ae to... · 2019. 4. 22. · requesting an effective date of “12/31/9998”2 for the tariff...

April 22, 2019

The Honorable Kimberly D. Bose

Secretary

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

Re: Southwest Power Pool, Inc., Docket No. ER19-____

Submission of Tariff Revisions to Allow Dispatchable Variable Energy

Resources to Utilize Control Statuses to Indicate the Resource is not Currently

Capable of Following a Dispatch Instruction

Dear Secretary Bose:

Pursuant to Section 205 of the Federal Power Act (“FPA”), 16 U.S.C. § 824d,

and Section 35.13 of the Federal Energy Regulatory Commission’s (“Commission”)

Regulations, 18 C.F.R. § 35.13, Southwest Power Pool, Inc. ("SPP"), as authorized by

its independent Board of Directors, submits revisions to Section 4.1.2.4 of Attachment

AE of the SPP Open Access Transmission Tariff (“Tariff”)1 to allow Dispatchable

Variable Energy Resources (“DVER”) to utilize control statuses to indicate the

Resource is not currently capable of following a Dispatch Instruction.

SPP is requesting that the Commission issue an order in this docket as soon as

practicable, but not later than July 1, 2019. SPP is also requesting an open effective

date. In light of the facts that the exact date of Commission action on this filing is

unclear at this time and that SPP will need a number of months to build, test, and

implement the necessary software on top of SPP’s new Settlement Management System

(“SMS”) currently scheduled to be implemented in the first quarter of 2020, SPP is

requesting an effective date of “12/31/9998”2 for the Tariff Records submitted in this

filing. SPP commits to submit a filing with the Commission specifying a precise

1 Southwest Power Pool, Inc., Open Access Transmission Tariff, Sixth Revised

Volume No. 1. References in this filing to "Tariff" refer to the version of SPP’s

Tariff currently in effect. "Proposed Tariff" refers to a version reflecting the

revisions proposed in this filing. All capitalized terms not otherwise defined in

this filing shall have the definitions assigned by the Tariff.

2 See, e.g., Implementation Guide for Electronic Filing of Parts 35, 154, 284, 300,

and 341 Tariff Filings at 10 (Nov. 14, 2016) (“If the effective date is not known

at the time of the filing, such as the effective date is contingent on FERC

approval . . . the date of 12/31/9998 must be used.”).


April 22, 2019

effective date not later than 30 days prior to implementation. Upon Commission

acceptance of SPP’s filing and the completion of the SMS, SPP will work as quickly

as practicable to technologically implement the proposed changes with a target

completion date in the second quarter of 2020.

SPP respectfully requests waiver of the Commission’s timing requirements to

allow these tariff revisions to be effective more than 120 days after the date of filing.

I. BACKGROUND

A. SPP

SPP is a Commission-approved Regional Transmission Organization

(“RTO”).3 It is an Arkansas non-profit corporation with its principal place of business

in Little Rock, Arkansas. SPP currently has 97 members, including 16 investor-owned

utilities, 14 municipal systems, 20 generation and transmission cooperatives, 8 state

agencies, 14 independent power producers, 12 power marketers, 11 independent

transmission companies, 1 federal agency, and 1 large retail customer. As an RTO,

SPP: (1) administers, across the facilities of SPP's Transmission Owners, open access

transmission service over approximately 66,500 miles of transmission lines covering

portions of Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana,

Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and

Wyoming; and (2) administers the Integrated Marketplace, a centralized day-ahead and

real-time Energy and Operating Reserve market with locational marginal pricing and

market-based congestion management.4

B. Stakeholder Approval

The proposed revisions were reviewed and approved through the SPP

stakeholder process, including: (1) a meeting of the Market Working Group ("MWG")

on September 11, 2018;5 (2) a meeting of the Regional Tariff Working Group

3 Sw. Power Pool, Inc., 109 FERC ¶ 61,009 (2004), order on reh’g, 110 FERC ¶

61,137 (2005).

4 Sw. Power Pool, Inc., 146 FERC ¶ 61,130 (2014) (order approving the start-up

and operation of the Integrated Marketplace effective March 1, 2014).

5 See MWG Minutes dated September 11-12, 2018, at Agenda Item 9 posted at:

https://www.spp.org/documents/58661/mwg%20minutes%20&%20attachmen

ts%2020180911%2012.pdf. The MWG is responsible for the development and

coordination of the changes necessary to support any SPP administered

wholesale market(s), including energy, congestion management, and market

monitoring, consistent with direction from the SPP Board of Directors.

https://www.spp.org/documents/58661/mwg%20minutes%20&%20attachments%2020180911%2012.pdf

https://www.spp.org/documents/58661/mwg%20minutes%20&%20attachments%2020180911%2012.pdf


April 22, 2019

("RTWG") on September 27, 2018;6 and (3) a meeting of the Markets and Operations

Policy Committee on October 16, 2018.7 The revisions were approved for filing with

the Commission at a meeting of the SPP Members Committee8 and Board of Directors

on October 30, 2018.9 While SPP recognizes that stakeholder approval does not by

itself cause a filing to be just and reasonable, SPP requests that the Commission extend

appropriate deference to the wishes of SPP’s stakeholders, consistent with Commission

precedent.10

6 See RTWG Minutes dated September 27, 2018, at Agenda Item 11(a) posted at:

https://spp.org/documents/58757/rtwg%20september%2027%202018%20min

utes.pdf. The RTWG is responsible for development, recommendation, overall

implementation, and oversight of SPP’s Tariff. The RTWG also advises SPP

staff on regulatory and implementation issues not specifically covered by the

Tariff or issues where there may be conflicts or differing interpretations of the

Tariff.

7 See MOPC Minutes dated October 16-17, 2018, at Agenda Item 5 posted at:

https://www.spp.org/documents/58860/mopc%20minutes%20and%20attachm

ents%2020181016-17%20revised%2010-25-2018.pdf. The MOPC consists of

a representative officer or employee from each SPP Member and reports to the

SPP Board of Directors. Its responsibilities include recommending

modifications to the SPP Tariff. See Southwest Power Pool, Inc., Bylaws, First

Revised Volume No. 4 ("Bylaws") at Section 6.1.

8 The Members Committee currently consists of up to 24 representatives of the

Transmission Owning Member and Transmission Using Member sectors of

SPP’s Membership. This committee provides input to and assists the SPP

Board of Directors with the management and direction of the general business

of SPP. See Bylaws at Section 5.1.

9 See Board of Directors/Members Committee Meeting Minutes No. 181, dated

October 30, 2018, at Agenda Item 3 posted at:

https://www.spp.org/documents/58979/bod-

mc%20minutes%2020181030.pdf.

10 The Commission has previously recognized that provisions approved through

RTO stakeholder processes are due deference. See Sw. Power Pool, Inc., 127

FERC ¶ 61,283, at P 33 (2009) (noting that the Commission "accord[s] an

appropriate degree of deference to RTO stakeholder processes"); New Eng.

Power Pool, 105 FERC ¶ 61,300, at P 34 (2003) (Commission approval of

transmission cost allocation proposal based upon an extensive and thorough

stakeholder process); Policy Statement Regarding Regional Transmission

Groups, 1991-1996 FERC Stats. & Regs., Preambles ¶ 30,976, at 30,872 (1993)

(the Commission will afford the appropriate degree of deference to the

stakeholder approval process). The Commission’s deference to RTO

https://spp.org/documents/58757/rtwg%20september%2027%202018%20minutes.pdf

https://spp.org/documents/58757/rtwg%20september%2027%202018%20minutes.pdf

https://www.spp.org/documents/58860/mopc%20minutes%20and%20attachments%2020181016-17%20revised%2010-25-2018.pdf

https://www.spp.org/documents/58860/mopc%20minutes%20and%20attachments%2020181016-17%20revised%2010-25-2018.pdf

https://www.spp.org/documents/58979/bod-mc%20minutes%2020181030.pdf

https://www.spp.org/documents/58979/bod-mc%20minutes%2020181030.pdf


April 22, 2019

II. PURPOSE AND JUSTIFICATION FOR PROPOSED TARIFF

REVISIONS

SPP’s proposed revisions to Section 4.1.2.4 of Attachment AE of the Tariff to

remove the phrase “even if the Market Participant has indicated that the Resource is

not dispatchable” will allow DVERs to use a Control Status, as other Resources do, to

indicate that a DVER is currently unable to follow Dispatch Instructions.

Control Status is a value telemetered to SPP via the Inter-Control Center

Communications Protocol (ICCP). Control Status is used by SPP and its systems to

determine, in real time, the ability of a Resource to respond to specific dispatch

instructions issued by the RTO. The Market Participant can indicate that a Resource is:

(A) “Off-line (Control Status 0) – This Control Status indicates that the Resource

is off-line and not available to the [Real-Time Balancing Market (“RTBM”)].

This status is reserved for Resources which are generating 0 MWs. This

includes Resources which are disconnected from the grid for an approved

outage and Resources lacking a current commitment or start instruction.

(B) Non-Regulating (Control Status 1) – This Control Status indicates that the

Resource is on-line and capable of following a Dispatch Instruction and/or

Contingency Reserve Deployment Instruction. Resources in Control Status of

Non-Regulating will not be eligible to clear Regulation-Up Service and/or

Regulation-Down Service.

(C) Regulating (Control Status 2) – This Control Status indicates that the

Resource is on-line and capable of following a Dispatch Instruction,

Contingency Reserve Deployment Instruction, and/or Regulation Deployment.

(D) Manual (Control Status 3) – This Control Status indicates that the Resource

is on-line but not capable of following a Dispatch Instruction. This status is

reserved for generating Resources operating under the following conditions:

(1) Start-up

(2) Shut-down

(3) Testing

(4) Experiencing, or recovering from, a unit trip

(5) Generating at an output to which the Resource is not capable of

responding to a Dispatch Instruction

(6) Condensing

stakeholder processes has been upheld by the courts. See Pub. Serv. Comm’n of

Wis. v. FERC, 545 F.3d 1058, 1062-63 (D.C. Cir. 2008) (noting the

Commission often gives weight to RTO proposals that reflect the position of

the majority of the RTO’s stakeholders) (quoting Am. Elec. Power Serv. Corp.

v. Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,083, at P

172 (2008)).


April 22, 2019

(7) Experiencing environmental, control or mechanical issues

(8) Qualifying Facility exercising its rights under PURPA to deliver its net

output to its host utility.”11

Currently, for the RTBM, DVER Dispatch Instructions are calculated assuming

the DVER is dispatchable regardless of its ability to control output as communicated

in its submitted Control Status. This creates a condition where a DVER is unable to

follow a Dispatch Instruction for a legitimate reason and has tried to communicate the

condition through the use of Control Status 3, yet could still receive a Dispatch

Instruction with an expectation to perform.

Ignoring a Control Status indicating that a DVER is currently unable to follow

a Dispatch Instruction can lead to discrepancies between the RTBM software and actual

system conditions. The differences could include (1) RTBM expects the DVER to

follow the Dispatch Instruction despite its inability to do so leading to increased

Regulation Deployment; and (2) congestion management inefficiencies due to

RTBM’s expectation that a DVER could relieve loading on a flowgate through dispatch

of that DVER when that DVER cannot actually respond resulting in unresolved

flowgate congestion.

Additionally, under the current Tariff language, when a DVER receives a

Dispatch Instruction to change its output despite its inability to follow that instruction,

the DVER is exposed to Uninstructed Resource Deviation (“URD”) under Section 6.4.1

of Attachment AE of the Tariff. Allowing DVERs to utilize Control Statuses to

indicate a current inability to follow Dispatch Instructions will indicate to the market

to set the Dispatch Instruction equal to the current output of the DVER thus removing

the exposure to URD.

DVERs can use Control Status 2 under the current Tariff language to indicate

to SPP that the DVER is capable of regulating. Any other Control Status is ignored

and the DVER is assumed dispatchable. The issues raised above exist specifically

because DVERs cannot currently use Control Status 3. In the initial design and filings

for the Integrated Marketplace, based on feedback from stakeholders and other RTOs,

SPP chose to ignore Control Modes other than 2 for DVERs. At that time, SPP and the

stakeholders believed that the usage of control mode 3 could be used to circumvent

being dispatched down by SPP. Additionally, it was assumed that, technically, a wind

powered DVER was dispatchable downwards at all times.

11 SPP Integrated Marketplace Market Protocols (“Market Protocols”) at Section

4.4.2.2.3. The Market Protocols are posted on SPP’s website at:

https://www.spp.org/spp-documents-filings/?id=18162.

https://www.spp.org/spp-documents-filings/?id=18162


April 22, 2019

Five years of experience in the Integrated Marketplace have shown that those

original assumptions were not entirely correct. Real-Time operational experience has

shown that instances exist where a DVER is not dispatchable in the downwards

direction. In these instances, SPP is forced to manually direct and communicate with

the DVER due to systems, under the current Tariff language, ignoring Control Status 3

from DVERs. This creates a burden on SPP’s Real-Time operators, requiring valuable

time to be spent on this issue that could be spent in other areas. As SPP’s experience in

the Integrated Marketplace has grown, both the membership and SPP are more

comfortable in the ability to monitor for situations where the appropriateness of Control

Status 3 needs to be evaluated.

Additionally, the language proposed allows the use of the Control Status 3

under the same rules as other Resources. Specifically, the use of Control Status 3 is

restricted to circumstances where the Resource is truly beyond the ability to respond.

As with other Resources, use of Control Status 3 is subject to review by the SPP Market

Monitoring Unit under the Market Monitoring Plan for improper utilization.

Accordingly, SPP respectfully requests that the Commission accept the Tariff

revisions proposed herein as just and reasonable.

These changes are contingent upon and cannot be implemented until the SMS

goes live. The changes will take several months to implement once the SMS has gone

live and SPP has received an order on these changes from the Commission. At this

point, SPP expects that the software changes will be completed between two and four

months after the SMS goes live. Shortly after the SMS goes live, SPP will have a much

clearer picture of when the software will be completed.

SPP is requesting that the Commission issue an order in this docket as soon as

practicable, but not later than July 1, 2019. SPP is also requesting an open effective

date. In light of the facts that the exact date of Commission action on this filing is

unclear at this time and that SPP will need a number of months to build, test, and

implement the necessary software on top of the SMS, SPP is requesting an effective

date of “12/31/9998”12 for the Tariff Records submitted in this filing. SPP commits to

submit a filing with the Commission specifying a precise effective date at a later time.

Upon Commission acceptance of SPP’s filing and the completion of the SMS, SPP will

work as quickly as practicable to technologically implement the proposed changes with

a target completion date in the second quarter of 2020.

12 Supra n. 2.


April 22, 2019

III. DESCRIPTION OF TARIFF REVISIONS

A. Section 4.1.2.4 of Attachment AE (Dispatchable Variable Energy

Resource)

The revisions to current Tariff language in Section 4.1.2.4 of Attachment AE

remove the phrase “even if the Market Participant has indicated that the Resource is

not dispatchable[.]”

The purpose of the revision is to allow DVERs to utilize Control Statuses to

indicate the Resource is not currently capable of following a Dispatch Instruction. As

stated above this will enable RTBM to have more accurate information for reliably and

economically dispatching Resources to meet obligation and manage congestion.

IV. EFFECTIVE DATE AND REQUEST FOR WAIVER

SPP is requesting an effective date of “12/31/9998” for the Tariff Records

included with this filing. The expected effective date of the Tariff revisions included

herein is within the second quarter of 2020, which is more than 120 days after filing.

Therefore, SPP requests waiver of the Commission’s notice requirements.13 Good

cause exists for the proposed revisions to be effective in the second quarter of 2020 in

accordance with the Commission’s waiver of notice requirement codified in Section

35.11 of the Commission’s regulations14 because SPP will need a number of months to

build, test, and implement the necessary software on top of SPP’s new SMS currently

scheduled to be implemented in the first quarter of 2020. SPP requests the Commission

issue an order by July 1, 2019 to allow SPP sufficient time to make the necessary

software changes.

13 18 C.F.R. § 35.3(a)(1).

14 18 C.F.R. § 35.11.


April 22, 2019

V. ADDITIONAL INFORMATION

A. Information Provided Per Commission Regulations15

1. Documents submitted with this filing:

In addition to this Transmittal Letter, Clean and Redlined Tariff

revisions under the Sixth Revised Volume No. 1.

2. Service:

SPP has electronically served a copy of this filing on all its

Members, Transmission Customers and Market Participants. A

complete copy of this filing will be posted on the SPP web site,

www.spp.org, and is also being served on all affected state

commissions.

3. Requisite agreements:

Not applicable.

B. Communications

Correspondence and communications with respect to this filing should be sent

to, and SPP requests the Secretary to include on the official service list, the

following:

Nicole Wagner

Manager, Regulatory Policy

Southwest Power Pool, Inc.

201 Worthen Drive

Little Rock, AR 72223

Telephone: (501) 688-1642

Fax: (501) 482-2022

[email protected]

Christopher M. Nolen

Senior Attorney


201 Worthen Drive

Little Rock, AR 72223

Telephone: (501) 482-2394

Fax: (501) 482-2022

[email protected]

15 Because the revisions to the Tariff submitted herein do not involve any changes

in rates, the use of the abbreviated filing procedures as set forth in 18 C.F.R. §

35.13(a)(2)(iii) is appropriate.

mailto:[email protected]



April 22, 2019

VI. CONCLUSION

For all of the foregoing reasons, SPP respectfully requests that the Commission

issue an order accepting the Tariff revisions proposed herein as soon as practicable.

SPP will submit a filing with the Commission specifying a precise effective date not

later than 30 days prior to implementation.

Respectfully submitted,

/s/ Christopher M. Nolen

Christopher M. Nolen

Senior Attorney


201 Worthen Drive

Little Rock, AR 72223-4936

501.482.2394

[email protected]

Attorney for



4.1.2 Additional Provisions for Non-Traditional Resources

4.1.2.1 Demand Response Resources

(1) Dispatchable Demand Response Resource - A Dispatchable Demand Response

Resource is modeled in the Commercial Model the same as any other Resource,

except that the Settlement Location associated with the Dispatchable Demand

Response Resource must contain the Price Node, or aggregated Price Node as

described in Section 2.2(2) of this Attachment AE, associated with the Demand

Response Load. The Market Participant must submit the Real-Time value of the

Demand Response Load to the Transmission Provider via telemetering that meets

the technical requirements specified in the Market Protocols. A Dispatchable

Demand Response Resource shall submit Energy Offer Curves based on the

criteria in Section 3.2(F) of Attachment AF of this Tariff. For purposes of these

Resources, the short-run marginal cost may equal opportunity cost. A

Dispatchable Demand Response Resource may select one of two options for

reporting of the actual Dispatchable Demand Response Resource output:

(a) Submitted Resource production option:

The Dispatchable Demand Response Resource output is sent directly to

the Transmission Provider by the Market Participant via telemetering for

Real-Time operational purposes and the Meter Agent submits either five

(5) minute or hourly actual output values to the Transmission Provider for

use in settlements. The submitted Resource production option is only

allowed for Demand Response Resources that are: (1) utilizing strictly

Behind-The-Meter Generation to provide the response and are utilizing

Real-Time metering capable of reporting both the Behind-The-Meter

Generation output and the load; (2) Demand Response Resources where

the Market Participant is offering the Resource under a retail tariff

provision that includes near Real-Time measurement and verification

terms that are compliant with the Business Practices for Measurement and

Verification of Wholesale Electricity Demand Response of the North

American Energy Standards Board, incorporated by reference in the

Commission’s Regulations, 18 C.F.R. § 38.2(a)(12); or (3) Demand

Response Load utilizing near Real-Time measurement and verification

capability that is compliant with the Business Practices for Measurement

and Verification of Wholesale Electricity Demand Response of the North


Commission’s Regulations, 18 C.F.R. § 38.2(a)(12).

(b) Calculated Resource production option:

(i) For each Dispatch Interval in each hour in which the Demand

Response Resource has been committed, the Demand Response

Resource output for Real-Time operational purposes is calculated

by the Transmission Provider as the greater of zero (0) or the

difference between:

The lesser of the Real-Time consumption of the Demand

Response Load associated with the Demand Response

Resource in the Dispatch Interval immediately preceding

initial commitment of the Demand Response Resource or

the hourly baseline as described in (3) below for the hour,

and

The actual value of the associated Demand Response Load

received via telemetering.

(ii) For each Dispatch Interval in each hour in which the Demand


Resource output for settlement purposes is calculated by the

Transmission Provider as the maximum of zero (0) or the

difference between:






and


received from the Meter Agent either on a five (5) minute

basis or an hourly basis.

(2) Block Demand Response Resource – A Block Demand Response Resource is

modeled in the Commercial Model the same as any other Resource except that the

Settlement Location associated with the Block Demand Response Resource must

contain the Price Node, or aggregated Price Node as described in Section 2.2(2)

of this Attachment AE, associated with the Demand Response Load. The Market

Participant must submit the Real-Time value of the Demand Response Load to the

Transmission Provider via telemetering that meets the technical requirements

specified in the Market Protocols. All Block Demand Response Resources will

use the calculated Resource production option, described in Section 4.1.2.1(1)(b)

above, to determine the amount of Real-Time Resource production and actual

Resource production.

(a) If the Block Demand Response Resource is committed and dispatched in

the Day-Ahead Market, Day-Ahead RUC or Intra-Day RUC, the Block

Demand Response Resource’s Minimum Economic Capacity Operating

Limit will be increased in the RTBM to match the dispatched amount.

Spinning Reserve or Supplemental Reserve will be allowed to clear above

minimum output if the Block Demand Response Resource is a Spin

Qualified Resource and Supplemental Reserve will be allowed to clear

above minimum output if the Block Demand Response Resource is a

Supplemental Qualified Resource.

(b) Spinning Reserve and/or Supplemental Reserve clearing will be based

upon submitted ramp rates for the Block Demand Response Resource, the

submitted Spinning Reserve Offer, the Supplemental Reserve Offer and

the Block Demand Response Resource’s Maximum Economic Capacity

Operating Limit.

(3) Hourly Baseline

(a) The Market Participant must submit an hourly baseline for the Demand

Response Load indicating the level of energy consumption expected at

that location in MWh if the Demand Response Resource is not dispatched.

The baseline must cover, at a minimum, all hours the Resource is

submitting Offers for in the Energy and Operating Reserve Markets. This

baseline must be submitted by 1100 hours on the day prior to the

Operating Day and may be updated up to thirty (30) minutes in advance of

the operating hour. The baseline should be based on the average of the

hourly integrated Demand Response Load for the same hours in the last 30

calendar days when the Resource was not dispatched, adjusted by the

Market Participant as necessary to account for changes in the expected

level of energy consumption by the Demand Response Load.

(b) If there have been deviations in hourly integrated metered load from the

hourly baseline during periods when the Resource was not dispatched the

hourly baseline will be adjusted as follows by the Transmission Provider

prior to the calculation of the Demand Response Load. If the average of

the hourly deviation between integrated metered load and submitted

hourly baseline for the hours in the last thirty (30) calendar days when the

Resource was not dispatched is more than five percent (5%) below the

hourly baseline, the hourly baseline will be adjusted by the average

deviation. The Transmission Provider will perform this assessment each

day and notify the Market Participant of any adjustment.

(c) If the hourly baseline has not been submitted, the Transmission Provider

shall set the hourly baseline equal to the Real-Time consumption of the

Demand Response Load associated with the Demand Response Resource

in the Dispatch Interval immediately preceding initial commitment of the

Demand Response Resource.

4.1.2.2 Combined Cycle Resource

Market Participants shall select from one of the four following options

regarding submitting Resource Offers for their registered combined cycle

Resources, which will be declared during asset registration as described under

Sections 2.2 and 2.9 of this Attachment AE:

(1) A Resource Offer may be submitted for a single aggregate combined cycle

Resource, where the aggregate will represent a Market Participant selected

operating configuration of combustion turbines and steam turbines. Under

this option, the combined cycle Resource will be committed, dispatched

and settled the same as any other Resource; or

(2) A Resource Offer may be submitted for each combined cycle Resource

combustion turbine and/or steam turbine and each component will be

committed and dispatched independently and settled the same as any other

single Resource; or

(3) A Resource Offer may be submitted for each pseudo combined cycle

Resource, where each pseudo combined cycle Resource will represent the

combination of one combustion turbine and a portion of the steam turbine.

Under this option, each pseudo combined cycle Resource must be capable

of being committed and dispatched independently the same as any other

Resource and each pseudo combined cycle Resource will be settled the

same as any other Resource; or

(4) A Resource Offer may be submitted for each registered combined cycle

configuration, where each configuration represents an operating state of

the combined cycle Resource with a distinct set of physical operating

characteristics, as dictated by the physical attributes of the combined cycle

Resource. The Transmission Provider will determine the most economic

commitment configuration, if requested to do so by the Market Participant

as part of the submitted Resource Offer, and once committed, the most

economic configuration to transition to for use in both the Day-Ahead

Market and Real-Time Balancing Market. Settlement for a combined

cycle Resource submitting offers in this manner will occur in the same

manner as any other Resource except for Contingency Reserve during

transitions as described under Section 8.5.9 of this Attachment AE and

adjustments for Operating Reserves during transitions as described under

Section 8.6.5 of this Attachment AE. Under this option, Market

Participants must define during asset registration the:

(a) Valid configurations, one of which must represent the

maximum capacity of the combined cycle Resource;

(b) Valid transitions between configurations as defined in the

Market Protocols; and

(c) One or more sets of physical units that can participate in a

configuration.

4.1.2.3 Jointly Owned Unit

Under the individual Jointly Owned Unit Resource option, each Market

Participant may submit Resource Offers for its share of the Jointly Owned Unit as

specified in the Market Protocols. Offer parameters must meet the following

criteria in order to be accepted as valid Offers, otherwise the last submitted valid

offer shall apply:

(1) The sum of the Maximum Emergency Capacity Operating Limits of all

shares of the Jointly Owned Unit must be less than or equal to the Jointly

Owned Unit maximum physical capacity operating limit.

Commitment of individual Jointly Owned Unit shares that have registered under

the individual Resource option will be evaluated by security constrained unit

commitment (“SCUC”) based on the individually submitted Offers for each

Jointly Owned Unit share.

4.1.2.4 Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Dispatchable

Variable Energy Resources using the same Offer parameters available to any

other Resource, except that:

(1) The minimum operating limits specified in the Resource Offer must be

equal to zero;

(2) The maximum operating limits for use in the Day-Ahead RUC and the

Intra-Day RUC shall be calculated by the Transmission Provider as equal

to the lesser of the maximum operating limits submitted in the Resource

Offer or the Transmission Provider’s output forecast for that Resource to

the extent that such output forecast is available;

a) Dispatchable Variable Energy Resources for which the

Transmission Provider is calculating an output forecast are not

eligible to receive RUC make whole payments as described under

Section 8.6.5 of this Attachment AE.

(3) For the purposes of issuing Dispatch Instructions to Resources as

described under Section 4.1.2.4(6) of this Attachment AE, Dispatchable

Variable Energy Resources with a maximum capability of less than two-

hundred (200) MWs, submitted ramp rates multiplied by five (5) cannot

exceed forty (40) MWs;



Variable Energy Resources with a maximum capability of greater than or

equal to two-hundred (200) MWs, submitted ramp rates multiplied by five

(5) cannot exceed twenty percent (20%) of the maximum capability;

(5) For the RTBM, during times when the Transmission Provider issues a

Dispatch Instruction to a Dispatchable Variable Energy Resource to

reduce output, the Resource’s Setpoint Instruction shall be equal to the

sum of the Resource’s Dispatch Instruction and any Regulation-Down

deployment;



increase output in Dispatch Intervals immediately following a Dispatch

Interval in which a Dispatch Instruction was issued to reduce output as

described in Section 4.1.2.4(5) of this Attachment AE, the Transmission

Provider shall calculate the Resource maximum operating limit to be equal

to:

(a) The lesser of the maximum operating limits submitted in the

Resource Offer or the Transmission Provider’s Dispatchable

Variable Energy Resource output forecast for that Resource to the

extent the such forecast is available, except that, the Transmission

Provider’s output forecast for the Resource shall be used for the

maximum operating limits when: (i) maximum operating limits

have not been submitted; (ii) the maximum operating limits

submitted in the Resource Offer were not updated during the

Operating Hour prior to the Operating Hour in which the Resource

limit would apply but before the lead time described in Section 4.1

of this Attachment AE; or (iii) the maximum operating limits

submitted in the Resource Offer exceed the maximum physical

rating of the Resource as stated during market registration; or

(b) The maximum operating limits submitted in the Resource Offer if

the Transmission Provider’s Dispatchable Variable Energy

Resource output forecast for that Resource is not available.

The Transmission Provider shall continue to calculate such maximum

operating limits for each subsequent Dispatch Interval until the maximum

operating limit is equal to the lesser of the Transmission Provider’s

Dispatchable Variable Energy Resource output forecast for that Resource

or the maximum operating limit submitted in the Resource Offer, after

which, the Dispatchable Variable Energy Resource’s maximum operating

limit shall be calculated as described in Section 4.1.2.4(7) of this

Attachment AE.

(7) For the RTBM, during times other than those times described under

Section 4.1.2.4(6) of this Attachment AE, the Resource’s maximum

operating limit for use in the current Dispatch Interval shall be equal to the

Resource’s actual output at the start of the Dispatch Interval and the

ramping restrictions described under Sections 4.1.2.4(3) and (4) of this

Attachment AE shall not apply.

(8) Dispatchable Variable Energy Resources may also receive an OOME

according to the rules in Section 6.2.4 of this Attachment AE.

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-

Dispatchable Variable Energy Resources using the same Offer parameters

available to any other Resource, except that


equal to zero;

(2) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

(3) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the


Resources must operate as non-dispatchable;

(4) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for

the purposes of calculating production costs relating to RUC make whole

payments and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this

Attachment AE;

(5) An OOME may be issued to a Non-Dispatchable Variable Energy

Resource. In addition, the Transmission Provider will issue the dispatch

instruction to the Resource in accordance with Section 6.2.4 of this

Attachment AE; and





the extent that such output forecast is available, otherwise the maximum

operating limits shall be equal to those submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the




4.1.2.6 External Dynamic Resource

Each Market Participant may submit Resource Offers for External

Dynamic Resources (“EDR”) using the same Offer parameters available to any


(1) A Market Participant may only submit a commitment status as defined in

Section 4.1(10)(a) or (d) of this Attachment AE;

(2) For an EDR in the Eastern Interconnection, a Market Participant must

submit a dispatch status indicating that the EDR is not available for energy

dispatch as described under Section 4.1(11)(a) of this Attachment AE;

(3) For an EDR in the Eastern Interconnection, Resource Offer parameters are

limited to: Regulation-Up and Regulation-Down Offers, Spinning and

Supplemental Reserve Offers, Regulation Ramp Rate, Contingency

Reserve Ramp Rate and Resource Status. All other Resource Offer

parameters as listed in Section 4.1(9) of this Attachment AE shall not

apply to EDRs in the Eastern Interconnection.

(4) For an EDR that is not in the Eastern Interconnection, Resource Offer

parameters are limited to: Energy Offer Curve, Ramp-Rate-Up, Ramp-

Rate-Down, Regulation-Up and Regulation-Down Offers, Spinning and




apply to EDRs that are not in the Eastern Interconnection.

4.1.2 Additional Provisions for Non-Traditional Resources

4.1.2.1 Demand Response Resources

(1) Dispatchable Demand Response Resource - A Dispatchable Demand Response

Resource is modeled in the Commercial Model the same as any other Resource,

except that the Settlement Location associated with the Dispatchable Demand

Response Resource must contain the Price Node, or aggregated Price Node as

described in Section 2.2(2) of this Attachment AE, associated with the Demand

Response Load. The Market Participant must submit the Real-Time value of the

Demand Response Load to the Transmission Provider via telemetering that meets

the technical requirements specified in the Market Protocols. A Dispatchable

Demand Response Resource shall submit Energy Offer Curves based on the

criteria in Section 3.2(F) of Attachment AF of this Tariff. For purposes of these

Resources, the short-run marginal cost may equal opportunity cost. A

Dispatchable Demand Response Resource may select one of two options for

reporting of the actual Dispatchable Demand Response Resource output:

(a) Submitted Resource production option:

The Dispatchable Demand Response Resource output is sent directly to

the Transmission Provider by the Market Participant via telemetering for

Real-Time operational purposes and the Meter Agent submits either five

(5) minute or hourly actual output values to the Transmission Provider for

use in settlements. The submitted Resource production option is only

allowed for Demand Response Resources that are: (1) utilizing strictly

Behind-The-Meter Generation to provide the response and are utilizing

Real-Time metering capable of reporting both the Behind-The-Meter

Generation output and the load; (2) Demand Response Resources where

the Market Participant is offering the Resource under a retail tariff

provision that includes near Real-Time measurement and verification

terms that are compliant with the Business Practices for Measurement and

Verification of Wholesale Electricity Demand Response of the North


Commission’s Regulations, 18 C.F.R. § 38.2(a)(12); or (3) Demand

Response Load utilizing near Real-Time measurement and verification

capability that is compliant with the Business Practices for Measurement

and Verification of Wholesale Electricity Demand Response of the North


Commission’s Regulations, 18 C.F.R. § 38.2(a)(12).

(b) Calculated Resource production option:

(i) For each Dispatch Interval in each hour in which the Demand


Resource output for Real-Time operational purposes is calculated

by the Transmission Provider as the greater of zero (0) or the

difference between:






and


received via telemetering.

(ii) For each Dispatch Interval in each hour in which the Demand


Resource output for settlement purposes is calculated by the

Transmission Provider as the maximum of zero (0) or the

difference between:






and


received from the Meter Agent either on a five (5) minute

basis or an hourly basis.

(2) Block Demand Response Resource – A Block Demand Response Resource is

modeled in the Commercial Model the same as any other Resource except that the

Settlement Location associated with the Block Demand Response Resource must

contain the Price Node, or aggregated Price Node as described in Section 2.2(2)

of this Attachment AE, associated with the Demand Response Load. The Market

Participant must submit the Real-Time value of the Demand Response Load to the

Transmission Provider via telemetering that meets the technical requirements

specified in the Market Protocols. All Block Demand Response Resources will

use the calculated Resource production option, described in Section 4.1.2.1(1)(b)

above, to determine the amount of Real-Time Resource production and actual

Resource production.

(a) If the Block Demand Response Resource is committed and dispatched in

the Day-Ahead Market, Day-Ahead RUC or Intra-Day RUC, the Block

Demand Response Resource’s Minimum Economic Capacity Operating

Limit will be increased in the RTBM to match the dispatched amount.

Spinning Reserve or Supplemental Reserve will be allowed to clear above

minimum output if the Block Demand Response Resource is a Spin

Qualified Resource and Supplemental Reserve will be allowed to clear

above minimum output if the Block Demand Response Resource is a

Supplemental Qualified Resource.

(b) Spinning Reserve and/or Supplemental Reserve clearing will be based

upon submitted ramp rates for the Block Demand Response Resource, the

submitted Spinning Reserve Offer, the Supplemental Reserve Offer and

the Block Demand Response Resource’s Maximum Economic Capacity

Operating Limit.

(3) Hourly Baseline

(a) The Market Participant must submit an hourly baseline for the Demand

Response Load indicating the level of energy consumption expected at

that location in MWh if the Demand Response Resource is not dispatched.

The baseline must cover, at a minimum, all hours the Resource is

submitting Offers for in the Energy and Operating Reserve Markets. This

baseline must be submitted by 1100 hours on the day prior to the

Operating Day and may be updated up to thirty (30) minutes in advance of

the operating hour. The baseline should be based on the average of the

hourly integrated Demand Response Load for the same hours in the last 30

calendar days when the Resource was not dispatched, adjusted by the

Market Participant as necessary to account for changes in the expected

level of energy consumption by the Demand Response Load.

(b) If there have been deviations in hourly integrated metered load from the

hourly baseline during periods when the Resource was not dispatched the

hourly baseline will be adjusted as follows by the Transmission Provider

prior to the calculation of the Demand Response Load. If the average of

the hourly deviation between integrated metered load and submitted

hourly baseline for the hours in the last thirty (30) calendar days when the

Resource was not dispatched is more than five percent (5%) below the

hourly baseline, the hourly baseline will be adjusted by the average

deviation. The Transmission Provider will perform this assessment each

day and notify the Market Participant of any adjustment.

(c) If the hourly baseline has not been submitted, the Transmission Provider

shall set the hourly baseline equal to the Real-Time consumption of the

Demand Response Load associated with the Demand Response Resource

in the Dispatch Interval immediately preceding initial commitment of the

Demand Response Resource.

4.1.2.2 Combined Cycle Resource

Market Participants shall select from one of the four following options

regarding submitting Resource Offers for their registered combined cycle

Resources, which will be declared during asset registration as described under

Sections 2.2 and 2.9 of this Attachment AE:

(1) A Resource Offer may be submitted for a single aggregate combined cycle

Resource, where the aggregate will represent a Market Participant selected

operating configuration of combustion turbines and steam turbines. Under

this option, the combined cycle Resource will be committed, dispatched

and settled the same as any other Resource; or

(2) A Resource Offer may be submitted for each combined cycle Resource

combustion turbine and/or steam turbine and each component will be

committed and dispatched independently and settled the same as any other

single Resource; or

(3) A Resource Offer may be submitted for each pseudo combined cycle

Resource, where each pseudo combined cycle Resource will represent the

combination of one combustion turbine and a portion of the steam turbine.

Under this option, each pseudo combined cycle Resource must be capable

of being committed and dispatched independently the same as any other

Resource and each pseudo combined cycle Resource will be settled the

same as any other Resource; or

(4) A Resource Offer may be submitted for each registered combined cycle

configuration, where each configuration represents an operating state of

the combined cycle Resource with a distinct set of physical operating

characteristics, as dictated by the physical attributes of the combined cycle

Resource. The Transmission Provider will determine the most economic

commitment configuration, if requested to do so by the Market Participant

as part of the submitted Resource Offer, and once committed, the most

economic configuration to transition to for use in both the Day-Ahead

Market and Real-Time Balancing Market. Settlement for a combined

cycle Resource submitting offers in this manner will occur in the same

manner as any other Resource except for Contingency Reserve during

transitions as described under Section 8.5.9 of this Attachment AE and

adjustments for Operating Reserves during transitions as described under

Section 8.6.5 of this Attachment AE. Under this option, Market

Participants must define during asset registration the:

(a) Valid configurations, one of which must represent the

maximum capacity of the combined cycle Resource;

(b) Valid transitions between configurations as defined in the

Market Protocols; and

(c) One or more sets of physical units that can participate in a

configuration.

4.1.2.3 Jointly Owned Unit

Under the individual Jointly Owned Unit Resource option, each Market

Participant may submit Resource Offers for its share of the Jointly Owned Unit as

specified in the Market Protocols. Offer parameters must meet the following

criteria in order to be accepted as valid Offers, otherwise the last submitted valid

offer shall apply:

(1) The sum of the Maximum Emergency Capacity Operating Limits of all

shares of the Jointly Owned Unit must be less than or equal to the Jointly

Owned Unit maximum physical capacity operating limit.

Commitment of individual Jointly Owned Unit shares that have registered under

the individual Resource option will be evaluated by security constrained unit

commitment (“SCUC”) based on the individually submitted Offers for each

Jointly Owned Unit share.

4.1.2.4 Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Dispatchable

Variable Energy Resources using the same Offer parameters available to any



equal to zero;





the extent that such output forecast is available;

a) Dispatchable Variable Energy Resources for which the






Variable Energy Resources with a maximum capability of less than two-

hundred (200) MWs, submitted ramp rates multiplied by five (5) cannot

exceed forty (40) MWs;



Variable Energy Resources with a maximum capability of greater than or

equal to two-hundred (200) MWs, submitted ramp rates multiplied by five

(5) cannot exceed twenty percent (20%) of the maximum capability;



reduce output, the Resource’s Setpoint Instruction shall be equal to the

sum of the Resource’s Dispatch Instruction and any Regulation-Down

deployment, even if the Market Participant has indicated that the Resource

is not dispatchable;



increase output in Dispatch Intervals immediately following a Dispatch

Interval in which a Dispatch Instruction was issued to reduce output as

described in Section 4.1.2.4(5) of this Attachment AE, the Transmission

Provider shall calculate the Resource maximum operating limit to be equal

to:

(a) The lesser of the maximum operating limits submitted in the

Resource Offer or the Transmission Provider’s Dispatchable

Variable Energy Resource output forecast for that Resource to the

extent the such forecast is available, except that, the Transmission

Provider’s output forecast for the Resource shall be used for the

maximum operating limits when: (i) maximum operating limits

have not been submitted; (ii) the maximum operating limits

submitted in the Resource Offer were not updated during the

Operating Hour prior to the Operating Hour in which the Resource

limit would apply but before the lead time described in Section 4.1

of this Attachment AE; or (iii) the maximum operating limits

submitted in the Resource Offer exceed the maximum physical

rating of the Resource as stated during market registration; or

(b) The maximum operating limits submitted in the Resource Offer if

the Transmission Provider’s Dispatchable Variable Energy

Resource output forecast for that Resource is not available.

The Transmission Provider shall continue to calculate such maximum

operating limits for each subsequent Dispatch Interval until the maximum

operating limit is equal to the lesser of the Transmission Provider’s

Dispatchable Variable Energy Resource output forecast for that Resource

or the maximum operating limit submitted in the Resource Offer, after

which, the Dispatchable Variable Energy Resource’s maximum operating

limit shall be calculated as described in Section 4.1.2.4(7) of this

Attachment AE.

(7) For the RTBM, during times other than those times described under

Section 4.1.2.4(6) of this Attachment AE, the Resource’s maximum

operating limit for use in the current Dispatch Interval shall be equal to the


ramping restrictions described under Sections 4.1.2.4(3) and (4) of this

Attachment AE shall not apply.

(8) Dispatchable Variable Energy Resources may also receive an OOME

according to the rules in Section 6.2.4 of this Attachment AE.

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-

Dispatchable Variable Energy Resources using the same Offer parameters

available to any other Resource, except that


equal to zero;

(2) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

(3) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the


Resources must operate as non-dispatchable;

(4) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for

the purposes of calculating production costs relating to RUC make whole

payments and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this

Attachment AE;

(5) An OOME may be issued to a Non-Dispatchable Variable Energy

Resource. In addition, the Transmission Provider will issue the dispatch

instruction to the Resource in accordance with Section 6.2.4 of this

Attachment AE; and





the extent that such output forecast is available, otherwise the maximum

operating limits shall be equal to those submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the




4.1.2.6 External Dynamic Resource

Each Market Participant may submit Resource Offers for External

Dynamic Resources (“EDR”) using the same Offer parameters available to any


(1) A Market Participant may only submit a commitment status as defined in

Section 4.1(10)(a) or (d) of this Attachment AE;

(2) For an EDR in the Eastern Interconnection, a Market Participant must

submit a dispatch status indicating that the EDR is not available for energy

dispatch as described under Section 4.1(11)(a) of this Attachment AE;

(3) For an EDR in the Eastern Interconnection, Resource Offer parameters are

limited to: Regulation-Up and Regulation-Down Offers, Spinning and




apply to EDRs in the Eastern Interconnection.

(4) For an EDR that is not in the Eastern Interconnection, Resource Offer

parameters are limited to: Energy Offer Curve, Ramp-Rate-Up, Ramp-

Rate-Down, Regulation-Up and Regulation-Down Offers, Spinning and




apply to EDRs that are not in the Eastern Interconnection.