129 FERC ¶ 61,252 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 and Philip D. Moeller. 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket No. RM07-19-002 

ORDER NO. 719-B 

ORDER DENYING REHEARING AND PROVIDING CLARIFICATION 

(Issued December 17, 2009) 

1. In this order, the Commission addresses requests for clarification and rehearing of 

certain aspects of Order No. 719-A,1

 which affirmed in part and granted in part rehearing 

of the Final Rule on Wholesale Competition in Regions with Organized Electric 

Markets.

2

 As discussed below, the Commission affirms its basic determinations in Order 

No. 719 and Order No. 719-A regarding demand response and pricing during periods of 

operating reserve shortages in organized markets, grants limited clarification, and denies 

rehearing. 

I. Background

2. On October 17, 2008, the Commission issued a Final Rule in this proceeding that 

established reforms to improve the operation of organized wholesale electric power 

markets3

 and amended the Commission’s regulations under the Federal Power Act (FPA) 

 

(continued...) 

1 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719-A, 74 FR 37776 (Jul. 29, 2009), FERC Stats. & Regs. ¶ 31,292 (2009) (Order 

No. 719-A). 

2 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, FERC Stats. & Regs. ¶ 31,281 (2008) (Order No. 719 or Final Rule). 

3

 Organized market regions are areas of the country in which a regional 

transmission organization (RTO) or independent system operator (ISO) operates dayahead and/or real-time energy markets. The following Commission-approved RTOs and 

ISOs have organized markets: PJM Interconnection, L.L.C. (PJM); New York 

Independent System Operator, Inc. (NYISO); Midwest Independent Transmission System 
Docket No. RM07-19-002 - 2 - 

in the areas of: (1) demand response, including pricing during periods of operating 

reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and 

(4) the responsiveness of RTOs and ISOs to their customers and other stakeholders. The 

Commission stated that these reforms are intended to improve wholesale competition to 

protect consumers in several ways: by providing more power supply options, 

encouraging new entry and innovation, spurring deployment of new technologies, 

removing barriers to comparable treatment of demand response, improving operating 

performance, exerting downward pressure on costs, and shifting risk away from 

consumers. Order No. 719 became effective on December 29, 2008. 

3. A number of entities sought rehearing of Order No. 719. In response, on July 16, 

2009, the Commission issued Order No. 719-A, affirming in part its determinations in the 

Final Rule and granting rehearing and clarification in part regarding certain provisions of 

Order No. 719. Among other things, in Order No. 719-A, the Commission affirmed its 

determinations in the Final Rule regarding demand response and pricing during periods 

of operating reserve shortages in organized markets. The Commission also granted in 

part clarification and rehearing regarding aggregation of retail customers and revised its 

regulatory text. Order No. 719-A became effective on August 28, 2009. 

II. Requests for Clarification and/or Rehearing

4. American Public Power Association (APPA), the National Rural Electric 

Cooperative Association (NRECA), the Transmission Access Policy Study Group 

(TAPS), and American Municipal Power, Inc. (AMP) (collectively, APPA Petitioners) 

filed a joint request for clarification, or in the alternative, a request for rehearing. 

NRECA filed a separate request for clarification, or in the alternative, a request for 

rehearing. New Hampshire Electric Cooperative (New Hampshire Coop) filed a request 

for clarification. 

III. Discussion

A. Aggregation of Retail Customers

5. In Order No. 719, the Commission required RTOs and ISOs to amend their market 

rules as necessary to permit an aggregator of retail customers (ARC) to bid demand 

response on behalf of retail customers directly into the RTO’s or ISO’s organized 

wholesale markets, unless the laws or regulations of the relevant electric retail regulatory 

authority do not permit a retail customer to participate. The Commission reasoned that 

allowing an ARC to act as an intermediary for many small retail loads that cannot 

 

Operator, Inc. (Midwest ISO); ISO New England, Inc. (ISO New England); California 

Independent System Operator Corp. (CAISO); and Southwest Power Pool, Inc. (SPP). 
Docket No. RM07-19-002 - 3 - 

individually participate in the organized markets would reduce a barrier to demand 

response participation in such markets.4

 The Commission also stated that the ARC 

requirement applies only to RTOs and ISOs and does not require the relevant electric 

retail regulatory authority to make any showing or to take any action in compliance with 

the Final Rule.5

6. In Order No. 719-A, the Commission affirmed that the Final Rule’s ARC 

requirement applies only to RTOs and ISOs.6

 However, in response to comments that 

argued that the ARC requirement would significantly burden the relevant electric retail 

regulatory authorities of small systems,7

 the Commission revised the ARC requirement 

by adopting a modified version of a proposal that APPA and TAPS submitted to alleviate 

this perceived burden. The Commission directed RTOs and ISOs to amend their market 

rules as necessary to accept bids from ARCs that aggregate the demand response of: 

(1) the customers of utilities that distributed more than 4 million MWh in the previous 

fiscal year,8

 and (2) the customers of utilities that distributed 4 million MWh or less in 

the previous fiscal year, where the relevant electric retail regulatory authority permits 

 4

 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154. 

5 Id. P 155. 

6

 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 56 (noting that the “[notice 

of proposed rulemaking] specifically stated that those entities directly affected by this 

proceeding are the six RTOs and ISOs, namely CAISO, NYISO, PJM, SPP, Midwest 

ISO, and ISO New England”). Wholesale Competition in Regions with Organized 

Electric Markets, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,628 (2008) 

(NOPR). 

7

 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 27-31. 

8

 The Commission stated that it is reasonable to use a 4 million megawatt-hour 

(MWh) cutoff for purposes of distinguishing small utilities. Id. P 51, 59. The Regulatory 

Flexibility Act definition of “small entity” refers to the definition provided in the Small 

Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. See

5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 632. The Small 

Business Size Standards component of the North American Industry Classification 

system defines a small utility as one that, including its affiliates, is primarily engaged in 

the generation, transmission, or distribution of electric energy for sale, and whose total 

electric output for the preceding fiscal year did not exceed 4 million MWh. 13 C.F.R. 

§ 121.202 (Sector 22, Utilities, North American Industry Classification System (NAICS)) 

(2004). 
Docket No. RM07-19-002 - 4 - 

such customers’ demand response to be bid into organized markets by an ARC. RTOs 

and ISOs may not accept bids from ARCs that aggregate the demand response of: (1) the 

customers of utilities that distributed more than 4 million MWh in the previous fiscal 

year, where the relevant electric retail regulatory authority prohibits such customers’ 

demand response to be bid into organized markets by an ARC, or (2) the customers of 

utilities that distributed 4 million MWh or less in the previous fiscal year, unless the 

relevant electric retail regulatory authority permits such customers’ demand response to 

be bid into organized markets by an ARC.9

1. Demand Response by Individual Retail Customers and by ARCs

a. Request for Clarification/Rehearing

7. APPA Petitioners state that they generally support Order No. 719-A’s small 

system provision, but assert that the regulatory text contains certain ambiguities and 

inconsistencies that raise concerns that the small system provision will be misinterpreted 

and misapplied.10 Accordingly, APPA Petitioners request that the Commission clarify 

the regulatory language to prevent any confusion and uncertainty, and to reduce 

unintended barriers to the participation of retail demand response in RTO and ISO 

markets. For instance, APPA Petitioners ask the Commission to remedy an alleged 

internal inconsistency in the regulatory text to ensure that demand response by an 

individual retail customer is treated the same as demand response by an ARC. APPA 

Petitioners state that Order Nos. 719 and 719-A suggest an intent to treat an individual 

retail customer the same as an aggregator of multiple retail customers.11 There is no 

suggestion to apply a different standard to determine when an individual retail customer 

may bid its own demand response into the RTO and ISO markets and when an ARC may 

do so. However, according to APPA Petitioners, Order No. 719-A created a potential for 

inconsistency or confusion by inserting small system language in the regulatory text that 

applies to ARCs12 without a parallel language in the regulatory text that applies to 

ancillary services.13 To remedy this inconsistency, APPA Petitioners propose that the 

 9 Id.; 18 C.F.R. § 35.28(g)(1)(iii). 

10 APPA Petitioners at 2. 

11 Id. at 15. 

12 18 C.F.R. § 35.28(g)(1)(iii). 

13 Id. 35.28(g)(1)(i)(A). 
Docket No. RM07-19-002 - 5 - 

Commission add a definition of an ARC in section in 35.28(b)(9)14 and add small system 

language to the regulatory text that applies to ancillary services.15

8. According to APPA Petitioners, the new definition would clarify that the term 

“ARC” includes both individual retail customers and entities that aggregate the demand 

response of multiple retail customers. They add that adopting the proposed revisions in 

35.28(g)(1)(i)(A) would ensure that a single, consistent set of rules applies to retail 

customers bidding their demand response into organized markets, either individually or 

through an ARC. APPA Petitioners ask that if the Commission does not modify the 

regulatory text, it should clarify in the preamble that: (1) individual retail customers that 

bid their own demand response are subject to the same provisions as ARCs as to when an 

RTO or ISO may accept their bids; and (2) the more specific language of section 

 14 APPA Petitioners propose to define an ARC this way: “Aggregator of retail 

customers means an entity that aggregates demand response bids (which are mostly from 

retail loads). An individual retail customer that bids its own demand response into a 

Commission approved independent system operator’s or regional transmission 

organization’s organized markets shall be considered an aggregator of retail customers.” 

APPA Petitioners at 13. 

15 APPA Petitioners propose to revise section 35.28(g)(1)(i)(A) by deleting 

“unless not permitted by the laws or regulations of the relevant electric retail regulatory 

authority” and inserting “subject to subsection (iii)”: 

Every Commission-approved independent system operator or 

regional transmission organization that operates organized 

markets based on competitive bidding for energy imbalance, 

spinning reserves, supplemental reserves, reactive power and 

voltage control, or regulation and frequency response 

ancillary services (or its functional equivalent in the 

Commission-approved independent system operator’s or 

regional transmission organization’s tariff) must accept bids 

from demand response resources in these markets for that 

product on a basis comparable to any other resources, if the 

demand response resource meets the necessary technical 

requirements under the tariff, and submits a bid under the 

Commission-approved independent system operator’s or 

regional transmission organization’s bidding rules at or below 

the market-clearing price, subject to subsection (iii). 

Id.
Docket No. RM07-19-002 - 6 - 

35.28(g)(1)(iii), with its alternative language for small systems is intended to cover 

individual retail customers, as well as aggregators of multiple retail customers.16

b. Commission Determination

9. We find that APPA Petitioners’ request for modification of the regulatory text to 

define “ARC” and add small system language to section 35.28(g)(1)(i)(A) is outside the 

scope of a rehearing.17 This regulation requires that demand response be allowed to bid 

into competitive markets to provide ancillary services. APPA Petitioners seek revisions 

to the regulatory text on issues that were never raised in their initial comments. At 

APPA’s own request, on rehearing of Order No. 719, the Commission added the small 

system language to the section of the regulatory text that addresses ARCs. No 

commenter, including APPA, sought rehearing of Order No. 719 with regard to the 

language of the regulatory text governing ancillary services. A request for rehearing is 

not the appropriate venue to bring up issues in the first instance.18 Therefore, we will 

dismiss APPA Petitioners’ request for rehearing on this issue. 

10. However, if the Commission were to consider APPA Petitioners’ rehearing 

request, we would deny it because the revisions to the regulatory text are not necessary. 

First, regarding the definition of an ARC, Order No. 719 defined an ARC broadly by 

stating that it “refer[s] to an entity that aggregates demand response bids.”19 It also noted 

that “[a]n ARC can bid demand response either on behalf of only one retail customer or 

multiple retail customers,” and “[a]n individual customer may serve as an ARC on behalf 

of itself and others.”20 Additionally, Order No. 719 stated that an ARC’s demand 

response bid must meet the same requirements as a demand response bid of a load-

 16 Id. at 16. 

17 Because APPA Petitioners seek changes to the regulatory text that would 

represent a changed ruling on the Commission’s part, we construe its filing as a request 

for rehearing, and not a motion for clarification. 18 C.F.R. § 385.713 (2009). 

18 The Commission has held that a request for rehearing of new issues is outside 

the proper scope of a rehearing. PJM Interconnection, LLC, 126 FERC ¶ 61,030, at P 15 

& n.10 (2009) (noting that “raising issues for the first time on rehearing is disruptive to 

the administrative process and denies parties the opportunity to respond”); see also Enron 

Energy Services Inc. v. Sellers of Energy, 122 FERC ¶ 61,015, at P 64 (2008); Midwest 

Indep. Transmission Sys. Operator, Inc., 117 FERC ¶ 61,113, at P 188 (2006). 

19 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at n.3. 

20 Id. P 158. 
Docket No. RM07-19-002 - 7 - 

serving entity or any other entity.21 The Commission also reiterated in Order No. 719-A 

that retail customers can participate in wholesale demand response programs either 

individually or through an ARC.22 Given such a definition and clarifications, we do not 

find that a specific definition of an ARC in the regulatory text is necessary to make clear 

that an individual customer may act as an ARC. 

11. Second, we do not find that section 35.28(g)(1)(A) of the regulatory text is 

inconsistent with section 35.28(g)(1)(iii), as APPA Petitioners assert. The regulatory text 

regarding ARCs (in section 35.28(g)(1)(iii)) states that “[e]ach Commission approved 

independent system operator and regional transmission organization must accept bids 

from an aggregator of retail customers that aggregates the demand response of . . . .” 

certain customers. The phrase “the demand response” does not distinguish among 

demand response bids, including those for energy, capacity, and ancillary services. 

Therefore, to the extent necessary, we provide limited clarification that the requirements 

under section 35.28(g)(i)(iii) apply to all demand response bids, including bids for 

ancillary service products. For this reason, we find that APPA Petitioners’ proposed 

revision to section 35.28(g)(1)(A) is unnecessary. 

2. Determining ARC Qualifications and Requirements

a. Request for Clarification/Rehearing

12. APPA Petitioners state that Order No. 719-A emphasized the role of relevant 

electric retail regulatory authorities to determine whether and how to permit ARCs to 

participate in wholesale demand response programs.23 APPA Petitioners contend that the 

regulatory language must be clarified so that permission granted by the relevant electric 

retail regulatory authority is ARC-specific.24 This would allow a relevant electric retail 

regulatory authority to determine an ARC’s qualifications and requirements.25 

13. According to APPA Petitioners, Order No. 719-A’s regulatory language creates an 

ambiguity that some may seek to use to restrict a relevant electric retail regulatory 

authority’s ability to determine and enforce qualifications regarding which ARCs may 

aggregate the demand response of retail customers subject to its jurisdiction and on what 

 21 Id. 

22 See, e.g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 68-69. 

23 Id. P 54, 68. 

24 APPA Petitioners at 18. 

25 Id. at 16-17. 
Docket No. RM07-19-002 - 8 - 

terms. APPA Petitioners contend that Order No. 719-A permitted relevant electric retail 

regulatory authorities to limit which ARCs may aggregate retail customers’ demand 

response, and under what terms, and that it also expressly recognized a retail regulator’s 

continuing role in “addressing the complexity of allowing the sale of demand response 

into organized wholesale markets by retail customers subject to” that retail regulatory 

authority’s jurisdiction.26 They state that this language can only be given effect if the 

permission granted by relevant electric retail regulatory authorities to aggregate demand 

response is ARC-specific. Therefore, APPA Petitioners propose changes to section 

35.28(g)(1)(iii) that they say will particularize the RTO’s or ISO’s obligations to accept 

ARC bids. APPA Petitioners argue that these changes will reduce barriers to demand 

response participation by facilitating the relevant electric retail regulatory authority’s 

ability to establish and enforce qualifications for ARCs, which would be applied on an 

ARC-by-ARC basis: 

 . . . accept a bids from an aggregator of retail customers that 

aggregates the demand response of: (1) the customers of 

utilities . . . and (2) the customers of utilities that distributed 4 

million megawatt-hours or less in the previous fiscal year, 

where the relevant electric retail regulatory authority permits 

such customers’ demand response to be bid into organized 

markets by that an aggregator of retail customers . . . . An 

independent system operator or regional transmission 

organization must not accept a bids from an aggregator of 

retail customers that aggregates the demand response of: 

(1) the customers . . . or (2) the customers of utilities that 

distributed 4 million megawatt-hours or less in the previous 

fiscal year, unless the relevant electric retail regulatory 

authority permits such customers’ demand response to be bid 

into organized markets by that an aggregator of retail 

customers. 

14. APPA Petitioners state that the proposed revisions are consistent with the 

Commission’s intent not to place RTOs and ISOs in the position of interpreting local 

laws and ordinances.27 According to APPA Petitioners, the RTO or ISO can implement 

the revised text simply by requiring the ARC to certify to the RTO or ISO that it is not 

prohibited from aggregating the demand response of retail customers of a large utility, or 

 26 Id. (quoting Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 54, 68). 

27 See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 49 & n.78, P 158 & 

n.212; Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 50. 
Docket No. RM07-19-002 - 9 - 

that it has been granted permission to aggregate the demand response of retail customers 

of a small utility.28

15. If the Commission does not accept the proposed clarifications to the regulatory 

text, APPA Petitioners state that the Commission should make clear its intent to allow 

relevant electric retail regulatory authorities to determine which specific ARCs satisfy 

their qualifications and requirements to aggregate their retail customers’ demand 

response. Thus, APPA Petitioners urge the Commission to clarify in the preamble that it 

is not restricting a relevant electric retail regulatory authority’s authority to permit some 

ARCs from operating in their jurisdiction and not others. 

b. Commission Determination

16. We do not agree with APPA Petitioners that Order No. 719-A’s regulatory 

language restricts the relevant electric retail regulatory authority’s ability to determine 

and enforce qualifications for ARCs. We have stated previously that neither the intent 

nor the effect of this proceeding is to undermine or require changes to existing retail 

aggregation programs, or to interfere with the relevant electric retail regulatory 

authority’s role in determining the qualifications and requirements for ARCs within its 

jurisdiction.29 We leave it to each relevant electric retail regulatory authority to set and 

enforce qualifications and requirements for aggregation of demand response within its 

jurisdiction. 

17. APPA Petitioners’ proposed revisions to the regulatory text, as we read them, 

would require retail regulatory authorities to implement qualifications for ARCs by 

considering each ARC individually. This is inconsistent with our goals, stated above, not 

to interfere with retail regulation or existing demand response programs. We therefore 

will not require an ARC-by-ARC determination of eligibility as the only method of 

implementing qualifications for ARCs. It is up to the individual relevant electric retail 

regulatory authority to determine the suitable method for qualifying ARCs within its 

jurisdiction.30 Accordingly, we find that APPA Petitioner’s proposed revision in this 

area is unnecessary, and we reject it. 

 28 APPA Petitioners at 20. 

29 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 67-68. 

30 See, e.g., PJM Interconnection, L.L.C., 128 FERC ¶ 61,238, at P 22 (2009) 

(recognizing that relevant electric retail regulatory authorities “retain substantial 

flexibility in establishing requirements for eligibility of retail customers to provide 

demand response”), reh’g pending. 
Docket No. RM07-19-002 - 10 - 

3. Load-Serving Entities and Their Third-Party Designees

a. Request for Clarification/Rehearing

18. APPA Petitioners state that Order No. 719 is ambiguous as to whether loadserving entities are included within the definition of an ARC. If they are considered as 

ARCs, subject to the small system language adopted in Order No. 719-A, APPA 

Petitioners assert that the Commission may unwittingly undermine its intent not to 

interfere with, undermine, or change existing demand response programs, and thereby 

create a new obstacle to demand response programs.31 Under Order No. 719-A’s small 

system ARC language, load-serving entities that want to continue or enhance their 

existing demand response programs by bidding their own demand response into RTO or 

ISO markets may have to secure laws and regulations expressly permitting such 

aggregation from the relevant electric retail regulatory authority for each affected small 

system, according to APPA Petitioners. 

19. To fulfill the Commission’s objective in this proceeding to eliminate barriers to 

demand response, APPA Petitioners urge the Commission to clarify that the small system 

language does not apply to the load-serving entity responsible for the retail customers in 

the RTO or ISO market, thereby enabling the load-serving entity to continue and enhance 

its existing demand response programs as Order No. 719-A expressly intended.32 To that 

end, APPA Petitioners seek clarification, or in the alternative rehearing, that the small 

system ARC requirements of section 35.28(g)(1)(iii) do not apply to demand response 

bids submitted by the load-serving entity “responsible for that retail customer’s load in 

such organized markets” and propose revisions to the regulatory text. APPA Petitioners 

state that this clarification would reduce barriers to demand response by: (1) avoiding the 

need to educate small utilities and their relevant electric retail regulatory authorities about 

the need to take legislative action on this issue; (2) putting load-serving entities 

responsible for retail load of small utilities in the same position as load-serving entities 

serving retail customers of large utilities; and (3) minimizing administrative burdens for 

RTOs and ISOs. 

20. Similarly, APPA Petitioners ask the Commission to include language in the 

regulatory text to clarify that a load-serving entity responsible for retail customer load in 

the organized market may also designate a third-party agent with appropriate technical 

expertise to provide demand response, without going through the burdensome resolution 

process of, or securing new laws or regulations from, the relevant electric retail 

 31 APPA Petitioners at 21-22. 

32 Id. at 23. 
Docket No. RM07-19-002 - 11 - 

regulatory authority of each affected small system.33 They state that adopting the revised 

language would enable a load-serving entity to contract with a third party having demand 

response experience to facilitate the load-serving entity’s own efforts to aggregate retail 

customer demand response and, thereby, avoid any unintended barriers to effective loadserving entity demand response programs.34

21. If the Commission does not modify the regulatory text, APPA Petitioners ask the 

Commission to clarify in the preamble that when Order No. 719-A provided assurance 

that this proceeding is not intended to interfere with, undermine, or change existing 

demand response programs, the Commission intended to preserve load-serving entities’ 

ability, including joint action agencies’ and generation and transmission cooperatives’ 

ability, to aggregate the demand response of the retail customer loads for which they are 

responsible in the RTO and ISO markets, without first securing new legislation or 

regulations from the relevant electric retail regulatory authorities of each affected small 

 33 APPA Petitioners propose that the Commission provide an exception to the 

small system aggregation clause by inserting the following phrase in section 

35.28(g)(1)(iii): “or where the demand response bid is submitted by the load-serving 

entity responsible for that retail customer’s load in such organized markets or such loadserving entity’s designee.” APPA Petitioners at 27. Thus, section 35.38(g)(1)(iii) would 

read as follows: 

Aggregation of retail customers. Each Commission approved 

independent system operator and regional transmission 

organization must accept a bids from an aggregator of retail 

customers that aggregates the demand response of . . . or 

where the demand response bid is submitted by the loadserving entity responsible for that retail customer’s load 

in such organized markets or such load-serving entity’s 

designee. An independent system operator or regional 

transmission organization must not accept a bids from an 

aggregator of retail customers that aggregates the demand 

response of . . . or where the demand response bid is 

submitted by the load-serving entity responsible for that 

retail customer’s load in such organized markets or such 

load-serving entity’s designee. 

34 APPA Petitioners note that some of their members have contracted or are in the 

process of contracting with third-party providers. For example, Burlington, Vermont, 

which participates in ISO-New England’s emergency demand response program, 

contracted with EnerNoc to enhance and expand that program. Id. at 26. 
Docket No. RM07-19-002 - 12 - 

system. Also, APPA Petitioners ask the Commission to clarify in the preamble that it 

expects RTOs and ISOs to cooperate with load-serving entities serving the loads of small 

utilities that have contracted with third parties to facilitate aggregation of the demand 

response of retail loads for which they are responsible.35 APPA Petitioners also note that 

the authorization for these third parties would come from the load-serving entities 

responsible for the retail customer load in the RTO and ISO market and, therefore, 

eliminating this barrier to demand response will not be an administrative burden to RTOs 

and ISOs. 

b. Commission Determination

22. We deny APPA Petitioners’ rehearing request regarding load-serving entities and 

their third-party designees.36 We find that the revisions APPA Petitioners seek in this 

regard are contrary to the goal of this proceeding. In essence, APPA Petitioners ask the 

Commission to provide special treatment to a particular group of aggregators by allowing 

them to be exempt from Order No. 719-A’s small system provision (which was adopted 

in response to APPA’s own comments and request for rehearing of Order No. 719). 

23. We reiterate that the focus of this proceeding is to further improve the operation of 

wholesale competitive markets in organized market regions.37 Consistent with the 

national policy of fostering competition in wholesale markets, the Commission 

recognized that “ensuring the competitiveness of organized wholesale markets is integral 

to . . . fulfilling its statutory mandate to ensure adequate and reliable non-discriminatory 

service at just and reasonable prices.”38 Providing effective competition that will protect 

consumers “by providing greater supply options, encouraging new entry and innovation, 

and encouraging demand response and energy efficiency” is at the core of this 

proceeding.39 

24. If we were to grant APPA Petitioners’ request, then a load-serving entity for a 

small utility system (or its designated third-party aggregator) would not have to make a 

 35 Id. at 27-28. 

36 As noted above, we consider APPA Petitioners’ filing a request for rehearing, 

rather than a motion for clarification, because it seeks amendments to the regulatory text 

that would represent a changed ruling on the Commission’s part. 18 C.F.R. § 385.713 

(2009). 

37 NOPR, FERC Stats. & Regs. ¶ 32,628 at P 1, 12-13. 

38 Id. P 1. 

39 Id.
Docket No. RM07-19-002 - 13 - 

showing of authorization by the relevant electric retail regulatory authority to make a 

demand response bid into an RTO’s or ISO’s organized market, as required under Order 

No. 719-A, while all other ARCs would be required to make such a showing. In that 

respect, granting APPA Petitioners’ request would potentially permit a load-serving 

entity to circumvent the relevant electric retail regulatory authority’s policies regarding 

ARC qualifications and requirements and, would effectively have the Commission 

provide load-serving entities and their designees with a competitive advantage over other 

ARCs. Such action would be contrary to the Commission’s stated intent that each 

relevant electric retail regulatory authority may set and enforce qualifications and 

requirements for aggregation of demand response within its jurisdiction. We also are not 

persuaded that such action is consistent with our obligation to prevent undue 

discrimination.40 Therefore, we will deny APPA Petitioners’ request for proposed 

revisions to the regulatory text in this regard. 

4. Coordination among Local Authorities

a. Request for Clarification

25. New Hampshire Coop is concerned that Order No. 719-A’s discussion regarding 

aggregators of retail customers could be read, in instances in which cooperative 

customers have switched to a competitive energy supplier, to preclude New Hampshire 

Coop from taking actions aimed at ensuring that all of its customers receive retail 

services at the lowest reasonable costs.41 New Hampshire Coop states that, for those 

cooperative members who are purchasing power from them, the relevant electric retail 

regulatory authority for demand response purposes is the New Hampshire Coop Board. 

However, according to New Hampshire Coop, it is not clear whether the relevant electric 

retail regulatory authority for those of its members who are purchasing power from others 

is the New Hampshire Coop Board or the New Hampshire Public Utilities Commission, 

or some other entity. This means that those cooperative members who choose to change 

their power supplier to a competitive alternative may also change their relevant electric 

retail regulatory authority.42

26. Given this scenario, New Hampshire Coop is concerned that the shift to a 

competitive supplier and, potentially, a new relevant electric retail regulatory authority, 

may endanger the cooperative’s efforts to coordinate demand response program actions 

so as to ensure that all of the New Hampshire Coop’s members receive service at the 

 40 16 U.S.C. §§ 824d, 824e (2006). 

41 New Hampshire Coop at 1-2. 

42 Id. at 5. 
Docket No. RM07-19-002 - 14 - 

lowest cost. It is concerned that, if those controlling the demand response programs do 

not coordinate with New Hampshire Coop, a significant fixed cost can be imposed upon 

all members. New Hampshire Coop states that it is not asking the Commission to require 

coordination where a competitive supplier is involved. However, to help facilitate 

dialogue with other New Hampshire authorities, New Hampshire Coop asks the 

Commission to clarify that nothing in the orders issued in this docket is intended to 

preclude or impede actions by New Hampshire Coop and New Hampshire regulatory 

authorities to confront and craft acceptable solutions to the coordination issues raised 

here. 

b. Commission Determination

27. As stated above, we reiterate that the intent and effect of this proceeding are 

neither to undermine nor require changes to existing demand response programs.43 The 

Commission also stated in Order No. 719-A that it is up to the relevant electric retail 

regulatory authorities, if they so choose, to decide whether existing retail aggregation 

programs provide benefits and whether retail customer participation in wholesale demand 

response programs, individually or through an ARC, would adversely affect those 

programs.44 We do not object to relevant electric retail authorities coordinating as 

needed to achieve these goals. 

B. Market Rules Governing Price Formation during Periods of 

Operating Reserve Shortage

28. In Order No. 719-A, the Commission affirmed its finding in the Final Rule that 

existing RTO and ISO market rules that do not allow for prices to rise sufficiently during 

an operating reserve shortage to allow supply to meet demand are unjust, unreasonable, 

and may be unduly discriminatory. The Commission stated that the shortage pricing 

reform in this proceeding is intended to correct this issue while providing protection 

against the exercise of market power.45

29. The Final Rule required each RTO or ISO to reform or demonstrate the adequacy 

of its existing market rules to ensure that the market price for energy reflects the value of 

energy during an operating reserve shortage.46 The Commission stated that each RTO or 

 43 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 67. 

44 Id. P 68. 

45 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 93. 

46 Id. P 194. 
Docket No. RM07-19-002 - 15 - 

ISO may propose in its compliance filing one of four suggested approaches to pricing 

reform during an operating reserve shortage, or develop its own alternative approach to 

achieve the same objectives.47 The Commission also required each RTO or ISO to 

support its compliance filing with adequate factual support. To that end, the Commission 

outlined six criteria it will consider in reviewing whether the factual record compiled by 

the RTO or ISO meets the requirements of the Final Rule.48 

1. Request for Clarification/Rehearing

30. NRECA requests clarification that its proposed alternative shortage pricing 

proposal, which differentiates between the price paid to generation resources and the 

price paid to demand response resources during periods of operating reserve shortage, 

complies with the Commission’s six pricing criteria and with the regulations 

implementing those criteria.49 According to NRECA, under its approach, RTOs and 

ISOs would remove bid caps for demand response resources during emergencies, 

provided that those higher bids for demand response do not set the market-clearing price 

for all resources. NRECA contends that this approach will encourage additional demand 

response by allowing demand response resources to obtain a higher price for their 

 47 The four approaches are: (1) RTOs and ISOs would increase the energy supply 

and demand bid caps above the current levels only during an emergency; (2) RTOs and 

ISOs would increase bid caps above the current level during an emergency only for 

demand bids while keeping generation bid caps in place; (3) RTOs and ISOs would 

establish a demand curve for operating reserves, which has the effect of raising prices in a 

previously agreed-upon way as operating reserves grow short; and (4) RTOs and ISOs 

would set the market-clearing price during an emergency for all supply and demand 

response resources dispatched equal to the payment made to participants in an emergency 

demand response program. Id. P 208. 

48 The six criteria are: (1) improve reliability by reducing demand and increasing 

supply during periods of operating reserve shortages; (2) make it more worthwhile for 

customers to invest in demand response technologies; (3) encourage existing generation 

and demand resources to continue to be relied upon during an operating reserve shortage; 

(4) encourage entry of new generation and demand resources; (5) ensure that the 

principle of comparability in treatment of and compensation to all resources is not 

discarded during periods of operating reserve shortage; and (6) ensure market power is 

mitigated and gaming behavior is deterred during periods of operating reserve shortages 

including, but not limited to, showing how demand resources discipline bidding behavior 

to competitive levels. Id. P 246-47. 

49 NRECA at 1-2. 
Docket No. RM07-19-002 - 16 - 

response during emergencies and improve reliability without exposing consumers to 

unjust and unreasonable prices.50

31. NRECA states that the Commission indicated in Order Nos. 719 and 719-A that it 

would allow RTOs and ISOs to consider the NRECA proposal as an alternative to the 

Commission’s four approaches to shortage pricing.51 However, NRECA contends that its 

alternative approach can be read to be in conflict with the regulatory text that appears to 

require that the same market-clearing price be paid to both generator resources and 

demand response resources.52 Similarly, NRECA states that the Commission’s fifth 

criterion could be read to require that the same market-clearing price be paid to both 

generator resources and demand response resources.53 Therefore, NRECA requests that 

the Commission clarify that its shortage pricing rules do not require a single marketclearing price for all resources, and that NRECA’s alternative approach to shortage 

pricing complies with the section 35.28(g)(1)(iv)(A) and the shortage pricing criteria. 

32. In the absence of the requested clarification, NRECA seeks rehearing of Order 

No. 719-A, to the extent that Order No. 719-A required RTOs and ISOs to provide a 

single market clearing price for both demand response and generation resources in 

periods of reserve shortage.54 

 50 Id. at 6. 

51 Id. at 6-7 (citing Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 237; Order 

No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 104). 

52 NRECA notes that relevant regulatory text refers to “the market-clearing price,” 

implying that there is to be a single, identical market-clearing price for resources. 

Section 35.28(g)(1)(iv)(A) states: 

Each Commission-approved independent system operator or 

regional transmission organization must modify its market 

rules to allow the market-clearing price during periods of 

operating reserve shortage to reach a level that rebalances 

supply and demand so as to maintain reliability while 

providing sufficient provisions for mitigating market power. 

53 The Commission’s fifth criterion states that: 

Ensure that the principle of comparability in treatment of and 

compensation to all resources is not discarded during periods 

of operating reserve shortage. 

54 NRECA at 2. 
Docket No. RM07-19-002 - 17 - 

33. NRECA argues that the Commission arbitrarily and capriciously rejected its 

alternative pricing proposal and ignored evidence that the Commission’s shortage pricing 

proposal will likely lead to unjust and unreasonable rates.55 NRECA emphasizes that the 

Commission acknowledged in Order No. 719-A that it has not performed an analysis of 

the rates that are likely to be produced as a result of the Commission’s pricing 

approaches.56 NRECA asserts that, absent such an analysis, Order No. 719’s pricing 

proposal will require RTOs and ISOs to utilize a single-market clearing price for demand 

response and supply resources to the exclusion of any approach that would differentiate 

between the prices paid to generation and demand response resources, effectively 

precluding NRECA’s alternative pricing proposal. 

34. NRECA further states that the Commission’s four pricing approaches are not 

supported by substantial evidence in the record.57 APPA Petitioners add that Order 

Nos. 719 and 719-A have offered no justification for adopting the four pricing 

approaches in spite of its evidence demonstrating that the Commission’s pricing proposal 

would yield unjust and unreasonable rates. For example, NRECA argues that the 

Commission ignored evidence showing significant flaws in the Commission’s pricing 

proposal.58 NRECA also argues that the Commission ignored a number of arguments 

and evidence it presented in this proceeding that the Commission must address in order

sustain an order adopting a single market-clearing price proposal: 

 to 

 55 Id.

56 Id. at 3 (citing Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 104). 

57 For example, NRECA states that Order No. 719-A merely provided that “an 

entry of demand response over time may lead to lower prices in the long run” and noted 

that at least one commenter observed that existing market rules may deter investment in 

demand response and generation resources. Id. at 12 (citing Order No. 719-A, FERC 

Stats. & Regs. ¶ 31,292 at P 96). 

58 Specifically, NRECA states that it submitted an affidavit of Dr. Laurence D. 

Kirsch and Dr. Matthew J. Morey (Kirsch-Morey Affidavit) that identified several 

reasons why bid and offer caps should not be removed without careful consideration 

during periods of operating reserve shortage: (1) market power problems are ubiquitous 

in RTO-run markets; (2) the conduct-impact test of the Midwest ISO, ISO New England, 

and the New York ISO allow suppliers substantial latitude to manipulate market prices 

and allows inefficient market outcomes; (3) permitting prices to rise during emergencies 

may not be sufficient to overcome regulatory and other barriers to entry that preserve the 

market power of incumbents; and (4) increased demand response will not ensure 

competitive prices in markets that continue to suffer from high concentration of 

generation ownership given the transmission constraints that limit competition. Id. at 12. 
Docket No. RM07-19-002 - 18 - 

 Argument that the Commission’s four approaches would undermine reliability, 

rather than preserve it. And to the extent that they preserve reliability, they do 

not do so in a manner consistent with the FPA because they would unlawfully 

permit shifting rents from consumers to generators.59

 

 Argument that the Commission’s four pricing approaches will not attract new 

supply resources in real time and cannot attract long-term investment in new 

supply resources.60 

 Argument that Order Nos. 719 and 719-A failed to explain how the 

Commission’s pricing proposal would be superior to the NRECA proposal in 

attracting investment in demand-side resources. Also, both orders failed to 

respond to NRECA’s argument that the Commission’s pricing proposal would 

attract demand-side resources at a dramatically higher cost to consumers than 

the NRECA approach.61 

 Argument that by allowing generators to be paid more during emergency 

situations than they would ordinarily receive under existing market rules, the 

four pricing approaches would encourage behavior that creates emergencies, 

thereby undermining reliability during the long-term period required for entry 

into generation markets.62 

 Argument that under the Commission’s pricing proposal, suppliers would have 

the incentive in the short-term to mid-term to create emergencies during these 

periods so that they can collect the excessively high prices the NOPR’s 

proposals would afford them. Even in the long-term, suppliers would lack the 

incentive to develop new resources because without the shortages, they would 

no longer collect excessive rents.63 

 59 Id. at 20 (citing NRECA NOPR Comments at 30-32; NRECA Rehearing 

Request of Order No. 719 at 36). 

60 Id. (citing NRECA NOPR Comments at 36-42; NRECA Rehearing Request of 

Order No. 719 at 36-37; Kirsch-Morey Affidavit at 57-63). 

61 Id. at 21 (citing NRECA NOPR Comments at 43-44; NRECA Rehearing 

Request of Order No. 719 at 37). 

62 Id. (citing NRECA Rehearing Request of Order No. 719 at 37). 

63 Id.
Docket No. RM07-19-002 - 19 - 

NRECA states that in the absence of any evidence in response to these arguments, the 

Commission has failed to demonstrate that its four pricing approaches are just and 

reasonable. 

35. Further, NRECA states that when the Commission acts under section 206 of the 

FPA, it bears the burden of showing that the existing rate structure it seeks to modify is 

unjust and unreasonable. It asserts that the Commission has made no such showing in the 

this proceeding that the bid caps it seeks to remove are related to the lack of generation 

and demand response investment it seeks to promote.64 NRECA adds that Order No. 

719-A failed to address its arguments that the Final Rule’s four pricing approaches will 

not achieve the Commission’s goals, including improving reliability and spurring 

investment in demand response and generation resources.65 NRECA also argues that the 

Commission ignored its argument and evidence that the existence of emergencies is a 

reflection not of unreasonably low prices during those emergencies, but rather a failure of 

the RTO and ISO market design to assure resource adequacy.66 According to NRECA, 

the Commission failed to provide a reasoned explanation for why it prefers to raise prices 

during emergencies rather than looking for alternative market structures that would be 

consistent with the Commission’s obligation under the FPA. 

36. Finally, NRECA states that, absent a clarification that RTOs and ISOs are not 

required to adopt a single market-clearing price for all resources during emergency 

periods, the Commission’s holding in Order No. 719-A that RTOs and ISOs are free to 

propose the NRECA approach is arbitrary and capricious. It states that if the 

Commission is to reject the NRECA approach it is required to articulate the reasons for 

its decision and not create the impression that it is open to considering this approach in a 

subsequent proceeding.67 

2. Commission Determination

37. We will dismiss NRECA’s request for clarification and rehearing. The 

Commission does not allow rehearing of an order denying rehearing.68 Any other result 

 64 Id. at 16. 

65 Id. at 16-17. 

66 Id. at 17 (citing NRECA NOPR Comments at 33). 

67 Id. at 22. 

68 See, e.g., Southern Co. Services, Inc., 111 FERC ¶ 61,329 (2005); AES Warrior 

Run, Inc. v. Potomac Edison Co. d/b/a Allegheny Power, 106 FERC ¶ 61,181 (2004); 

Southwestern Public Service Co., 65 FERC ¶ 61,088, at 61,533 (1993). 
Docket No. RM07-19-002 - 20 - 

would lead to never-ending litigation as every response by the Commission to a party’s 

arguments would allow yet another opportunity for rehearing unless presumably that 

response were word-for-word identical to what the Commission earlier said.69 Litigation 

before the Commission cannot be allowed to drag on indefinitely – at some point it must 

end – and so the Commission does not allow parties to seek rehearing of an order denying 

rehearing. And, as the District of Columbia Circuit has put it, even “an improved 

rationale” would not justify a further request for rehearing.70

38. Rehearing of an order on rehearing lies only when the order on rehearing modifies 

the result reached in the original order in a manner that gives rise to a wholly new 

objection.71 In fact, a second rehearing request is required in instances when the later 

order modifies the results of the earlier order in a significant way.72

39. We find that NRECA has not provided any new arguments in its present request 

for clarification and rehearing. As discussed below, we find that Order Nos. 719 and 

719-A did address NRECA’s contentions that it raises here, but the Commission did so as 

part of responding to similar issues. Although we dismiss the requests for clarification 

and rehearing, we will discuss them for the purposes of providing clarity and guidance. 

40. With regard to NRECA’s request for clarification as to whether its proposed 

alternative pricing proposal complies with the Final Rule’s six pricing criteria and with 

the regulations pertaining to shortage pricing, we reiterate that Order No. 719 required 

each RTO or ISO to file a shortage pricing proposal in its compliance filing that 

incorporated one of the four pricing approaches offered by the Commission or to develop 

its own approach that would meet the Commission’s requirements as presented in the 

Final Rule.73 Order Nos. 719 and 719-A both state that an RTO or ISO may consider 

 69 Accord, e.g., Canadian Association of Petroleum Producers v. FERC, 254 F.3d 

289, 296 (D.C. Cir. 2001) (rejecting the notion of “infinite regress” that would “serve no 

useful end”). 

70 Southern Natural Gas Co. v. FERC, 877 F.2d 1066, 1073 (D.C. Cir. 1999) 

(Southern) (citing Tennessee Gas Pipeline Co. v. FERC, 871 F.2d 1099, 1109-10 (D.C. 

Cir. 1988)). 

71 See Southern, 273 F.3d at 424.

72 See California Department of Water Resources v. FERC, 306 F.3d 1121, 1125 

(D.C. Cir. 2002); Town of Norwood, Massachusetts v. FERC, 906 F.2d 772, 775 (D.C. 

Cir. 1990). 

73 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 234. 
Docket No. RM07-19-002 - 21 - 

NRECA’s alternative proposal and present it to the Commission within its compliance 

filing, with supporting documentation to show how it complies with the Commission’s 

requirements.74 If and when such an alternative proposal is presented to the Commission, 

the Commission will review the evidence and information provided by the RTO or ISO in 

its compliance filing and make a determination as to whether its proposal meets the 

requirements set out in the Final Rule.75 Therefore, NRECA’s request for clarification is 

misplaced. This is not the proper forum to seek a determination as to whether NRECA’s 

alternative pricing proposal meets the Commission’s requirements. As noted in Order 

Nos. 719 and 719-A, such a determination is better left to each RTO’s and ISO’s 

compliance filing. 

41. With regard to NRECA’s request for rehearing, had it been properly filed, we 

would have reaffirmed our finding in Order Nos. 719 and 719-A that the existing RTO 

and ISO market rules that do not allow for prices to rise sufficiently during an operating 

reserve shortage to allow supply to meet demand are unjust and unreasonable, and may 

be unduly discriminatory.76 The pricing approach adopted in the Final Rule and affirmed 

in Order No. 719-A is designed to correct this issue while providing protection against 

the exercise of market power. We reiterate, contrary to NRECA’s assertion, this 

procedure does not remove price caps during periods of system emergencies. Rather, it 

requires RTOs and ISOs to propose to the Commission a pricing proposal that is designed 

to better match market supply and demand and to allow the market price to more 

accurately reflect market conditions.77 The Commission’s approach to pricing also 

requires each RTO and ISO to make a factual showing as to how its proposed pricing 

methodology achieves the Commission’s goal of better matching market demand and 

supply while simultaneously protecting consumers from the exercise of market power. 

The Commission will determine whether any specific proposal meets its requirements 

after it is submitted by the RTO or ISO in its compliance filing.78 Therefore, this is not 

 

(continued...) 

74 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 104. 

75 The Commission has already addressed issues related to shortage pricing for 

some RTOs and ISOs in their Order No. 719 compliance filings. See, e.g., Southwest 

Power Pool, Inc., 129 FERC ¶ 61,163 (2009); Calif. Indep. Sys. Operator Corp., 129 

FERC ¶ 61,157 (2009); New York Indep. Sys. Operator, Inc., 129 FERC ¶ 61,164 (2009). 

76 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192; Order No. 719-A, 

FERC Stats. & Regs. ¶ 31,292 at P 93. 

77 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 195; Order No. 719-A, 

FERC Stats. & Regs. ¶ 31,292 at P 95. 

78 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 235 (“only when an RTO or 

ISO submits a compliance filing can and will the Commission determine if its pricing 
Docket No. RM07-19-002 - 22 - 

the proper forum for NRECA’s assertion that the Commission’s policy will result in rates 

that are unjust and unreasonable and will allow the exercise of market power. Any issues 

regarding particular rates belong within each RTO’s and ISO’s compliance filing. 

42. NRECA argues that the Commission’s four pricing approaches would undermine 

reliability.79 We will not make specific findings here, but we reiterate that the Final Rule 

addressed concerns regarding reliability. To ensure that RTOs and ISOs incorporate 

safeguards to protect reliability, Order No. 719 required each RTO and ISO to provide, in 

its compliance filing, “a factual record that includes historical evidence for its region 

regarding the interaction of supply and demand during periods of scarcity and the 

resulting effects on market prices, an explanation of the degree to which demand 

resources are integrated into the various markets, the ability of demand resources to 

mitigate market power, and how market power will be monitored and mitigated.”80 Also, 

Order No. 719 specifically stated that the RTO’s or ISO’s pricing approach must show 

how it improves reliability by reducing demand and increasing generation during periods 

of operating reserve shortage.81 Therefore, any reliability concerns regarding an RTO’s 

or ISO’s shortage pricing proposal should be raised in the RTO’s or ISO’s compliance 

filing. This is not the proper forum to discuss such concerns since the Commission is not 

making any specific findings regarding each RTO’s or ISO’s pricing proposal. 

43. We disagree with NRECA’s argument that the four pricing approaches will not 

attract new supply resources in real time and will not attract long-term investment in new 

supply resources. As the Commission has stated on numerous occasions, the 

Commission’s goal in this proceeding is to eliminate barriers to demand response, 

including barriers to demand response resources’ participation in organized energy 

markets.82 The Commission found that existing market rules do not accurately reflect the 

value of energy during periods of shortage and, therefore may deter new entry of demand 

response and generation resources. Higher shortage prices will encourage investment in 

 

rules are just and reasonable, not unduly discriminatory and sufficient to meet the stated 

goals of this rulemaking”); Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 102. 

79 For example, it contends that the four pricing approaches would encourage 

behavior that creates emergencies that would undermine reliability during the long-term 

period required for entry into generation markets. 

80 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194. 

81 Id. P 239. 

82 See, e.g., Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 96. 
Docket No. RM07-19-002 - 23 - 

additional generation and demand response resources.83 As noted in Order No. 719-A, 

“with improved price signals, more buyers would find it worthwhile to invest in 

technologies that allow them to respond to prices.”84 

44. We also reject NRECA’s argument that Order Nos. 719 and 719-A failed to 

explain how the Commission’s pricing proposal is superior to the NRECA’s alternative 

proposal in attracting investment in demand-side resources. In Order No. 719, the 

Commission did not comment on each individual alternative approach because it was not 

mandating one specific approach. Instead, the Commission offered a menu of options.85 

The Commission also clearly stated that it will allow each RTO and ISO to propose to 

amend its market rule to adopt any of the four approaches or adopt an alternative 

approach that is appropriate for its market.86 Order No. 719 did not reject any of the 

alternative pricing approaches, including NRECA’s. Therefore, there was no need to 

explain why or how the Commission’s proposal was “superior” to NRECA’s proposal. 

45. We also reiterate our finding in Order No. 719-A that our Final Rule relied on 

sufficient evidence to support our determinations.87 The Commission carefully 

considered the evidence and arguments submitted by many commenters, including 

NRECA, in reaching its determination regarding shortage pricing. The Commission 

gathered evidence from three technical conferences, as well as evidence submitted in the 

ANOPR and NOPR, to conclude that RTO and ISO market rules do not produce rates 

that accurately reflect the true value of energy during periods of operating reserve 

shortages.88 The fact that this evidence does not support NRECA’s desired outcome does 

not mean that the Commission’s findings are arbitrary and capricious, as NRECA asserts. 

 83 Id.

84 Id. P 98. 

85 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 235. 

86 Id. at P 234. 

87 Order No. 791-A, FERC Stats. & Regs. ¶ 31,292 at P 94. 

88 Id. P 57. 
Docket No. RM07-19-002 - 24 - 

The Commission orders: 

The requests for rehearing of Order No. 719-A are hereby denied, as discussed in 

the body of this order. Clarification is granted to the extent discussed in the body of this 

order. 

By the Commission. Commissioner Kelly dissenting in part with a separate statement 

 attached. 

( S E A L ) 

Kimberly D. Bose, 

Secretary
 UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Wholesale Competition in Regions with Organized 

Electric Markets 

Docket No. RM07-19-002 

(Issued December 17, 2009) 

KELLY, Commissioner, dissenting in part:

 I dissent in part on this order with regard to the Commission’s failure to 

update the regulatory text of section 35.28(g)(1)(i)(A) of the Commission’s 

regulations1

 to reflect changes made in Order No. 719-A.2 In Order No. 719-A, 

the Commission granted rehearing in part, modifying the aggregator of retail 

customers (ARC) requirements by directing RTOs and ISOs to amend their market 

rules as necessary to accept bids from ARCs that aggregate the demand response 

of: (1) the customers of utilities that distributed more than 4 million MWh in the 

previous fiscal year, and (2) the customers of utilities that distributed 4 million 

MWh or less in the previous fiscal year, where the relevant electric retail 

regulatory authority permits such customers’ demand response to be bid into 

organized markets by an ARC.3

 Under Order No. 719-A, RTOs and ISOs may not

accept bids from ARCs that aggregate the demand response of the customers of 

utilities that distributed 4 million MWh or less in the previous fiscal year, unless

the relevant electric retail regulatory authority permits such customers’ demand 

response to be bid into organized markets by an ARC. Order No. 719-A amended 

the language in the ARC-specific regulation, section 35.28(g)(1)(iii),4

 to reflect 

these changes. 

Unfortunately, the Commission failed to correspondingly update the 

regulatory text in section 35.28(g)(1)(i)(A), which regulates the provision of 

ancillary services by demand response resources. Under this section, RTOs/ISOs 

must accept the bids of demand response resources that are technically capable of 

 1

 18 C.F.R. § 35.28(g)(1)(i)(A). 

2 Wholesale Competition in Regions with Organized Electric Markets, 

Order No. 719-A, 74 Fed. Reg. 37,776 (Jul. 16, 2009), FERC Stats. & Regs. ¶ 

31,292 (2009). 

3 Id. P 51. 

4

 18 C.F.R. § 35.28(g)(1)(iii). 
Docket No. RM07-19-002 - 2 - 

providing the enumerated ancillary services and submit a bid at or below the 

market-clearing price, “unless not permitted by the laws or regulations of the 

relevant electric retail regulatory authority.” I believe that the Commission should 

have updated this language when it made the changes to section 35.28(g)(1)(iii) in 

Order No. 719-A. While it is true that a non-ARC demand response resource may 

provide ancillary services “unless not permitted by the laws of regulations of the 

relevant electric retail authority”, this section also covers ARC demand response 

resources and should have been amended to specify that, for those ARCs that 

aggregate the demand response of the customers of utilities that distributed 4 

million MWhs or less in the previous fiscal year, the relevant regulatory authority 

must specifically permit such customers’ demand response to be bid into 

organized markets by an aggregator of retail customers. I would have so clarified 

the regulatory text of section 35.28(g)(1)(i)(A) in this order. 

Accordingly, I respectfully dissent in part. 

______________________________ 

Suedeen G. Kelly