141 FERC ¶ 61,232

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris, and

Cheryl A. LaFleur.

Integration of Variable Energy Resources Docket No. RM10-11-001

ORDER NO. 764-A

ORDER ON REHEARING AND CLARIFICATION AND GRANTING MOTION FOR 

EXTENSION OF TIME

(Issued December 20, 2012)

1. On June 22, 2012, the Commission issued the Integration of Variable Energy 

Resources Final Rule, requiring each public utility transmission provider to: (1) offer 

intra-hourly transmission scheduling at 15-minute intervals; and, (2) incorporate 

provisions into the pro forma Large Generator Interconnection Agreement (LGIA) 

requiring interconnection customers whose generating facilities are variable energy 

resources (VER) to provide meteorological and forced outage data to the public utility 

transmission provider for the purpose of power production forecasting.

1

 The 

Commission also provided guidance regarding the development and evaluation of 

proposals related to recovering the costs of regulation reserves associated with VER 

integration. Order No. 764 defined a VER as a device for the production of electricity 

that is characterized by an energy source that: (1) is renewable; (2) cannot be stored by 

 1 Integration of Variable Energy Resources, Order No. 764, 77 FR 41482 (July 13, 

2012) FERC Stats. & Regs. ¶ 31,331 (2012) (Order No. 764). Order No. 764 resulted 

from the Integration of Variable Energy Resources, Notice of Proposed Rulemaking, 

FERC Stats. & Regs. ¶ 32,664 (2010) (Proposed Rule) and the Integration of Variable 

Energy Resources, Notice of Inquiry, FERC Stats. & Regs. ¶ 35,563 (2010) (Notice of 

Inquiry).
Docket No. RM10-11-001 - 2 -

the facility owner or operator; and (3) has variability that is beyond the control of the 

facility owner or operator.2

2. Requests for rehearing and clarification were submitted regarding certain aspects 

of: (1) the intra-hour scheduling and forecasting reforms adopted in Order No. 764; 

(2) statements addressing public utility transmission provider’s obligation to offer 

generator regulation service; and (3) the estimated burden on small entities to comply 

with the Final Rule. Additionally, Edison Electric Institute (EEI) filed a motion to extend 

the period for compliance filings from September 11, 2013, to November 12, 2013. In 

this order, the Commission affirms its basic determinations in Order No. 764, provides 

clarification, and grants EEI’s request to extend the period for compliance filings. 

I. Background 

3. In Order No. 764, the Commission adopted reforms designed to remove barriers to 

the integration of VERs and to ensure that the rates, terms, and conditions for 

Commission-jurisdictional services provided by public utility transmission providers are 

just and reasonable and not unduly discriminatory or preferential.3

 Noting the increasing 

number of VERs being brought online, the Commission concluded that reforms were 

needed to ensure that transmission customers are not exposed to excessive or unduly 

discriminatory charges, and that public utility transmission providers have the 

information needed to efficiently manage reserve-related costs.

4. Specifically, the Commission amended the pro forma Open Access Transmission 

Tariff (OATT) to provide all transmission customers the option of using more frequent 

transmission scheduling intervals within each operating hour, at 15-minute intervals.4

 

The Commission found transmission customers’ inability to adjust their transmission 

schedules within the hour to reflect changes in generation output can cause charges for 

Schedule 9 generator imbalance service to be unjust and unreasonable or unduly 

discriminatory. The intra-hour scheduling amendment was designed to correct this 

deficiency. It was also designed to allow public utility transmission providers, over time,

to use fewer reserves to maintain overall system balance.

5

 

 2 Order No. 764, 1FERC Stats. & Regs. ¶ 31,331 at P 1.

3 Id. P 1.

4 Id. P 2.

5 Id. P 95.
Docket No. RM10-11-001 - 3 -

5. The Commission also amended the pro forma LGIA to require new 

interconnection customers whose generating facilities are VERs to provide 

meteorological and forced outage data to the public utility transmission provider with 

which the customer is interconnected.

6

 Such data would only be required where it is 

necessary for that public utility transmission provider to develop and deploy power 

production forecasting. This reform was designed to facilitate public utility transmission 

providers’ use of power production forecasts, which the Commission found can provide 

public utility transmission providers with advanced knowledge of system conditions 

needed to manage the variability of VER generation through the unit commitment and 

dispatch process, rather than through the deployment of more costly reserve service, such 

as regulation reserves.

6. Finally, the Commission declined to modify the pro forma OATT to include a new 

Schedule 10 governing generator regulation service.7

 The Commission explained that the 

Schedule 10 proposal was intended to provide clarity to public utility transmission 

providers and transmission customers alike by setting forth a generic approach to the 

provision of generator regulation service. In light of the numerous comments stressing 

the importance of flexibility in the design of capacity services needed to efficiently 

integrate VERs into the transmission system, the Commission decided to maintain its 

existing case-by-case approach to evaluating proposals related to recovering the costs of 

regulation reserves associated with VER integration. However, the Commission 

provided guidance in response to the comments submitted to assist public utility 

transmission providers and their customers in the development and evaluation of such 

proposals.

II. Motion for Extension of Compliance Period

7. On October 19, 2012, EEI filed a motion to extend the compliance deadline from 

September 11, 2013, to November 12, 2013.8

 EEI expresses concern that the existing 

compliance deadline of September 11, 2013, would require public utility transmission 

providers to implement the modifications associated with Order No. 764’s intra-hour 

scheduling reform during the summer peak season. EEI states that such modifications to 

industry practices may result in unforeseen issues, which could be exacerbated during 

 6 Id. P 3.

7 Id. P 4.

8 EEI notes that American Public Power Association (APPA) and National Rural 

Electric Cooperative Association (NRECA) have authorized EEI to state that they do not 

oppose the motion.
Docket No. RM10-11-001 - 4 -

strained situations, such as summer peak conditions. Therefore, EEI requests that the 

Commission extend the deadline for compliance by 62 days in order to provide public 

utility transmission providers with flexibility in addressing operational challenges that 

may arise during the transition to intra-hourly scheduling without jeopardizing reliability. 

8. We grant EEI’s request for an extension of time for compliance with Order 

No. 764. The Commission finds good cause to extend the compliance deadline in order 

to allow public utility transmission providers to implement to reforms set forth in Order 

No. 764 outside of the summer peak season. The Commission therefore extends the 

compliance period, with compliance filings now due by November 12, 2013. 

III. Requests for Clarification and Rehearing

9. The following parties sought clarification and/or rehearing of various portions of 

Order No. 764: APPA, Florida Municipal Power Agency, and Public Power Council 

(collectively, Public Power); American Wind Energy Association (AWEA); Bonneville 

Power Administration (Bonneville); Iberdrola Renewables, LLC (Iberdrola); NRECA; 

Powerex Corporation (Powerex); and Public Interest Organizations (PIOs).

9

 

A. Intra-hour Scheduling Reform

10. In Order No. 764, the Commission amended the pro forma OATT to provide all 

transmission customers the option of using more frequent transmission scheduling 

intervals within each operating hour, at 15-minute intervals.10 This reform was designed 

to allow transmission customers the flexibility to adjust their transmission schedules, in 

advance of real-time, to reflect the variability of output in generation, more accurate 

power production forecasts, and other changes in load profiles and system conditions.11 

The Commission implemented this reform to ensure that charges for generator imbalance 

service under Schedule 9 of the pro forma OATT and for other ancillary services through 

 9 Public Interest Organizations are: Alliance for Clean Energy New York; 

Citizens Utility Board of Wisconsin; Climate and Energy Project; Conservation Law 

Foundation; Energy Conservation Council of Pennsylvania; Environment Northeast; 

Environmental Defense Fund; Great Plains Institute; Natural Resources Defense Council; 

Pace Energy and Climate Center; Sustainable FERC Project; Sierra Club; Union of 

Concerned Scientists; The Wilderness Society; Western Grid Group; Western Resource 

Advocates; and Wind on the Wires.

10 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 91.

11 Id. P 92.
Docket No. RM10-11-001 - 5 -

which reserve-related costs are recovered are just and reasonable and are not unduly 

discriminatory. The Commission received requests for rehearing and clarification of 

several discrete aspects of this requirement.

1. Applicability of Intra-hour Scheduling

a. Order No. 764

11. In the Final Rule, the Commission stated that it expects that many types of entities, 

not only VERs, may benefit from the availability of intra-hour scheduling. The 

Commission further explained:

Every transmission customer will have the ability to adjust its 

schedule at 15-minute intervals to reflect changing 

conditions. This includes, for example, transmission 

customers that experience a within-hour forced outage or 

transmission customers taking delivery from energy 

constrained resources (such as flow-limited hydro-electric 

generators, emission-limited thermal generators, and energy 

storage resources), even if using point-to-point transmission 

internal to the system.... [T]he Commission finds that intrahour scheduling will provide a range of transmission 

customers with a necessary tool to mitigate exposure to 

Schedule 9 generator imbalance charges in light of changing 

conditions.12

b. Requests for Rehearing/Clarification

12. Several commenters request that the Commission clarify the applicability of the 

intra-hour scheduling reform adopted in Order No. 764. Public Power requests the 

Commission clarify that 15-minute scheduling is available: (1) to Network Integration 

Transmission Service (NITS) customers to the extent they are subject to scheduling 

requirements for their network resources; and (2) for scheduling secondary network 

service under Part III of the pro forma OATT. Public Power states that the intra-hour 

scheduling reform requires amendments to sections 13.8 and 14.6 of the pro forma 

OATT, which are provisions in Part II of the OATT that relate to point-to-point 

transmission service. Public Power observes that no changes are required under Part III 

of the tariff specifically addressing NITS, yet there are statements made in Order No. 764 

 12 Id. P 94.
Docket No. RM10-11-001 - 6 -

that indicate that the intra-hour scheduling reform would be available for all customers.13 

Public Power contends that while the Commission did not specifically address the 

applicability of the intra-hour scheduling reform to NITS, it did indicate a strong intent to 

reach all transmission customers; only in doing so would Order No. 764 achieve its goals 

of ensuring just, reasonable and not unduly discriminatory service. 

13. Moreover, Public Power argues that a customer using secondary network service 

and a customer using point-to-point transmission service are subject to the same 

generator imbalance charges.

14 Therefore, Public Power contends that if NITS customers 

are unable to utilize intra-hour scheduling, they would be exposed to excessive imbalance 

charges. Public Power also argues that consistent scheduling practices across 

transmission systems are necessary to ensure that intra-hour scheduling is available for 

VERs that rely on both point-to-point and network service to deliver energy across 

multiple systems. 

14. AWEA and Iberdrola seek clarification that the Commission intends for all pointto-point transmission customers, including those using point-to-point transmission 

service to schedule to loads, to have the option to use intra-hour scheduling.15 AWEA 

requests that the Commission clarify that load-serving entities that use point-to-point 

transmission service to deliver energy from adjacent transmission service providers to 

load are eligible to use intra-hour scheduling.

c. Commission Determination

15. The Commission clarifies that the intra-hour scheduling reform adopted in the 

Order No. 764 applies to all transmission customers that schedule transmission service

under the OATT. This includes load serving entities, entities using point-to-point 

transmission service to schedule to loads, and transmission customers using network 

service. Order No. 764 should not be read to limit the scope of transmission customers 

eligible to use the intra-hour scheduling reform, but instead should be read as allowing 

any customer that schedules transmission service to adjust those schedules on a 15-

minute basis. The Commission believes this clarification to be consistent with the scope 

of Order No. 764 and does not require any further changes to the pro forma OATT to 

 13 Public Power at 3 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at PP 2, 

94,151).

14 Id. at 4-5.

15 Iberdrola at 3-4; AWEA at 3-4.
Docket No. RM10-11-001 - 7 -

allow all transmission customers taking service under the pro forma OATT to adjust 

transmission schedules on a 15-minute basis.

2. Calculation of Imbalance Charges 

a. Order No. 764

16. In Order No. 764, the Commission explained that the intra-hour scheduling 

requirement applies only to scheduling practices, and that transmission providers may 

continue to calculate imbalance charges on an hourly basis.16 The Commission 

explained, however, that the metric against which generator imbalances are measured 

will be more granular than under current hourly scheduling protocols.

17. The Commission rejected requests to reform the imbalance settlement time period, 

recognizing the costs associated with such changes. However, the Commission explained 

that if a public utility transmission provider believes that aligning the imbalance 

settlement interval with the intra-hour scheduling interval or implementing sub-hourly 

dispatch will lead to more efficient operations, provide appropriate price signals to 

customers, or address other potential issues, it may seek the necessary authorizations to 

do so from the Commission under section 205 of the Federal Power Act (FPA).

17

b. Requests for Rehearing/Clarification

18. Iberdrola and AWEA argue that in the absence of sub-hourly settlement and 

dispatch requirements, the Commission should clarify how intra-hour scheduling 

information will factor into the calculation of Schedule 9 charges. Iberdrola states that 

while the Commission asserted that “the metric against which generator imbalances are 

measured will be more granular than under current hourly scheduling protocols,” it did 

not provide specifics regarding the manner in which generation imbalance should be 

measured and/or calculated as a result of the new requirement.18 Accordingly, Iberdrola 

and AWEA request that the Commission clarify that public utility transmission providers 

are required to average a transmission customer’s intra-hour schedules to determine the 

hourly imbalance charged, or credited, over a given hour.19 Iberdrola and AWEA 

 16 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 104.

17 Id. P 105.

18 Iberdrola at 2-3 (quoting Order No. 764, FERC Stats. & Regs. ¶ 31,331 

at P 105).

19 Iberdrola at 2-3; AWEA at 2-3.
Docket No. RM10-11-001 - 8 -

contend that this clarification will ensure that the intra-hour schedules are properly 

factored into the hourly scheduled amount, thereby minimizing the overall hourly 

schedule deviation and any associated imbalance penalty charge.

c. Commission Determination

19. The Commission agrees with Iberdrola and AWEA that, in the absence of subhourly settlement and dispatch, a public utility transmission provider must account for 

intra-hour imbalances in order to ensure that they are properly factored into the 

calculation of hourly imbalance charges. As Iberdrola notes, the Commission in Order 

No. 764 intended that the use of 15-minute scheduling will cause the metric against 

which generator imbalances are measured to be more granular when compared to the use 

of hourly scheduling. To the extent a transmission customer using 15-minute scheduling 

is taking service from a public utility transmission provider with hourly imbalance 

charges, the public utility transmission provider would calculate the hourly imbalance 

volume by averaging the imbalances during each 15-minute scheduling interval over the 

hour, which is equivalent to what Iberdrola and AWEA described in their requests for 

clarification.

20 

3. Curtailment Priority

a. Order No. 764

20. In Order No. 764, the Commission did not propose any changes to curtailment 

priorities or the available transmission capacity (ATC) calculation to accommodate intrahour transmission schedules.21 The Commission recognized that when a public utility

 20 The calculation of average hourly imbalances is the same whether one uses 

(a) the average of the four separate 15-minute imbalances within the hour, or (b) the 

difference between the average of the scheduled amounts over the four 15-minute 

intervals and the average of the actual generation during the same period. Consider the 

following example: there are four 15-minute schedules of 10MW, 11MW, 9MW, and 

10MW, with four 15-minute actual usages of 10MW, 12MW, 10MW, and 9MW. The 

difference between these schedules and actual usages results in four 15-minute 

imbalances of 0MW, -1MW, -1MW, and +1MW. The average of the four 15-minute 

imbalances is (0-1-1+1)/4 = -0.25MW. This is identical to taking the difference of the 

average hourly scheduled amounts ((10+11+9+10)/4 = 10MW) and the average hourly 

actual usage ((10+12+10+9)/4 = 10.25MW). This difference is (10MW – 10.25MW) = -

0.25MW.

21 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 136.
Docket No. RM10-11-001 - 9 -

transmission provider makes unscheduled transmission service available after firm 

schedules have been received, the application of curtailment rules and the ATC 

calculation may become more complicated. However, the Commission indicated that this 

is already the case under hourly scheduling, and it reiterated that transmission schedules 

for firm service will continue to have curtailment priority over schedules for non-firm 

service.22 

21. In response to comments on whether a review of standards or business practices 

is necessary to implement 15-minute scheduling, the Commission found no North 

American Electric Reliability Corporation (NERC) standards or NAESB business 

practices that would prevent industry from implementing intra-hour scheduling.23 The 

Commission stated that to the extent industry believes it is beneficial to refine one or 

more standards or business practices to reflect intra-hour scheduling, industry can use 

existing processes to pursue such refinements.

b. Requests for Rehearing/Clarification

22. Powerex asks the Commission to clarify what it meant in saying that, “all 

transmission schedules for firm service will continue to have curtailment priority over all 

schedules for non-firm service.”24 Powerex urges the Commission to clarify whether the 

submission of firm intra-hour schedules will displace non-firm hourly schedules on 

constrained paths. Powerex also requests that the Commission require the North 

American Energy Standards Board (NAESB) to adopt business practice standards that 

establish the priority of firm intra-hour schedules over non-firm hourly schedules.

c. Commission Determination

23. The Commission confirms that schedules for firm transmission service will 

continue to have curtailment priority over schedules for non-firm transmission service.25 

 22 Id. P 136 & n.173 (noting that section 14.5 of the pro forma OATT clearly 

states that “[p]arties requesting Non-Firm Point-To-Point Transmission Service for the 

transmission of firm power do so with the full realization that such service is subject to 

availability and to Curtailment or Interruption under the terms of the Tariff”). 

23 Id. P 146.

24 Powerex at 10 (quoting Order No. 764, FERC Stats. & Regs. ¶ 31,331 

at P 136).

25 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 136.
Docket No. RM10-11-001 - 10 -

Powerex provides no reason why a non-firm hourly schedule should have priority over a 

firm schedule submitted within the hour. We reiterate that a firm transmission schedule 

should be treated as firm and retain curtailment priority over a non-firm transmission 

schedule. Thus, firm transmission schedules have priority over non-firm transmission 

schedules for 15-minute intervals, just as they currently have for hourly intervals. To the 

extent Powerex believes that refinements to standards or business practices are needed to 

account for intra-hour schedule changes, it should work through the relevant standards 

body to develop standards or business practices related to transmission schedule 

curtailment priorities.

4. Customer Benefits of Intra-hour Scheduling

a. Order No. 764

24. In Order No. 764, the Commission indicated that over time, the implementation of 

intra-hour scheduling should allow public utility transmission providers to rely more on 

planned scheduling and dispatch procedures, and less on reserves, to maintain overall 

system balance. The Commission further explained that:

By moving from hourly to 15-minute scheduling intervals, the 

amount of imbalance energy for which the source balancing 

authority is potentially responsible can be reduced.... This 

can lead to a corresponding reduction in the amount of 

capacity held to provide that energy and, in turn, lower 

reserve-related costs for the source balancing authority, and 

ultimately consumers. Therefore, the Commission also finds 

that implementation of intra-hour schedules is necessary in 

order to ensure that charges for ancillary services through 

which reserve-related costs are recovered are just and 

reasonable and not unduly discriminatory.26

b. Requests for Rehearing/Clarification

25. Iberdrola contends that the intra-hour scheduling reform focuses not only on the 

beneficial impacts intra-hour scheduling can have on a VER generators’ exposure to 

generation imbalance charges, but also recognizes the benefits that all point-to-point 

transmission customers would receive from this capability. Specifically, Iberdrola points 

to the Commission’s expectation that Order No. 764 would ensure that “other ancillary 

services through which reserve related costs are recovered are just and reasonable and not 

 26 Id. P 96.
Docket No. RM10-11-001 - 11 -

unduly discriminatory.”27 Iberdrola seeks clarification that, to the extent 15-minute 

scheduling reduces the reserve requirements for other ancillary services (specifically 

Schedules 3 and 4), customers will benefit from reduced reserve-related costs and 

reduced exposure to regulation and imbalance charges.

c. Commission Determination

26. As indicated by the above-quoted passage from Order No. 764, use of intra-hour 

scheduling can reduce the amount of imbalance energy for which a balancing authority is 

potentially responsible and, in turn, lower reserve-related costs. Such benefits could

manifest themselves in the form of reduced regulation charges under Schedule 3 of the 

pro forma OATT as well as any other ancillary service schedule through which a public 

utility transmission provider recovers the costs of capacity needed to provide generator 

imbalance service. Moreover, to the extent a transmission customer uses intra-hour 

scheduling to reduce the total imbalance charges it may incur under Schedule 4 of the

pro forma OATT, that customer would directly benefit from the proposed reform. 

B. Data and Forecasting Reform

27. In Order No. 764, the Commission required public utility transmission providers 

to modify their pro forma LGIAs to require new interconnection customers whose 

generating facilities are VERs to provide meteorological and forced outage data to the 

public utility transmission provider where necessary for that public utility transmission 

provider to develop and deploy power production forecasting. In requiring this change to 

the pro forma LGIA, the Commission decided not to modify existing LGIAs, in part 

because doing so would be administratively burdensome.28 The Commission received 

one request for rehearing of this requirement. 

1. Order No. 764

28. In Order No. 764, the Commission required each public utility transmission 

provider to incorporate provisions into the pro forma LGIA requiring interconnection 

customers whose generating facilities are VERs to provide meteorological and forced 

outage data to the public utility transmission provider for the purpose of power 

production forecasting. Specifically, the Commission required public utility transmission 

providers to revise article 8.4 of the LGIA to provide that reporting requirements for 

 27 Iberdrola at 4 (quoting Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 91).

28 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 195.
Docket No. RM10-11-001 - 12 -

meteorological and forced outage data would be set forth in Appendix C, Interconnection 

Details, of an LGIA.29 

29. In requiring this change to the pro forma LGIA, the Commission decided not to 

modify existing LGIAs, in part because doing so would be administratively burdensome.

The Commission noted that nothing in the pro forma LGIA precludes the parties to an 

LGIA from mutually agreeing to revise the requirements set forth in Appendix C to 

reflect the reporting of meteorological and forced outage data.30 To the extent that 

the parties are unable to agree to modifications of Appendix C, the Commission 

acknowledged that article 30.11 of the pro forma LGIA gives the transmission provider 

the right to make a unilateral filing to the Commission proposing to modify an existing 

LGIA under section 205 of the FPA.31

2. Request for Rehearing/Clarification

30. Bonneville requests that the Commission clarify that transmission providers 

have the unilateral right to amend Appendix C of the LGIA to include data reporting 

requirements. Bonneville cites a Commission order in which the Commission found that 

Bonneville’s proposal to clarify that the transmission provider has the unilateral right to 

modify Appendix C as control area requirements change was unnecessary because 

Article 9.3 already gives the transmission provider the right to unilaterally amend 

Appendix C for operational requirements.

32 Bonneville cites the following passage from 

the Safe Harbor Order:

While the Interconnection Customer does have the right to 

agree to modifications to the agreement, the LGIA should be 

read as granting the Transmission Provider the right to 

determine the applicable reliability criteria. Moreover, under 

LGIA article 9.3 (Transmission Provider Obligations), the 

Transmission Provider has the responsibility for establishing 

 29 Id. P 193.

30 Id. P 195 (noting that article 9.4 of the pro forma LGIA recognizes that 

Appendix C will be modified to reflect changes to the interconnection customer’s 

requirements as they may change from time to time).

31 Id.

32 Bonneville at 10 (citing Bonneville Power Admin., 112 FERC ¶ 61,195 (2005) 

(Safe Harbor Order)).
Docket No. RM10-11-001 - 13 -

the Interconnection Customer’s operating instructions and 

operating protocols and procedures. Because these 

instructions, protocols, and procedures will include reliability 

requirements, article 9.3 already gives the Transmission 

Provider responsibility for modifications to Appendix C. The 

same provision gives the Interconnection Customer the right 

to propose changes for the Transmission Provider to consider,

but not the right to make unilateral changes. In light of this 

provision, we conclude that BPA’s proposed change is 

unnecessary. . . .

33

In light of the Safe Harbor Order, Bonneville urges the Commission to clarify Order 

No. 764 to state specifically that transmission providers have the unilateral right to amend 

Appendix C of the LGIA to include data reporting requirements.

31. Alternatively, Bonneville urges the Commission to clarify that the requirement of 

mutual agreement or a filing under section 205 of the FPA does not apply to nonjurisdictional transmission providers because section 205 does not apply to nonjurisdictional transmission providers such as Bonneville. Bonneville argues that the 

ability to unilaterally amend Appendix C is essential for non-jurisdictional transmission 

providers. Bonneville states that if the Safe Harbor Order had not granted Bonneville the 

right to unilaterally amend Appendix C for operational requirements, Bonneville might 

not have sought reciprocity safe harbor status with the Commission. Bonneville further 

states that without the ability to make unilateral changes to Appendix C of the LGIA for 

operational requirements, Bonneville may not be able to implement the rule’s data 

reporting requirements and continuously obtain the data required from VERs.34

32. To the extent that the Commission does not grant either of these clarifications, 

Bonneville seeks rehearing. Bonneville states that it relied on the Safe Harbor Order in 

seeking safe harbor status and entering into interconnection contracts with multiple 

generators. Bonneville argues that the Commission failed to explain its departure from 

the Safe Harbor Order, which Bonneville contends results in an arbitrary and capricious 

 33 Safe Harbor Order, 112 FERC ¶ 61,195 at P 20 (emphasis added by 

Bonneville).

34 Bonneville at 11-12 (noting that Bonneville has more than 4,900 MW of 

existing VER generation on its system).
Docket No. RM10-11-001 - 14 -

order, especially where there are “serious reliance interests that must be taken into 

account.”35 

3. Commission Determination

33. We deny Bonneville’s requests for clarification or rehearing. The data provision 

requirements established in Order No. 764 require interconnection customers to provide 

public utility transmission providers with a specific set of data (i.e., meteorological and 

forced outage data) to be set forth in Appendix C of the LGIA. The Commission directed 

that these data provision requirements apply only to new interconnection agreements. 

Recognizing that there may be instances where transmission providers wish to 

incorporate these provisions into existing LGIAs, the Commission explained that such 

changes could be accomplished in one of two ways: (1) through mutual agreement with 

the interconnection customer, or (2) through a unilateral filing with the Commission 

under section 205 of the FPA, as contemplated by article 30.11 of the LGIA.36

34. In its request for rehearing, Bonneville urges the Commission to clarify, 

notwithstanding the Commission’s determination in Order No. 764, that transmission 

 35 Id. at 12 (citing FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)). 

36 Article 30.11 of the pro forma LGIA states: 

Transmission Provider shall have the right to make a 

unilateral filing with FERC to modify this LGIA with respect 

to any rates, terms and conditions, charges, classifications of 

service, rule or regulation under section 205 or any other 

applicable provision of the Federal Power Act and FERC's 

rules and regulations thereunder, and Interconnection 

Customer shall have the right to make a unilateral filing with 

FERC to modify this LGIA pursuant to section 206 or any 

other applicable provision of the Federal Power Act and 

FERC's rules and regulations thereunder; provided that each 

Party shall have the right to protest any such filing by the 

other Party and to participate fully in any proceeding before 

FERC in which such modifications may be considered. 

Nothing in this LGIA shall limit the rights of the Parties or of 

FERC under sections 205 or 206 of the Federal Power Act 

and FERC's rules and regulations thereunder, except to the 

extent that the Parties otherwise mutually agree as provided 

herein.
Docket No. RM10-11-001 - 15 -

providers have the unilateral right to amend Appendix C of the LGIA to include Order 

No. 764’s data reporting requirements. Bonneville’s argument is based on the Safe 

Harbor Order’s holding, quoted at length above, that interpreted article 9.3 of the LGIA 

to give transmission providers the responsibility for modifying Appendix C of the LGIA 

to establish the interconnection customer’s operating instructions, protocols, and 

procedures, which include reliability requirements.

37

35. In Order No. 764, the Commission recognized that power production forecasts 

could yield significant benefits if incorporated into scheduling and unit commitment 

processes.38 The Commission noted, however, that such forecasts are only as good as the 

data upon which they rely. The Commission also concluded that the current lack of 

meteorological and forced outage data reporting requirements in the pro forma LGIA 

may limit the efforts of transmission providers to manage operating costs more 

efficiently.

39 Therefore, in Order No. 764 the Commission revised the pro forma LGIA 

for new interconnection customers to require inclusion of certain data in those LGIAs. 

The Commission concluded that such information will enable transmission providers to 

commit resources providing reserves more accurately, thereby ensuring that reserverelated charges remain just, reasonable, and not unduly discriminatory.40 

36. The Commission then specified how the data should be added to existing and new 

LGIAs, finding that it would be administratively burdensome on public utility 

transmission providers and interconnection customers, especially where the public utility 

transmission provider is not engaged in power production forecasting, to apply Order 

No. 764 retroactively to existing agreements.41 The Commission found in Order No. 764 

 37 Safe Harbor Order, 112 FERC ¶ 61,195 at P 20.

38 Order No. 764, FERC Stats, & Regs. ¶ 31,331 at P 172 (referencing National 

Renewable Energy Laboratory, Western Wind and Solar Integration Study ES-18 (2010), 

available at http://www.nrel.gov/wind/systemsintegration/wwsis.html. In addition, 

NERC has recommended that forecasting techniques be incorporated into day-to-day 

operational planning and real-time operations routines/practices including unit 

commitment and dispatch. North Am. Elec. Reliability Corp., Accommodating High 

Levels of Variable Generation 54 (2009), available at

http://www.nerc.com/files/IVGTF_Report_041609.pdf).

39 Id. at P 173. 

40 Id.

41 Id. P 195.
Docket No. RM10-11-001 - 16 -

that the provision of the specified data for the performance of meaningful forecasting and 

the process by which it should be included in LGIAs will assure just and reasonable rates 

and avoid undue discrimination. Therefore, the Commission concludes that Order 

No. 764 limits the unilateral right that Bonneville asserts flows from the Safe Harbor 

Order’s interpretation of article 9.3 with regard to the issues addressed in Order 

No. 764—i.e., with regard to meteorological and forced outage data provision 

requirements and the procedures for including them in LGIAs as addressed in Order 

No. 764. Allowing transmission providers unilateral rights to act in a manner 

inconsistent with the findings in Order No. 764 could result in the provision of services 

in an unduly discriminatory manner and at rates that are unjust and unreasonable. 

37. The reason for requiring revisions to Appendix C of existing LGIAs that 

incorporate the specific set of data described in Order No. 764 to be made either through 

the mutual agreement of the parties or through a filing with the Commission is so that the 

Commission can ensure that any such changes are made in a just, reasonable, and not 

unduly discriminatory manner. In Order No. 764, the Commission established a flexible 

approach regarding the specific data that would be required from individual customers, in 

which public utility transmission providers and interconnection customers are expected to 

negotiate in the first instance.42 Moreover, the Commission recognized the potential that

certain data reporting requirements could result in increased costs to the interconnection 

customer.43

38. While new interconnection customers will be in a position to work out the details 

of the meteorological and forced outage data prior to developing their projects, existing 

interconnection customers are not in the same position. It would be unfair to allow public 

utility transmission providers to unilaterally impose unexpected costs associated with 

data reporting provisions on existing interconnection customers without being required to 

make at least some showing that specific data sought by the transmission provider (and 

the associated costs) are just and reasonable. 

39. We also deny Bonneville’s alternative request for clarification or rehearing, 

which urges the Commission to clarify that the requirement of mutual agreement or a 

section 205 filing for inclusion of the data reporting requirements addressed above in 

existing LGIAs does not apply to non-jurisdictional transmission providers. Order 

No. 764 does not apply to non-jurisdictional entities such as Bonneville unless such 

entities seek to qualify for, or maintain safe harbor status.

44 To the extent Bonneville 

 42 Id. PP 175-76.

43 Id. n.207.

44 Id. P 377.
Docket No. RM10-11-001 - 17 -

seeks to qualify for, or maintain safe harbor status, and wants to include the data 

reporting requirements addressed above in its existing LGIAs and Bonneville’s customers 

disagree with the inclusion, Bonneville may seek to incorporate these data reporting

requirements into existing LGIAs through a petition for declaratory order. In such case, 

Bonneville would need to demonstrate that its proposal substantially conforms or is 

superior to the Commission’s pro forma LGIA. In such a filing, the Commission would 

be in a position to consider facts and circumstances unique to Bonneville (such as the 

high penetration of VER interconnection customers) in the context of Bonneville’s tariff 

as a whole. 

C. Generator Regulation Service

40. In Order No. 764, the Commission declined to adopt the proposed Schedule 10 

component of the Proposed Rule.45 Instead, the Commission indicated that it would 

continue its current policy of evaluating proposals to recover capacity costs incurred to 

provide Schedule 9 generator imbalance service on a case-by-case basis. However, in 

light of the disparate views on the generator regulation service in comments on the 

Proposed Rule, the Commission provided guidance on the proper design of a generator 

regulation service charge.46 The Commission received requests for rehearing or 

clarification regarding several aspects of the guidance provided in Order No. 764.

1. Case-by-Case Approach to Generator Regulation Service 

Proposals

a. Order No. 764

41. In response to the Proposed Rule, the Commission received numerous comments 

urging flexibility in the design of capacity services needed to integrate VERs into 

transmission systems. In response to these comments, Order No. 764 maintained the 

Commission’s existing approach of evaluating individual proposals to recover the 

capacity costs incurred to provide generator imbalance service on a case-by-case basis.47

The Commission explained that this result allowed public utility transmission providers 

to retain the flexibility needed to propose capacity services that best respond to the needs 

of their customers; it also avoided requiring them to expend resources to adopt the one-

 45 Id. P 268.

46 Id. PP 315-335.

47 Id. PP 268-269. The Commission specifically withheld comment on whether 

additional reforms to contingency reserves were necessary. Id. P 342.
Docket No. RM10-11-001 - 18 -

size-fits-all generator regulation service discussed in the Proposed Rule. The 

Commission set forth guiding principles that public utility transmission providers should 

take note of in calculating the relative impact of individual customers or customer classes 

on a public utility transmission provider’s overall generation regulating reserve needs and 

allocating those costs accordingly.48 

b. Requests for Rehearing/Clarification

42. PIOs argue that the end result of Order No. 764 is to permit the imposition of 

unjust and unreasonable rates by allowing public utility transmission providers to charge 

VERs directly for integration costs while allowing other generation integration costs to be 

spread system-wide, resulting in unlawful discrimination. PIOs argue that by permitting 

public utility transmission providers “to impose Schedule 10-type of service charges,” 

Order No. 764 reflects unsound regulatory policy.49 PIOs argue that the guidance set 

forth in Order No. 764 on how such generator regulation charges should be developed is 

unworkable, and that the service itself is too expensive, complex, and may not be 

necessary in light of the other reforms adopted in Order No. 764. PIOs contend that, at 

a minimum, the Commission should prohibit public utility transmission providers from 

implementing such a service for at least two years after the effective date of Order 

No. 764 in order to provide sufficient time for the other reforms to be implemented and 

their effects studied.

43. PIOs suggest that Order No. 764 allows public utility transmission providers to 

charge VERs for their contribution to system variability while allocating the costs of the 

variability of conventional generators across all system customers, which PIOs believe to 

unduly discriminatory and in contravention of section 205 of the FPA. PIOs contend that 

both VERs and conventional generators share attributes of uncertainty and variability, 

asserting that thermal generators routinely fail to start, trip offline, and vary from their 

schedules. PIOs further contend that “dispatchability” is not a consistent distinction 

between the two categories of generators, as some VERs can be dispatchable.50 PIOs 

disagree with the Commission’s conclusion in Order No. 764 that VERs are not similarly 

situated to conventional, dispatchable generation for purposes of evaluating the need to 

implement the reforms adopted therein.51 PIOs assert that the only support given by the 

 48 Id. P 317.

49 PIOs at 8.

50 Id. at 5-6 (citing instances where public utility transmission providers require 

generators, including VERs, to be dispatchable).

51 Id. at 5-6 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 47). 
Docket No. RM10-11-001 - 19 -

Commission when recognizing that VERs are not similarly situated to conventional 

generators was the Commission’s definition of VERs set forth in Order No. 764.52 PIOs 

argue that the Commission cannot support its conclusion using only this definition of 

VERs. PIOs argue that the Commission erred to the extent that it intended the general 

assertion that VERs are not similarly situated to conventional generation to be 

determinative as to the specific issue of both uncertainty and variability. PIOs argue that 

the Commission provided no factual or economic support for this assertion, nor does the 

Commission tie the statement to the discussion of Schedule 10-type regulation service. 

PIOs contend that all generators impose integration costs on a transmission system, and 

that the Commission should allocate all such costs to all customers in a service territory, 

rather than allowing public utility transmission providers to allocate different generator 

regulation charges to different sets of customers.53 PIOs argue that the Commission 

should amend Order No. 764 to prohibit public utility transmission providers from 

charging different volumetric reserve requirements to different customers.

44. PIOs state that if the Commission does not grant rehearing on these points, it 

should, at a minimum, condition any Schedule 10-type service on the public utility 

transmission provider utilizing a design that reflects the following two options.54 First, 

PIOs argue that the Commission could require public utility transmission providers to 

implement a slower reserve service (akin to load-following or spinning reserves). 

Second, PIOs argue that the Commission could require that the regulation service be 

designed to compensate only for the moment-to-moment balancing associated with 

generation variability, and not for VER variability that affects the system beyond the 

balancing timeframe. Expanding on this point, PIOs argue that the Commission’s use of 

the term “regulation” is imprecise and could include both seconds-to-minutes, and 

minutes-to-hours. PIOs argue that Schedule 10 rates for all schedule variations within an 

hourly period is likely to be unjust and unreasonable, and therefore PIOs urge the 

Commission to oppose it here.

45. PIOs also argue that Order No. 764 failed to expressly address how the 

six principles applicable to any Schedule 10-type filing will ensure that the proposal is 

not unduly discriminatory toward VERs.55 PIOs believe that the Commission should 

establish a technical conference to address the operational issues associated with the 

 52 Id. at 6 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at n.1).

53 Id. at 10-12 (citing AWEA, Comments on Proposed Rule at 28-32).

54 Id. at 13-14.

55 Id. at 13.
Docket No. RM10-11-001 - 20 -

implementation of a Schedule 10-type service as well as the six principles discussed in 

Order No. 764. PIOs allege that the Commission ignored requests for a technical 

conference in Order No. 764.

c. Commission Determination

46. The Commission finds that PIOs’ concerns have been thoroughly considered and 

addressed in this proceeding and that PIOs’ request for a finding that VERs are no 

different from other generators is misplaced at this time. As a general matter, all 

transmission customers are required to account for ancillary services in a similar manner. 

To the extent that a public utility transmission provider proposes to allocate to VERs their 

share of system variability, it must also allocate to all other generation resources as 

transmission customers their corresponding share of system variability.56

47. Where appropriate, the Commission has recognized how the unique characteristics 

of VERs can inform regulatory policies.57 Within the context of this proceeding, we 

continue to believe that the fact-intensive nature of public utility transmission provider 

proposals to implement a generator regulation charge with a differentiated rate justifies a 

case-by-case review of such proposals. At that time, the Commission would be in a 

position to determine the ways in which a public utility seeks to apply different generator 

regulating reserves to different customers (or customer classes), and whether such rates 

accurately reflect the customers’ proportionate share of the public utility transmission 

provider’s overall regulation needs.58 Moreover, such individual cases are the 

appropriate place to evaluate the extent to which different customers may impose such a 

degree of variability or uncertainty on a transmission system that they merit different 

generator regulating rates. 

 56 Order No. 764, 139 FERC ¶ 61,246 at P 320.

57 See, e.g., Preventing Undue Discrimination and Preference in Transmission 

Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, at PP 663-666, order on reh’g, 

Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-

B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 

(2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

(recognizing the limited ability of intermittent generators to precisely forecast or control 

generation levels); Interconnection for Wind Energy, Order No. 661, FERC Stats. 

& Regs. ¶ 31,186, order on reh’g, Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 

(2005) (adopting a package of interconnection standards applicable to large wind 

generators).

58 Order No. 764, FERC Stats & Regs. ¶ 31,331 at P 320.
Docket No. RM10-11-001 - 21 -

48. Order No. 764 implemented a minimum set of requirements applicable to all

public utility transmission providers that would build on existing regional efforts to 

address VER integration.59 Within individual cases, a public utility transmission provider 

seeking to allocate the cost of generator regulation service to customers based on their 

responsibility for those costs must show that the rates for any such service are just and 

reasonable. In making this showing, the public utility transmission provider may propose 

additional operational reforms or other complementary services, such as following or 

spinning reserve services, as warranted for its particular circumstances. At the same 

time, transmission customers may advocate that additional reforms should be 

implemented. Based on the record in an individual proceeding, the Commission will 

determine whether such additional operational reforms or complementary services are 

necessary to ensure that the public utility transmission provider’s rates remain just and 

reasonable and not unduly discriminatory. The public utility transmission provider will 

be expected to reduce the costs of generator regulation service to the extent practicable60

and allocate such costs based on transmission customers’ proportionate share of 

responsibility.61

49. While we acknowledge that the Commission did not explicitly repeat in Order 

No. 764 each of PIOs’ arguments in response to the Proposed Rule, we did consider and 

respond to the substance of their arguments by: (1) not adopting the proposed reform to 

which PIOs objected; (2) allowing for flexibility in how any capacity service would be 

designed and thereby not prescribing that all public utility transmission providers must 

provide the regulation-type service to which PIOs object; and (3) setting forth guidelines 

that will ensure that future proposals to implement generator regulation charges with 

differentiated rates are just, reasonable, and not unduly discriminatory. 

50. For these reasons, we will not make the determinations sought by PIOs on 

rehearing because the record in this proceeding leads us to believe that generator 

regulation services are best addressed on a case-by-case basis, where the specific facts 

and circumstances of a public utility transmission provider’s system and its proposed 

generator regulation service can be explored.62 Nor will we adopt the additional 

 59 Id. P 24 (emphasis added).

60 Id. PP 321-23.

61 Id. P 320.

62 See Westar Energy Inc., 130 FERC ¶ 61,215, at P 36 (2010), order on reh’g, 

137 FERC ¶ 61,142 (2011) (Westar) (accepting a proposal by a public utility 

transmission provider to assess intermittent generators higher regulation costs in a 

manner consistent with cost causation principles); PacifiCorp, 136 FERC ¶ 61,092 

(continued...)
Docket No. RM10-11-001 - 22 -

conditions and two-year waiting period advanced by PIOs. The Commission was 

mindful of these suggestions when developing Order No. 764. Indeed, the Commission 

found in Order No. 764 that the requirement for public utility transmission providers to 

offer shorter, 15-minute scheduling would tend to reduce the amount of capacity that 

source balancing authorities would need to maintain.63 However, upon evaluating the 

competing interests of different industry participants, including those raised by PIOs

here,64 the Commission concluded that its existing case-by-case approach provided the 

necessary flexibility for capacity services to be tailored to the particular needs of a 

transmission system. 

51. Likewise, rather than establishing time periods before allowing public utility 

transmission providers to implement a generator regulation service, the Commission 

sought to achieve a balanced approach that emphasizes public utility transmission 

providers’ obligation to take the intra-hour scheduling and forecasting reforms into 

account in supporting any such proposal.65 The Commission stated that “[i]n reviewing 

any future proposal to allocate a greater quantity of capacity costs to a particular set of 

transmission customers, it would be reasonable for the Commission to consider whether 

the public utility transmission provider has taken steps to mitigate such costs.”66 Thus, 

while the Commission will consider the extent to which additional reforms might 

mitigate a public utility transmission provider’s reserve costs, there is no need for a twoyear wait-and-see period. Public utility transmission providers are entitled to an effective 

opportunity to recover the costs of providing service,67 and we will not foreclose their 

option to seek such cost-recovery for reasonably incurred reserve costs. However, in 

light of the potential for the reforms in Order No. 764 to result in additional cost savings 

over time,68 the Commission will be open to considering whether a public utility 

 

(2011) (setting a proposed generator regulation service rate schedule, among other things, 

for hearing and settlement procedures); Puget Sound Energy, Inc., 137 FERC ¶ 61,063 

(2011) (setting a proposed generator regulation service rate schedule that charges 

different rates for different customers for hearing and settlement procedures).

63 Order No. 764, 139 FERC ¶ 61,246 at PP 95-96.

64 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at PP 248-50.

65 Id. PP 322-325.

66 Id. P 334.

67 Id. P 324.

68 See, e.g., id. PP 95-96.
Docket No. RM10-11-001 - 23 -

transmission provider should be required to update its rates to reflect the impact of these 

reforms over time to ensure that rates remain just and reasonable and not unduly 

discriminatory.

2. Load and Conventional Generation Anomalies and Cost 

Allocation

a. Order No. 764

52. In Order No. 764, the Commission recognized that calculating the relative impact 

of individual customers or customer classes on a public utility transmission provider’s 

overall generator regulation reserve needs and allocating those costs accordingly could be

difficult and complex.

69 Accordingly, Order No. 764 set forth specific guidance as to 

how the Commission expects proposals to implement a generator regulation service to be 

developed and supported. Among other things, the Commission explained: 

[T]o the extent a public utility transmission provider proposes 

to differentiate among customers (or customer classes) in 

determining their relative regulating reserve responsibilities, 

the public utility transmission provider must demonstrate that 

the overall quantity of regulating reserve it requires of its 

transmission customers accounts for diversity benefits among 

all resources and loads, and the allocations to individual 

customers (or customer classes) of their proportionate share is 

based on the operational characteristics of such customers (or 

customer classes).70

53. The Commission further explained that “diversity events, though perhaps 

characterized as anomalies, should be included in the data set so that the quantity and 

costs of such reserves are more reflective of actual system operations.”71 The 

Commission described weather events, such as droughts that may affect the required 

quantity of generator regulation reserves more or less during different parts of the year as 

an example of such “diversity events.” 

 69 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 317.

70 Id. P 320.

71 Id. P 321.
Docket No. RM10-11-001 - 24 -

b. Request for Rehearing/Clarification

54. AWEA seeks clarification of the guidance in Order No. 764 that proposals to 

implement generator regulation service should account for “diversity events” and data 

anomalies in the calculation of the quantity and allocation of generator regulation 

reserves.

72 AWEA asks the Commission to affirm that this includes the anomalous 

behavior of conventional generators and loads. AWEA states that a transmission service 

provider might argue that it should exempt a conventional generator’s deviations from 

scheduled output during periods in which the conventional generator is ramping from one 

output level to another, or that a load schedule deviation caused by the behavior of a nonconforming industrial load is anomalous and should be excluded from the dataset. 

According to AWEA, such deviations can account for a sizeable share of the regulation 

burden of the power system. AWEA contends that excluding such deviations could bias

the allocation of reserve costs away from conventional generators and loads, thereby 

imposing excessive and discriminatory costs on entities such as VERs.

c. Commission Determination

55. The Commission believes that Order No. 764 already addresses AWEA’s concern. 

As the Commission explained in Order No. 764, once the overall quantity of regulation 

reserves is calculated for transmission customers, it should be allocated to individual 

customers (or customer classes) based on their “proportionate share,” as determined by 

the operating characteristics of those customers (or customer classes).73 However, we 

agree with AWEA that public utility transmission providers proposing a generator 

regulation charge must calculate their total regulating reserve need with respect to all 

operational causes that drive the need for regulating reserves. In the absence of system 

specific data, it would be difficult to determine whether certain behavior (such as the 

ramps and schedule deviations described by AWEA) is “anomalous.” Thus, while we 

decline to make a per se finding here that any one customer (or customer class) or any 

one type of behavior is “anomalous,” we emphasize that the public utility transmission 

provider must explain how the variations of all resources and loads are accounted for in 

its section 205 filing. To the extent AWEA believes that a public utility transmission 

provider has not justified how it accounts for all variations in a section 205 filing, AWEA 

may raise that issue in that proceeding.

 72 AWEA at 4 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 224).

73 Order No. 764, FERC Stats. & Regs. ¶ at P 320.
Docket No. RM10-11-001 - 25 -

3. Transmission Provider’s Discretion & Deployment of Resources

a. Order No. 764

56. In Order No. 764, the Commission acknowledged comments seeking guidance on 

the extent to which power production forecasting would affect a differentiated rate 

structure under the proposed Schedule 10 generator regulation service. One commenter 

(Puget Sound Energy, Inc. (Puget)) sought clarification of the proposed Schedule 10 as to 

whether a transmission customer delivering from a VER would be required to schedule 

according to the public utility transmission provider’s centralized power production 

forecast.

74

57. The Commission responded to this comment by explaining that a transmission 

customer is responsible for the accuracy of transmission schedules and the public utility 

transmission provider is responsible for the reliability of its system.75 The Commission 

also explained that power production forecasting is intended to inform the transmission 

provider regarding aggregate system variability that results from having VERs on its 

system, but it is not intended to replace transmission schedules from transmission 

customers delivering from VERs. The Commission further clarified that public utility 

transmission providers that use power production forecasts should use them to manage 

uncertainty in the same manner they use other forecasts of uncertainty for the 

transmission system. 

58. Accordingly, the Commission declined to require transmission customers 

delivering from VERs to submit transmission schedules according to the public utility 

transmission provider’s forecast. The Commission further stated:

[T]he public utility transmission provider’s obligation should 

be to deploy its resources according to its own forecast in 

order to maintain the reliability of the system. The public 

utility transmission provider retains the risk and responsibility 

 74 Id. P 302 (describing a comment stating that if the public utility transmission 

provider’s forecast sets the schedule, then there could be a perverse incentive for public 

utility transmission providers to generate inaccurate forecasts and collect larger generator 

imbalance charges under Schedule 9; however, if the VER is permitted to set its own 

schedule that differs from the public utility transmission provider’s forecast, it remains 

unclear how the public utility transmission provider is supposed to manage and deploy its 

resources—according to its own forecast or to the VER’s schedule).

75 Id. P 328.
Docket No. RM10-11-001 - 26 -

for inaccurate procurement of reserve requirements while the 

transmission customer retains the financial risk and 

responsibility for inaccurate schedules.76 

b. Request for Rehearing/Clarification

59. Bonneville requests clarification that each transmission provider may determine 

how to use its forecasts to plan and deploy its resources. Bonneville explains that it is 

concerned with the statement in Order No. 764 that a transmission provider is obligated 

“to deploy its resources according to its own forecast in order to maintain the reliability 

of its system.”77 Bonneville indicates that VER power production forecasts have several 

uses, such as: (1) establishing an agreed-upon approach to scheduling; and (2) helping to 

ensure that reserve costs are minimized by identifying the likely range of reserves to be 

deployed and the direction of the reserve deployment. However, Bonneville believes that 

the transmission provider must deploy reserves in response to actual variability on its 

system, and it needs to consider factors beyond just the power production forecast. 

60. For these reasons, Bonneville urges the Commission to clarify that, while power 

production forecasts may inform planning decisions, each transmission provider may 

determine how to use its forecasts to plan and deploy its resources. Alternatively, 

Bonneville contends that if the Commission intends to require a transmission provider to 

plan to deploy resources only according to its power production forecast, then the 

Commission should clarify that the transmission provider may limit the provision of 

generator imbalance service to the amount that it can supply from the resources it 

deployed in accordance with the forecast.78

c. Commission Determination 

61. As the context for the statement highlighted by Bonneville indicates, the 

Commission did not require public utility transmission providers to deploy their reserves 

solely based on centralized forecasts, without regard to actual system conditions and 

circumstances. Rather, Order No. 764 pointed to centralized forecasts as a tool available 

to public utility transmission providers to manage system variability and the associated 

costs. The statement highlighted by Bonneville was made in order to differentiate the 

responsibilities and risks of transmission customers and public utility transmission 

 76 Id. P 331.

77 Bonneville at 25 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 331).

78 Id. at 26.
Docket No. RM10-11-001 - 27 -

providers regarding the manner in which they use forecasts. It was not intended to be a 

prescriptive statement that would limit the public utility transmission provider to 

deploying reserves based solely upon the forecast, without regard to other facts and 

system conditions.

62. Public utility transmission providers have a significant amount of flexibility in 

how they choose to incorporate centralized forecasts into their system operations.

Consistent with Order No. 764, public utility transmission providers remain free to 

propose capacity services that best respond to the needs of their customers with the 

expectation that the implementation of power production forecasting will be addressed in 

any proposal to require different transmission customers to purchase or otherwise account 

for different quantities of generator regulating reserves.79 

4. Financial Risk of Reserve Capacity Procurement

a. Order No. 764

63. In Order No. 764, the Commission recognized that there was disagreement on

exactly how power production forecasting should be factored into public utility 

transmission providers’ allocation of regulation reserves. Therefore, the Commission 

reserved judgment as to the appropriate power production forecasting requirements for a 

particular public utility transmission provider. At the same time, the Commission 

expressed its expectation that the implementation of power production forecasting will be 

addressed in any proposal to require different transmission customers to purchase or 

otherwise account for different quantities of generator regulation reserves.80 The 

Commission set forth the following policy guidance in order to assist public utility 

transmission providers in crafting any such proposals:

[T]he transmission customer is responsible for the accuracy 

of transmission schedules and the public utility transmission 

provider is responsible for the reliability of its system. 

Therefore, the public utility transmission provider would 

utilize the power production forecast to identify the necessary 

amount of reserves and to use those reserves to maintain 

reliability of the transmission system. The obligation of the 

transmission customer is to submit schedules for deliveries. 

Power production forecasting is intended to inform the 

 79 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 325.

80 Id.
Docket No. RM10-11-001 - 28 -

transmission provider regarding aggregate system variability 

that results from having VERs on its system, not to replace 

transmission schedules from transmission customers 

delivering from VERs. Public utility transmission providers 

using power production forecasts should do so to manage 

uncertainty in the same manner they use other forecasts of 

uncertainty for the transmission system. For example, despite 

service agreements to serve load, public utility transmission 

providers develop and use load forecasts to assure load can be 

met reliably and efficiently. Similarly, despite transmission 

schedules to deliver from a VER, public utility transmission 

providers should use power production forecasts to assure 

energy can be provided to load in a reliable and efficient 

manner.81 

64. The Commission further described the appropriate division of responsibilities 

among public utility transmission providers and transmission customers, stating that “the 

public utility transmission provider’s obligation should be to deploy its resources 

according to its own forecast in order to maintain the reliability of the system.”82 The 

Commission explained that “the public utility transmission provider retains the risk and 

responsibility for inaccurate procurement of reserve requirements while the transmission 

customer retains the financial risk and responsibility for inaccurate schedules.”83 

b. Request for Rehearing/Clarification

65. Bonneville contends that the Commission should clarify that while the 

transmission provider retains the responsibility for the reliable operation of its system, 

VER customers bear the risk of inaccurate reserve capacity procurement. Bonneville 

argues that this clarification is necessary because Order No. 764 places the risk and 

responsibility for the inaccurate procurement of reserve requirements on public utility 

transmission providers,84 while at the same time requiring public utility transmission 

providers to use power production forecasts to identify the necessary amount of 

 81 Id. P 328.

82 Id. P 331.

83 Id.

84 Bonneville at 6 (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 331).
Docket No. RM10-11-001 - 29 -

reserves.

85 Bonneville contends that because these forecasts are based on data supplied 

by VER customers, they will only be as good as the data used to generate them. 

Bonneville argues that if the data are wrong, the forecasts will be wrong, causing the 

transmission provider to procure an incorrect amount of reserves. Bonneville further 

points out that even if the data are correct and generate an accurate forecast, the amount 

of reserves procured based on the forecast may not align with the amount actually needed 

for balancing VER customers.

66. Accordingly, Bonneville contends that VER customers should bear the costs of 

(1) excess reserves when the transmission provider acquires too many reserves based on a 

power production forecast; and (2) potentially expensive, short-term purchases when the 

transmission provider acquires too few reserves based on similar forecasting methods. 

Bonneville asserts that, alternatively, the transmission provider may have to resort to 

transmission curtailments to preserve system reliability and alleviate excess or inadequate 

energy flows.

67. To the extent that the Commission does not make this clarification, Bonneville 

seeks rehearing. Bonneville states that the Commission’s conclusion that the 

transmission provider retains the risk and responsibility for inaccurate procurement of 

reserves creates an inequitable cost shift to other transmission customers.86 Bonneville 

also contends that the Commission did not address its comments on this point in Order 

No. 764. In response to the Proposed Rule, Bonneville stated:

Since the centralized forecast is based on the information 

provided from the VERs, is developed for the benefit of the 

VERs, and since the plant-specific components of the 

centralized forecast would ideally be used to establish VER 

schedules, VERs should bear the residual risk and costs 

associated with forecast error, which will not be completely 

eliminated, even through the deployment of state-of-the-art 

centralized forecasting systems. For example, the risks and 

costs associated with centralized forecast error would include 

generation imbalance charges that result from the difference 

between scheduled generation and actual generation. These 

costs reflect the nature of generation imbalances and should 

continue to be recovered from VER generation customers. In 

addition, VERs should accept reasonable risks or costs 

 85 Id. (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 328).

86 Id. at 8-9.
Docket No. RM10-11-001 - 30 -

associated with balancing reserve capacity shortfalls that 

may result from centralized forecast error, such as VER 

generation limitations or curtailments from the transmission 

provider or emergency balancing reserve capacity purchases.

Allocation of such risks and costs to other transmission 

customers and rate payers would be inequitable and 

inconsistent with the principle of cost causation.87

68. Bonneville urges the Commission to respond to these comments by granting 

rehearing and by holding that, if the transmission provider procures an incorrect amount 

of reserve capacity, either because the VER power production forecast is developed with 

inaccurate VER data or because VER scheduling practices do not correspond to 

predictions generated with VER data, VER customers assume the risk of those 

inaccuracies—both the economic risk associated with the costs of procurement and the 

risk of curtailments when needed to preserve reliability.

c. Commission Determination

69. As the Commission explained in Order No. 764, the public utility transmission 

provider must procure an amount of regulating reserves sufficient to manage the 

aggregate variability caused by the loads and resources on its system, taking into account 

offsetting deviations or “diversity benefits” among loads and resources.88 In turn, the 

public utility transmission provider is entitled to recover the just and reasonable costs 

associated with providing these capacity reserves to its transmission customers. The 

obligation to procure generator regulation reserves did not change in Order No. 764.89 

Moreover, Order No. 764 affirmed the Commission’s existing policy of allowing public 

utility transmission providers to allocate the costs of generator regulation service to 

customers based on their responsibility for those costs,90 while at the same time requiring 

public utility transmission providers to reduce those costs to the extent practicable91 and 

 87 Id. at 8 (citing Bonneville Comments on Proposed Rule at 50-51 (emphasis 

added)). 

88 Order No. 764, FERC Stats. & Regs. ¶ 21,331 at P 319.

89 Id. P 270.

90 Id. PP 269, 317-323.

91 Id. PP 321-323.
Docket No. RM10-11-001 - 31 -

allocating them based on transmission customers’ “proportionate share” of the 

responsibility.92 

70. Order No. 764 pointedly determined that public utility transmission providers 

should remain free to propose capacity services that best respond to the needs of their 

customers,

93 and it clearly articulated the Commission’s expectation that power 

production forecasting will be addressed in any proposal to require different transmission 

customers to purchase or otherwise account for different quantities of generator 

regulating reserves.94 We believe this leaves adequate room for a public utility 

transmission provider to demonstrate that inaccurate data are leading to increased reserve 

costs and the public utility transmission provider should be able to recover such costs 

from customers causing them. Thus, we will not determine on a generic basis here that 

VER customers should bear the costs of excess reserves procured as a result of power 

production forecasting based upon poor quality data; nor will we find generically that 

VER customers should bear the costs of expensive, short-term purchases made because 

the transmission provider acquired too few reserves based on similarly poor data. The 

interplay between forecasting data quality and reserve cost allocation is more 

appropriately addressed in individual section 205 filings raising the issue. 

5. Intra-Hour Scheduling Flexibility & Rate Design

a. Order No. 764

71. Order No. 764 allows public utility transmission providers to propose to recover 

and allocate generator regulation costs by way of a proposal under section 205 of the 

FPA.95 The Commission provided guidance as to its expectations for such proposals, 

expressly stating that a public utility transmission provider should consider the extent to 

which transmission customers are using intra-hour scheduling in evaluating whether to 

require different transmission customers (or groups of customers) to purchase or 

otherwise account for different quantities of generator regulating reserves.

 92 Id. P 320.

93 Id. P 268.

94 Id. P 325.

95 Id. P 333.
Docket No. RM10-11-001 - 32 -

b. Request for Clarification/Rehearing

72. Bonneville contends that the Commission should clarify that transmission 

providers may establish reserve requirements and commensurate rates based on historical 

hourly scheduling for VER customers that choose to switch between hourly and intrahour scheduling instead of committing to intra-hour scheduling.96 Bonneville contends 

that this clarification is important because transmission providers will be unable to make 

reductions in the amount of reserve capacity needed to meet the balancing needs of all 

VER customers if transmission providers have no certainty that VER customers will 

correct their scheduling error on an intra-hour basis. 

73. Bonneville contends that the voluntary intra-hour scheduling requirement of Order 

No. 764 will not provide enough certainty for transmission providers to reduce operating 

reserves. Bonneville further contends that generator imbalance service charges do not

provide sufficient incentives for VER customers to participate in voluntary 15-minute 

scheduling.97 Bonneville therefore argues that mandatory intra-hour scheduling is the 

best way to ensure system-wide reductions in reserve capacity and cost savings for VER 

customers. Accordingly, Bonneville urges the Commission to acknowledge that there 

may not be cost savings if VER customers do not utilize intra-hour scheduling to correct 

their schedule error in every scheduling interval, and to clarify that transmission 

providers may establish options for VER customers to commit to schedule on an intrahour basis.

74. Bonneville requests that the Commission ratify Bonneville’s model through which

VER customers may commit to make intra-hour schedule adjustments and to meet a level 

of scheduling accuracy that is predetermined and measurable, such as scheduling to an 

agreed-upon forecast or basing schedules on persistence scheduling assumptions. Under 

this approach, VER customers would be able to choose to commit to utilize intra-hour 

scheduling to correct their schedule error for every interval, or to choose to schedule on 

an hourly basis or mix of hourly and intra-hour scheduling. Bonneville explains that the 

consequence of choosing the option to switch between hourly and intra-hour scheduling, 

however, is that the VER customer will pay higher rates because the transmission 

 96 Bonneville at 13.

97 Id. at 15 (citing its own experience that despite generator imbalance service 

penalty charges, VER customers have not consistently utilized intra-hour scheduling to 

correct schedule error).
Docket No. RM10-11-001 - 33 -

provider will have to ensure sufficient reserve capacity is available at all times to balance 

a potential scheduling error based on historical hourly scheduling of VER customers.98 

75. Bonneville contends that this approach is necessary to ensure that sufficient 

reserve capacity is available to meet system reliability needs and the potential scheduling

errors of VER customers, while providing system operators with the flexibility to manage 

their systems efficiently. Bonneville further states that its requested clarification will 

ensure that the users of reserve capacity are allocated the costs associated with that 

capacity, consistent with the principle of cost causation.

c. Commission Determination

76. While we will not address the specifics of Bonneville’s model here, we find as a 

general matter that whether a transmission customer commits to scheduling at every 

intra-hour interval can be a relevant consideration as to the quantity of reserves properly 

allocated to that customer. As indicated above, Order No. 764 explicitly envisions that 

public utility transmission providers should consider the extent to which customers use 

intra-hour scheduling in determining whether to require different transmission customers 

(or groups of customers) to purchase or otherwise account for different quantities of 

generator regulation reserves. Therefore, it follows that if a public utility transmission 

provider can show that transmission customers that schedule at every intra-hour interval 

impose less of a regulating burden than those customers that do not schedule as 

frequently, a different reserve requirement may be reasonable. However, because any 

such proposal would be necessarily fact-intensive and system specific, we will not 

address the specifics of Bonneville’s proposal here. Instead, such proposals will be 

addressed on a case-by-case basis, as described in Order No. 764.

99 

77. Finally, we note that the Commission set forth a potential remedy for the problem 

described by Bonneville, i.e., that despite existing generator imbalance service penalty 

charges, VER customers do not use intra-hour scheduling to correct scheduling errors. 

Order No. 764 explained that if a public utility transmission provider believes it is 

necessary to address customers that intentionally deviate from their schedules, the public 

utility transmission provider may propose revisions to Schedule 9 generator imbalance 

service pursuant to section 205 of the FPA.100 We affirm that decision here and further 

 98 Id. at 16.

99 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 269.

100 Id. P 108 (noting that such proposals would need to demonstrate that VERs are 

not adjusting their transmission schedules despite their reasonable ability to foresee that 

output will deviate significantly from existing transmission schedules).
Docket No. RM10-11-001 - 34 -

note that even where deviations are not “intentional,” public utility transmission 

providers may propose revisions to Schedule 9 generator imbalance service to address the 

effect of those deviations on reserve requirements.

6. Lack of Data & Higher Reserve Costs

a. Order No. 764

78. In Order No. 764, the Commission recognized the relationship between the use of 

power production forecasting and the allocation of generator regulation reserve quantities 

to a particular class of customers. The Commission found that: (1) the quantity of 

reserves used to provide generator regulation service can be managed most efficiently 

with the implementation of power production forecasting (as well as intra-hour 

scheduling) by public utility transmission providers; (2) power production forecasts can 

provide public utility transmission providers with advanced knowledge of system 

conditions needed to manage the variability of VER generation through the unit 

commitment and dispatch process, rather than through the deployment of reserve 

services; and (3) without the increased situational awareness of projected variability 

provided by power production forecasts, the public utility transmission provider’s ability 

to efficiently commit or de-commit resources providing regulation reserves can be 

constrained, potentially resulting in rates for generator regulation service that are unjust 

and unreasonable or unduly discriminatory.101

b. Request for Rehearing/Clarification

79. Bonneville urges the Commission to clarify that it is not unduly discriminatory for 

transmission providers to impose higher generator regulation charges and larger reserve 

capacity requirements on VER customers that do not provide the data necessary to 

construct a forecast.

102 Bonneville argues that power production forecasts depend on 

information received from VER customers, and that the absence of data prevents 

transmission providers from producing a power production forecast. Bonneville states 

that Order No. 764 recognizes both the benefits of power production forecasting and the 

potential harm from not using forecasts. Noting that Order No. 764 limits the ability of 

transmission providers to collect data from existing customers, Bonneville argues that 

this lack of data requires the transmission provider to hold more reserve capacity.

 101 Id. P 323.

102 Bonneville at 26-27.
Docket No. RM10-11-001 - 35 -

c. Commission Determination

80. Order No. 764 recognized the contentious nature of proposals by public utility 

transmission providers to implement power production forecasting requirements and to 

allocate different reserve requirements to different transmission customers.103 For this 

reason, the Commission reserved judgment as to the appropriate power production 

forecasting requirements for particular public utility transmission providers, with the 

expectation that such matters would be addressed in individual proposals to require 

different transmission customers to purchase or otherwise account for different quantities 

of generator regulating reserves. Given the flexibility afforded by Order No. 764, public 

utility transmission providers are not precluded from attempting to demonstrate, for 

example, that the lack of data from some group of customers has a direct effect on the 

quality of their forecasts and the quantity of reserves they must retain, and thereby 

justifying a higher rate for that group of customers. Because such a proposal would 

require a fact-intensive inquiry unique to the public utility transmission provider’s 

system, we decline to address it in the abstract here. 

7. Curtailment & e-Tagging

a. Order No. 764

81. In Order No. 764, the Commission explained that its decision not to adopt a 

generic generator regulation rate schedule does not relieve public utility transmission 

providers of their obligation to maintain sufficient capacity to provide Schedule 9 

generator imbalance service.104 The Commission then reiterated the scope of a public 

utility transmission provider’s obligation to provide Schedule 9 generator imbalance 

service that it established in the Order No. 890 proceeding. Specifically, the Commission 

explained that:

[I]f it is not physically feasible for a transmission provider to 

offer generator imbalance service using its own resources, 

either because they do not exist or they are fully subscribed, 

the public utility transmission provider must attempt to 

procure alternatives to provide the service, taking appropriate 

steps to offer an option that customers can use to satisfy their 

 103 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 324.

104 Id. P 270 (citing NorthWestern Corp., 129 FERC ¶ 61,116, at P 24 (2009), 

order denying reh’g, 131 FERC ¶ 61,202, at PP 17-18 (2010)).
Docket No. RM10-11-001 - 36 -

obligation to acquire generator imbalance service as a 

condition of taking transmission service.105

82. The Commission explained that a public utility transmission provider can establish 

the amount of generator imbalance service and generator regulation service that it is 

capable of providing by either stating the maximum amount on its OASIS or by 

performing system impact studies on a case-by-case basis.106 The Commission also 

reiterated when there are no additional resources available, the public utility transmission 

provider must accept the use of dynamic scheduling with a neighboring control area.

107 

Moreover, the Commission explained its existing requirement for public utility 

transmission providers to allow customers to self-supply ancillary services.108

b. Requests for Rehearing/Clarification

83. Bonneville contends that the Commission should clarify that the transmission 

provider may limit the output of VER customers that are over-generating to their 

schedules, or curtail the schedules of VER customers that are under-generating to their 

actual output if it is not physically feasible for the transmission provider to provide 

additional reserve capacity from its resources or from third parties or to allow dynamic 

scheduling.109 

84. Bonneville states that it is possible that a transmission provider may not be able to 

provide generator imbalance service where factors such as fuel or environmental 

constraints, maintenance, or other outages result in insufficient capacity to do so.

110 

Bonneville further states that when a transmission provider is out of balancing reserve 

capacity (from its own resources as well as those in the marketplace), it is no longer able 

to absorb the difference between scheduled and actual output, and it must take other steps 

to keep its transmission system balanced, or else risk violating reliability standards or 

other legal requirements. Bonneville asserts that it would be inequitable for transmission 

 105 Id. (citing Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at PP 289-290).

106 Id. PP 270-271 (noting that Order No. 764 does not place an obligation to build 

generation on public utility transmission providers).

107 Id. n.277 (citing Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 290).

108 Id. PP 273-274.

109 Bonneville at 20.

110 Id. at 20-21.
Docket No. RM10-11-001 - 37 -

customers that are not the source of these errors to bear the resulting cost. Bonneville 

concludes that when a transmission provider no longer has available balancing resources 

(of its own or from a third-party), it is appropriate to adjust the schedules or output of 

generating facilities whose scheduling errors have depleted the available balancing 

resources.

85. Bonneville explains that in the event of schedule curtailments, the sink balancing 

authority area or purchasing entity would need to deploy its own reserve capacity 

resources or resources available to it to maintain load and resource balance. Bonneville 

further explains that in order to maintain system reliability, the source and sink balancing 

areas need to exchange information about the likelihood of such events.111 

86. Bonneville argues that these issues are not limited to Bonneville or the Pacific 

Northwest, asserting that they are ripe for a rulemaking because weather, system 

maintenance, market liquidity, and environmental obligations may affect transmission 

providers’ ability to provide reserve capacity for generator imbalance service. Bonneville 

further contends that the likelihood for reserve capacity constraints increases as VER 

integration increases across the country.

87. To the extent that the Commission does not grant clarification, Bonneville requests 

that the Commission grant rehearing on this point.112 Bonneville asserts that while the 

Commission acknowledged the possibility of reserve capacity limitations, it did not 

discuss how transmission providers should manage system reliability when they had no

more reserve capacity and dynamic scheduling was not feasible.

88. Powerex urges the Commission to clarify that a transmission customer’s discretion 

to submit schedules for transmission service does not override the transmission 

provider’s right and responsibility to ensure that firm transmission schedules originating 

on its system are supported by sufficient reserves. Powerex expresses concern that Order 

No. 764 could be interpreted as providing transmission customers with unfettered rights 

to submit firm transmission schedules, regardless of their forecasted power production 

and/or the transmission system’s available reserves.113 Powerex argues that, by not 

requiring customers to schedule transmission service according to the transmission 

 111 Id. at 22 (noting that it provides customers information about the probabilities 

of curtailments given their preferred level of service, and has developed tools to provide 

real-time information regarding Bonneville’s reserve capacity deployment).

112 Id. at 22-23.

113 Powerex at 5.
Docket No. RM10-11-001 - 38 -

provider’s centralized forecast, while at the same time placing the transmission provider 

at risk for inaccurate procurement of reserves, Order No. 764 could be interpreted to 

mean that the customer’s scheduling rights are unlimited, even where there is a 

demonstrable mismatch between a resource’s expected production and its firm 

transmission schedules.

89. For these reasons, Powerex, urges the Commission to allow public utility 

transmission providers to deny transmission customers’ firm schedules based on available 

reserves in a transparent and non-discriminatory fashion by: (1) advising customers in 

advance regarding the amount of balancing reserves the public utility transmission 

provider will provide; (2) specifying the portion of a VER’s output that will be allowed to 

be firm, with any remaining amount being classified as non-firm; and (3) allowing 

customers to self-supply additional reserves in order to fully schedule all of their VER 

output.114 Powerex argues that if the public utility transmission provider exhausts its 

established level of reserves, it should be permitted to deny firm e-Tags115 in order to 

maintain reliability. Powerex further argues that the Commission should clarify that 

transmission customers’ transactions must be properly e-Tagged (i.e., as to whether they 

are firm or non-firm) to ensure that sink balancing authorities are fully aware of the 

firmness of energy that they are receiving and whether they should procure additional 

reserves to back particular schedules.116 To the extent the Commission is unwilling to 

make these clarifications, Powerex urges the Commission to make clear that customers 

that overstate firm schedules may be subject to substantial fines or penalties, including 

any fines or penalties that result from reliability events.

90. Powerex argues that these clarifications are critical because, in Powerex’s 

experience, imbalance penalties and charges are not robust enough to deter deliberate 

generation imbalances in every single hour, as deliberate imbalances can be profitable in 

given market conditions. Powerex states that during periods when prices in an organized 

market such as California Independent System Operator Corporation (CAISO) are high, 

wind generators in the Pacific Northwest have a substantial economic incentive to submit 

schedules for their full output, even if they do not expect to fulfill those schedules.117 

 114 Id. at 5-6.

115 E-Tags, also known as Requests for Interchange, are used by NERC and/or 

Regional Entities to schedule interchange transactions in wholesale markets.

116 Powerex at 6.

117 Id. at 7 (explaining that energy prices in CAISO can climb high enough that 

when the wind generators’ firm schedules flow, the generator imbalance penalties 

(continued...)
Docket No. RM10-11-001 - 39 -

Powerex posits that in this scenario, CAISO could unknowingly receive a large volume 

of energy that is e-Tagged as firm energy, relying on such energy to meet firm load in the 

CAISO balancing authority area, when in actuality the energy is not fully backed by 

sufficient VER output and reserves at the source balancing authority area. Powerex 

therefore argues that if the transmission provider expects that it may exhaust its 

established level of balancing reserves, the transmission provider should be able to deny 

firm e-Tags in order to maintain reliability, allowing customers to submit non-firm 

schedules instead.

118

c. Commission Determination

91. The requests for clarification made by Bonneville and Powerex119 both go to the 

extent of a public utility transmission provider’s obligation to maintain sufficient reserves 

to provide generator imbalance service to transmission customers. The Commission has 

previously denied a proposal by a public utility transmission provider to disclaim its

responsibility to offer generator regulation service for intermittent renewable generator 

export transactions.

120 Order No. 764 kept in place the Commission’s policy of requiring 

public utility transmission providers to maintain sufficient reserves to provide generator 

imbalance service under Schedule 9 of the pro forma OATT.121 

92. Both Bonneville and Powerex urge the Commission to limit a public utility 

transmission provider’s obligation to provide this service to some pre-determined amount 

of reserves. We decline to make that determination in this proceeding, in which the 

Commission did not propose to modify and is not modifying the obligation previously set 

forth. 

 

combined with the cost of generator regulation service are still less than the price the 

wind generators will receive for such schedules).

118 Id. at 6.

119 Powerex filed an answer to Bonneville’s request for clarification or rehearing. 

Rule 713(d) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. 

§ 385.713(d) (2012), provides that the Commission will not permit answers to requests 

for rehearing. Accordingly, we will reject Powerex’s answer.

120 NorthWestern Corp., 129 FERC ¶ 61,116, order denying reh’g, 131 FERC 

¶ 61,202.

121 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 270.
Docket No. RM10-11-001 - 40 -

93. Nevertheless, consistent with Powerex’s request, we affirm our determination in 

Order No. 890-A, reiterated in Order No. 764, that a public utility transmission provider 

may, when it has exhausted all other options, establish the amount of generator imbalance 

service and generator regulation service that it is physically capable of providing by 

either stating the maximum amount on its OASIS or by performing system impact studies 

on a case-by-case basis.122 To the extent that a public utility transmission provider seeks 

to curtail a transmission customer’s transmission service due to a lack of balancing 

reserves, then it would have to show that it made the efforts specified by the Commission 

in Order No. 890-A, i.e., that it attempted to procure alternative balancing resources,

123

and where such resources are unavailable, it accepted the use of dynamic scheduling with 

a neighboring control area or allowed customers to self-supply the service.

94. We also note that Bonneville requests that it be allowed to curtail only VERs but 

makes no mention of curtailing other transmission customers. Under the pro forma

OATT, curtailments are required to be made on a non-discriminatory basis to the 

transaction(s) that effectively relieve the constraint and to network customers and 

transmission customers taking firm point-to-point transmission service on a basis 

comparable to the curtailment of service to the transmission provider’s native load 

customers.124 While Order No. 764 allows public utility transmission providers to 

require different customers to purchase or otherwise account for different amounts of 

regulating reserves, such distinctions must be reasonable and well-supported. Of course, 

the Commission would require similar evidentiary showings by a public utility 

transmission provider seeking to limit the reserves it would provide to any customer or 

class of customers. 

95. We also decline to address the specifics of Powerex’s concern regarding the scope 

of a transmission customer’s discretion to submit schedules for transmission service at 

this time. Order No. 764 did not make any changes in the transmission customer’s 

discretion to schedule transmission service that it has already reserved. Powerex 

describes a situation in which customers intentionally deviate from their schedules when 

it is economically beneficial for them to do so, even in light of the imbalance penalties 

 122 Id. PP 270-271.

123 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 290 (“If it is not 

physically feasible for the transmission provider to offer generator imbalance service 

using its own resources, either because they do not exist or they are fully subscribed, the 

transmission provider must attempt to procure alternatives to provide the service....”).

124 Section 13.6 of the pro forma Open Access Transmission Tariff, available at

http://www.ferc.gov/whats-new/comm-meet/2008/061908/E-1.pdf. 
Docket No. RM10-11-001 - 41 -

they would incur. However, as discussed in other sections above Order No. 764 

addressed this situation stating that if a public utility transmission provider believes it is 

necessary to address intentional deviations, it may propose revisions to Schedule 9 

generator imbalance service pursuant to section 205 of the FPA.125 Accordingly, rather 

than impose a novel and generic restriction on transmission customers’ discretion to 

schedule transmission service here, without the benefit of broad industry comment, we 

will allow the mechanisms discussed in Order No. 764 to work and revisit them when and 

if necessary.

96. Finally, we find Powerex’s concerns about e-Tagging to be beyond the scope of 

this proceeding. Powerex’s concern appears to be specific to power being exported from 

Bonneville’s system and the extent to which Bonneville’s curtailment practices pursuant 

to as Dispatcher Standing Order 216 (DSO 216) render certain transactions sufficiently 

“firm.” Ultimately, however, Powerex’s concern is more of a commercial matter 

between the buyer and the seller of power being exported from Bonneville’s system. To 

the extent power is being exported from Bonneville’s system, customers and neighboring 

balancing authorities are aware that Bonneville has implemented DSO 216 and that 

export transactions are subject to curtailment. It is up to these customers to decide for 

themselves whether such transactions can be marketed as “firm” or as something else. 

97. Moreover, Powerex’s concern appears to be based primarily on the firmness of the 

energy that is scheduled by the e-Tag and not on the firmness of the transmission service. 

E-Tags only reflect the firmness of transmission service priorities that transmission 

customers reserved prior to scheduling; they do not reflect the firmness of energy. While 

certain events (e.g., a forced outage or a curtailment pursuant to DSO 216) could 

interrupt the flow of energy scheduled by an e-Tag, that does not change the underlying 

nature of transmission service. Because the Commission’s focus here is on the reserves 

necessary to support transmission service, we decline to require generic revisions to eTags here to address the unrelated issue of whether changes to e-Tags are necessary to 

reflect the potential that energy scheduled by an e-Tag as firm may ultimately not flow. 

In terms of reliability, transmission providers still have the authority to alleviate capacity 

and energy emergencies according to applicable reliability standards.126

 125 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 108.

126 See, e.g., EOP-002-3.1 Capacity and Energy Emergencies (authorizing 

balancing authorities and reliability coordinator to take whatever actions are needed to 

ensure the reliability of their respective areas and to alleviate capacity and energy 

emergencies).
Docket No. RM10-11-001 - 42 -

D. Regulatory Flexibility Act Analysis

1. Order No. 764

98. In Order No. 764, the Commission recognized that “the cost of moving from 

hourly to 15-minute transmission scheduling could be substantial.”127 The Commission 

further stated that:

Several transmission providers state that costs will depend 

heavily on the extent to which intra-hour scheduling is 

actually used by transmission customers, estimating staffing 

costs to be in the range of $1-2 million per year if widely 

used. While these costs are not insignificant, greater use of 

intra-hour schedules means that more transmission customers 

are mitigating exposure to Schedule 9 generator imbalance 

charges and providing greater opportunities for public utility 

transmission providers to lower reserve-related costs.128 

99. The Commission noted that many of the costs cited by commenters as being 

specific to 15-minute scheduling are really related to the automation of systems used to 

process transmission schedules and verify cross-balancing authority aggregate schedules, 

which the Commission did not mandate.

129 Furthermore, the Commission acknowledged 

that some commenters raised concerns about costs associated with sub-hourly settlement 

of imbalance charges and sub-hourly dispatch of resources, neither of which the 

Commission required in Order No. 764.130

100. The Commission also conducted an analysis under the RFA.131 The Commission 

explained that Order No. 764 applies to public utilities that own, control or operate 

interstate transmission facilities (that have not received waiver of the obligation to 

comply with Order Nos. 888, 889, and 890) and to variable energy resources. The

 127 Order No. 764, FERC Stats. & Regs, ¶ 31,331 at P 102.

128 Id. (internal footnote omitted).

129 Id. P 103.

130 Id. P 104.

131 Id. P 384.
Docket No. RM10-11-001 - 43 -

Commission estimated that ten small public utility transmission providers132 would be 

affected equally by Order No. 764, at an average cost of $13,500 per year. The 

Commission found that this was not a significant economic impact, noting that in any 

event, each of these entities may seek waiver of these requirements.133 (The Commission 

also found that Order No. 764 would not have a significant economic impact on VERs, 

which NRECA does not challenge in its rehearing request.) Accordingly, the 

Commission certified that Order No. 764 would not have a significant economic impact 

on a substantial number of small entities.

2. Request for Rehearing

101. NRECA argues that the Commission erred in concluding that Order No. 764 will 

not have a significant impact on a substantial number of small entities and that, therefore, 

no final regulatory flexibility analysis is required under the Regulatory Flexibility Act

(RFA).

134 Specifically, NRECA objects to the Commission’s determination that Order 

No. 764 will “impact all the applicable transmission providers equally at an annual cost 

of $13,500 per year.”135

102. NRECA argues that in response to the Proposed Rule, it provided estimates of the 

cost impacts of the Commission’s intra-hour scheduling reform, explaining that the 

changes needed to implement the reform will depend on a number of factors, including 

the size of the transmission provider, whether the transmission provider is an RTO, and 

the number of customers that take advantage of 15-minute scheduling.136 On rehearing, 

 132 A “small entity” as referenced in the RFA refers to the definition provided in 

section 3 of the Small Business Act where a firm is “small” if, including its affiliates, it is 

primarily engaged in the generation, transmission, and/or distribution of electric energy 

for sale and its total electric output for the preceding fiscal year did not exceed 4 million 

megawatt hours.

133 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 384 & n.365 (“The criteria 

for waiver that would be applied under this rulemaking for small entities is unchanged 

from that used to evaluate requests for waiver under Order Nos. 888, 889, and 890.”).

134 NRECA at 2 (citing Regulatory Flexibility Act of 1980, 5 U.S.C. §§ 601-612 

(2006)).

135 Id. (referencing Order No. 764, FERC Stats. & Regs, ¶ 31,331 at P 384).

136 Id. at 3 (citing NRECA, Comments on Proposed Rule at 10-15).
Docket No. RM10-11-001 - 44 -

NRECA quotes the Commission’s description of its cost estimates in response to the 

Proposed Rule:

Assuming hourly schedules at a 15-minute interval used only 

by VERs, NRECA anticipates the need for software 

modifications in the range of $50,000 per company, but notes 

that some of its members have incurred expenses in the range 

of $250,000 annually for software licensing and maintenance 

related to scheduling and energy accounting software 

upgrades. If hourly schedules at a 15-minute interval are 

widely used by transmission customers, NRECA estimates a 

minimum of one additional 24x7 shift, resulting in 

approximately $1.0 million of staffing costs, and potentially 

two 24x7 positions depending on the size of the transmission 

provider.137 

103. NRECA emphasizes that the Commission noted that such costs were “not 

insignificant” and that the Commission did not question or criticize NRECA’s cost 

estimates.138 NRECA contrasts these findings with the Commission’s RFA analysis, in 

which the Commission found that Order No. 764 would affect all applicable small 

transmission providers equally at an average cost of $13,500 per year, and that it will not 

have a significant economic impact on a substantial number of small entities.

139 

104. NRECA argues that the Commission did not provide any evidence to support the 

assumption that the average cost impact of Order No. 764 on small transmission 

providers will be $13,500. Further, NRECA states that the estimates the Commission did 

cite, and characterized as “not insignificant” and potentially “substantial,” are in the 

range of $1-2 million per year if intra-hour scheduling is widely used. NRECA contends 

that even if intra-hour scheduling were limited to VERs, NRECA estimated a cost impact 

of $50,000, which does not take into account $250,000 in annual additional softwarerelated costs that some NRECA members have incurred.140 NRECA notes that this 

$50,000 estimate is “nearly quadruple” the Commission estimate of $13,500 per year. 

For these reasons, NRECA contends that the Commission has not articulated a 

 137 Id. at 4 (quoting Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 82).

138 Id. (citing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 102).

139 Id. at 4-5 (referencing Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 384).

140 Id. at 5.
Docket No. RM10-11-001 - 45 -

satisfactory explanation for concluding that Order No. 764 will not have a substantial 

economic impact on a substantial number of small entities.

3. Commission Determination 

105. As an initial matter, we note that NRECA challenges only one portion of the 

Commission’s RFA certification—the Commission’s finding that the average cost impact 

on small public utility transmission providers would be $13,500 per year, which the 

Commission determined was not a significant economic impact.

141 NRECA does not 

challenge the Commission’s finding that Order No. 764 will only affect ten small public 

utility transmission providers, nor does it challenge the Commission’s estimates or its 

finding that Order No. 764 would not have a significant economic impact on the 

160 VERs that the Commission found to be small entities.

142 Moreover, NRECA does 

not challenge, let alone address, Order No. 764’s express acknowledgment that small 

public utility transmission providers may seek waiver of the Commission’s intra-hour 

scheduling requirement.143

106. NRECA’s key argument focuses on the Commission’s acknowledgement that the 

costs of implementing the intra-hour scheduling reform could be significant, as well as

the fact that the Commission did not specifically discredit cost estimates in the range of

$1-2 million. Simply because the Commission acknowledged that such costs are “not 

insignificant,” however, does not mean that the Commission accepted $1-2 million

estimates as reasonable cost estimates for small public utilities. Indeed, the Commission 

acknowledged these higher cost estimates in the context of evaluating how the potential 

costs of the intra-hour scheduling reform measured against the potential benefits for all 

public utility transmission providers, not just small public utility transmission providers. 

In this context, the Commission found that even if the costs of the reform were on the 

higher side due to substantial use of intra-hour scheduling by customers, such costs 

would be justified in light of the significant benefits to customers in the form of reduced 

 141 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 384.

142 See id. (noting that approximately 100 VERs will be required to comply with 

Order No. 764, whereas 60 VERs will have the option to do so).

143 Id. See Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 738

(D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002) (recognizing that 

the Commission, in the context of an RFA certification, was not insensitive to the 

potential impact of Order No. 888 on small non-jurisdictional entities, allowing such 

entities to file for a waiver from compliance with the reciprocity conditions).
Docket No. RM10-11-001 - 46 -

imbalance charges.144 It bears emphasis that the discussion of potential costs in this 

section of Order No. 764 was in reference to all public utility transmission providers. It 

is therefore unremarkable that estimated costs for small public utility transmission 

providers, which the Commission discussed elsewhere in Order No. 764, would be 

different. 

107. As the Commission explained in Order No. 764, a principal driver of costs 

associated with the intra-hour scheduling reform is the number of transmission customers 

who will request intra-hour schedules.145 Due to their relative small size, the 

Commission expects small public utility transmission providers to have fewer customers 

that take advantage of intra-hour scheduling, and therefore fewer costs. As a result, 

NRECA’s lower $50,000 estimate is more in line with expected costs described in Order 

No. 764 to the ten public utility transmission providers that qualify as small entities for 

the complete implementation of the Commission’s reforms, and the higher estimates (in 

the $1-2 million range) are unlikely, as explained in Order No. 764 and clarified here.

146 

108. The Commission based the $13,500 estimate on the cost per small public utility 

transmission provider as described in the information collection statement in Order 

No. 764.147 Specifically, the Commission estimated 118 hours of burden for each 

transmission provider. The Commission applied a $114 per hour average wage148 to the 

burden hour to arrive at the $13,500 estimate (118 hours * $114 per hour = $13,452). 

The Commission believes that such costs are an accurate representation of both the 

staffing and software costs associated with the reforms required by Order No. 764. 

Additionally, the Commission estimate of $13,500 per year is based on the expected cost 

 144 Id. P 102.

145 Id.

146 NRECA itself acknowledged in its comments on the Proposed Rule that the 

costs of intra-hour scheduling should be manageable, stating that “NRECA expects that 

in some cases, there will be significant costs needed to implement this reform. But 

NRECA believes the costs will not be extraordinary, and that these costs can and should 

be mitigated through proper design and implementation.” NRECA, Comments on 

Proposed Rule at 11. 

147 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 381.

148 $114 per hour represents the average cost of an attorney ($200 per hour), 

consultant ($150 per hour), technical ($80 per hour), and administrative support 

($25 per hour). 
Docket No. RM10-11-001 - 47 -

over the first three years of compliance with Order No. 764, whereas the NRECA 

estimate of $50,000 is characterized as “limited to upfront software modifications.”149

Accordingly, we interpret NRECA’s $50,000 estimate as related to a single investment 

rather than recurring yearly costs. With that in mind, considering the full three-year 

Commission estimate of $40,500 ($13,500 multiplied by three years), the Commission 

estimate is not much different from NRECA’s estimate of $50,000. 

109. Finally, even if the Commission were to consider NRECA’s software cost estimate 

as not included in the estimate described in Order No. 764, we nonetheless find that the 

combined Commission and NRECA cost estimates (the $40,500 Commission three-year 

estimate plus the $50,000 NRECA software cost estimate) would still not be a significant 

burden on small entities. The annual cost of these combined estimates would be 

approximately $30,200 per year ($90,500 divided by 3 years). The Commission would 

not consider this $30,200 per year estimate to be a significant economic burden on small 

public utility transmission providers. Therefore, even if the Commission were to accept a 

burden estimate nearly double NRECA’s estimate, the Commission still would not be 

required to perform a final regulatory flexibility analysis under the RFA.

110. Accordingly, the Commission affirms Order No. 764’s conclusion that costs of 

that rule do not represent a significant economic impact on a substantial number of small 

entities.

150

The Commission orders:

(A) Requests for clarification and rehearing are granted or denied, as discussed 

in the body of this order.

(B) The deadline for compliance with Order No. 764 is hereby extended to 

November 12, 2013.

By the Commission. Commissioner Clark is not participating.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.

 149 NRECA, Comments on Proposed Rule at 12.

150 Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 384.