 

therefore, be surprising that the Commission collects only limited information about 

Virtual/FTR Participants and often cannot paint a complete picture of their relationships 

with other market participants. Similarly, the Commission has no mechanism for 

tracking recidivist fraudsters and manipulators who deal in these products and perpetuate 

their fraud by moving to different companies or participating in more than one RTO or 

ISO. And, perhaps most egregiously, the Commission’s current regulations do not 

impose a duty of candor on Virtual/FTR Participants, meaning that bad actors can lie 

with impunity, at least insofar as the Commission is concerned.5

 The abandoned aspects 

of the NOPR would have addressed all three deficiencies, among others. 

The Commission “declines to adopt” this Connected Entity Information aspect of 

the NOPR based only on its “appreciat[ion]” of the “difficulties of and burdens imposed 

by this aspect of the NOPR.”6

 That is hardly a reasoned explanation for why an 

 4 See NOPR, 156 FERC ¶ 61,045 at P 43. 

5 In contrast, section 35.41(b) of the Commission’s regulations requires a Seller to 

“provide accurate and factual information and not submit false or misleading information, 

or omit material information, in any communication with the Commission,” market 

monitors, RTOs/ISOs, or jurisdictional transmission providers, unless the “Seller 

exercises due diligence to prevent such occurrences. Virtual/FTR Participants are not 

subject to this duty of candor. The Connected Entity portion of the NOPR proposed to 

add a new section 35.50(d) to the Commission’s regulations that would require the same 

candor from Virtual/FTR Participants in all of their communications with the 

Commission, Commission-approved market monitors, RTOs, ISOs, and jurisdictional 

transmission providers. NOPR, 156 FERC ¶ 61,045 at P 20. 

6 Data Collection for Analytics and Surveillance and Market-Based Rate 

Purposes, 170 FERC ¶ 61,129, at P 44 (2020). 
Docket No. RM16-17-001 - 3 -

unspecified burden outweighs the boon that Connected Entities Information would 

provide to the Commission’s ability to carry out its enforcement responsibilities. The 

Commission does note that it has transferred the record to a new docket for “possible 

consideration in the future as the Commission may deem appropriate.”7

 Unfortunately, 

there is every indication that it will languish there for the foreseeable future. 

That is a shame. Without the Connected Entity Information, we are forcing the 

Commission’s Office of Enforcement to police the markets for manipulation with one 

arm tied behind its back. And despite the Office’s valiant efforts, that means that market 

participants are more likely to find themselves subject to a manipulative scheme than if 

we had proceeded to a final rule on these aspects of the NOPR. 

For these reasons, I respectfully dissent in part.

______________________________

Richard Glick

Commissioner

 7 Id. P 45.