Southwest Power Pool, Inc. no 755...directing SPP to file its Order No. 755 compliance filing by June 30, 2013 and deferring the implementation until “no later than one year following

June 21, 2013

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. ER13-____-000 Order No. 755 Compliance Filing

Dear Secretary Bose:

Pursuant to Federal Energy Regulatory Commission (“Commission”) Order

No. 7551 and the Commission’s October 18, 2012 and March 21, 2013 orders in Docket No. ER12-1179,2 Southwest Power Pool, Inc. (“SPP”) submits revisions to its Open Access Transmission Tariff3 to adopt a two-part compensation methodology for Resources that provide Regulation-Up and Regulation-Down Operating Reserve products in the SPP Integrated Marketplace, and to adopt other Tariff language required by Order No. 755. SPP requests an effective date of March 1, 2015 for the Tariff revisions proposed in this filing, consistent with the Commission’s directive in the March 2013

1 Frequency Regulation Compensation in the Organized Wholesale Power Markets,

Order No. 755, III FERC Stats. & Regs., Regs. Preambles ¶ 31,324 (2011), reh’g denied, Order No. 755-A, 138 FERC ¶ 61,123 (2012).

2 Sw. Power Pool, Inc., 141 FERC ¶ 61,048 (2012) (“October 2012 Order”), order on reh’g, 142 FERC ¶ 61,205 (2013) (“March 2013 Order”).

3 Southwest Power Pool, Inc., FERC Electric Tariff, Sixth Revised Volume No. 1 (“Tariff”). For the sake of clarity, in this filing, SPP refers to Tariff provisions applicable to the Integrated Marketplace effective March 1, 2014 that have been accepted by the Commission or are pending before the Commission as the “Integrated Marketplace Tariff.” Tariff provisions proposed in this filing are referred to as “Proposed Tariff.”

The Honorable Kimberly D. Bose June 21, 2013 Page 2 Order that SPP implement its Order No. 755 compliance “no later than one year following [Integrated Marketplace] start-up.”4 I. BACKGROUND A. SPP

SPP is a Commission-approved Regional Transmission Organization (“RTO”). It is an Arkansas non-profit corporation with its principal place of business in Little Rock, Arkansas. SPP currently has 72 members serving more than 6 million households in a 370,000 square-mile area. Its members include 14 investor-owned utilities, 11 municipal systems, 13 generation and transmission cooperatives, 4 state agencies, 11 independent power producers, 10 power marketers, and 9 independent transmission companies. As an RTO, SPP administers open access transmission service over approximately 48,930 miles of transmission lines covering portions of Arkansas, Kansas, Louisiana, Missouri, Nebraska, New Mexico, Oklahoma, and Texas, across the facilities of the SPP Transmission Owners,5 and administers a centralized real-time energy imbalance service market (“EIS Market”).6

B. Integrated Marketplace Filings and Orders On February 29, 2012,7 as amended on May 15, 2012,8 SPP submitted to the

Commission proposed revisions to its Tariff to transition from its current real-time EIS Market to the SPP Integrated Marketplace in March 2014. The Integrated Marketplace includes Day-Ahead and Real-Time Energy and Operating Reserve Markets and a Transmission Congestion Rights (“TCR”) Market aimed at maximizing the cost-effective utilization of energy Resources and the regional transmission system, as well as

4 March 2013 Order at P 40.

5 See Sw. Power Pool, Inc., 89 FERC ¶ 61,084 (1999); Sw. Power Pool, Inc., 86 FERC ¶ 61,090 (1999); Sw. Power Pool, Inc., 82 FERC ¶ 61,267, order on reh’g, 85 FERC ¶ 61,031 (1998).

6 Sw. Power Pool, Inc., 118 FERC ¶ 61,055 (2007) (accepting SPP’s Market Readiness Certification and authorizing a February 1, 2007 start date for the EIS Market).

7 Submission of Tariff Revisions to Implement SPP Integrated Marketplace, Docket No. ER12-1179-000 (Feb. 29, 2012) (“Integrated Marketplace Filing”).

8 Amendatory Filing of Tariff Revisions to Implement SPP Integrated Marketplace, Docket No. ER12-1179-001 (dated May 15, 2012) (“May 2012 Supplemental Filing”).

The Honorable Kimberly D. Bose June 21, 2013 Page 3 consolidation of the 16 separate Balancing Authority Areas currently operating within the SPP footprint into a single Balancing Authority Area operated by SPP. Among the Operating Reserve products offered in the Integrated Marketplace are Regulation-Up9 and Regulation-Down.10 The SPP Integrated Marketplace co-optimizes the deployment of Energy and Operating Reserve to achieve lowest-cost Resource utilization in both the Day-Ahead Market and Real-Time Balancing Market (“RTBM”).

Through its co-optimization logic, the Integrated Marketplace will co-optimize

Energy dispatch and Operating Reserve procurement, resulting in the most efficient and lowest cost utilization of Resources to clear in the Day-Ahead Market and dispatch in the RTBM.11 The objective of co-optimization is to ensure that Market Participants are indifferent as to whether their Resource is cleared for Energy or Operating Reserve through a rational clearing of the products, considering operational constraints and the least total cost solution. The co-optimization logic incorporates opportunity costs into the setting of the Market Clearing Prices (“MCP”) for Operating Reserve to keep Market Participants indifferent as to the whether the Resource is cleared for Energy or Operating Reserve.12 SPP’s co-optimization logic is similar to the logic employed by other RTOs.13

9 Regulation-Up is defined as “[a]n Operating Reserve product procured by the

Transmission Provider from qualified Resources that increase their energy output in response to a Regulation Deployment Instruction from the Transmission Provider.” Integrated Marketplace Tariff at Attachment AE § 1.1, Definitions R. Resources providing Regulation-Up must be capable of being deployed through automatic generation control equipment to automatically and continuously adjust Resource output to balance supply and demand in near Real-Time and must be able to deploy the full amount of Regulation-Up cleared within the Regulation Response Time, currently set at five minutes.

10 Regulation-Down is defined as “[a]n Operating Reserve product procured by the Transmission Provider from qualified Resources that reduce their energy output in response to a Regulation Deployment instruction from the Transmission Provider.” Id. at Attachment AE § 1.1, Definitions R. Like Regulation-Up, Resources qualified to provide Regulation-Down must be capable of being deployed automatically and continuously through automatic generation control and must be able to deploy the full amount of Regulation-Down cleared within the Regulation Response Time, currently set at five minutes.

11 Integrated Marketplace Filing, Transmittal Letter at 7-9, 13.

12 Id., Exhibit No. SPP-3 (Prepared Direct Testimony of Richard L. Dillon) at 17.

13 Id. at 18.

The Honorable Kimberly D. Bose June 21, 2013 Page 4

In its October 2012 Order, the Commission conditionally accepted SPP’s Integrated Marketplace,14 subject to certain compliance filings, the first of which SPP submitted on February 15, 2013.15 Relevant to this filing, the October 2012 Order conditionally accepted SPP’s proposed co-optimized procurement, settlement, and cost recovery of Operating Reserve, finding that SPP’s proposed co-optimization procurement of Operating Reserve is just and reasonable and consistent with the method accepted in other RTO markets.16 The Commission noted that, with adoption of the Integrated Marketplace, SPP will be required to comply with Order No. 755, and directed SPP to submit Tariff revisions to comply with Order No. 755 no later than June 30, 2013 to be effective “[a]t the time of market start-up.”17 The Commission also directed SPP to submit various revisions to its Operating Reserve provisions, which SPP submitted as part of its February 2013 Compliance Filing18 that is pending before the Commission.

On November 19, 2012, SPP submitted a request for rehearing and clarification of

the October 2012 Order, in which SPP requested (among other things) that the Commission grant rehearing of the requirement to implement SPP’s Order No. 755 compliance at the time that the Integrated Marketplace commences.19 SPP stated that it anticipated being able to submit its Order No. 755 compliance proposal by the June 30, 2013 deadline set forth in the October 2012 Order, but that the system changes required to implement the Order No. 755 compliance upon market start would hamper SPP’s ability to complete development of other Integrated Marketplace system components, which would threaten the anticipated March 1, 2014 launch of the Integrated Marketplace.20

14 October 2012 Order at P 2.

15 Submission of Tariff Revisions to Implement SPP Integrated Marketplace, Docket No. ER12-1179-003 (Feb. 15, 2013) (“February 2013 Compliance Filing”).

16 October 2012 Order at P 221 (citing Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,172 (2008)).

17 Id. at P 222.

18 See February 2013 Compliance Filing, Transmittal Letter at 22-23, 36-40.

19 Request of Southwest Power Pool, Inc. for Rehearing and/or Clarification of Commission Order, Docket Nos. ER12-1179-000, et al. (Nov. 19, 2012) (“November 2012 Rehearing Request”).

20 Id. at 6-10.


In the March 2013 Order, the Commission granted SPP’s request for rehearing, directing SPP to file its Order No. 755 compliance filing by June 30, 2013 and deferring the implementation until “no later than one year following market start-up.”21

C. Order No. 755 On October 20, 2011, the Commission issued Order No. 755 “to remedy undue

discrimination in the procurement of frequency regulation in the organized wholesale electric markets and ensure that providers of frequency regulation receive just and reasonable and not unduly discriminatory or preferential rates.”22 Finding that current RTO regulation compensation mechanisms fail to acknowledge the inherently greater amount of frequency regulation service provided by faster-ramping resources given that resources are compensated at the same level even when providing different amounts of frequency regulation service,23 the Commission directed RTOs to modify their tariffs to establish mechanisms to ensure just and reasonable compensation to resources providing regulation service.

Specifically, the Commission directed RTOs to develop mechanisms to

compensate frequency regulation resources based on the actual services they provide by adopting a two-part payment methodology: (1) a capacity payment that includes the marginal unit’s opportunity costs; and (2) a payment for performance that reflects the actual quantity of frequency regulation service provided by a resource when the resource is accurately following the RTO’s dispatch signal.24 The Commission required that the payments be determined by a competitive process,25 and found that requiring a performance payment based on competitively determined prices that include appropriate opportunity costs will appropriately compensate resources that are asked to do more work and will ensure just and reasonable rates.26 Order No. 755 gave RTOs the discretion to identify the manner in which to implement the two-part compensation methodology.27

The Commission also required RTOs to account for frequency regulation

resources’ accuracy in following the RTO’s automatic generation control (“AGC”) 21 March 2013 Order at P 40.

22 Order No. 755 at P 1.

23 Id. at PP 2, 64.

24 Id. at PP 3, 77, 197.

25 Id. at PP 198-199.

26 Id. at PP 67, 99.

27 Id. at P 185.

The Honorable Kimberly D. Bose June 21, 2013 Page 6 dispatch signal when determining the performance payment compensation, and directed RTOs to determine the technical specifications for measuring accuracy.28 Also, noting that the changes required by Order No. 755 represent “fundamental changes to the way RTOs and ISOs procure and compensate frequency regulation resources, which may render existing RTO and ISO market power rules insufficient for purposes of addressing market power concerns,”29 the Commission instructed RTOs either to submit tariff provisions for market power mitigation methods appropriate to their redesigned frequency regulation markets or explain how their current mitigation methods are sufficient to address market power concerns in the modified market.30

The Order No. 755 reforms were imposed on RTOs that have “a tariff that

provides for the compensation for frequency regulation service.”31 At the time Order No. 755 became effective, SPP did not have such a mechanism in its Tariff.32 With the implementation of the Integrated Marketplace, SPP will begin procuring and compensating Resources providing Regulation, and therefore will be subject to the requirements of Order No. 755.

On February 16, 2013, the Commission denied rehearing of Order No. 755.33 D. Stakeholder Process SPP developed the Tariff revisions proposed in this filing through its customary

stakeholder process. Specifically, the proposed Tariff revisions were developed and approved by the SPP Market Working Group34 during meetings held on October 23, 2012, March 12, 2013 and April 23, 2013. The SPP Operating Reliability Working 28 Id. at PP 77, 153.

29 Id. at P 136.

30 Id.

31 18 C.F.R. § 35.28(g)(3).

32 See Order No. 755 at P 205 n.263 (“SPP is not included in the respondents because they currently do not have a frequency regulation compensation mechanism in their tariff.”).

33 Frequency Regulation Compensation in the Organized Wholesale Power Markets, Order No. 755-A, 138 FERC ¶ 61,123, at PP 12-15 (2012).

34 The Market Working Group 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.

The Honorable Kimberly D. Bose June 21, 2013 Page 7 Group35 considered and approved the revisions on March 27, 2013, and the SPP Regional Tariff Working Group36 considered and approved the revisions on April 5, 2013. The Markets and Operations Policy Committee (“MOPC”)37 approved the revisions on April 16, 2013. On April 30, 2013, the SPP Members Committee38 and Board of Directors approved the revisions proposed in this filing. SPP recognizes that stakeholder approval does not by itself cause a filing to be just and reasonable; however, SPP requests that the Commission extend appropriate deference to the wishes of its stakeholders regarding the revisions proposed in this filing, consistent with Commission precedent.39

35 Among its other duties, the Operating Reliability Working Group: maintains,

coordinates, and implements Criteria related to ensuring the reliable and secure operation of the bulk electric system operated by the members of SPP, consistent with North American Electric Reliability Corporation and Regional Reliability Standards; provides oversight and direction for the SPP Reliability Coordinator function; and provides policy input to the SPP Board of Directors and its committees.

36 The Regional Tariff Working Group is responsible for development, recommendation, overall implementation, and oversight of SPP’s Tariff. The Regional Tariff Working Group 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.

37 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 Tariff. See Southwest Power Pool, Inc., Bylaws, First Revised Volume No. 4 (“Bylaws”) § 6.1.

38 The Members Committee consists of up to 19 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 id. § 5.1.

39 The Commission previously has recognized that provisions approved through the stakeholder processes of RTOs 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 England 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., Regs. Preambles ¶ 30,976, at 30,872 (1993) (the Commission will afford an appropriate degree of deference to the stakeholder approval process). The Commission’s deference to RTO 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 that the Commission often gives weight to

(continued. . . )


II. COMPLIANCE FILING

As discussed above, Order No. 755 requires RTOs to adopt a two-part payment structure for compensation of resources providing frequency regulation, and to base the performance portion of the payment on a resource’s accuracy in following AGC dispatch signals. As detailed below, SPP proposes to adopt a two-part bidding and pricing mechanism for Regulation-Up Service and Regulation-Down Service, with the performance portion of the compensation based on a regulation “mileage” concept similar to that adopted in other RTOs.40

A. Order No. 755 Compliance Requirements

1. Capacity Payment In Order No. 755, the Commission determined that paying all cleared frequency

regulation resources a uniform capacity clearing price that includes the marginal resource’s opportunity cost is just and reasonable.41 The Commission therefore directed RTOs to pay all cleared frequency regulation resources a uniform clearing price that includes the marginal resource’s opportunity cost.42 The uniform clearing price must be market-based, derived from market participant bids for the provision of frequency regulation capacity.43 The Commission directed RTOs to calculate the marginal resource’s cross-product opportunity costs, which reflect the foregone opportunity to participate in the energy and other ancillary services markets,44 and include these costs in

(. . . continued)

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)).

40 See, e.g., Midwest Indep. Transmission Sys. Operator, Inc., 140 FERC ¶ 61,224, at PP 7-13 (2012) (“MISO Order”) (summarizing the Midwest Independent Transmission System Operator, Inc.’s (“MISO”) mileage-based regulation compensation methodology).

41 Order No. 755 at P 99.

42 Id. at PP 99, 198.

43 Id.

44 The Commission defined “cross-product opportunity cost” as “the revenue a regulation provider loses because it is on stand-by to provide regulation and is not providing energy or another product.” Id. at P 80 n.123.

The Honorable Kimberly D. Bose June 21, 2013 Page 9 each resource’s offer to supply frequency regulation capacity for use when determining the market clearing price and which resources clear.45 The Commission also required RTOs to allow for inter-temporal opportunity costs46 to be included in a resource’s offer to sell frequency regulation service (with the requirement that costs be verifiable), but left it to the RTO to determine who is responsible (the RTO or the market participant) for calculating such costs.47

2. Performance Payment

In addition to a capacity payment, the Commission mandated that each RTO

provide a performance payment to each regulating resource, “reflect[ing] the amount of work each resource performs in real-time” and “the accuracy with which each resource responds to the system operator’s dispatch signal.”48 The Commission required that the performance payment be market-based (i.e., based on resource bids that reflect the cost of providing service),49 and left it to the RTO to propose the details of its methodology including bidding parameters.50 The Commission directed RTOs to propose the specific technical requirements and required that the market clearing performance price be paid uniformly to all resources cleared during the same settlement period.51 A resource’s performance must be measured based on the absolute amount of regulation up and down that it provides in response to the RTO’s dispatch signal.52

3. Accuracy Measurement

In Order No. 755, the Commission found that a resource’s frequency regulation

compensation should account for the resource’s accuracy in following the RTO’s AGC

45 Id. at PP 99, 102, 198.

46 The Commission defined “inter-temporal opportunity costs” as “the foregone value when a resource must operate at one time, and therefore must either forego a profit from selling energy at a later time or incur costs due to consuming at a later time.” Id. at P 80 n.124.

47 Id. at P 103.

48 Id. at P 199.

49 Id. at PP 128-129, 199.

50 Id. at PP 130, 199.

51 Id. at PP 131-132.

52 Id. at P 133.

The Honorable Kimberly D. Bose June 21, 2013 Page 10 dispatch signal,53 to provide resources with an economic incentive to follow dispatch instructions.54 Therefore, the Commission required RTOs to account for a resource’s accuracy in following AGC dispatch signals in determining the performance payment compensation and to propose the technical specifications for measuring accuracy.55 The Commission did not mandate any particular method for measuring accuracy, but required that the same accuracy measurement method must apply to all frequency regulation resources.56

4. Market Power Mitigation In Order No. 755, the Commission noted that, given the additional performance

payment requirements of Order No. 755, it is appropriate for RTOs to revisit their market power monitoring and mitigation provisions to ensure that they remain adequate to protect against market power abuse.57 Accordingly, the Commission directed RTOs “either to submit tariff provisions for market power mitigation methods appropriate to redesigned frequency regulation markets or to explain how their current mitigation methods are sufficient to address market power concerns given the changes required” by Order No. 755.58

B. SPP Compliance Proposal 1. Overview SPP proposes in this filing to comply with Order No. 755 by establishing a two-

part methodology for Regulation-Up and Regulation-Down offers and compensation, with the capacity component of the Offer and price based on SPP’s current, Commission-approved methodology, and a performance component based on a resource’s Regulation-Up and Regulation-Down Mileage. Mileage is measured for each five minute dispatch interval and is equal to the sum of the absolute value of movements by a Resource in response to Regulation Deployment instructions provided through AGC every four seconds.

53 Id. at PP 151, 200.

54 Id. at P 152.

55 Id. at PP 153, 200.

56 Id. at PP 153-154, 200.

57 Id. at P 136.

58 Id.


To offer Regulation products in the Day-Ahead Market or RTBM, a Resource59 will be required to submit a two-part Offer consisting of: (1) a Regulation-Up or Regulation-Down Offer, in dollars per MW, representing the price at which the Resource has agreed to hold capacity in reserve to provide Regulation-Up or Regulation-Down; and (2) a Regulation-Up or Regulation-Down Mileage Offer, in dollars per MW, representing the price at which the Resource has agreed to sell Expected Regulation Reserve Mileage. The Regulation Mileage Offer is multiplied by a Regulation Mileage Factor, which is determined through a historical system-wide Regulation Deployment analysis that represents the ratio of cleared Regulation Service to the Instructed Regulation Mileage. Given the lack of historical data for Regulation Deployment, the Regulation Mileage Factor for both Regulation-Up and Regulation-Down will initially be set to 1.0, and will be updated periodically as specified in the Market Protocols. The Regulation Mileage Offer (as multiplied by the Mileage Factor) is summed with the Regulation Offer to calculate a combined Regulation Service Offer, which is used in the market clearing engine to determine least-cost commitment and dispatch of Regulation Resources in the Day-Ahead Market and RTBM.

The market clearing engine uses the combined Regulation-Up Service Offers and

Regulation-Down Service Offers to meet Regulation-Up and Regulation-Down requirements, respectively, and produces Regulation-Up Service MCPs and Regulation-Down Service MCPs. Deployment of Regulation Reserves remains the same as in SPP’s Integrated Marketplace Filing approved by the Commission. In the Day-Ahead Market, cleared Resources will be compensated for their cleared Regulation-Up Service or Regulation-Down Service at the applicable Day-Ahead MCP. This represents the same compensation that is applicable in SPP’s current Integrated Marketplace design conditionally approved by the Commission.

To determine an appropriate performance payment, SPP will charge or credit a

Resource in the RTBM by comparing its Actual Regulation Mileage to its Expected Regulation Mileage. “Expected Regulation-Up Mileage” and “Expected Regulation-Down Mileage” will be calculated as the amount of Regulation-Up Service MW or Regulation-Down Service MW cleared, multiplied by the Regulation-Up Mileage Factor or Regulation-Down Mileage Factor. SPP also will calculate RTBM Expected Regulation Mileage MCPs (for both Regulation-Up Mileage and Regulation-Down Mileage), which represent the highest of the Regulation Mileage Offers of all Resources economically cleared for each of the Regulation products (Up and Down).

In the RTBM settlement, SPP will determine the appropriate charge or credit to

the Resource as the sum of: (1) deviations between cleared RTBM Regulation and cleared Day-Ahead Market Regulation; (2) Excess Regulation Mileage; and (3) Unused

59 To offer Regulation-Up and/or Regulation-Down, a Resource must satisfy the

requirements in Section 2.10.3 of Attachment AE of the SPP Integrated Marketplace Tariff.

The Honorable Kimberly D. Bose June 21, 2013 Page 12 Regulation Mileage. Excess Regulation Mileage occurs if the lesser of the Actual Mileage or Instructed Regulation Mileage exceeds the Expected Regulation Mileage, and Unused Regulation Mileage occurs when the lesser of the Actual Regulation Mileage or Instructed Regulation Mileage is less than the Expected Regulation Mileage. In the event of Excess Regulation Mileage, the Resource receives a credit for the excess, and, in the event of Unused Regulation Mileage, the Resource is charged for the unused mileage for which it was compensated. Because Mileage is a concept applicable only in the RTBM (because Regulation Resources are not actually “moved” in the Day-Ahead Market), such charges and credits do not apply in the Day-Ahead Market.

Because settlements in the RTBM are based on Expected Mileage MCPs, SPP

proposes to incorporate a Make Whole Payment for Unused Regulation Mileage, which will compensate the Resource for the difference between its Mileage Offer and the settled amount charged at MCP. This Make Whole Payment will ensure that Resources are not penalized for Unused Regulation Mileage when MCP exceeds their Regulation Mileage Offer (i.e., when the Resource’s Offer did not set the MCP). The costs of the Make Whole Payment are recovered on a load ratio share basis. The Commission previously has accepted a make whole mechanism to address similar circumstances when a resource is charged for real-time mileage deployment that differs from the expected mileage amount.60

SPP’s proposed two-part Offer and compensation mechanism, with additional charges and credits in real-time to account for the performance component of the compensation, is substantively similar to the mechanism approved by the Commission for frequency regulation compensation in MISO.61

60 The Commission rejected MISO’s proposal to charge “undeployed” mileage at

the resource’s offer price rather than MCP, finding that doing so would result in different resources receiving different payments for providing the same amount of service, in violation of Order No. 755. See MISO Order at PP 34-35 nn.37-38. The Commission directed MISO to charge undeployed mileage the MCP, but permitted MISO to provide make whole compensation to the resource for its payment of MCP that is higher than its mileage offer. Id. at P 36; see also Midwest Indep. Transmission Sys. Operator, Inc., Letter Order, Docket No. ER12-1664-001 (Jan. 25, 2013) (accepting MISO’s proposed “Undeployed Regulating Mileage Revenue Sufficiency Guarantee Credit”); Filing of Midwest Independent Transmission System Operator, Inc., Docket No. ER12-1664-001, 3-4 (Oct. 22, 2012) (describing MISO’s proposed “Undeployed Regulating Mileage Revenue Sufficiency Guarantee Credit”).

61 See MISO Order at PP 7-13 (describing MISO’s Order No. 755 compliance proposal) and 25 (conditionally accepting MISO’s proposed two-part payment methodology as a “reasonable approach to compensating resources that provide frequency regulation service”).


To ensure that a Resource’s accuracy in following AGC dispatch signals is incorporated into its performance compensation as required by Order No. 755, SPP proposes to modify its current Real-Time Regulation Non-Performance Amount charge for Resources that operate outside of their Operating Tolerance by including excess mileage payments and unused mileage charges. If Resources operate outside of their Operating Tolerance, in addition to forfeiting their Regulation-Up or Regulation-Down capability payments, they will also forfeit all mileage-based charges and credits. In addition, SPP proposes to calculate and pay for excess mileage and to calculate and charge for unused mileage using the lesser of the actual mileage or instructed mileage to provide a market incentive for Resources to perform at their instructed mileage. These economic signals provide incentives for Resources to follow AGC dispatch instructions, consistent with the directives of Order No. 755.62

2. Capacity Payment Compliance

As discussed above, Order No. 755 requires that RTOs compensate all cleared

frequency regulation resources at a uniform, market-based (i.e., offer-based) capacity clearing price that includes the marginal resource’s cross-product opportunity costs as calculated by the RTO and allows for inclusion of inter-temporal opportunity costs.63 SPP’s current compensation methodology for Regulation already complies with this requirement. Specifically, SPP accepts Offers for Regulation-Up and Regulation-Down, which are used to calculate the MCPs that are then used to compensate cleared Resources in both the Day-Ahead Market64 and RTBM.65 The co-optimization logic used in both the Day-Ahead Market and RTBM calculate MCPs for Operating Reserve that include lost opportunity costs incurred as a result of Operating Reserve Clearing,66 thus

62 See Order No. 755 at PP 152-153 (“[T]he system operator needs to have the

confidence that when a dispatch signal is sent, resources will respond to it as directed. This is best accomplished by providing resources with an economic incentive to follow dispatch signals. Therefore, we will require all RTOs and ISOs to account for frequency regulation resources’ accuracy in following the AGC dispatch signal when determining the performance payment compensation.”).

63 Id. at PP 99, 102-103, 198.

64 See Integrated Marketplace Tariff at Attachment AE § 8.5.2 (setting forth the methodology for calculating the Day-Ahead Regulation Amount based on Day-Ahead MCP).

65 See id. at Attachment AE § 8.6.2 (setting forth the methodology for calculating the Real-Time Regulation Amount based on Real-Time MCP).

66 See id. at Attachment AE §§ 5.1.2(2)(d) & 6.2.2(5).

The Honorable Kimberly D. Bose June 21, 2013 Page 14 complying with the requirement to include RTO-calculated cross-product opportunity costs. Under SPP’s current Integrated Marketplace Tariff, the Market Participant can include inter-temporal opportunity costs in its Offers. The SPP Market Monitoring Unit has the ability to review and analyze such Offers for potential market manipulation. Because SPP’s current Integrated Marketplace Tariff already permits the inclusion of inter-temporal opportunity costs in Regulation offers, SPP is not proposing any additional changes in this filing.

3. Performance Payment Compliance

As discussed above, Order No. 755 mandated that each RTO provide a uniform,

market-based performance payment to each regulating resource, “reflect[ing] the amount of work each resource performs in real-time” and “the accuracy with which each resource responds to the system operator’s dispatch signal.” 67 While the Commission afforded RTOs discretion to design their performance payment, it directed RTOs to propose the specific technical requirements and bidding parameters.68 The Commission instructed that each resource’s performance must be measured based on the absolute amount of regulation up and down it provides in response to the RTO’s dispatch signal.69

SPP proposes several revisions to comply with this requirement. As discussed

above, SPP will compensate Resources based on the Expected Regulation-Up Mileage and Expected Regulation-Down Mileage, and then will credit or charge the Resource based on whether there is Excess Regulation-Up/-Down Mileage or Unused Regulation-Up/-Down Mileage in the RTBM. Thus, SPP proposes to adopt the following definitions in Attachment AE of the Tariff:70

Defined Term Definition

Actual Regulation-Down Mileage

The sum of the absolute values of actual movements by a Resource with cleared Regulation-Down Service MW in response to Regulation Deployment instructions.

67 Order No. 755 at PP 128-132, 199.

68 Id. at PP 130-131, 199.

69 Id. at P 133.

70 All definitions are included in Section 1.1 of Proposed Attachment AE, except as otherwise indicated.



Actual Regulation-Up Mileage

The sum of the absolute values of actual movements by a Resource with cleared Regulation-Up Service MW in response to Regulation Deployment instructions.

Excess Regulation-Down Mileage

The amount by which Actual Regulation-Down Mileage exceeds Expected Regulation-Down Mileage except that, if Actual Regulation-Down Mileage is greater than or equal to Instructed Regulation-Down Mileage multiplied by a factor equal to one minus Regulation-Mileage Operating Tolerance, Excess Regulation-Down Mileage is equal to the amount by which Instructed Regulation-Down Mileage exceeds Expected Regulation-Down Mileage.71

Excess Regulation-Up Mileage

The amount by which Actual Regulation-Up Mileage exceeds Expected Regulation-Up Mileage except that, if Actual Regulation-Up Mileage is greater than or equal to Instructed Regulation-Up Mileage multiplied by a factor equal to one minus Regulation Mileage Operating Tolerance, Excess Regulation-Up Mileage is equal to the amount by which Instructed Regulation-Up Mileage exceeds Expected Regulation-Up Mileage.72

Expected Regulation-Down Mileage

The amount of Regulation-Down Service MW cleared multiplied by the Regulation-Down Mileage Factor.

Expected Regulation-Up Mileage

The amount of Regulation-Up Service MW cleared multiplied by the Regulation-Up Mileage Factor.

Instructed Regulation-Down Mileage

The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Down Service through Regulation Deployment instructions.

Instructed Regulation-Up Mileage

The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Up Service MW through Regulation Deployment instructions.

71 See Proposed Tariff at Attachment AE § 8.6.2(2)(a)(v).

72 See id. at Attachment AE § 8.6.2(1)(a)(v).



Regulation-Down Mileage Factor

A factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Down Service MW to the Instructed Regulation-Down Mileage. The Regulation-Down Mileage Factor shall initially be set equal to 1.0 and shall be updated periodically pursuant to the Market Protocols.

Regulation-Down Mileage Offer

The price at which a Regulation Qualified Resource or a Regulation-Down Qualified Resource has agreed to sell Expected Regulation-Down Mileage.

Regulation-Down Service

The provision of Actual Regulation-Down Mileage associated with cleared Regulation-Down Service MW in response to Regulation Deployment instructions.

Regulation-Down Service Offer

The sum of (i) a Resource’s Regulation-Down Mileage Offer multiplied by the Regulation-Down Mileage Factor and (ii) that Resource’s Regulation-Down Offer.

Regulation Mileage Operating Tolerance

The allowable percentage deviation below a Resource’s Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage over the Dispatch Interval where the Resource will settle based upon Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage versus Actual Regulation-Up and/or Actual Regulation-Down Mileage. Such percentage is set at 5%.

Regulation-Up Mileage Factor

A factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Up Service MW to the Instructed Regulation-Up Mileage. The Regulation-Up Mileage Factor shall initially be set equal to 1.0 and shall be updated periodically pursuant to the Market Protocols.

Regulation-Up Mileage Offer

The price at which a Regulation Qualified Resource or a Regulation-Up Qualified Resource has agreed to sell Expected Regulation-Up Mileage.

Regulation-Up Service

The provision of Actual Regulation-Up Mileage associated with cleared Regulation-Up Service MW in response to Regulation Deployment instructions.



Regulation-Up Service Offer

The sum of (i) a Resource’s Regulation-Up Mileage Offer multiplied by the Regulation-Up Mileage Factor and (ii) that Resource’s Regulation-Up Offer.

Unused Regulation-Down Mileage

The amount by which Expected Regulation-Down Mileage exceeds Actual Regulation-Down Mileage except that, if Actual Regulation-Down Mileage is greater than or equal to Instructed Regulation-Down Mileage multiplied by a factor equal to one minus Regulation Mileage Operating Tolerance, then Unused Regulation-Down Mileage is equal to the amount by which Expected Regulation-Down Mileage exceeds Instructed Regulation-Down Mileage.73

Unused Regulation-Up Mileage

The amount by which Expected Regulation-Up Mileage exceeds Actual Regulation-Up Mileage except that, if Actual Regulation-Up Mileage is greater than or equal to Instructed Regulation-Up Mileage multiplied by a factor equal to one minus Regulation Mileage Operating Tolerance, then Unused Regulation-Up Mileage is equal to the amount by which Expected Regulation-Up Mileage exceeds Instructed Regulation-Up Mileage.74

The terms Actual Regulation-Up/-Down Mileage and Instructed Regulation-Up/-

Down Mileage include the absolute value of all up and down movements, in compliance with the requirement that the performance payment be based on the measurement of the Resource’s absolute amount of Regulation-Up and Regulation-Down provided.75 The adoption of defined terms “Regulation-Up Service” and “Regulation-Down Service” incorporate both the capacity and mileage concepts required by Order No. 755.76

73 See id. at Attachment AE § 8.6.2(2)(a)(iv).

74 See id. at Attachment AE § 8.6.2(1)(a)(iv).

75 See Order No. 755 at P 133.

76 Adopting these terms requires conforming changes throughout Attachment AE. See Proposed Tariff at Attachment AE §§ 1.1 (Definition of “Operating Reserve,” “Regulation Deployment,” and “Resource Offer”), 2.11.1, 3.5, 5.1.2, 5.1.2.1, 5.1.2.2, 5.1.3, 5.2.2, 6.1.2, 6.2.1.1, 6.2.1.2, 6.2.2, 6.2.2.2, 6.2.3, 6.3, 6.3.1, 6.4.2, 8.3.4.2, 8.5.2, 8.5.5, 8.5.6, 8.5.9, 8.6.2, 8.6.8, 8.6.11, 8.6.12, 8.6.15.


SPP also proposes to revise the definition of “Market Clearing Price” to include Regulation-Up Service, Regulation-Down Service, Expected Regulation-Up Mileage, and Expected Regulation-Down Mileage.77 Additionally, SPP proposes to revise the definitions of “Regulation-Down Qualified Resource,” “Regulation Qualified Resource,” and “Regulation-Up Qualified Resource” to include the Regulation Mileage concept.78 SPP also proposes to modify the Resource Offer parameters to include “Regulation-Up Mileage and Regulation-Down Mileage Offers.”79

To ensure that all Resources providing Regulation are compensated at a uniform,

market-based price, SPP has modified the Tariff to require calculation of MCPs for Regulation-Up Service and Regulation-Down Service (which are required in the current Integrated Marketplace design but are being modified to incorporate the Mileage component), and, for the RTBM, MCPs for Expected Regulation-Up Mileage and Expected Regulation-Down Mileage.80 MCPs for Expected Regulation-Up Mileage and Expected Regulation-Down Mileage are equal to the highest Regulation Mileage Offer of all Resources economically cleared to provide Regulation-Up Service or Regulation-Down Service in a particular dispatch interval, multiplied by the Mileage Factor.81

As discussed above, a Resource’s performance payment is achieved through the

existing Real-Time Regulation Service Amount mechanism, as modified by this filing.82 The component of the RTBM payment or charge attributable to the Resource’s Regulation performance payment is calculated based on the extent to which its Actual Regulation-Up Mileage or Regulation-Down Mileage (or corresponding Instructed Mileages) deviates from the Expected Regulation-Up Mileage or Regulation-Down Mileage, resulting in Excess Regulation Mileage or Unused Regulation Mileage.83 The Unused Regulation-Up Mileage or Unused Regulation-Down Mileage charge is calculated by multiplying the Unused Regulation Mileage by the MCPs for Expected Regulation-Up Mileage or Expected Regulation-Down Mileage.84 This calculation ensures that a Resource will not be overcompensated for its actual provision of

77 See Proposed Tariff at Attachment AE § 1.1 Definitions M.

78 See id. at Attachment AE § 1.1 Definitions R.

79 See id. at Attachment AE § 4.1(9).

80 See id. at Attachment AE §§ 3.5, 6.2.3, 8.3.4.

81 See id. at Attachment AE §§ 8.3.4(3) & (4).

82 See id. at Attachment AE § 8.6.2.

83 See id.

84 See id. at Attachment AE §§ 8.6.2(1)(a)(iv) & 8.6.2(2)(a)(iv).

The Honorable Kimberly D. Bose June 21, 2013 Page 19 Regulation Mileage. Likewise, Excess Regulation Mileage credits (for both Up and Down) are calculated using the MCPs for Expected Regulation Mileage, and are paid to the Resource, ensuring that it is compensated for its full response to AGC dispatch instructions.85

Additionally, SPP is proposing in this filing to incorporate mechanisms to provide

Make Whole Payments to Resources that are charged for Unused Regulation-Up Mileage and Unused Regulation-Down Mileage based at the Expected Regulation-Up Mileage or Expected Regulation-Down Mileage MCP. Unless a Resource’s Regulation Mileage Offers happen to set the MCP, charging the Resource for Unused Mileage will result in a loss to the Resource. The Make Whole Payment for Unused Regulation Mileage will compensate the Resource for the difference between its Mileage Offer and the settled amount charged at MCP,86 which will ensure that Resources are not penalized for Unused Regulation Mileage.

Finally, costs associated with compensating Resources providing Regulation-Up

Service and Regulation-Down Service (including Regulation Mileage) are allocated based on Load Ratio Share,87 including costs associated with the Unused Regulation Mileage Make Whole Payments.88

SPP’s proposed performance payment is similar to the method adopted in

MISO,89 in which a Resource is paid for Regulation capacity and an expected amount of Regulation Mileage, and then is credited or charged based on the actual Mileage used in real-time. SPP’s proposal complies with the requirements of Order No. 755 to provide uniform, market-based compensation for regulation capacity and actual work performed by a regulation resource based on the accuracy of the resource in responding to AGC dispatch instruction, and therefore is just and reasonable and should be accepted by the Commission.

85 See id. at Attachment AE §§ 8.6.2(1)(a)(v) & 8.6.2(2)(a)(v).

86 See id. at Attachment AE §§ 8.6.19 & 8.6.20; see also id. at Attachment AE § 8.6.5(4)(b) (stating that an Asset Owner’s Reliability Unit Commitment Make Whole Payment Revenue Amount includes the Unused Regulation Make Whole Payments calculated under Sections 8.6.19 and 8.6.20 of Attachment AE).

87 See, e.g., id. at Attachment AE §§ 8.5.5, 8.5.6, 8.6.8.

88 See id. at Attachment AE §§ 8.6.8(1)(a) & (2)(a).

89 See MISO Order at PP 7-13 (describing MISO’s two-part payment), 25 (conditionally accepting MISO’s proposal), 29 (conditionally accepting MISO’s capacity payment), 33 (conditionally accepting MISO’s performance payment based on Mileage).


4. Accuracy Measurement

In Order No. 755, the Commission required RTOs to account for a resource’s

accuracy in following AGC dispatch signals in determining the performance payment compensation and to propose the technical specifications for measuring accuracy.90 The Commission did not mandate any particular method for measuring accuracy, but required that the same accuracy measurement method must apply to all frequency regulation resources.91

As discussed above, to ensure Resource accuracy in following AGC dispatch

signals, SPP proposes to modify its current Real-Time Regulation Non-Performance Amount charge for Resources that operate outside of their Operating Tolerance by including excess mileage payments and unused mileage charges,92 and to calculate mileage based on the lesser of actual or instructed mileage, consistent with Order No. 755.93 However, because there could be some latency associated with receiving a Regulation AGC signal via four-second Setpoint Instruction, SPP proposes to adopt a Regulation Mileage Operating Tolerance of five-percent to allow for such latency. For example, if a Resource’s instructed mileage was 100 MWs and its actual mileage was 96 MWs, then SPP will use 100 MWs to calculate the Resource’s excess mileage or unused mileage. If the Resource’s actual mileage was 94 MWs, then SPP would use 94 MWs to calculate the Resource’s excess mileage or unused mileage. These revisions will ensure that the performance compensation received by a Resource takes the Resource’s accuracy in responding to AGC signals into account, and that the accuracy measurement and payment mechanisms apply equally to all resources.

5. Market Power Mitigation In Order No. 755, the Commission noted that, given the additional performance

payment requirements of Order No. 755, it is appropriate for RTOs to revisit their market power monitoring and mitigation provisions to ensure that they remain adequate to protect against market power abuse.94 Accordingly, the Commission directed RTOs “either to submit tariff provisions for market power mitigation methods appropriate to redesigned frequency regulation markets or to explain how their current mitigation

90 Order No. 755 at PP 151-153, 200.

91 Id. at PP 153-154, 200.

92 See Proposed Tariff at Attachment AE § 8.6.11.

93 See supra note 62 and accompanying text.

94 Order No. 755 at P 136.

The Honorable Kimberly D. Bose June 21, 2013 Page 21 methods are sufficient to address market power concerns given the changes required” by Order No. 755.95

SPP proposes several Tariff revisions to address potential market manipulation given the adoption of a two-part compensation method. Specifically, to prevent Market Participants from making artificially low capacity offers with artificially high mileage offers, SPP proposes to require that when a Regulation Offer (Up or Down) is negative, the corresponding Regulation Mileage Offer must equal zero.96 SPP also proposes to revise the Offer Caps and Floors set forth in Section 4.1.1 of Attachment AE to add Regulation-Up Mileage Offer and Regulation-Down Mileage Offer floors of $0/MW,97 to prevent the submission of negative Regulation Mileage Offers. SPP also proposes to clarify that the existing Regulation Offer Cap of $500/MW applies both to Regulation-Up Service Offers and Regulation-Down Service Offers (which, by definition, include both the Regulation-Up/-Down capacity offer and the Regulation-Up/-Down Mileage Offer).98 Additionally, SPP proposes to require that, if a Resource is cleared in the Day-Ahead Market for Regulation-Up Service or Regulation-Down Service, the Regulation-Up Mileage Offers and/or Regulation-Down Mileage Offers for the Resource submitted for use in the RTBM must be equal to the same Mileage Offers submitted by the Resource in its cleared Day-Ahead Offers.99 The Commission accepted similar mitigation measures in MISO’s Order No. 755 compliance filing.100 Additionally, SPP has developed and approved through its stakeholder process101 protocols for enhanced mitigation of Regulation mileage Offers based on SPP’s current mitigated Regulation Offer provisions that are pending in the February 2013 Compliance Filing.102 Specifically, SPP has adopted definitions of “Mitigated Regulation-Down 95 Id.

96 See Proposed Tariff at Attachment AE § 4.1(7).



99 See id. at Attachment AE § 4.1(1).

100 MISO Order at P 47.

101 See Southwest Power Pool, Inc., Board of Directors Minutes No. 151, page 134 of 1158 of PDF (“Marketplace Protocol Revision Request No. 102”) (Apr. 30, 2013), http://www.spp.org/publications/BOD043013.pdf. SPP is in the process of incorporating these revisions into the Integrated Marketplace Protocols, which will be posted on the SPP website.

102 See February 2013 Compliance Filing, Transmittal Letter at 38-40.

The Honorable Kimberly D. Bose June 21, 2013 Page 22 Mileage Offer” and “Mitigated Regulation-Up Mileage Offer” and has incorporated these Offers into the existing Mitigated Resource Offers, which Market Participants are required to develop in accordance with the Section 3 of Attachment AF of the Integrated Marketplace Tariff and Appendix G of the Market Protocols. SPP also has incorporated Mitigated Regulation-Up Mileage Offers and Mitigated Regulation-Down Mileage Offers into the Resource Offer parameter requirements of Section 4.2.2.1 of the Integrated Marketplace Protocols. Consistent with SPP’s existing procedures for mitigated Offers, SPP’s automatic Offer mitigation procedures will check all market price impacts of any combined Regulation capability and mileage Offers submitted by Resources with local market power that exceed the applicable conduct threshold. If such an Offer fails the market impact test, both the Regulation capability and mileage Offers will be replaced by the corresponding mitigated Offers, which represent the short-run marginal costs of providing Regulation Service.

SPP’s mitigated mileage Offer procedures, which are currently set forth in the Integrated Marketplace Protocols, are undergoing further stakeholder review for possible refinement and incorporation into the Tariff. SPP anticipates submitting additional Tariff provisions to adopt its enhanced mitigated mileage Offer procedures, after consideration by stakeholders and the SPP Board of Directors, after the October 29, 2013 meeting of the Board of Directors.103 These provisions, combined with SPP’s existing market power monitoring and mitigation measures and the measures proposed in this filing, will protect against market power abuse following the implementation of SPP’s two-part Regulation compensation methodology in 2015. III. ADDITIONAL INFORMATION A. Information Required by the Commission’s Regulations (1) Documents submitted with this filing:

In addition to this transmittal letter, SPP includes in this filing clean and redlined versions of the proposed Tariff revisions in electronic format.

103 This timeframe will allow sufficient time for Commission review well in advance

of the March 2015 implementation of SPP’s Order No. 755 compliance. See March 2013 Order at P 40 (“SPP is required to file Tariff revisions to comply with the requirements of Order No. 755 no later than June 30, 2013, which are to be implemented no later than one year following market start-up.”).


(2) Effective date:

SPP requests that the Commission accept the proposed revisions to the SPP Tariff effective March 1, 2015, consistent with the Commission’s directive that SPP “file Tariff revisions to comply with the requirements of Order No. 755 no later than June 30, 2013, which are to be implemented no later than one year following market start-up.”104

(3) Service:

SPP has served a copy of this filing on all SPP Members and Customers and all affected state commissions. A complete copy of this filing will be posted on the SPP web site, www.spp.org. SPP also has served a copy on all parties listed on the service list in Docket No. ER12-1179, SPP’s Integrated Marketplace compliance docket.

B. Communications

Correspondence and communications with respect to this filing should be sent to, and SPP requests that the Commission include on the official service list for this proceeding, the following individuals:

Nicole Wagner Manager, Regulatory Policy Southwest Power Pool, Inc. 201 Worthen Drive Little Rock, AR 72223-4936 Telephone: (501) 688-1642 Fax: (501) 664-9553 [email protected]

Barry S. Spector Matthew J. Binette WRIGHT & TALISMAN, P.C. 1200 G Street, N.W., Suite 600 Washington, DC 20005-3802 Telephone: (202) 393-1200 Fax: (202) 393-1240 [email protected] [email protected]

104 Id. To the extent necessary, SPP requests a waiver of the Commission’s notice

requirements set forth in section 35.3 of the Commission’s regulations, 18 C.F.R. § 35.3, to allow SPP to submit these Tariff revisions to the Commission more than 120 days prior to the requested effective date. Good cause exists to grant such a waiver, to enable SPP to comply with the Commission’s directives to submit Tariff revisions by June 30, 2013 to implement SPP’s Order No. 755 compliance one year after market launch.

The Honorable Kimberly D. Bose June 21, 2013 Page 24 IV. CONCLUSION

For all of the foregoing reasons, SPP respectfully requests that the Commission accept the Tariff revisions proposed herein as compliant with Order No. 755, effective as discussed above.

Respectfully submitted, /s/ Matthew J. Binette Barry S. Spector Matthew J. Binette WRIGHT & TALISMAN, P.C. 1200 G Street, N.W., Suite 600 Washington, DC 20005-3802 Telephone: (202) 393-1200 Fax: (202) 393-1240 Attorneys for Southwest Power Pool, Inc.

cc: Penny Murrell Michael Donnini John Rogers Patrick Clarey Laura Vallance

ATTACHMENT AE

INTEGRATED MARKETPLACE

Attachment AE

Table of Contents

1. Introduction

1.1 Definitions and Acronyms

1.1 Definitions A

1.1 Definitions B

1.1 Definitions C

1.1 Definitions D

1.1 Definitions E

1.1 Definitions F

1.1 Definitions G

1.1 Definitions I

1.1 Definitions J

1.1 Definitions L

1.1 Definitions M

1.1 Definitions N

1.1 Definitions O

1.1 Definitions P

1.1 Definitions Q

1.1 Definitions R

1.1 Definitions S

1.1 Definitions T

1.1 Definitions U

1.1 Definitions V

2. Market Participant Obligations

2.1 Service Agreement

2.2 Application and Asset Registration

2.3 Market Manipulation

2.4 Commitment and Dispatch

2.5 Provision of Load and Generation Data

2.6 Dispatchable Demand Response Resource

2.7 Block Demand Response Resource

2.8 Aggregators of Retail Customers

2.9 Combined Cycle Resource

2.10 Operating Reserve Certification

2.10.1 Spin Qualified Resources

2.10.2 Supplemental Qualified Resources

2.10.3 Regulation Qualified Resources

2.11 Must-Offer Requirement

2.11.1 Day-Ahead Market

2.11.2 Reliability Unit Commitment and the Real-Time Balancing Market

2.12 Non-Conforming Load

2.13 Market Protocols and SPP Criteria

2.14 External Dynamic Resource

2.15 Provision of Wind Forecast Data

3. Transmission Provider Rights and Obligations

3.1 Transmission Provider Scope of Services

3.1.1 Market Hub Establishment and Modification

3.1.2 Forecasting

3.1.3 Reserve Zone Establishment

3.1.4 Operating Reserve Requirements

3.1.5 Outage Scheduling and Reporting

3.2 Market Protocols

3.3 Integrated Marketplace Operations

3.4 Violation Relaxation Limit Reporting

3.5 Integrated Marketplace Pricing

3.6 Integrated Marketplace Settlements

3.7 Integrated Marketplace Participation Readiness

4. Pre-Day-Ahead Period Activities

4.1 Offer Submittal

4.1.1 Offer Caps and Floors

4.1.2 Additional Provisions for Non-Traditional Resources

4.2 Provisions for Non-Resource Related Offers

4.2.1 Virtual Energy Offers

4.2.2 Import Interchange Transaction Offers

4.3 Bid Submittal

4.3.1 Demand Bids

4.3.2 Virtual Energy Bids

4.3.3 Export Interchange Transaction Bids

4.4 Through Interchange Transactions

4.5 Multi-Day Reliability Assessment

4.5.1 Multi-Day Reliability Assessment Inputs

4.5.2 Multi-Day Reliability Assessment Analysis

4.5.3 Multi-Day Reliability Assessment Results

5. Day-Ahead Period Activities

5.1 Day-Ahead Market

5.1.1 Day-Ahead Market Inputs

5.1.2 Day-Ahead Market Execution

5.1.3 Day-Ahead Market Results

5.2 Day-Ahead Reliability Unit Commitment

5.2.1 Day-Ahead Reliability Unit Commitment Inputs

5.2.2 Day-Ahead Reliability Unit Commitment Execution

5.2.3 Day-Ahead Reliability Unit Commitment Results

6. Operating Day Activities

6.1 Intra-Day Reliability Unit Commitment

6.1.1 Intra-Day Reliability Unit Commitment Inputs

6.1.2 Intra-Day Reliability Unit Commitment Execution

6.1.3 Intra-Day Reliability Unit Commitment Results

6.2 Real-Time Balancing Market

6.2.1 Real-Time Balancing Market Inputs

6.2.2 Real-Time Balancing Market Execution

6.2.3 Real-Time Balancing Market Results

6.2.4 Out-of-Merit Energy Dispatch

6.3 Energy and Operating Reserve Deployment

6.3.1 Regulation Deployment

6.3.2 Contingency Reserve Deployment

6.3.3 Reserve Sharing Group Scheduling Procedures

6.3.4 Contingency Reserve Recovery

6.4 Energy and Operating Reserve Deployment Failure

6.4.1 Uninstructed Resource Deviation

6.4.2 Regulation Deployment Failure Charges

6.4.3 Contingency Reserve Deployment Failure Charges

6.5 Inadvertent Management

6.5.1 Inadvertent Payback Reporting

7. Transmission Congestion Rights Markets

7.1 Annual Auction Revenue Right Verification

7.1.1 Transmission Service Verification

7.1.2 Candidate Auction Revenue Rights

7.1.3 Auction Revenue Right Nomination Cap

7.2 Annual Auction Revenue Right Allocation

7.2.1 Auction Revenue Right Nominations

7.2.2 Auction Revenue Right Allocation

7.2.3 Annual Auction Revenue Right Awards

7.3 Annual Transmission Congestion Right Auction

7.3.1 Transmission Congestion Right Offer and Bid Submittal

7.3.2 Annual Transmission Congestion Right Auction

7.3.3 Annual Transmission Congestion Right Auction Clearing and

Simultaneous Feasibility

7.3.4 Annual Transmission Congestion Right Awards

7.4 Monthly Transmission Congestion Right Auctions

7.4.1 Monthly Transmission Congestion Right Offer and Bid Submittal

7.4.2 Monthly Transmission Congestion Right Auction

7.4.3 Monthly Transmission Congestion Right Auction Clearing and


7.4.4 Monthly Transmission Congestion Right Awards

7.5 Monthly Auction Revenue Right Allocation

7.5.1 Monthly Auction Revenue Right Transmission Service Verification

7.5.2 Reserved for Future Use

7.5.3 Monthly Auction Revenue Right Nominations

7.5.4 Monthly Auction Revenue Right Awards

7.6 Auction Revenue Right Allocation and Transmission Congestion Right Auction

Settlements

7.7 Transmission Congestion Right Secondary Market

7.8 Liquidation of Transmission Congestion Rights in the Event of Market Participant

Default

7.9 Initial TCR Markets Schedule

8. Post Operating Day and Settlement Activities

8.1 Settlement Sign Conventions

8.2 Bilateral Settlement Schedules

8.2.1 Default Procedures for Pre-Existing Bilateral Contracts Transitioning to

Integrated Marketplace

8.3 Calculation of Locational Marginal Prices, Locational Marginal Price

Components, and Market Clearing Prices

8.3.1 Locational Marginal Price Calculations and Components

8.3.2 Violation Relaxation Limit

8.3.3 Impact of Violation Relaxation Limits on Locational Marginal Prices

8.3.4 Market Clearing Price Calculations

8.4 Price Corrections

8.5 Day-Ahead Market Settlement

8.5.1 Day-Ahead Energy Amount

8.5.2 Day-Ahead Regulation Service Amount

8.5.3 Day-Ahead Spinning Reserve Amount

8.5.4 Day-Ahead Supplemental Reserve Amount

8.5.5 Day-Ahead Regulation-Up Service Distribution Amount

8.5.6 Day-Ahead Regulation-Down Service Distribution Amount

8.5.7 Day-Ahead Spinning Reserve Distribution Amount

8.5.8 Day-Ahead Supplemental Reserve Distribution Amount

8.5.9 Day-Ahead Make Whole Payment Amount

8.5.10 Day-Ahead Make Whole Payment Distribution Amount

8.5.11 Transmission Congestion Rights Funding Amount

8.5.12 Transmission Congestion Rights Daily Uplift Amount

8.5.13 Transmission Congestion Rights Monthly Payback Amount

8.5.14 Transmission Congestion Rights Annual Payback Amount

8.5.15 Transmission Congestion Rights Annual Closeout Amount

8.5.16 Day-Ahead Over-Collected Losses Distribution Amount

8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount

8.6 Real-Time Balancing Market Settlement

8.6.1 Real-Time Energy Amount

8.6.2 Real-Time Regulation Service Amount

8.6.3 Real-Time Spinning Reserve Amount

8.6.4 Real-Time Supplemental Reserve Amount

8.6.5 Reliability Unit Commitment Make Whole Payment Amount

8.6.6 Real-Time Out-of-Merit Amount

8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount

8.6.8 Real-Time Regulation Service Distribution Amount

8.6.9 Real-Time Spinning Reserve Distribution Amount

8.6.10 Real-Time Supplemental Reserve Distribution Amount

8.6.11 Real-Time Regulation Service Non-Performance Amount

8.6.12 Real-Time Regulation Service Non-Performance Distribution Amount

8.6.13 Real-Time Contingency Reserve Deployment Failure Amount

8.6.14 Real-Time Contingency Reserve Deployment Failure Distribution Amount

8.6.15 Real-Time Regulation Service Deployment Adjustment Amount

8.6.16 Real-Time Over-Collected Losses Distribution Amount

8.6.17 Real-Time Reserve Sharing Group Amount

8.6.18 Real-Time Reserve Sharing Group Distribution Amount

8.6.19 Real-Time Unused Regulation-Up Mileage Make Whole Payment

8.6.20 Real-Time Unused Regulation-Down Mileage Make Whole Payment

8.7 Auction Revenue Rights and Transmissions Congestion Rights Auction

Settlement

8.7.1 Transmission Congestion Rights Auction Transaction Amount

8.7.2 Auction Revenue Rights Funding Amount

8.7.3 Auction Revenue Rights Uplift Amount

8.7.4 Auction Revenue Rights Monthly Payback Amount

8.7.5 Auction Revenue Rights Annual Payback Amount

8.7.6 Auction Revenue Rights Annual Closeout Amount

8.8 Revenue Neutrality Uplift Distribution Amount

9. Release of Offer Curve Data

10. Billing

10.1 Settlement Statements

10.2 Invoices

10.3 Invoice Disputes

10.4 Interest on Unpaid Balances

10.5 Customer Default

11. Confidentiality Provisions

11.1 Restrictions on Confidential Information Provided to Receiving Party

11.1.1 Procedures for Confidential Information

11.1.2 Exceptions

11.1.3 Injunctive Relief and Specific Performance

11.1.4 Market Participant Access and Transmission Provider Use of Confidential

Information

11.1.5 Required Disclosure

11.1.6 Limitations

11.2 Confidentiality Provisions Applicable to the Market Monitor Reporting to the

Board of Directors

11.3 Disclosure to Commission

11.4 Disclosure to Authorized Agencies

11.4.1 Basic Requirements for Disclosure

11.4.2 Schedule of Authorized Requestors

11.4.3 Use of Confidential Information

11.4.4 Limited Oral Disclosures

11.4.5 Information Requests

11.4.6 Limited Discussion of Confidential Information Among Authorized

Requestors Sponsored By Different Authorized Agencies

11.4.7 Breach of Non-Disclosure Obligations

11.5 Preservation of Rights

11.6 Notice

Addendum 1 Violation Relaxation Limit Values (“VRLs”)

Addendum 2 Bilateral Settlement Schedule Example System Power Sale

1.1 Definitions A


The sum of the absolute values of actual movements by a Resource with cleared Regulation-

Down Service MW in response to Regulation Deployment instructions.


The sum of the absolute values of actual movements by a Resource with cleared Regulation-Up

Service MW in response to Regulation Deployment instructions.

Asset Owner

An owner of any combination of: (1) registered physical assets (Resource, load, Import

Interchange Transaction, Export Interchange Transaction, Through Interchange Transaction), (2)

Transmission Congestion Rights, (3) Virtual Energy Offers, (4) Virtual Energy Bids, or (5)

Bilateral Settlement Schedules.

Asset Owner Reserve Zone Load Ratio Share

The sum of an Asset Owner’s Reported Load and Export Interchange Transactions in a Reserve

Zone divided by the sum of all Asset Owners’ Reported Load and Export Interchange

Transactions in all Reserve Zones for a given hour.

Auction Clearing Price (“ACP”)

The price generated at each source and sink Settlement Location in each round of the Annual

Transmission Congestion Right Auction and Monthly Transmission Congestion Right Auction

based upon the Transmission Congestion Right Offers and Bids submitted.

Auction Revenue Right (“ARR”)

A right, awarded during the annual Auction Revenue Right allocation process and the monthly

Auction Revenue Right allocation process, which entitles the holder to a share of the auction

revenues generated in the applicable Transmission Congestion Rights auction(s) and entitles the

holder to self-convert the Auction Revenue Right to a Transmission Congestion Right.

Auction Revenue Right Nomination Cap (“ARR Nomination Cap”)

A cap on the maximum total amount of Auction Revenue Rights that an Eligible Entity may

nominate in each month and season in the annual Auction Revenue Right allocation process and

the monthly Auction Revenue Right allocation process.

1.1 Definitions E

Electrical Node (“ENode”)

A physical node represented in the Network Model where electrical equipment and components

are connected.

Eligible Entity

A Transmission Customer or Market Participant having firm SPP Transmission Service or firm

non-SPP transmission service (referred to as a “grandfathered agreement” or “GFA”) into, out

of, within or through the SPP Region.

Emergency Condition

As defined in Section 1 of the Tariff.

Energy

An amount of electricity that is Bid or Offered, produced, purchased, consumed, sold or

transmitted over a period of time, which is measured or calculated in Megawatt hours.

Energy and Operating Reserve Markets


Energy Offer Curve

A set of price/quantity pairs that consists of Megawatts and dollars per Megawatt hour with up to

ten (10) price/quantity pairs.


The amount calculated under Section 8.6.2 of this Attachment AE.




The amount of Regulation-Down Service MW cleared multiplied by the Regulation-Down

Mileage Factor.


The amount of Regulation-Up Service MW cleared multiplied by the Regulation-Up Mileage

Factor.

Export Interchange Transaction

A Market Participant schedule for exporting Energy out of the SPP Balancing Authority Area.

Export Interchange Transaction Bid

A proposal by a Market Participant to purchase a fixed or price sensitive amount of Energy for

delivery outside of the SPP Balancing Authority Area at a specified External Interface and for a

period of time.

External Dynamic Resource

A registered Resource that represents one or more resources, located external to the SPP

Balancing Authority Area, which is dynamically scheduled into or out of the SPP Balancing

Authority Area.

External Interface

A Settlement Location representing a physical interconnection point(s) between the SPP

Balancing Authority Area and an external Balancing Authority Area.

1.1 Definitions I

Import Interchange Transaction

A schedule for importing Energy into the SPP Balancing Authority Area.

Import Interchange Transaction Offer

A proposal by a Market Participant to provide Energy from a source external to the SPP

Balancing Authority Area at a specified External Interface and period of time.


The sum of the absolute values of instructed movements to a Resource with cleared Regulation-

Down Service through Regulation Deployment instructions.



Up Service MW through Regulation Deployment instructions.


The Day-Ahead Market, the Real-Time Balancing Market, the Transmission Congestion Rights

Market and the Reliability Unit Commitment processes.

Integrated Marketplace Counterparty

The Transmission Provider, as counterparty to all Integrated Marketplace transactions (and not

in any other capacity of the Transmission Provider under the Tariff) in accordance with the

provisions of Section 3.8 of this Attachment AE.

Interchange Transaction

Any Energy transaction that is crossing the boundary of the SPP Balancing Authority Area and

requires checkout with one or more external Balancing Authority Areas. This includes any

Import Interchange Transaction, Export Interchange Transaction or Through Interchange

Transaction.

Intra-Day Reliability Unit Commitment (“Intra-Day RUC”)

The process performed by the Transmission Provider following the completion of the Day-

Ahead Reliability Unit Commitment process and throughout the Operating Day to assess

Resource and Operating Reserve adequacy for the Operating Day, commit or de-commit

Resources as necessary, and communicate commitment or de-commitment of Resources to the

appropriate Market Participants as necessary.

1.1 Definitions M

Manual Dispatch Instruction

A Dispatch Instruction that originates from SPP outside of the normal Real-Time Balancing

Market security constrained economic dispatch solution to address a system reliability condition.

Market Clearing Price (“MCP”)

The price used for settlements of an Operating Reserve product in each Reserve Zone. A

separate price is calculated for Regulation-Up Service, Expected Regulation-Up Mileage,

Regulation-Down Service, Expected Regulation-Down Mileage, Spinning Reserve and

Supplemental Reserve.

Market Flow

The aggregate Megawatt flow on a Coordinated Flowgate or a Reciprocal Coordinated Flowgate

caused by the Real-Time Balancing Market.

Market Hub

A Settlement Location consisting of an aggregation of Price Nodes.

Market Participant


Marginal Congestion Component (“MCC”)

The calculated portion of the Locational Marginal Price at a Settlement Location representing

transmission congestion costs between that Settlement Location and a reference location as

calculated under Section 8.3 of this Attachment AE.

Marginal Loss Component (“MLC”)


marginal loss costs between that Settlement Location and a reference location as calculated

under Section 8.3 of this Attachment AE.

Maximum Economic Capacity Operating Limit

An economic MW level at or below a Resource’s Maximum Normal Capacity Operating Limit

used for constraining Energy dispatch and Contingency Reserve clearing during normal system

conditions.

Maximum Emergency Capacity Operating Limit

The maximum Megawatt level at which a Resource other than a Block Demand Response

Resource may operate under Emergency Conditions.

Maximum Normal Capacity Operating Limit

The maximum Megawatt level at which a Resource may operate continuously.

Maximum Regulation Capacity Operating Limit

The maximum Megawatt level at which a Regulation Qualified Resource, a Regulation-Up

Qualified Resource or a Regulation-Down Qualified Resource may operate while providing

Regulation Deployment.

Megawatt (“MW”)

A measurement unit of the instantaneous demand for Energy.

Meter Agent

An entity responsible for collecting load and Resource data associated with identified Meter

Settlement Locations within a Settlement Area for the purpose of energy accounting that impacts

market settlements.

Meter Data Submittal Location

One or more Meter Settlement Locations contained within a single Settlement Area for which

meter data is submitted to the Transmission Provider by the Meter Agent for settlement

purposes.

Meter Settlement Location

The point at which a Market Participant’s registered load and Resources interchange Energy with

the Real-Time Balancing Market.

Minimum Economic Capacity Operating Limit

A Megawatt level at or above a Resource’s Minimum Normal Capacity Operating Limit used for

energy dispatch at a minimum level during normal operating conditions.

Minimum Emergency Capacity Operating Limit

The minimum Megawatt level at which a Resource other than a Block Demand Response


Minimum Normal Capacity Operating Limit

The minimum Megawatt level at which a Resource may operate continuously.

Minimum Regulation Capacity Operating Limit

The minimum Megawatt level at which a Regulation Qualified Resource, a Regulation-Up



Minimum Run Time

The minimum length of time a Resource must run from the time the Resource is put online to the

time the Resource is shut-down.

Multi-Day Reliability Assessment

The process to assess Resource adequacy for the Operating Day, commit Resources with long

Start-Up Times that cannot be considered as part of the Day-Ahead Market or Day-Ahead

Reliability Unit Commitment, and communicate commitment of such Resources as necessary.

1.1 Definitions O

Offer

A commitment to sell (i) a quantity of Energy at a specific minimum price that includes a

Resource Offer, a Virtual Energy Offer or an Import Interchange Transaction Offer, or (ii) a

quantity of Transmission Congestion Rights at a specific minimum price, where such quantities

may be submitted in 0.1 MW increments.

Off-Peak

As defined in Schedule 1 of the Tariff.

On-Peak


Operating Day

A daily period beginning at midnight.

Operating Hour

A sixty (60) minute period of time during the Operating Day corresponding to a clock hour

typically expressed as hour-ending.

Operating Reserve

Resource capacity held in reserve for Resource contingencies and NERC control performance

compliance that includes the following products: Regulation-Up Service, Regulation-Down

Service, Spinning Reserve and Supplemental Reserve.

Operating Tolerance

The Megawatt range of actual Resource output above and below the Resource’s average Setpoint

Instruction over the Dispatch Interval where the Resource will not be subject to charges

associated with Uninstructed Resource Deviation.

1.1 Definitions R

Real-Time

The continuous time period during which the Real-Time Balancing Market is operated.

Real-Time Balancing Market (“RTBM”)


Real-Time Load Ratio Share

The sum of a Market Participant’s Reported Load and Export Interchange Transactions at all

Settlement Locations divided by the sum of all Market Participants’ Report Load and Export

Interchange Transactions at all Settlement Locations for a given hour.

Reciprocal Coordinated Flowgate

A Coordinated Flowgate defined within a joint operating agreement between SPP and another

transmission provider as being affected by the transmission of Energy on both of their respective

transmission systems.

Reference Bus

The location on the Transmission System relative to which all mathematical quantities, including

shift factors and penalty factors relating to physical operation, will be calculated.

Regulation Deployment

The utilization of Regulation-Up Service and/or Regulation-Down Service through automatic

generation control equipment to automatically and continuously adjust Resource output to

balance the SPP Balancing Authority Area in accordance with NERC control performance

criteria.

Regulation-Down

An Operating Reserve product procured by the Transmission Provider from qualified Resources

that reduce their energy output in response to a Regulation Deployment instruction from the

Transmission Provider.


A factor determined through historical Regulation Deployment analysis that represents the ratio

of cleared Regulation-Down Service MW to the Instructed Regulation-Down Mileage. The

Regulation-Down Mileage Factor shall initially be set equal to 1.0 and shall be updated

periodically pursuant to the Market Protocols.


The price at which a Regulation Qualified Resource or a Regulation-Down Qualified Resource

has agreed to sell Expected Regulation-Down Mileage.

Regulation-Down Offer


has committed to sell Regulation-Down.

Regulation-Down Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Down Offers and

Regulation-Down Mileage Offers into the Energy and Operating Reserve Markets.


The provision of Actual Regulation-Down Mileage associated with cleared Regulation-Down



The sum of (i) a Resource’s Regulation-Down Mileage Offer multiplied by the Regulation-Down

Mileage Factor and (ii) that Resource’s Regulation-Down Offer.


The allowable percentage deviation below a Resource’s Instructed Regulation-Up Mileage

and/or Instructed Regulation-Down Mileage over the Dispatch Interval where the Resource will

settle based upon Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage

versus Actual Regulation-Up and/or Actual Regulation-Down Mileage. Such percentage is set at

5%.

Regulation Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Up Offers,

Regulation-Up Mileage Offers, Regulation-Down Offers and Regulation-Down Mileage Offers

into the Energy and Operating Reserve Markets.

Regulation Response Time

The maximum amount of time allowed for a Resource to move its output from zero (0)

Regulation Deployment to the full amount of Regulation-Up cleared or to move from zero (0)

Regulation Deployment to the full amount of Regulation-Down cleared.

Regulation-Up


that increase their energy output in response to a Regulation Deployment instruction from the




of cleared Regulation-Up Service MW to the Instructed Regulation-Up Mileage. The

Regulation-Up Mileage Factor shall initially be set equal to 1.0 and shall be updated periodically

pursuant to the Market Protocols.


The price at which a Regulation Qualified Resource or a Regulation-Up Qualified Resource has

agreed to sell Expected Regulation-Up Mileage.

Regulation-Up Offer


committed to sell Regulation-Up.

Regulation-Up Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Up Offers and

Regulation-Up Mileage Offers into the Energy and Operating Reserve Markets.


The provision of Actual Regulation-Up Mileage associated with cleared Regulation-Up Service

MW in response to Regulation Deployment instructions.


The sum of (i) a Resource’s Regulation-Up Mileage Offer multiplied by the Regulation-Up

Mileage Factor and (ii) that Resource’s Regulation-Up Offer.

Reliability Unit Commitment (“RUC”)

The process performed by the Transmission Provider to assess resource and Operating Reserve

adequacy for the Operating Day, commit or de-commit resource as necessary, and communicate

commitment or de-commitment of Resources to the appropriate Market Participants as

necessary.

Reliability Unit Commitment Period (“RUC Commitment Period”)

The contiguous period of time between a Resource’s Reliability Unit Commitment Commit Time

and Reliability Unit Commitment De-Commit Time.

Reported Load

A Market Participant's actual value of energy withdrawn from the Transmission System at a

Settlement Location adjusted as described under Section 8.6.1.1 of Attachment AE and further

adjusted, if necessary, to account for distribution system losses between the actual metering point

and the Transmission System Settlement Location as described under Appendix D of the Market

Protocols.

Reservation Capacity

The reservation Megawatt between a specified source and sink associated with SPP

Transmission Service.

Reserve Sharing Event

A request for assistance to deploy Contingency Reserve by any signatory to the Reserve Sharing

Group Agreement following the sudden loss of a Resource.

Reserve Sharing Group

A group whose members consist of two or more Balancing Authorities that collectively maintain,

allocate, and supply operating reserves required for each Balancing Authority’s use in recovering

from contingencies within the group.

Reserve Sharing Group Agreement

The Agreement detailing the rights and obligations of the Reserve Sharing Group members for

use in recovering from contingencies within the group.

Reserve Zone

A zone containing a specific group of Price Nodes for which a minimum and maximum

Operating Reserve requirement is calculated.

Residual Load

Settlement Area Net Load less all other directly metered Reported Load within the Settlement

Area.

Resource

An asset that injects energy into the transmission grid or reduces the withdrawal of energy from

the transmission grid including a Demand Response Resource, a Variable Energy Resource, a

Dispatchable Resource, External Resource, External Dynamic Resource and a Quick-Start

Resource.

Resource Offer

For a Resource, the combination of its Start-Up Offer, No-Load Offer, Energy Offer Curve,

Regulation-Up Service Offer, Regulation-Down Service Offer, Spinning Reserve Offer,

Supplemental Reserve Offer and Resource physical operating parameters.

1.1 Definitions U

Uninstructed Resource Deviation (“URD”)

The Megawatt amount by which a Resource’s actual output in a Dispatch Interval is above or

below that Resource’s average Setpoint Instruction in the Dispatch Interval.






A. Each Market Participant must offer sufficient Resources to the Day-Ahead Market to

cover its load plus Operating Reserve obligation to the extent its Resources are available.

(1) A Market Participant’s load for purposes of this section shall be equal to that

Market Participant’s maximum hourly Reported Load for the Operating Day.

(2) A Market Participant’s daily Operating Reserve obligation shall be equal to the

sum of that Market Participant’s maximum daily Regulation-Up Service,

Regulation-Down Service and Contingency Reserve obligations as estimated by

the Transmission Provider in accordance with Section 3.1.4(3) of this Attachment

AE.

(3) A Market Participant may satisfy this requirement only by offering Resources

with a commitment status indicating either that the Market Participant is self-

committing the Resource or that the Resource may be committed by the

Transmission Provider, as specified in Section 4.1.(10)(a) and (b) of the

Attachment AE.(4) A Market Participant’s net resource capacity, for purposes

of this section shall include:

i. Offered capacity by Resources identified in Section 2.11.1.A(3) of

Attachment AE less the Operating Reserve obligation identified in Section

2.11.1.A(2) of Attachment AE; and

ii. Firm power purchases less firm power sales. For purposes of this Section

2.11.1 of this Attachment AE firm power purchases and firm power sales

shall mean sales and purchases that are deliverable with transmission

service comparable to Firm Point-To-Point Transmission Service or Firm

Network Integration Transmission Service and the capacity and energy is

supplied under standards of reliability and availability equivalent to

supply of native load customers with the supplier assuming the obligation

to provide both capacity and energy.

B. Market Monitor shall monitor offered Resources, self-committed Resources, firm power

purchases, firm power sales, and Reported Load for the Operating Day.

(1) Market Participants who have offered and/or self-committed 100% of their net

resource capacity, as determined in Section 2.11.1.A(4) of this Attachment AE,

are deemed to be in compliance with the must offer requirement.

(2) Market Participants who have offered and/or self-committed less than 100% of

their net resource capacity, as determined in Section 2.11.1.A(4) of this

Attachment AE, and less than 90% of the Market Participant’s maximum hourly

Reported Load for the Operating Day shall be deemed resource deficient and may

be subject to sanctions as determined in Attachment AF, Section 3.9 of this Tariff.


The Transmission Provider shall calculate Day-Ahead Market and RTBM LMPs

for Energy at each Settlement Location.

The Transmission Provider shall calculate the Reserve Zone Market Clearing

Prices (“MCPs”) for Regulation-Up Service, Regulation-Down Service, Spinning

Reserve and Supplemental Reserve for the Day-Ahead Market and RTBM and Market

Clearing Prices for Expected Regulation-Up Mileage and Expected Regulation-Down

Mileage for the RTBM.

The Transmission Provider shall calculate annual and monthly Auction Clearing

Prices (“ACPs”) at each Settlement Location.

4.1 Offer Submittal

Beginning seven (7) days prior to the Operating Day, Market Participants may

begin to submit Offers for use in the Day-Ahead Market and Offers for use in the RTBM.

Day-Ahead Market Offers may be updated up to 1100 hours Day-Ahead and RTBM

Offers may be updated thirty (30) minutes prior to each Operating Hour. Offer

submittals shall conform to the following:

(1) Offers submitted in the Day-Ahead Market are independent from Offers

submitted in the RTBM except that, if Regulation-Up Service and/or Regulation-

Down Service is cleared in the Day-Ahead Market, submitted Regulation-Up

Mileage Offers and/or Regulation-Down Mileage Offers for the associated

Resources submitted for use in the RTBM must be equal to the Regulation-Up


Resources submitted for use in the Day-Ahead Market;

(2) Market Participants may specify that the Offers submitted in the Day-Ahead

Market also apply in the RTBM;

(a) Such an Offer shall be rejected in the RTBM if the Market Participant has

submitted a Resource commitment status of “not participating” as

described in Section 4.1(10)(e) of this Attachment AE and the Resource is

not participating in the Day-Ahead Market.

(3) Submitted Resource Offers will automatically roll forward hour to hour until

changed within each respective market;

(4) Offers may be submitted that vary for each hour of the Operating Day, except the

Offer parameters related to unit commitment as defined in the Market Protocols

for which a single value is submitted. These unit commitment Offer parameters

will automatically roll forward in each hour until updated;

(5) Offers submitted for use in the RTBM are also used in the RUC;

(6) Resource Offers may only be submitted at Resource Settlement Locations, Import

Interchange Transaction Offers may only be submitted at External Interface

Settlement Locations and Virtual Energy Offers may be submitted at any

Settlement Location, including a Market Hub;

(7) For Regulation Qualified Resources and Regulation-Up Qualified Resources,

Market Participants may submit Regulation-Up Offers, Regulation-Up Mileage

Offers, Spinning Reserve Offers and Supplemental Reserve Offers provided that

if the Regulation-Up Offer is negative, the Regulation-Up Mileage Offer must

equal zero. For Regulation-Down Qualified Resources and Regulation Qualified

Resources, Market Participants may submit Regulation-Down Offers and

Regulation-Down Mileage Offers provided that if the Regulation-Down Offer is

negative, the Regulation-Down Mileage Offer must equal zero. For Spin

Qualified Resources, Market Participants may submit Resource Offers for

Spinning Reserve and Supplemental Reserve. For Supplemental Qualified

Resources, Market Participants may submit Resource Offers for Supplemental

Reserve. Resource qualifications are verified by the Transmission Provider as

part of the registration process as follows:

(a) A Regulation Qualified Resource, Regulation-Up Qualified Resource or

Regulation-Down Qualified Resource must pass a specific regulation test

as defined in Section 2.10.3 of this Attachment AE and must be capable of

deploying one hundred percent (100%) of cleared Regulation-Up and/or

Regulation-Down within the Regulation Response Time for a continuous

duration of sixty (60) minutes and provide telemetered output data that

meets the technical requirements specified in the Market Protocols.

(b) A Spin Qualified Resource must self-certify that the Resource is capable

of deploying one hundred percent (100%) of cleared Spinning Reserve or

cleared Supplemental Reserve within the Contingency Reserve

Deployment Period for a continuous duration of sixty (60) minutes and

provide telemetered output data that meets the technical requirements

specified in the Market Protocols.

(c) A Supplemental Qualified Resource must self-certify that the Resource is

capable of deploying one hundred percent (100%) of cleared

Supplemental Reserve from an off-line state within the Contingency

Reserve Deployment Period for a continuous duration of sixty (60)

minutes and provide telemetered output data that meets the technical

requirements specified in the Market Protocols.

(8) Resource Offers are limited by the Offer caps and floors specified in Section 4.1.1

of this Attachment AE;

(9) The Resource Offer parameters that constitute a valid Offer for use in either the

Day-Ahead Market or RTBM are submitted using the data formats, procedures,

and information defined in the Market Protocols and will include the following

(as further defined in the Market Protocols):

Resource Name

Resource Type

Start-up Offer

No-Load Offer

Energy Offer Curve

Regulation–Up and Regulation-Down Offers

Regulation-Up Mileage and Regulation-Down Mileage Offers

Spinning and Supplemental Reserve Offers

Sync-To-Min and Min-To-Off Times

Start-Up Time

Hot to Intermediate and Hot to Cold Times

Maximum Daily and Weekly Starts

Maximum Daily Energy

Maximum and Minimum Run Times

Minimum Down Time

Minimum Emergency Capacity Operating Limit and Run Time

Minimum Normal, Economic, and Regulation Capacity Operating Limits

Maximum Normal, Economic, and Regulation Capacity Operating Limits

Maximum Emergency Capacity Operating Limits and Run Time

Maximum Quick-Start Response Limit

Ramp-Rate-Up and Ramp-Rate-Down

Turn-Around Ramp Rate Factor

Regulation Ramp Rate

Contingency Reserve Ramp Rate

Resource Status

JOU Ownership Share

(10) Market Participants must specify a Resource commitment status as part of the

Resource Offer using the data formats, procedures, and information defined in the

Market Protocols. Market Participants use the commitment status to indicate;

(a) Whether they are self-committing a Resource;

(b) Whether the Resource may be committed by the Transmission Provider;

(c) Whether the Resource may be committed by the Transmission Provider

only to alleviate an anticipated Emergency Condition or local reliability

issue;

(d) Whether the Resource is on an outage; or

(e) Whether the Resource is not participating in the Day-Ahead Market.

(11) Market Participants must specify a Resource dispatch status as part of the

Resource Offer using the data formats, procedures and information defined in the

Market Protocols. Market Participants use the dispatch status to notify the

Transmission Provider whether the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

(12) Resource limits submitted as part of the Resource Offer must pass the validation

rules defined in the Market Protocols, otherwise, the Resource Offer will be

rejected; and

(13) The Market Participant must comply with the must-offer requirements as defined

in Section 2.11 of this Attachment AE.


Submission of Energy Offer Curves, Start-Up Offers, No-Load Offers, and

Operating Reserve Offers by Market Participants for use in the Day-Ahead Market and

the RTBM shall be limited by the following Offer caps and floors:

(1) Safety-net Energy Offer cap = $1,000/MWh;

(2) Regulation-Up Service Offer cap = $500/MW;

(3) Regulation-Down Service Offer cap = $500/MW;

(4) Contingency Reserve Offer cap = $100/MW;

(5) Energy Offer floor = Negative $500/MWh;

(6) Regulation Service Offer floor = Negative $500/MW;

(7) Regulation-Up Mileage Offer floor = $0/MW;

(8) Regulation-Down Mileage Offer floor = $0/MW;

(9) Contingency Reserve Offer floor = Negative $100/MW;

(10) Start-Up Offer floor = $0;

(11) No-Load Offer floor = $0.

In addition to these Offer caps and floors, submission of Offers may be limited by

the requirements of Attachment AF of this Tariff.


The Transmission Provider will employ a simultaneous co-optimization

methodology to perform the following tasks in order to clear the Day-Ahead Market for

each hour of the upcoming Operating Day:

(1) Commit Offered Resources, Import Interchange Transaction Offers and Virtual

Energy Offers using the SCUC algorithm to meet the Demand Bids, Virtual

Energy Bids, Export Interchange Transactions Bids and Operating Reserve

requirements on a least cost basis for each hour of the upcoming Operating Day.

(a) The Day-Ahead Market SCUC algorithm will initially consider

commitment of Resources not specified for reliability only use as

described in Section 4.1(10)(c) of this Attachment AE, including

Resources committed in the Multi-Day Reliability Assessment, up to the

Resources’ Maximum Economic Capacity Operating Limit or Maximum

Regulation Capacity Operating Limit if selected for Regulation-Up

Service, and down to the Resources’ Minimum Economic Capacity

Operating Limit or Minimum Regulation Capacity Operating Limit if

selected for Regulation-Down Service.

(i) If this capacity is not sufficient to meet the fixed Demand Bids and

fixed Export Interchange Transaction Bids plus Operating Reserve

requirements on a system-wide basis, the Day-Ahead Market

SCUC algorithm will, in priority order: (1) curtail non-firm fixed

Export Interchange Transaction Bids until the capacity shortage is

eliminated; and (2) incorporate capacity up to Resources’

Maximum Emergency Capacity Operating Limits and/or commit

Resources designated as reliability only use, as described in

Section 4.1(10)(c) of this Attachment AE, on an economic basis

until the capacity shortage is eliminated while attempting to

maintain the Regulation-Up requirement to the extent possible .

(ii) If there is a capacity surplus on a system-wide basis calculated as

the sum of self-committed capacity at minimum output, fixed

Import Interchange Transaction Offers and the Regulation-Down

requirement that is in excess of the sum of fixed Demand Bids and

fixed Export Interchange Transaction Bids, the Day-Ahead Market


Import Interchange Transaction Offers until the capacity surplus is

eliminated; and (2) incorporate capacity down to Resources’

Minimum Emergency Capacity Operating Limits until the capacity

surplus is eliminated while attempting to maintain the Regulation-

Down requirement.

(b) To the extent that a particular reliability issue cannot be directly addressed

within the Day-Ahead Market SCUC algorithm as described under

Subsections (i) and (ii) above, the Transmission Provider may manually

commit Resources to alleviate such reliability issues. The Transmission

Provider will re-run the Day-Ahead SCUC algorithm after such manual

commitments, time permitting, and will notify the Market Participants that

units were manually committed.

(2) Using the Resource commitment results from the SCUC, clear Resource Offers,

Virtual Energy Offers and Import Interchange Transaction Offers to meet

Demand Bids, Virtual Energy Bids, Export Interchange Transaction Bids and

Operating Reserve requirements on a least cost basis for each hour of the

upcoming Operating Day using the SCED algorithm.

(a) The SCED algorithm includes marginal loss sensitivity factors that

approximate the change in marginal system losses for a change in Energy

dispatch.

(b) In certain situations, enforcing constraints may result in a solution that is

not feasible at a Shadow Price less than an appropriately priced VRL. In

such cases, the Transmission Provider must apply VRLs in SCED as

described in Section 8.3.2 of this Attachment AE.

(c) The SCED algorithm will include product substitution logic as follows to

clear Operating Reserve Offers:

(i) Any Regulation-Up Offers remaining once the Regulation-Up

Requirement is satisfied may be used to meet Contingency Reserve

requirements if Regulation-Up Offer is more economic or is

required to meet the overall Operating Reserve requirement;

(ii) Any Spinning Reserve Offers remaining once the Spinning

Reserve Requirement is satisfied may be used to meet

Supplemental Reserve requirements if Spinning Reserve Offer is

more economic or is required to meet the overall Operating

Reserve requirement; and

(iii) The product substitution logic ensures that the MCP for

Regulation-Up Service is always greater than or equal to the

Spinning Reserve MCP and that the Spinning Reserve MCP is

always greater than or equal to the Supplemental Reserve MCP.

(d) Use of co-optimization logic will provide, through the Shadow Price

calculation, MCPs for Operating Reserve that include any lost opportunity

costs incurred as a result of Operating Reserve clearing.

5.1.2.1 Clearing During Capacity Shortage

(1) In the event of an Operating Reserve shortage in any hour that is not due to ramp

limitations, Scarcity Pricing shall be implemented.

(2) In the event of a capacity shortage to meet the fixed Demand Bids and fixed firm

Export Interchange Transactions in any hour, the fixed Demand Bids and fixed

firm Export Interchange Transactions will be reduced on a pro-rata reduction

basis based on the fixed MW amounts to match the available capacity and

Scarcity Pricing shall be implemented.

(3) The Transmission Provider may implement sharing of ramping capability

between Energy and Operating Reserve product clearing to ensure, to the extent

possible, that short-term ramping deficiencies from hour to hour do not initiate

Scarcity Pricing as described in Section 8.3.4.2(2) of this Attachment AE. To the

extent that ramp sharing is implemented, it shall remain in effect in all hours of

the Day-Ahead Market, in order to clear sufficient amounts of Energy,

Regulation-Up Service and Spinning Reserve to meet the requirements. The

Transmission Provider will not implement ramp sharing that will result in the

inability to meet applicable NERC reliability standards and control performance

requirements.

(4) If a transmission constraint cannot be relieved due to a shortage of capacity in any

hour, the SCED algorithm will clear the bid-in demands on a pro-rata basis based

upon the impact on relieving the constraint.

5.1.2.2 Clearing During Excess Generation Conditions

In the event the sum of the Minimum Emergency Capacity Operating Limits on

self-committed Resources plus the Regulation-Down requirement is in excess of the

cleared bid-in demands in any hour, the SCED algorithm will reduce Resources on a pro-

rata reduction basis such that the resulting sum of minimum limits matches the bid-in

demand. LMPs will be set by the Offer prices associated with Energy down to the

Minimum Emergency Capacity Operating Limit to the extent that the Regulation-Down

requirement can be maintained. If the actions under Section 5.1.2(1)(a)(ii) above create a

Regulation-Down Service shortage during any hour either on a system-wide basis or

Reserve Zone basis, the MCPs for Regulation-Down Service will reflect Scarcity Prices

and LMPs will reflect negative Scarcity Prices as set by the Regulation-Down Service

Demand Curve price described under Section 8.3.4.2 of this Attachment AE.


No later than 1600 hours Day-Ahead, the Transmission Provider will notify each

Market Participant of the Day-Ahead Market results for each hour of the Operating Day.

The following results are communicated to each Market Participant for only its

specific Resources:

(1) Cleared Resource Offers for Energy, Regulation-Up Service, Regulation-Down

Service, Spinning Reserve or Supplemental Reserve;

(a) Cleared Offers for Energy associated with Resource Offers represent a

physical Resource commitment.

(b) Resources committed by the Transmission Provider in the Day-Ahead

Market that incur one or more start-up costs within the Operating Day as a

result of the Transmission Provider Day-Ahead Market commitment are

guaranteed to receive revenues that are at least equal to the Resource Offer

costs for the cleared amount of Energy, Regulation-Up Service,

Regulation-Down Service, Spinning Reserve or Supplemental Reserve for

that Resource.

(2) Cleared Virtual Energy Offers;

(3) Cleared Import Interchange Transaction Offers;

(4) Cleared Demand Bids;

(5) Cleared Virtual Energy Bids;

(6) Cleared Export Interchange Transaction Bids; and

(7) Cleared Through Interchange Transactions.

The following results are communicated to all Market Participants:

(1) LMPs for each Settlement Location, the marginal Energy component (“MEC”) of

the LMP, the Marginal Congestion Component (“MCC”) of the LMP and the

Marginal Loss Component (“MLC”) of the LMP for each Settlement Location;

and

(2) MCPs for Regulation-Up Service, Regulation-Down Service, Spinning Reserve

and Supplemental Reserve for each Reserve Zone.


The Transmission Provider will perform a capacity adequacy analysis for the

upcoming Operating Day using the SCUC algorithm with the objective of committing

Resources to meet the Transmission Provider load forecast and Operating Reserve

requirements over the Operating Day such that commitment costs are minimized while

adhering to Transmission System security constraints and the Resource operating

parameter constraints submitted as part of the RTBM Offers.

(1) Commitment costs used in the SCUC are defined as Start-Up Offer, No-Load

Offer and incremental cost to operate at minimum output as defined in the

submitted Energy Offer Curve.

(2) The SCUC algorithm will initially consider commitment of Resources not

specified for reliability only use as described in Section 4.1(10)(c) of this

Attachment AE, up to the Resources’ Maximum Economic Capacity Operating

Limit or Maximum Regulation Capacity Operating Limit if selected for

Regulation-Up Service, and down to the Resources’ Minimum Economic

Capacity Operating Limit or Minimum Regulation Capacity Operating Limit if


(a) If this capacity is not sufficient on a system-wide basis to meet the

Transmission Provider load forecast plus Operating Reserve requirements,

the SCUC algorithm will, in priority order: (1) Curtail non-firm fixed


eliminated; and (2) Incorporate capacity up to Resources’ Maximum

Emergency Capacity Operating Limits and/or commit Resources

designated as reliability only use, as described in Section 4.1(10)(c) of this

Attachment AE, on an economic basis until the capacity shortage is

eliminated while attempting to maintain the Regulation-Up requirement.

(b) If there is a capacity surplus on a system-wide basis calculated as the sum

of self-committed capacity at minimum output, fixed Import Interchange

Transaction Offers and the Regulation-Down requirement that is in excess

of the sum of the Transmission Provider load forecast and fixed Export

Interchange Transaction Bids, the SCUC algorithm will, in priority order:

(1) curtail non-firm fixed Import Interchange Transaction Offers until the

capacity surplus is eliminated; (2) incorporate capacity down to

Resources’ Minimum Emergency Capacity Operating Limits until the

capacity surplus is eliminated while attempting to maintain the

Regulation-Down requirement; (3) de-commit Resources that were

committed by the Transmission Provider in the Day-Ahead Market that

were not self-committed until the capacity surplus is eliminated; and (4)

de-commit self-committed Resources until the capacity surplus is

eliminated.

(3) To the extent that a particular Transmission System security constraint cannot be

directly addressed within the SCUC algorithm, the Transmission Provider may

manually commit Resources and/or decommit Resources, including self-

committed Resources to alleviate such a Transmission System security constraint

in accordance with its authority as Reliability Coordinator.

(a) A reliability issue may arise within the operating area of a local

transmission operator during the Day-Ahead Reliability Unit Commitment

process. Such reliability issues may require out of merit commitment,

decommitment, or dispatch instructions to be issued to one or more

Resources to resolve the reliability issue. In such cases, the local

transmission operator shall request the Transmission Provider to issue

such instructions. To the extent that the Transmission Provider, at the

request of a local transmission operator, issues instructions to a Resource

to address a reliability issue, such Resource shall be eligible for

compensation in the same manner as any other Resource. Recovery of

such compensation shall be collected regionally as described under

Section 8.6.7(A) of this Attachment AE, unless the Transmission Provider

determines that the instructions were required for a Local Reliability

Issue; in such case recovery of such compensation shall be collected

locally as described under Section 8.6.7(B) of this Attachment AE.


Using the inputs described in Section 6.1.1, the Transmission Provider will

perform a capacity adequacy analysis using the SCUC algorithm with the objective of

committing Resources to meet the Transmission Provider’s load forecast and Operating

Reserve requirements over the Operating Day such that commitment costs are minimized

while adhering to Transmission System security constraints and the resource operating



Offer and incremental cost to operate at minimum output as defined on the

submitted Energy Offer Curve. Incremental Energy costs above minimum output

and Operating Reserve Offers are not considered by the SCUC in making

commitment decisions.



Attachment AE, only including capacity up to the Resources’ Maximum

Economic Capacity Operating Limits (or Maximum Regulation Capacity

Operating Limits if selected for Regulation-Up Service) and down to the

Resources’ Minimum Economic Capacity Operating Limits (or Minimum

Regulation Capacity Operating Limits if selected for Regulation-Down Service).


Transmission Provider’s load forecast plus Operating Reserve

requirements, the SCUC algorithm will, in priority order: (1) Curtail non-

firm fixed Export Interchange Transaction Bids until the capacity shortage

is eliminated; and (2) Incorporate capacity up to Resources’ Maximum





(b) If there is a system-wide capacity surplus calculated as the sum of self-

committed capacity at minimum output, fixed Import Interchange



Interchange Transaction Bids, the Day-Ahead Market SCUC algorithm

will, in priority order: (1) Curtail non-firm fixed Import Interchange

Transaction Offers until the capacity surplus is eliminated; (2) Incorporate

capacity down to Resources’ Minimum Emergency Capacity Operating

Limits until the capacity surplus is eliminated while attempting to

maintain the Regulation-Down requirement; (3) De-commit Resources

that were committed by the Transmission Provider in the Day-Ahead

Market that were not self-committed until the capacity surplus is

eliminated; and (4) De-commit self-committed Resources until the

capacity surplus is eliminated.

(3) To the extent that a particular reliability issue cannot be directly addressed within

the SCUC algorithm as described under subsections (a) and (b) above, the

Transmission Provider or local transmission operator may manually commit

Resources and/or decommit Resources, including self-committed Resources to

alleviate such reliability issues.

(4) A Local Reliability Issue may arise within the operating area of a local

transmission operator during the Intra-Day Reliability Unit Commitment Process.

Such Local Reliability Issues may require out of merit commitment,

decommitment, or dispatch instructions to be issued to one or more Resources to

resolve the Local Reliability Issue. Time permitting, the local transmission

operator shall request the Transmission Provider to issue such instructions. To

the extent time does not permit, the local transmission operator may issue such

instructions to the Resource. In such cases, the following shall take place:

(a) If initial instructions are issued by a local transmission operator, the

transmission operator shall notify the Transmission Provider of the

instructions given to the Resource.

(b) The transmission operator and Transmission Provider will coordinate to

ensure subsequent instructions are provided by the Transmission Provider.

(c) The transmission operator shall log such instructions, and shall notify the

Transmission Provider of such action. The Transmission Provider shall

log such instructions as manual commitment, decommitment, or OOME

Dispatch instruction, as appropriate, as if it gave such instruction to the

Resource.

(d) The Resource shall be eligible to receive the compensation for such

instructions in the same manner as if it had been committed by the

Transmission Provider; provided that the Transmission Provider

determines that the Resource selected in response to such instructions was

selected in a non-discriminatory manner. Such determination shall be

made using the standards and procedures set forth in Section 6.1.2.1 of

this Attachment AE. If the Transmission Provider determines that

instructions were issued to resolve a Local Reliability Issue, recovery of

such compensation shall be collected locally as described under Section

8.6.7(B) of this Attachment AE.

(5) In the event that the local transmission operator issues instructions to a Resource

to resolve an issue other than a Local Reliability Issue, the Resource will be

compensated in the same manner as if it had been committed by the Transmission

Provider; provided that the Transmission Provider determines that the Resource

selected in response to such instructions was selected in a non-discriminatory

manner. Such determination shall be made using the standards and procedures

set forth in Section 6.1.2.1 of this Attachment AE. Recovery of such compensation

shall be collected regionally as described under Section 8.6.7(A) of this

Attachment AE.

(6) In the event that the Transmission Provider issues instructions to a Resource at

the request of a local transmission operator to resolve a Local Reliability Issue,

the Resource will be compensated in the same manner as if it had been committed

by the Transmission Provider. Recovery of such compensation shall be collected



the request of a local transmission operator to resolve an issue other than a Local

Reliability Issue, the Resource will be compensated in the same manner as if it

had been committed by the Transmission Provider. Recovery of such

compensation shall be collected regionally as described under Section 8.6.7(A) of

this Attachment AE.

6.1.2.1 Determination of Non-Discriminatory Resource Selection by a Local

Transmission Operator

The Transmission Provider shall verify that the process used by the local

transmission operator to select Resources in the Intra-Day Reliability Unit

Commitment process in response to a reliability issue was performed in a non-

discriminatory manner. Such verification shall be performed as follows:

(i) The Transmission Provider’s evaluation of whether the selection process

was non-discriminatory shall consider the cost, ownership, resource

operating parameters, availability of non-selected Resources relative to the

selected Resources and any prior instances where the local transmission

operator committed Resources.

(ii) When the Transmission Provider determines that a Resource was selected

in a discriminatory manner, the Transmission Provider shall notify the

local transmission operator of the best practice should the situation arise

again.


Inputs into the RTBM will include the data provided prior to each Operating Hour

and data provided within each Operating Hour.

6.2.1.1 Pre-Operating Hour Inputs

Pre-Operating hour inputs to the RTBM will include the following:

(1) RTBM Resource Offers;

(2) Approved and tagged Export Interchange Transactions, Import Interchange

Transactions and Through Interchange Transactions;

(3) Operating Reserve requirements (system-wide and Reserve Zone minimum and

maximum);

(4) Resources selected to provide Regulation-Up Service or Regulation-Down

Service from the most recent RUC. This set of Resources will remain on

regulation control for the Operating Hour and will be used by SCED to clear

Regulation-Up and Regulation-Down on a five (5) minute basis to meet the

regulation requirements;

(5) Resource commitment from the Current Operating Plan. The Current Operating

Plan includes Resource commitments and Resource de-commitments from the

Multi-Day Reliability Assessment, Day-Ahead Market, Day-Ahead RUC and

Intra-Day RUC;

(6) Maximum Emergency Capacity Operating Limits on Resources identified in the

Day-Ahead RUC or Intra-Day RUC; and

(7) Minimum Emergency Capacity Operating Limits on Resources identified in the

Day-Ahead RUC or Intra-Day RUC.

6.2.1.2 Intra-Operating Hour Inputs

Intra-operating hour inputs to the RTBM will include the following:

(1) Latest State Estimator solution for:

(a) Distribution of load forecast throughout the Network Model;

(b) Latest transmission topology for the Network Model; and

(c) Backup initial Energy injection of Resources if SCADA not available;

(2) Actual Resource output from latest SCADA snapshot to determine initial Energy

injection of Resources and Generator outages;

(3) Active transmission constraints;

(4) Intra-operating hour adjustments to Interchange Transactions due to curtailments

or initiation of a Reserve Sharing Event involving external Balancing Authorities;

(5) Intra-operating hour adjustments to Resource Offer physical operating parameters

due to changes in a Resource’s capability. Market Participants shall notify the

Transmission Provider of a change in a Resource Offer physical operating

parameter during an Operating Hour. For the current Operating Hour the

Transmission Provider will make the requested modification to the Resource

Offer physical operating parameter. For subsequent hours the Market Participant

shall remain responsible for accurately reflecting Resource operating parameters

in its Resource Offer submissions;

(6) Intra-hour adjustments to selection of Resources to provide Regulation-Up

Service or Regulation-Down Service to the extent that Resources selected as

described under Section 6.2.1.1(4) become unavailable to provide regulation

service;

(7) Transmission Provider load forecast;

(8) The Transmission Provider’s wind Resource MWh output forecast; and

(9) The Transmission Provider’s estimate of Parallel Flows.


The Transmission Provider will execute the RTBM every five (5) minutes for the

next Dispatch Interval based on the inputs described above.

(1) A simultaneous co-optimization methodology utilizing a SCED algorithm is

employed to calculate Resource Dispatch Instructions and clear Regulation-Up

Service, Regulation Down Service, Spinning Reserve and Supplemental Reserve

to meet the Transmission Provider load forecast and Operating Reserve

requirements at minimum costs based upon submitted Offers while respecting

Resource operating constraints and transmission constraints.

(2) The SCED algorithm includes marginal loss sensitivity factors that approximate

the change in marginal system losses for a change in Energy dispatch.

(3) In certain situations, enforcing constraints may result in a solution that is not

feasible at a Shadow Price less than an appropriately priced VRL. In such cases,

the Transmission Provider must apply VRLs in SCED.

(4) To ensure rational pricing of cleared Operating Reserve products, the SCED

algorithm will include product substitution logic as follows:

(a) Any Regulation-Up Offers remaining once the Regulation-Up

Requirement is satisfied will be used to meet Contingency Reserve

requirements if Regulation-Up Offer is more economic or is needed to

meet the overall Operating Reserve requirement;

(b) Any Spinning Reserve Offers remaining once the Spinning Reserve

Requirement is satisfied will be used to meet the Supplemental Reserve

requirements if the Spinning Reserve Offer is more economic or is needed

to meet the overall Operating Reserve requirement.

(5) The co-optimization logic will provide through the Shadow Price calculation,

MCPs for Operating Reserve that include lost opportunity costs incurred as a

result of Operating Reserve clearing.

(6) Additionally, the Transmission Provider will execute a look-ahead SCED prior to

the RTBM SCED process. The look-ahead SCED will perform at least these two

functions: (1) anticipate the need to adjust Dispatch Instructions for the current

Dispatch Interval to prepare to meet forecasted changes in the load several

Dispatch Intervals into the future and (2) determine commitment of Quick-Start

Resources within the Operating Hour. The look-ahead period is at least two

Dispatch Intervals, one of which is the next Dispatch Interval following the

current Dispatch Interval.

6.2.2.1 Emergency Operations – Capacity Shortage

(1) In addition to the incorporation of the capacity up to Resources’ Maximum

Emergency Capacity Operating Limits prior to the Operating Hour as described

under Sections 5.1.2(1)(a)(i) and 5.2.2(2)(a) of this Attachment AE, the

Transmission Provider may incorporate any remaining emergency capacity limits

as needed during the Operating Hour. The Transmission Provider shall continue

implementation of emergency procedures which may have been implemented

prior to the Operating Hour or shall begin implementation of emergency

procedures within the Operating Hour, as needed, in accordance with its authority

as Reliability Coordinator.

(a) If there is an actual Operating Reserve shortage during a Dispatch Interval,

either on a system-wide or a Reserve Zone basis, the system-wide or

Reserve Zone Scarcity Prices will be implemented as specified in Sections

8.3.1 and 8.3.4.2 of this Attachment AE.

(b) If there is a shortage of available capacity to meet Energy requirements on

a system-wide, LMPs will be set through Scarcity Pricing procedures as

specified in Section 8.3.1 of this Attachment AE.

(2) Ramp sharing will continue to be applied consistent with its application in the

Day-Ahead Market as described under Section 5.1.2.1(3) of this Attachment AE.

6.2.2.2 Emergency Operations – Excess Generation

(1) The Transmission Provider will take any or all of the following actions, as time

permits, within the Operating Hour to address excess generation conditions on

either a system-wide or Reserve Zone basis:

(a) Notify any remaining Resources not cleared for Regulation-Down Service

and not notified prior to the Operating Hour that they will be dispatched

down to their Minimum Emergency Capacity Operating Limits;

(b) De-commit any remaining Resources that were self-committed following

the Day-Ahead RUC;

(c) Pro-rata curtail, on a MW basis, any remaining fixed non-firm Import

Interchange Transactions;

(d) Pro-rata curtail, on a per MW basis, any fixed firm Import Interchange

Transactions;

(e) Reduce Resources with cleared Regulation-Down Service economically,

as needed, down to Minimum Emergency Capacity Operating Limit; and

(f) Coordinate with generation Operators, SPP Balancing Authority Operator

and SPP Reliability Coordinator to de-commit generation to meet power

balance.

(2) If actions taken under (1) above are not sufficient to relieve the excess generation

condition in any Dispatch Interval either on a system-wide or Reserve Zone basis,

LMPs will be set to the lesser of zero (0) or the Offer prices associated with

Energy down to the Minimum Emergency Capacity Operating Limit, to the extent

that the Regulation-Down requirement can be maintained. If the actions under (1)

above create a Regulation-Down Service shortage during any Dispatch Interval

either on a system-wide or Reserve Zone basis, the MCPs for Regulation-Down

Service will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices.

(3) In parallel with the actions under (1) above, if there is a transmission constraint

within a Reserve Zone occurring simultaneously with a Reserve Zone excess

capacity event, the Transmission Provider may take any or all of the following

additional actions:

(a) Identify and communicate with the Market Participant concerning

Resources with greater than a five percent (5%) generation shift factor on

the constraint and fixed Import Interchange Transactions with greater than

a three percent (3%) transfer distribution factor on constraint;

(b) Issue Transmission Loading Relief (“TLR”) provisions, in accordance

with Attachment R, to curtail any Interchange Transactions that may be

contributing to the loading;

(c) Commit Quick Start Resources in the constrained area if they can be re-

dispatched with other Resources in the constrained area to relieve

constraint without contributing to the excess capacity situation.

6.2.2.3 Seams Coordination

The Transmission Provider shall use the following process to coordinate the

operations of the RTBM to manage congestion between the SPP Balancing Authority

Area and external Balancing Authority Areas:

(a) The Transmission Provider shall submit the Market Flow impact on each

Coordinated Flowgate and Reciprocal Coordinated Flowgate to the NERC

IDC.

(b) The Transmission Provider shall assign curtailment priorities to the

Market Flow on each flowgate in the following priority categories:

(i) Curtailment priorities for flowgates that have not been defined as a

Coordinated Flowgate or a Reciprocal Coordinated Flowgate shall

be assigned in accordance with NERC TLR procedures.

(ii) For Coordinated Flowgates, the Transmission Provider will assign

Market Flow in the firm priority up to the firm limit with any

excess Market Flow assigned as non-firm network.

(iii) For Reciprocal Coordinated Flowgates, the Transmission Provider

will divide its Market Flows into firm, non-firm network, and non-

firm hourly curtailment priorities. The Transmission Provider will

first assign Market Flow in the firm priority up to the firm limit,

then assign remaining Market Flow in the non-firm network

priority up to the non-firm network limit, and finally assign any

excess Market Flow as non-firm hourly.

(c) The Market Flow associated with operation of the RTBM shall be

determined by the Transmission Provider. For Coordinated Flowgates,

any Market Flow from RTBM operation in excess of that assigned to the

firm priority shall be assigned a non-firm priority. For Reciprocal

Coordinated Flowgates, any Market Flow from RTBM operation in

excess of amounts assigned to firm or non-firm network priorities shall be

assigned a non-firm hourly priority.

(d) When congestion occurs on a flowgate that requires a TLR event, the

NERC IDC will identify the amount of relief required from Market Flows

on the Coordinated Flowgate or Reciprocal Coordinated Flowgate.

(e) The Transmission Provider shall achieve the required reduction in Market

Flows provided by the NERC IDC using its security constrained dispatch

software in the following order until the desired reduction in Market

Flows is achieved:

(i) To the extent that Market Flows are contributing to the constrained

condition, the Transmission Provider shall restrict the ability of the

market operating system from contributing further to the

constrained condition by binding the Coordinated Flowgate or

Reciprocal Coordinated Flowgate constraint. The security

constrained dispatch of Dispatchable Resources shall continue

within each priority level until the Market Flows within that

priority level have been reduced to zero or the flowgate constraint

is eliminated, whichever comes first.


Following execution of the RTBM SCED, the Transmission Provider shall

communicate the results to Market Participants prior to the start of the applicable

Dispatch Interval.

(1) The following results are communicated to each Market Participant for only its

specific Resources:

(a) Resource Dispatch Instructions. The Dispatch Instruction is a MW output

target for the end of the applicable Dispatch Interval.

(b) Cleared Regulation-Up Service, Regulation-Down Service, Spinning

Reserve and Supplemental Reserve MW by Resource.

(2) The following results are communicated to all Market Participants and are used

for settlement purposes;

(a) LMPs for each Settlement Location, the MCC of LMP for each Settlement

Location and the MLC of LMP for each Settlement Location.

(b) MCPs for Regulation-Up Service, Expected Regulation-Up Mileage,

Regulation-Down Service, Expected Regulation-Down Mileage, Spinning

Reserve and Supplemental Reserve for each Reserve Zone.


The Transmission Provider will deploy Energy, Regulation-Up Service,

Regulation-Down Service, Spinning Reserve and on-line Supplemental Reserve

simultaneously through the issuance of Setpoint Instructions to each Resource in

accordance with the technical requirements specified in the Market Protocols.

Deployment of Supplemental Reserve from off-line Quick-Start Resources is

accomplished through the Transmission Provider issuance of a Commitment Instruction

to start-up following a Contingency Reserve event.

(1) The Setpoint Instruction for a Resource that has indicated that it is dispatchable is

equal to the sum of:

(a) The Resource MW Dispatch Instruction for the current Dispatch Interval

either as developed by SCED or by Manual Dispatch Instruction;

(b) Regulation-Up Service deployment instruction for Resources with cleared

Regulation-Up Service;

(c) Regulation-Down Service deployment instruction for Resources with

cleared Regulation-Down Service;

(d) Spinning Reserve deployment instruction for Resources with cleared

Spinning Reserve; and

(e) On-Line Supplemental Reserve deployment instruction for Resources with

cleared on-line Supplemental Reserve.

(2) The Setpoint Instruction for a Resource that has indicated that it is non-

dispatchable shall be equal to the most recently recorded actual telemetered

Resource output.


Regulation Deployment is limited to Resources that have cleared Regulation-Up

Service or Regulation-Down Service. Regulation-Up Service and Regulation-Down

Service are deployed on specific Resources through Setpoint Instructions via the

automatic generation control system on a pro-rata basis based upon Regulation-Up

Service or Regulation-Down Service cleared MW, adjusted as needed to ensure

deliverability. No Regulation Deployment will occur on Resources that have not cleared

Regulation-Up Service or Regulation-Down Service. Market Participants providing

Regulation-Up Service or Regulation-Down Service during the Operating Hour are

obligated to report to the Transmission Provider when their Resources are no longer

capable of providing the service due to physical problems.


In any Dispatch Interval, if the URD of a Resource with cleared Regulation-Up

Service, Regulation-Down Service or both is outside of the Resource’s Operating

Tolerance, that Market Participant will incur a Regulation Deployment failure charge as



The MCP represents the cost of supplying an increment of Operating Reserve,

taking into account lost opportunity cost and is composed of the marginal Operating

Reserve costs and marginal costs associated with Operating Reserve scarcity. The Day-

Ahead Market and RTBM MCPs at a Reserve Zone for Resources with cleared

Regulation-Up Service, Regulation-Down Service, Spinning Reserve and/or

Supplemental Reserve in that Reserve Zone are equal to the summation of the applicable

Shadow Prices associated with the constraints as described in subsections (1) and (2)

below. Calculation of MCPs for Expected Regulation-Up Mileage and Expected

Regulation-Down Mileage are calculated as described in subsections (3) and (4) below:

(1) There are four sets of constraints which apply on both a system-wide basis and a

Reserve Zone basis:

(a) A contingency reserve plus regulation-up constraint is equal to the sum of

the Contingency Reserve requirement and the Regulation-Up requirement;

(b) A regulation-up plus spinning reserve constraint is equal to the sum of the

Regulation-Up requirement and the Spinning Reserve requirement;

(c) A regulation-up constraint is equal to the Regulation-Up requirement; and

(d) A regulation-down constraint is equal to the Regulation-Down

requirement.

(2) Operating Reserve MCPs for each Reserve Zone are calculated as follows:

(a) The Regulation-Up Service MCP is equal to sum of the Shadow Prices for

the system-wide and zonal regulation-up constraints, system-wide and

zonal regulation-up plus spinning reserve constraints and the system-wide

and zonal contingency reserve plus regulation-up constraints;

(b) The Spinning Reserve MCP is equal to the sum of the Shadow Prices for

the system-wide and zonal regulation-up plus spinning reserve constraints

and the system-wide and zonal contingency reserve plus regulation-up

constraints;

(c) The Supplemental Reserve MCP is equal to the sum of the Shadow Prices

for the system-wide and zonal contingency reserve plus regulation-up

constraints; and

(d) The Regulation-Down Service MCP is equal to the Shadow Price for the

system-wide and zonal regulation-down constraint.

(3) RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest

Regulation-Up Mileage Offer of all Resources economically cleared to provide

Regulation-Up Service in a particular Dispatch Interval, multiplied by the

Regulation-Up Mileage Factor. For Resources submitting a Regulation-Up

Service dispatch status as described under Section 4.1(11)(c) of this Attachment

AE, the cleared amount of Regulation-Up Service MW must be greater than the

submitted self-schedule MW in order to be considered economically cleared;

(4) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest

Regulation-Down Mileage Offer of all Resources economically cleared to provide

Regulation-Down Service in a particular Dispatch Interval, multiplied by the

Regulation-Down Mileage Factor. For Resources submitting a Regulation-Down


AE, the cleared amount of Regulation-Down Service MW must be greater than

the submitted self-schedule MW in order to be considered economically cleared;

(5) In the event a system-wide failure of the RTBM systems results in a loss of the

ability to calculate MCPs, RTBM Operating Reserve will continue to be settled

financially under this Tariff based upon estimated MCPs. The Transmission

Provider shall notify Market Participants if RTBM Operating Reserve is to be

settled using estimated prices.

(a) If the failure of the RTBM systems occurs for twelve (12) Dispatch

Intervals or less, the estimated MCPs shall be the most recently calculated

MCPs for each affected Reserve Zone and shall be utilized for settlement

purposes for each of the Dispatch Intervals in which MCP pricing data is

missing.

(b) If the failure of the RTBM systems occurs for more than twelve (12)

Dispatch Intervals, the Transmission Provider shall calculate MCPs using

mitigated Offers for the RTBM in a manner that reflects, as closely as

practicable, the MCPs that would have resulted but for the RTBM systems

failure, and shall use such MCPs for settlement purposes for each of the

Dispatch Intervals in which MCP pricing data is missing. To the extent

that the Transmission Provider is unable to calculate RTBM MCPs, the

Transmission Provide shall use the MCPs generated in the Day-Ahead

Market for RTBM settlement.

(6) If for any reason a portion of generation and load within the SPP Balancing

Authority Area becomes isolated from the rest of the SPP Balancing Authority

Area (“Island”), RTBM MCPs will not be calculated and procurement of

Operating Reserve within the Island will not be performed.

8.3.4.1 Impact of Violation Relaxation Limits on Market Clearing Prices

When the Shadow Price of the regulation-up plus spinning reserve constraint is

exceeded, the Spinning Reserve requirement will be relaxed such that the Shadow Price

of the regulation-up plus spinning reserve constraint is less than or equal to the

regulation-up plus spinning reserve constraint VRL value.

8.3.4.2 Impact of Scarcity Pricing on Market Clearing Prices

(1) The Transmission Provider shall use Demand Curves to limit Shadow Prices of

the Operating Reserve constraints described under Section 8.3.4 of this

Attachment AE in both the Day-Ahead Market and RTBM during times of

Operating Reserve shortages, either on a system-wide and/or Reserve Zone basis.

(2) Operating Reserve shortages caused by insufficient ramping capability shall not

be subject to Scarcity Pricing.

(3) Shadow Prices are limited using the following Demand Curves that apply on a

system-wide and Reserve Zone basis as follows:

(a) Operating Reserve Demand Curve – Shadow Prices of the system-wide

and/or zonal Contingency Reserve plus Regulation-Up constraint are

limited to the sum of the safety-net Energy Offer cap and the Contingency

Reserve Offer cap as specified in Section 4.1.1 of this Attachment AE.

(b) Regulation-Up Demand Curve – Shadow Prices of the system-wide

Regulation-Up constraint are limited to the sum of the Regulation-Up

Service Offer cap and the Contingency Reserve Offer cap as specified in

Section 4.1.1 of this Attachment AE.

(c) Regulation-Down Demand Curve – Shadow Prices of the system-wide

Regulation-Up constraint are limited to the sum of the Regulation-Down




A Day-Ahead Market payment for cleared Regulation-Up Service and cleared

Regulation-Down Service will be calculated at each Settlement Location for each Asset

Owner for each hour as follows:

(1) Regulation-Up Service

Day-Ahead Regulation-Up Service Hourly Amount =

[(Day-Ahead MCP) * (Day-Ahead Cleared Regulation-Up Service Hourly

Quantity)] * (-1)

(a) Day-Ahead MCP, as defined under Section 1 of this Attachment AE, for

Regulation-Up Service associated with the Reserve Zone in which the

applicable Resource is located.

(b) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service Hourly

Quantity is the MW quantity associated with cleared Regulation-Up

Service Offers as described under Section 5.1.3 of this Attachment AE.

(2) Regulation-Down Service

Day-Ahead Regulation-Down Service Hourly Amount =

[(Day-Ahead MCP) * (Day-Ahead Cleared Regulation-Down Service Hourly

Quantity)] * (-1)


Regulation-Down Service associated with the Reserve Zone in which the


(b) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service Hourly

Quantity is the MW quantity associated with cleared Regulation-Down



A Day-Ahead Market charge for Regulation-Up Service procurement costs

calculated under Section 8.5.2(1) will be calculated at each Reserve Zone for each Asset


Day-Ahead Regulation-Up Service Hourly Distribution Amount =

[(Day-Ahead Regulation-Up Service Obligation) * (Day-Ahead Regulation-Up

Procurement Rate)]

(1) An Asset Owner’s Day-Ahead Regulation-Up Service Obligation in each Reserve

Zone is equal to the system wide total of all cleared Regulation-Up Service

multiplied by the Asset Owner Reserve Zone Load Ratio Share, adjusted up or

down to account for any Bilateral Settlement Schedules for Regulation-Up

Service.

(2) For a Reserve Zone that clears more Regulation-Up Service than the sum of Asset

Owners’ Day-Ahead Regulation-Up Service Obligations for that Reserve Zone,

the zone is deemed an exporting zone and the Day-Ahead Regulation-Up Service

Procurement Rate is equal to the Regulation-Up Service MCP for that Reserve

Zone.

(3) For a Reserve Zone that clears less Regulation-Up Service than the sum of Asset


the Day-Ahead Regulation-Up Service Procurement Rate is as follows:

Day-Ahead Regulation-Up Service Procurement Rate =

{(Reserve Zone Regulation-Up Service MCP * Total of cleared

Regulation-Up Service for that Reserve Zone) + [(Weighted Average

Regulation-Up Service MCP of all Exporting Zones) * (Sum of Asset

Owners’ Day-Ahead Regulation-Up Service Obligations for that Reserve

Zone - Total of cleared Regulation-Up Service for that Reserve Zone)]} /

(Sum of Asset Owners’ Day-Ahead Regulation-Up Service Obligations

for that Reserve Zone).


A Day-Ahead Market charge for Regulation-Down Service procurement costs



Day-Ahead Regulation-Down Service Hourly Distribution Amount =

[(Day-Ahead Regulation-Down Service Obligation) * (Day-Ahead Regulation-

Down Service Procurement Rate)]

(1) An Asset Owner’s Day-Ahead Regulation-Down Service Obligation in each

Reserve Zone is equal to the system wide total of all cleared Regulation-Down

Service multiplied by the Asset Owner Reserve Zone Load Ratio Share, adjusted

up or down to account for any Bilateral Settlement Schedules for Regulation-

Down.

(2) For a Reserve Zone that clears more Regulation-Down Service than the sum of

Asset Owners’ Day-Ahead Regulation-Down Service Obligations for that Reserve

Zone, the zone is deemed an exporting zone and the Day-Ahead Regulation-

Down Service Procurement Rate is equal to the Regulation-Down Service MCP

for that Reserve Zone.

(3) For a Reserve Zone that clears less Regulation-Down Service than the sum of


Zone, the Day-Ahead Regulation-Down Service Procurement Rate is as follows:

Day-Ahead Regulation-Down Service Procurement Rate =

{(Reserve Zone Regulation-Down Service MCP * Total of cleared

Regulation-Down Service for that Reserve Zone) + [(Weighted Average

Regulation-Down Service MCP of all Exporting Zones) * (Sum of Asset

Owners’ Day-Ahead Regulation-Down Service Obligations for that

Reserve Zone - Total of cleared Regulation-Down Service for that Reserve

Zone)]} / (Sum of Asset Owners’ Day-Ahead Regulation-Down Service

Obligations for that Reserve Zone).


(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner

and is calculated for each Resource with an associated Day-Ahead Market

Commitment Period that was committed by the Transmission Provider with a

Day-Ahead Market Resource Offer commitment status as defined under Sections

4.1(10)(b) and (c) of this Attachment AE, or was committed as part of the Multi-

Day Reliability Assessment as defined under Section 4.5.3 of this Attachment AE.

A payment is made to the Asset Owner when the sum of the Resource’s costs is

greater than the Day-Ahead Market revenues received for that Resource over the

Resource’s Day-Ahead Market make whole payment eligibility period. The make

whole payment is equal to this difference between these costs and revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal

to a Resource’s Day-Ahead Market Commitment Period except as defined herein.

For Resources with an associated Day-Ahead Market Commitment Period that

begins in one Operating Day and ends in the next Operating Day, two (2) Day-

Ahead Market make whole payment eligibility periods are created. The first

period begins in the first Operating Day in the hour that the Day-Ahead Market

Commitment Period begins and ends in the last hour of the first Operating Day.

The second period begins in the first hour of the next Operating Day and ends in

the last hour of the Day-Ahead Market Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole

payment eligibility period. Offer costs are calculated using the Day-Ahead

Market Offer prices in effect at the time the commitment decision was made

except under the situation described under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment

eligibility period for a Resource in a single Operating Day for which a

charge or payment is calculated. A single Day-Ahead Market make whole

payment eligibility period is contained within a single Operating Day.

(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for

recovery in the following Day-Ahead Market make whole payment

eligibility periods:

(i) For any Day-Ahead Market make whole payment eligibility period

that is adjacent to the end of a RUC make whole payment

eligibility period except as described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that

contains a Day-Ahead Market self-commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for

which a Resource is a Synchronized Resource prior to this

commitment period at a time one (1) hour prior to that Resource’s

Day-Ahead Market Commit Time less the Resource’s Sync-To-

MinTime.

(c) For each Day-Ahead Market make whole payment eligibility period

within an Operating Day, a Resource’s Day-Ahead Market Start-Up Offer

is divided by the lesser of (1) the Resource’s Minimum Run Time rounded

down to the nearest hour or (2) twenty-four (24) hours, and that portion of

the Start-Up Offer is included as a cost in each hour of the Day-Ahead

Market make whole payment eligibility period until the sum of these

hourly costs are equal to the Day-Ahead Market Start-Up Offer or until the

end of the Day-Ahead Market make whole payment eligibility period,

whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up

Offer is not accounted for in the last Day-Ahead Market make whole

payment eligibility period in the Operating Day, any remaining Day-

Ahead Market Start-Up Offer costs are carried forward for recovery in the

first Day-Ahead Market make whole payment eligibility period of the

following Operating Day.

(4) The payment to each Asset Owner for each eligible Settlement Location for a

given Day-Ahead Market make whole payment eligibility period is calculated as

follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment

Cost Amount in the Day-Ahead Market Make Whole Payment Eligibility

Period) + (Day-Ahead Make Whole Payment Revenue Amount in the

Day-Ahead Market Make Whole Payment Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for

each eligible Resource is equal the sum for all hours in the Day-Ahead

Market Make Whole Payment Eligibility Period of:

(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Energy cost associated with cleared Resource Energy from

Resource Energy Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying cleared Resource

Energy by the cost of such Energy as calculated from the

Resource’s Day-Ahead Market Energy Offer Curve,

(iv) Regulation-Up Service cost associated with cleared Regulation-Up

Service from Regulation-Up Service Offers as described under

Section 5.1.3 of this Attachment AE, as calculated by multiplying

Regulation-Up Service by the cost of such Regulation-Up Service

as calculated from the Resource’s Day-Ahead Market Regulation-

Up Service Offer,

(v) Regulation-Down Service cost, associated with cleared

Regulation-Down Service from Regulation-Down Service Offers

as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying Regulation-Down Service by the cost of

such Regulation-Down Service as calculated from the Resource’s

Day-Ahead Market Regulation-Down Service Offer,

(vi) Spinning Reserve cost, associated with cleared Spinning Reserve

from Spinning Reserve Offers as described under Section 5.1.3 of

this Attachment AE, as calculated by multiplying Spinning

Reserve by the cost of such Spinning Reserve as calculated from

the Resource’s Day-Ahead Market Spinning Reserve Offer, and

(vii) Supplemental Reserve cost, associated with cleared Supplemental

Reserve from Supplemental Reserve Offers as described under


Supplemental Reserve by the cost of such Supplemental Reserve

as calculated from the Resource’s Day-Ahead Market

Supplemental Reserve Offer

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount

for each eligible Resource is equal to the sum for all hours in the Day-

Ahead Market Make Whole Payment Eligibility Period of:

(i) Energy revenue associated with cleared Resource Energy from


Attachment AE, calculated by multiplying Resource Energy by

Day-Ahead LMP at that Resource Settlement Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and

8.5.4 for that eligible Resource.


(1) An RTBM payment or charge for the sum of (i) deviations between cleared

RTBM Regulation-Up Service and cleared Day-Ahead Market Regulation-Up,

(ii) Excess Regulation-Up Mileage and (iii) Unused Regulation-Up Mileage, will

be calculated at each Settlement Location for each Asset Owner for each Dispatch

Interval and hour as follows:

(a) Real-Time Regulation-Up Service Dispatch Interval Amount =

[[(Real-Time MCP) * ((Real-Time Cleared Regulation-Up Service

Dispatch Interval Quantity) - (Day-Ahead Regulation-Up Hourly

Quantity)) / 12] - Unused Regulation-Up Mileage Dispatch Interval

Amount + Excess Regulation-Up Mileage Dispatch Interval Amount] * (-

1)

(i) Real-Time MCP, as defined under Section 1 of this Attachment

AE, for Regulation-Up Service associated with the Reserve Zone

in which the applicable Resource is located.

(ii) An Asset Owner’s Real-Time Cleared Regulation-Up Service

Dispatch Interval Quantity is the MW quantity associated with

cleared RTBM Regulation-Up Service Offers as described under


(iii) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service

Hourly Quantity is the MW quantity associated with cleared Day-

Ahead Market Regulation-Up Service Offers as described under


(iv) An Asset Owner’s Unused Regulation-Up Mileage Dispatch

Interval Amount is equal to the Asset Owner’s Unused Regulation-

Up Mileage multiplied by the MCP for Expected Regulation-Up

Mileage, as defined under Section 8.3.4.3(3) of this Attachment

AE, divided by 12. An Asset Owner’s Unused Regulation-Up

Mileage is equal to the amount by which Expected Regulation-Up

Mileage exceeds Actual Regulation-Up Mileage except that, if

Actual Regulation-Up Mileage is greater than or equal to

Instructed Regulation-Up Mileage multiplied by a factor equal to

one minus Regulation Mileage Operating Tolerance, then Unused

Regulation-Up Mileage is equal to the amount by which Expected

Regulation-Up Mileage exceeds Instructed Regulation-Up

Mileage.

(v) An Asset Owner’s Excess Regulation-Up Mileage Dispatch

Interval Amount is equal to the Asset Owner’s Excess Regulation-



AE, divided by 12. An Asset Owner’s Excess Regulation-Up

Mileage is the amount by which Actual Regulation-Up Mileage

exceeds Expected Regulation-Up Mileage except that, if Actual

Regulation-Up Mileage is greater than or equal to Instructed

Regulation-Up Mileage multiplied by a factor equal to one minus

Regulation Mileage Operating Tolerance, Excess Regulation-Up

Mileage is equal to the amount by which Instructed Regulation-Up

Mileage exceeds Expected Regulation-Up Mileage.

(b) Real-Time Regulation-Up Service Hourly Amount =

Sum of Real-Time Regulation-Up Service Dispatch Interval Amount over

all Dispatch Intervals in the Hour.


RTBM Regulation-Down Service and cleared Day-Ahead Market Regulation-

Down, (ii) Excess Regulation-Down Mileage and (iii) Unused Regulation-Down

Mileage, will be calculated at each Settlement Location for each Asset Owner for

each Dispatch Interval and hour as follows:

(a) Real-Time Regulation-Down Service Dispatch Interval Amount =

[[(Real-Time MCP) * ((Real-Time Cleared Regulation-Down Service

Dispatch Interval Quantity) – (Day-Ahead Regulation-Down Service

Hourly Quantity)) / 12] - Unused Regulation-Down Mileage Dispatch

Interval Amount + Excess Regulation-Down Mileage Dispatch Interval

Amount] * (-1)


AE, for Regulation-Down Service associated with the Reserve

Zone in which the applicable Resource is located.

(ii) An Asset Owner’s Real-Time Cleared Regulation-Down Service


cleared Regulation-Down Service Offers as described under


(iii) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service


Ahead Market Regulation-Down Service Offers as described under


(iv) An Asset Owner’s Unused Regulation-Down Mileage Dispatch


Down Mileage multiplied by the MCP for Expected Regulation-

Down Mileage, as defined under Section 8.3.4.3(4) of this

Attachment AE, divided by 12. An Asset Owner’s Unused

Regulation-Down Mileage is equal to the amount by which

Expected Regulation-Down Mileage exceeds Actual Regulation-

Down Mileage except that, if Actual Regulation-Down Mileage is

greater than or equal to Instructed Regulation-Down Mileage

multiplied by a factor equal to one minus Regulation Mileage

Operating Tolerance, then Unused Regulation-Down Mileage is

equal to the amount by which Expected Regulation-Down Mileage

exceeds Instructed Regulation-Down Mileage.

(v) An Asset Owner’s Excess Regulation-Down Mileage Amount is

equal to the Asset Owner’s Excess Regulation-Down Mileage

multiplied by the MCP for Expected Regulation-Down Mileage, as

defined under Section 8.3.4.3(4) of this Attachment AE, divided by

12. An Asset Owner’s Excess Regulation-Down Mileage is the

amount by which Actual Regulation-Down Mileage exceeds

Expected Regulation-Down Mileage except that, if Actual

Regulation-Down Mileage is greater than or equal to Instructed

Regulation-Down Mileage multiplied by a factor equal to one

minus Regulation-Mileage Operating Tolerance, Excess


Instructed Regulation-Down Mileage exceeds Expected

Regulation-Down Mileage.

(b) Real-Time Regulation-Down Service Hourly Amount =

Sum of Real-Time Regulation-Down Service Dispatch Interval Amount

over all Dispatch Intervals in the Hour.


(1) Asset Owners of Resources committed by the Transmission Provider with an

RTBM Resource Offer commitment status as defined under Sections 4.1(10)(b)

and (c) of this Attachment AE or committed by a local transmission operator that

the Transmission Provider determines were selected in a non-discriminatory

manner by the local transmission operator, as determined pursuant to Section

6.1.2.1 of this Attachment AE, are eligible to receive a RUC make whole payment.

A RUC make whole payment is made to the Asset Owner when the sum of a

Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy

Offer Curve and Operating Reserve Offer costs associated with actual Energy and

cleared RTBM Operating Reserve is greater than the Energy and Operating

Reserve RTBM revenues received over the Resource’s RUC make whole

payment eligibility period. Recovery of such compensation shall be collected in

accordance with Section 8.6.7 of this Attachment AE. Resources that are

committed by a local transmission operator that the Transmission Provider

determines were selected in a discriminatory manner by the local transmission

operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE, are

not eligible to receive a RUC make whole payment.

(2) A Resource’s RUC make whole payment eligibility period is equal to that

Resource’s RUC Commitment Period. For Resources with a RUC Commitment

Period that begins in one Operating Day and ends in the next Operating Day, two

RUC make whole payment eligibility periods are created. The first period begins

in the first Operating Day in the Dispatch Interval associated with the Resource’s

RUC Commit Time and ends at the last Dispatch Interval of the first Operating

Day. The second period begins in the first Dispatch Interval of the next Operating

Day and ends in the Dispatch Interval associated with the Resource’s RUC De-

Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment

eligibility period. Offer costs are calculated using the RTBM Offer prices in

effect at the time the commitment decision was made.

(a) If the Transmission Provider cancels a Commitment Instruction prior to

the start of the associated RUC make whole payment eligibility period and

the Resource is not a Synchronized Resource, the Asset Owner will

receive reimbursement for a time-based pro-rata share of the Resource’s

RTBM Start-Up Offer. Asset Owners may request additional

compensation through submittal of actual cost documentation to the

Transmission Provider. The Transmission Provider will review the

submitted documentation and confirm that the submitted information is

sufficient to document actual costs and that all or a portion of the actual

costs are eligible for recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a

RUC make whole payment eligibility period, the Resource must be a

Synchronized Resource in at least one Dispatch Interval in the RUC make

whole payment eligibility period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch

Interval in the RUC make whole payment eligibility period, the Resource

must be a Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period

for a Resource in a single Operating Day. A single RUC make whole


(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in

the following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period that is adjacent

to the end of a Day-Ahead Market make whole payment eligibility

period;

(ii) Any RUC make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment

period at a time one (1) hour prior to that Resource’s RUC Commit

Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a

RUC Commitment Period that contains an hour for which the

Resource was self-committed.

(f) For each RUC make whole payment eligibility period within an Operating

Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the

Resource’s Minimum Run Time multiplied by twelve (12), rounded down

to the nearest whole interval, or (2) twenty-four (24) hours multiplied by

twelve (12), and that portion of the Start-Up Offer is included as a cost in

each interval of the RUC make whole payment eligibility period until the

sum of these interval costs are equal to the RTBM Start-Up Offer or until

the end of the RUC make whole payment eligibility period, whichever

occurs first.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not

accounted for in the last RUC make whole payment eligibility period in

the Operating Day, any remaining RTBM Start-Up Offer costs are carried

forward for recovery in the first RUC make whole payment eligibility

period of the following Operating Day provided that the Resource has not

been committed in the Day-Ahead Market in any hour of the first RUC

make whole payment eligibility period as described in (h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period

adjacent to and following a RUC make whole payment eligibility period to

the extent that the full amount of the RTBM Start-Up Offer is not

accounted for in the RUC make whole payment eligibility period, any

remaining RTBM Start-Up Offer costs are carried forward for recovery in

the Day-Ahead make whole payment eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any

Dispatch Interval, any cost associated with energy output above the

Resource’s economic operating point is not eligible for recovery for that

Dispatch Interval where such cost is calculated as described under

Subsection 4(c) below.

(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating

point is not eligible for recovery for that Dispatch Interval where such cost

is calculated as described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the

Resource’s minimum operating limit that was used to make the

commitment decision, the increase is greater than the Resource’s

Operating Tolerance and the Resource remains dispatchable in any






given RUC make whole payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the

RUC Make Whole Payment Eligibility Period + RUC Make Whole Payment

Revenue Amount in the RUC Make Whole Payment Eligibility Period –

Uninstructed Resource Deviation Cost Disallowance – Non-Dispatchable Cost

Disallowance – Minimum Limit Cost Disallowance)]

(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each

eligible Resource is equal the sum for all Dispatch Intervals in the RUC

Make Whole Payment Eligibility Period of (i) Start-Up Offer used to

make commitment decision, (ii) No-Load Offer used to make commitment

decision, (iii) Energy cost at minimum output as calculated from the

Energy Offer Curve used to make commitment decision, (iv) Energy cost

above minimum output as calculated from the Energy Offer Curve that

applied to the current Dispatch Interval, and (v) Operating Reserve cost

associated with cleared Real-Time Operating Reserve as calculated from

the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-

schedules are less than or equal to the amount of Operating Reserve

cleared shall be set equal to zero.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each


Make Whole Payment Eligibility Period of (i) revenue associated with

Energy calculated by multiplying actual Energy by Real-Time LMP (ii)

the sum of the revenues calculated under Section 8.6.2, 8.6.3 and 8.6.4 of

this Attachment AE for that eligible Resource (iii) Energy revenue

associated with payments made under Section 8.6.6 of this Attachment AE

(iv) amounts associated with settlement made under Section 8.6.15 of this

Attachment AE (v) Unused Regulation-Up Mileage Make Whole Payment

as calculated under Section 8.6.19 of this Attachment AE and (vi) Unused

Regulation-Down Mileage Make Whole Payment as calculated under


(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance,

Non-Dispatchable Cost Disallowance, or Minimum Limit Cost

Disallowance is equal to the positive difference between the Resource’s

Energy cost at actual output as calculated from the Resource’s current

Dispatch Interval Energy Offer Curve and the Resource’s Energy cost at

the Resource’s economic operating point as calculated from the

Resource’s current Dispatch Interval Energy Offer Curve.

(d) A Resource’s economic operating point is the MW output where the cost

on the Resource’s current Dispatch Interval Energy Offer Curve is equal

to the Real-Time LMP for that Resource.


An RTBM charge will be calculated for each Asset Owner at each Settlement

Location for each hour for the purposes of funding payments made under Section 8.6.2 as

follows:

(1) Real-Time Regulation-Up Service Distribution Amount =

[(Real-Time Regulation-Up Service Amount) * (Real-Time Load Ratio Share)] *

(-1)

(a) The Real-Time Regulation-Up Service Amount shall be equal to the sum

of the all payments made under Section 8.6.2(1) for Regulation-Up

Service procurement and the sum of all payments made under Section

8.6.19 for Unused Regulation-Up Mileage Make Whole Payments for the

hour.

(b) Real-Time Load Ratio Share is as defined under Section 1 of this

Attachment AE.

(2) Real-Time Regulation-Down Service Distribution Amount =

[(Real-Time Regulation-Down Service Amount) * (Real-Time Load Ratio Share)]

* (-1)

(a) The Real-Time Regulation-Down Service Amount shall be equal to the

sum of the all payments made under Section 8.6.2(2) for Regulation-Down


8.6.20 for Unused Regulation-Down Mileage Make Whole Payments for

the hour.


Attachment AE.


An RTBM charge will be calculated at each Resource Settlement Location for

each Asset Owner for each Dispatch Interval when a Resource with cleared RTBM

Regulation-Up Service, Regulation-Down Service or both operates outside of its

Operating Tolerance. The amount will be determined as follows:

Real-Time Regulation Service Non-Performance Amount =

[[{Maximum of [Either Zero or ((Day-Ahead MCP for Regulation-Up Service) * (Day-

Ahead Cleared Regulation-Up Service Hourly Quantity) + (Real-Time MCP for

Regulation-Up Service) * (Real-Time Cleared Regulation-Up Service Dispatch Interval

Quantity – Day-Ahead Cleared Regulation-Up Service Hourly Quantity))]} +

{Maximum of [Either Zero or ((Day-Ahead MCP for Regulation-Down Service) * (Day-

Ahead Cleared Regulation-Down Service Hourly Quantity) + (Real-Time MCP for

Regulation-Down Service) * (Real-Time Cleared Regulation-Down Service Dispatch

Interval Quantity – Day-Ahead Cleared Regulation-Down Hourly Quantity))]}] / 12] -

Unused Regulation-Up Mileage Dispatch Interval Amount + Excess Regulation-Up

Mileage Dispatch Interval Amount - Unused Regulation-Down Mileage Dispatch Interval

Amount + Excess Regulation-Down Mileage Dispatch Interval Amount.

(1) Day-Ahead MCP, as defined under Section 1 of this Attachment AE, for

Regulation-Up Service associated with the Reserve Zone in which the applicable

Resource is located.




(3) Real-Time MCP, as defined under Section 1 of this Attachment AE, for






(5) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service Hourly Quantity is

the MW quantity associated with cleared Regulation-Up Service Offers as

described under Section 5.1.3 of this Attachment AE.

(6) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service Hourly

Quantity is the MW quantity associated with cleared Regulation-Down Service

Offers as described under Section 5.1.3 of this Attachment AE.

(7) An Asset Owner’s Real-Time Cleared Regulation-Up Service Dispatch Interval

Quantity is the MW quantity associated with cleared Regulation-Up Service


(8) An Asset Owner’s Real-Time Cleared Regulation-Down Dispatch Interval



(9) An Asset Owner’s Unused Regulation-Up Mileage Dispatch Interval Amount is

the amount calculated under Section 8.6.2(1)(a)(iv) of this Attachment AE.

(10) An Asset Owner’s Excess Regulation-Up Mileage Dispatch Interval Amount is

the amount calculated under Section 8.6.2(1)(a)(v) of this Attachment AE.

(11) An Asset Owner’s Unused Regulation-Down Mileage Dispatch Interval Amount

is the amount calculated under Section 8.6.2(2)(a)(iv) of this Attachment AE.

(12) An Asset Owner’s Excess Regulation-Down Mileage Dispatch Interval Amount is



An RTBM payment will be calculated for each Asset Owner at each Settlement

Location for each hour in order to distribute the funds collected under Section 8.6.11.

The Asset Owner amount is calculated as follows:

Real-Time Regulation Service Non-Performance Distribution Amount =

[(Real-Time Regulation Service Non-Performance Amount) * (Real-Time Load Ratio

Share)] * (-1)

(1) The Real-Time Regulation Service Non-Performance Amount shall be equal to

the sum of all charges made under Section 8.6.11 for hour.

(2) Real-Time Load Ratio Share is as defined under Section 1 of this Attachment AE.


A Real-Time regulation deployment adjustment amount charge or payment will

be calculated for each Asset Owner for each Dispatch Interval when a Resource with

cleared Real-Time Regulation-Up Service and/or Regulation-Down Service is deployed.

The amount will be determined as one-twelfth of the sum of:

(1) For Regulation-Up Service deployment, the amount is equal to the difference

between (1) actual Regulation-Up Service deployment MW multiplied by Real-

Time LMP at that Resource Settlement Location, and (2) Energy Offer Curve cost

of actual Regulation-Up Service deployment MW.

The actual Regulation-Up Service deployment MW is calculated as the

difference between the lesser of (1) Dispatch Instruction plus the average

Regulation-Up Service deployment or (2) Absolute value of actual Resource

output, and the Resource’s average Dispatch Instruction for Energy. If the

absolute value of the Resource’s actual output is less than or equal to the

Resource’s average Dispatch Instruction for Energy, then the actual Regulation-

Up Service deployment MW is equal to zero (0).

(2) For Regulation-Down Service deployment, the amount is equal to the difference

between (1) Energy Offer Curve cost of actual Regulation-Down Service

deployment MW, and (2) actual Regulation-Down Service deployment MW

multiplied by RTBM LMP.

The actual Regulation-Down Service deployment MW is calculated as the

difference between the Resource’s average Dispatch Instruction for Energy and

the greater of (1) Average Dispatch Instruction minus the average Regulation-

Down Service deployment or (2) Absolute value of actual Resource output. If the

absolute value of the Resource’s actual output is greater than or equal to the


Down Service deployment MW is equal to zero (0).

Distribution of such charges and recovery of such payments shall be made

in accordance with Section 8.8 of this Attachment AE.


An RTBM payment will be made to each Asset Owner with a Resource that is

charged for Unused Regulation-Up Mileage at a rate that is in excess of that Resource’s

Regulation-Up Mileage Offer. The amount will be calculated on a Dispatch Interval

basis as follows:

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount =

[Minimum of [zero or (Regulation-Up Mileage Offer - Expected

Regulation-Up Mileage MCP)]] * Unused Regulation-Up Mileage

Where Regulation-Up Mileage Offer is defined under Section 1 of this Attachment AE,

Unused Regulation-Up Mileage is calculated under Section 8.6.2(1)(a)(4) of this

Attachment AE and Expected Regulation-Up Mileage MCP is defined under Section

8.3.4(3) of this Attachment AE.



charged for Unused Regulation-Down Mileage at a rate that is in excess of that

Resource’s Regulation-Down Mileage Offer. The amount will be calculated on a

Dispatch Interval basis as follows:

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount =

[Minimum of [zero or (Regulation-Down Mileage Offer - Expected

Regulation-Down Mileage MCP)]] * Unused Regulation-Down Mileage

Where Regulation-Down Mileage Offer is defined under Section 1 of this Attachment

AE, Unused Regulation-Down Mileage is calculated under Section 8.6.2(2)(a)(4) of this

Attachment AE and Expected Regulation-Down Mileage MCP is defined under Section


ATTACHMENT AE

INTEGRATED MARKETPLACE

Attachment AE

Table of Contents

1. Introduction

1.1 Definitions and Acronyms

1.1 Definitions A

1.1 Definitions B

1.1 Definitions C

1.1 Definitions D

1.1 Definitions E

1.1 Definitions F

1.1 Definitions G

1.1 Definitions I

1.1 Definitions J

1.1 Definitions L

1.1 Definitions M

1.1 Definitions N

1.1 Definitions O

1.1 Definitions P

1.1 Definitions Q

1.1 Definitions R

1.1 Definitions S

1.1 Definitions T

1.1 Definitions U

1.1 Definitions V

2. Market Participant Obligations

2.1 Service Agreement

2.2 Application and Asset Registration

2.3 Market Manipulation

2.4 Commitment and Dispatch

2.5 Provision of Load and Generation Data

2.6 Dispatchable Demand Response Resource

2.7 Block Demand Response Resource

2.8 Aggregators of Retail Customers

2.9 Combined Cycle Resource

2.10 Operating Reserve Certification

2.10.1 Spin Qualified Resources

2.10.2 Supplemental Qualified Resources

2.10.3 Regulation Qualified Resources

2.11 Must-Offer Requirement


2.11.2 Reliability Unit Commitment and the Real-Time Balancing Market

2.12 Non-Conforming Load

2.13 Market Protocols and SPP Criteria

2.14 External Dynamic Resource

2.15 Provision of Wind Forecast Data

3. Transmission Provider Rights and Obligations

3.1 Transmission Provider Scope of Services

3.1.1 Market Hub Establishment and Modification

3.1.2 Forecasting

3.1.3 Reserve Zone Establishment

3.1.4 Operating Reserve Requirements

3.1.5 Outage Scheduling and Reporting

3.2 Market Protocols

3.3 Integrated Marketplace Operations

3.4 Violation Relaxation Limit Reporting


3.6 Integrated Marketplace Settlements

3.7 Integrated Marketplace Participation Readiness

4. Pre-Day-Ahead Period Activities

4.1 Offer Submittal


4.1.2 Additional Provisions for Non-Traditional Resources

4.2 Provisions for Non-Resource Related Offers

4.2.1 Virtual Energy Offers

4.2.2 Import Interchange Transaction Offers

4.3 Bid Submittal

4.3.1 Demand Bids

4.3.2 Virtual Energy Bids

4.3.3 Export Interchange Transaction Bids

4.4 Through Interchange Transactions

4.5 Multi-Day Reliability Assessment

4.5.1 Multi-Day Reliability Assessment Inputs

4.5.2 Multi-Day Reliability Assessment Analysis

4.5.3 Multi-Day Reliability Assessment Results

5. Day-Ahead Period Activities

5.1 Day-Ahead Market

5.1.1 Day-Ahead Market Inputs



5.2 Day-Ahead Reliability Unit Commitment

5.2.1 Day-Ahead Reliability Unit Commitment Inputs


5.2.3 Day-Ahead Reliability Unit Commitment Results

6. Operating Day Activities

6.1 Intra-Day Reliability Unit Commitment

6.1.1 Intra-Day Reliability Unit Commitment Inputs


6.1.3 Intra-Day Reliability Unit Commitment Results

6.2 Real-Time Balancing Market




6.2.4 Out-of-Merit Energy Dispatch



6.3.2 Contingency Reserve Deployment

6.3.3 Reserve Sharing Group Scheduling Procedures

6.3.4 Contingency Reserve Recovery

6.4 Energy and Operating Reserve Deployment Failure

6.4.1 Uninstructed Resource Deviation


6.4.3 Contingency Reserve Deployment Failure Charges

6.5 Inadvertent Management

6.5.1 Inadvertent Payback Reporting

7. Transmission Congestion Rights Markets

7.1 Annual Auction Revenue Right Verification

7.1.1 Transmission Service Verification

7.1.2 Candidate Auction Revenue Rights

7.1.3 Auction Revenue Right Nomination Cap

7.2 Annual Auction Revenue Right Allocation

7.2.1 Auction Revenue Right Nominations

7.2.2 Auction Revenue Right Allocation

7.2.3 Annual Auction Revenue Right Awards

7.3 Annual Transmission Congestion Right Auction

7.3.1 Transmission Congestion Right Offer and Bid Submittal

7.3.2 Annual Transmission Congestion Right Auction

7.3.3 Annual Transmission Congestion Right Auction Clearing and


7.3.4 Annual Transmission Congestion Right Awards

7.4 Monthly Transmission Congestion Right Auctions

7.4.1 Monthly Transmission Congestion Right Offer and Bid Submittal

7.4.2 Monthly Transmission Congestion Right Auction

7.4.3 Monthly Transmission Congestion Right Auction Clearing and


7.4.4 Monthly Transmission Congestion Right Awards

7.5 Monthly Auction Revenue Right Allocation

7.5.1 Monthly Auction Revenue Right Transmission Service Verification

7.5.2 Reserved for Future Use

7.5.3 Monthly Auction Revenue Right Nominations

7.5.4 Monthly Auction Revenue Right Awards

7.6 Auction Revenue Right Allocation and Transmission Congestion Right Auction

Settlements

7.7 Transmission Congestion Right Secondary Market

7.8 Liquidation of Transmission Congestion Rights in the Event of Market Participant

Default

7.9 Initial TCR Markets Schedule

8. Post Operating Day and Settlement Activities

8.1 Settlement Sign Conventions

8.2 Bilateral Settlement Schedules

8.2.1 Default Procedures for Pre-Existing Bilateral Contracts Transitioning to


8.3 Calculation of Locational Marginal Prices, Locational Marginal Price

Components, and Market Clearing Prices

8.3.1 Locational Marginal Price Calculations and Components

8.3.2 Violation Relaxation Limit

8.3.3 Impact of Violation Relaxation Limits on Locational Marginal Prices


8.4 Price Corrections

8.5 Day-Ahead Market Settlement

8.5.1 Day-Ahead Energy Amount


8.5.3 Day-Ahead Spinning Reserve Amount

8.5.4 Day-Ahead Supplemental Reserve Amount



8.5.7 Day-Ahead Spinning Reserve Distribution Amount

8.5.8 Day-Ahead Supplemental Reserve Distribution Amount


8.5.10 Day-Ahead Make Whole Payment Distribution Amount

8.5.11 Transmission Congestion Rights Funding Amount

8.5.12 Transmission Congestion Rights Daily Uplift Amount

8.5.13 Transmission Congestion Rights Monthly Payback Amount

8.5.14 Transmission Congestion Rights Annual Payback Amount

8.5.15 Transmission Congestion Rights Annual Closeout Amount

8.5.16 Day-Ahead Over-Collected Losses Distribution Amount

8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount

8.6 Real-Time Balancing Market Settlement

8.6.1 Real-Time Energy Amount


8.6.3 Real-Time Spinning Reserve Amount

8.6.4 Real-Time Supplemental Reserve Amount


8.6.6 Real-Time Out-of-Merit Amount

8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount


8.6.9 Real-Time Spinning Reserve Distribution Amount

8.6.10 Real-Time Supplemental Reserve Distribution Amount



8.6.13 Real-Time Contingency Reserve Deployment Failure Amount

8.6.14 Real-Time Contingency Reserve Deployment Failure Distribution Amount


8.6.16 Real-Time Over-Collected Losses Distribution Amount

8.6.17 Real-Time Reserve Sharing Group Amount

8.6.18 Real-Time Reserve Sharing Group Distribution Amount



8.7 Auction Revenue Rights and Transmissions Congestion Rights Auction

Settlement

8.7.1 Transmission Congestion Rights Auction Transaction Amount

8.7.2 Auction Revenue Rights Funding Amount

8.7.3 Auction Revenue Rights Uplift Amount

8.7.4 Auction Revenue Rights Monthly Payback Amount

8.7.5 Auction Revenue Rights Annual Payback Amount

8.7.6 Auction Revenue Rights Annual Closeout Amount

8.8 Revenue Neutrality Uplift Distribution Amount

9. Release of Offer Curve Data

10. Billing

10.1 Settlement Statements

10.2 Invoices

10.3 Invoice Disputes

10.4 Interest on Unpaid Balances

10.5 Customer Default

11. Confidentiality Provisions

11.1 Restrictions on Confidential Information Provided to Receiving Party

11.1.1 Procedures for Confidential Information

11.1.2 Exceptions

11.1.3 Injunctive Relief and Specific Performance

11.1.4 Market Participant Access and Transmission Provider Use of Confidential

Information

11.1.5 Required Disclosure

11.1.6 Limitations

11.2 Confidentiality Provisions Applicable to the Market Monitor Reporting to the

Board of Directors

11.3 Disclosure to Commission

11.4 Disclosure to Authorized Agencies

11.4.1 Basic Requirements for Disclosure

11.4.2 Schedule of Authorized Requestors

11.4.3 Use of Confidential Information

11.4.4 Limited Oral Disclosures

11.4.5 Information Requests

11.4.6 Limited Discussion of Confidential Information Among Authorized

Requestors Sponsored By Different Authorized Agencies

11.4.7 Breach of Non-Disclosure Obligations

11.5 Preservation of Rights

11.6 Notice

Addendum 1 Violation Relaxation Limit Values (“VRLs”)

Addendum 2 Bilateral Settlement Schedule Example System Power Sale

1.1 Definitions A


The sum of the absolute values of actual movements by a Resource with cleared Regulation-

Down Service MW in response to Regulation Deployment instructions.


The sum of the absolute values of actual movements by a Resource with cleared Regulation-Up


Asset Owner

An owner of any combination of: (1) registered physical assets (Resource, load, Import

Interchange Transaction, Export Interchange Transaction, Through Interchange Transaction), (2)

Transmission Congestion Rights, (3) Virtual Energy Offers, (4) Virtual Energy Bids, or (5)

Bilateral Settlement Schedules.

Asset Owner Reserve Zone Load Ratio Share

The sum of an Asset Owner’s Reported Load and Export Interchange Transactions in a Reserve

Zone divided by the sum of all Asset Owners’ Reported Load and Export Interchange

Transactions in all Reserve Zones for a given hour.

Auction Clearing Price (“ACP”)

The price generated at each source and sink Settlement Location in each round of the Annual

Transmission Congestion Right Auction and Monthly Transmission Congestion Right Auction

based upon the Transmission Congestion Right Offers and Bids submitted.

Auction Revenue Right (“ARR”)

A right, awarded during the annual Auction Revenue Right allocation process and the monthly

Auction Revenue Right allocation process, which entitles the holder to a share of the auction

revenues generated in the applicable Transmission Congestion Rights auction(s) and entitles the

holder to self-convert the Auction Revenue Right to a Transmission Congestion Right.

Auction Revenue Right Nomination Cap (“ARR Nomination Cap”)

A cap on the maximum total amount of Auction Revenue Rights that an Eligible Entity may

nominate in each month and season in the annual Auction Revenue Right allocation process and

the monthly Auction Revenue Right allocation process.

1.1 Definitions E

Electrical Node (“ENode”)

A physical node represented in the Network Model where electrical equipment and components

are connected.

Eligible Entity

A Transmission Customer or Market Participant having firm SPP Transmission Service or firm

non-SPP transmission service (referred to as a “grandfathered agreement” or “GFA”) into, out

of, within or through the SPP Region.

Emergency Condition


Energy

An amount of electricity that is Bid or Offered, produced, purchased, consumed, sold or

transmitted over a period of time, which is measured or calculated in Megawatt hours.

Energy and Operating Reserve Markets


Energy Offer Curve

A set of price/quantity pairs that consists of Megawatts and dollars per Megawatt hour with up to

ten (10) price/quantity pairs.






The amount of Regulation-Down Service MW cleared multiplied by the Regulation-Down

Mileage Factor.


The amount of Regulation-Up Service MW cleared multiplied by the Regulation-Up Mileage

Factor.

Export Interchange Transaction

A Market Participant schedule for exporting Energy out of the SPP Balancing Authority Area.

Export Interchange Transaction Bid

A proposal by a Market Participant to purchase a fixed or price sensitive amount of Energy for

delivery outside of the SPP Balancing Authority Area at a specified External Interface and for a

period of time.

External Dynamic Resource

A registered Resource that represents one or more resources, located external to the SPP

Balancing Authority Area, which is dynamically scheduled into or out of the SPP Balancing

Authority Area.

External Interface

A Settlement Location representing a physical interconnection point(s) between the SPP

Balancing Authority Area and an external Balancing Authority Area.

1.1 Definitions I

Import Interchange Transaction

A schedule for importing Energy into the SPP Balancing Authority Area.

Import Interchange Transaction Offer

A proposal by a Market Participant to provide Energy from a source external to the SPP

Balancing Authority Area at a specified External Interface and period of time.



Down Service through Regulation Deployment instructions.



Up Service MW through Regulation Deployment instructions.


The Day-Ahead Market, the Real-Time Balancing Market, the Transmission Congestion Rights

Market and the Reliability Unit Commitment processes.

Integrated Marketplace Counterparty

The Transmission Provider, as counterparty to all Integrated Marketplace transactions (and not

in any other capacity of the Transmission Provider under the Tariff) in accordance with the

provisions of Section 3.8 of this Attachment AE.

Interchange Transaction

Any Energy transaction that is crossing the boundary of the SPP Balancing Authority Area and

requires checkout with one or more external Balancing Authority Areas. This includes any

Import Interchange Transaction, Export Interchange Transaction or Through Interchange

Transaction.

Intra-Day Reliability Unit Commitment (“Intra-Day RUC”)

The process performed by the Transmission Provider following the completion of the Day-

Ahead Reliability Unit Commitment process and throughout the Operating Day to assess

Resource and Operating Reserve adequacy for the Operating Day, commit or de-commit

Resources as necessary, and communicate commitment or de-commitment of Resources to the

appropriate Market Participants as necessary.

1.1 Definitions M

Manual Dispatch Instruction

A Dispatch Instruction that originates from SPP outside of the normal Real-Time Balancing

Market security constrained economic dispatch solution to address a system reliability condition.

Market Clearing Price (“MCP”)

The price used for settlements of an Operating Reserve product in each Reserve Zone. A

separate price is calculated for Regulation-Up Service, Expected Regulation-Up Mileage,

Regulation-Down Service, Expected Regulation-Down Mileage, Spinning Reserve and

Supplemental Reserve.

Market Flow

The aggregate Megawatt flow on a Coordinated Flowgate or a Reciprocal Coordinated Flowgate

caused by the Real-Time Balancing Market.

Market Hub

A Settlement Location consisting of an aggregation of Price Nodes.

Market Participant


Marginal Congestion Component (“MCC”)


transmission congestion costs between that Settlement Location and a reference location as

calculated under Section 8.3 of this Attachment AE.

Marginal Loss Component (“MLC”)


marginal loss costs between that Settlement Location and a reference location as calculated

under Section 8.3 of this Attachment AE.

Maximum Economic Capacity Operating Limit

An economic MW level at or below a Resource’s Maximum Normal Capacity Operating Limit

used for constraining Energy dispatch and Contingency Reserve clearing during normal system

conditions.

Maximum Emergency Capacity Operating Limit

The maximum Megawatt level at which a Resource other than a Block Demand Response


Maximum Normal Capacity Operating Limit

The maximum Megawatt level at which a Resource may operate continuously.

Maximum Regulation Capacity Operating Limit

The maximum Megawatt level at which a Regulation Qualified Resource, a Regulation-Up



Megawatt (“MW”)

A measurement unit of the instantaneous demand for Energy.

Meter Agent

An entity responsible for collecting load and Resource data associated with identified Meter

Settlement Locations within a Settlement Area for the purpose of energy accounting that impacts

market settlements.

Meter Data Submittal Location

One or more Meter Settlement Locations contained within a single Settlement Area for which

meter data is submitted to the Transmission Provider by the Meter Agent for settlement

purposes.

Meter Settlement Location

The point at which a Market Participant’s registered load and Resources interchange Energy with

the Real-Time Balancing Market.

Minimum Economic Capacity Operating Limit

A Megawatt level at or above a Resource’s Minimum Normal Capacity Operating Limit used for

energy dispatch at a minimum level during normal operating conditions.

Minimum Emergency Capacity Operating Limit

The minimum Megawatt level at which a Resource other than a Block Demand Response


Minimum Normal Capacity Operating Limit

The minimum Megawatt level at which a Resource may operate continuously.

Minimum Regulation Capacity Operating Limit

The minimum Megawatt level at which a Regulation Qualified Resource, a Regulation-Up



Minimum Run Time

The minimum length of time a Resource must run from the time the Resource is put online to the

time the Resource is shut-down.

Multi-Day Reliability Assessment

The process to assess Resource adequacy for the Operating Day, commit Resources with long

Start-Up Times that cannot be considered as part of the Day-Ahead Market or Day-Ahead

Reliability Unit Commitment, and communicate commitment of such Resources as necessary.

1.1 Definitions O

Offer

A commitment to sell (i) a quantity of Energy at a specific minimum price that includes a

Resource Offer, a Virtual Energy Offer or an Import Interchange Transaction Offer, or (ii) a

quantity of Transmission Congestion Rights at a specific minimum price, where such quantities

may be submitted in 0.1 MW increments.

Off-Peak


On-Peak


Operating Day

A daily period beginning at midnight.

Operating Hour

A sixty (60) minute period of time during the Operating Day corresponding to a clock hour

typically expressed as hour-ending.

Operating Reserve

Resource capacity held in reserve for Resource contingencies and NERC control performance

compliance that includes the following products: Regulation-Up Service, Regulation-Down

Service, Spinning Reserve and Supplemental Reserve.

Operating Tolerance

The Megawatt range of actual Resource output above and below the Resource’s average Setpoint

Instruction over the Dispatch Interval where the Resource will not be subject to charges

associated with Uninstructed Resource Deviation.

1.1 Definitions R

Real-Time

The continuous time period during which the Real-Time Balancing Market is operated.

Real-Time Balancing Market (“RTBM”)


Real-Time Load Ratio Share

The sum of a Market Participant’s Reported Load and Export Interchange Transactions at all

Settlement Locations divided by the sum of all Market Participants’ Report Load and Export

Interchange Transactions at all Settlement Locations for a given hour.

Reciprocal Coordinated Flowgate

A Coordinated Flowgate defined within a joint operating agreement between SPP and another

transmission provider as being affected by the transmission of Energy on both of their respective

transmission systems.

Reference Bus

The location on the Transmission System relative to which all mathematical quantities, including

shift factors and penalty factors relating to physical operation, will be calculated.

Regulation Deployment

The utilization of Regulation-Up Service and/or Regulation-Down Service through automatic

generation control equipment to automatically and continuously adjust Resource output to

balance the SPP Balancing Authority Area in accordance with NERC control performance

criteria.

Regulation-Down


that reduce their energy output in response to a Regulation Deployment instruction from the




of cleared Regulation-Down Service MW to the Instructed Regulation-Down Mileage. The

Regulation-Down Mileage Factor shall initially be set equal to 1.0 and shall be updated

periodically pursuant to the Market Protocols.



has agreed to sell Expected Regulation-Down Mileage.

Regulation-Down Offer


has committed to sell Regulation-Down.

Regulation-Down Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Down Offers and

Regulation-Down Mileage Offers into the Energy and Operating Reserve Markets.


The provision of Actual Regulation-Down Mileage associated with cleared Regulation-Down



The sum of (i) a Resource’s Regulation-Down Mileage Offer multiplied by the Regulation-Down

Mileage Factor and (ii) that Resource’s Regulation-Down Offer.


The allowable percentage deviation below a Resource’s Instructed Regulation-Up Mileage

and/or Instructed Regulation-Down Mileage over the Dispatch Interval where the Resource will

settle based upon Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage

versus Actual Regulation-Up and/or Actual Regulation-Down Mileage. Such percentage is set at

5%.

Regulation Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Up Offers,

Regulation-Up Mileage Offers, Regulation-Down Offers and Regulation-Down Mileage Offers

into the Energy and Operating Reserve Markets.

Regulation Response Time

The maximum amount of time allowed for a Resource to move its output from zero (0)

Regulation Deployment to the full amount of Regulation-Up cleared or to move from zero (0)

Regulation Deployment to the full amount of Regulation-Down cleared.

Regulation-Up


that increase their energy output in response to a Regulation Deployment instruction from the




of cleared Regulation-Up Service MW to the Instructed Regulation-Up Mileage. The

Regulation-Up Mileage Factor shall initially be set equal to 1.0 and shall be updated periodically

pursuant to the Market Protocols.



agreed to sell Expected Regulation-Up Mileage.

Regulation-Up Offer


committed to sell Regulation-Up.

Regulation-Up Qualified Resource

A Resource that has met the requirements to be eligible to submit Regulation-Up Offers and

Regulation-Up Mileage Offers into the Energy and Operating Reserve Markets.


The provision of Actual Regulation-Up Mileage associated with cleared Regulation-Up Service

MW in response to Regulation Deployment instructions.


The sum of (i) a Resource’s Regulation-Up Mileage Offer multiplied by the Regulation-Up

Mileage Factor and (ii) that Resource’s Regulation-Up Offer.

Reliability Unit Commitment (“RUC”)

The process performed by the Transmission Provider to assess resource and Operating Reserve

adequacy for the Operating Day, commit or de-commit resource as necessary, and communicate

commitment or de-commitment of Resources to the appropriate Market Participants as

necessary.

Reliability Unit Commitment Period (“RUC Commitment Period”)

The contiguous period of time between a Resource’s Reliability Unit Commitment Commit Time

and Reliability Unit Commitment De-Commit Time.

Reported Load

A Market Participant's actual value of energy withdrawn from the Transmission System at a

Settlement Location adjusted as described under Section 8.6.1.1 of Attachment AE and further

adjusted, if necessary, to account for distribution system losses between the actual metering point

and the Transmission System Settlement Location as described under Appendix D of the Market

Protocols.

Reservation Capacity

The reservation Megawatt between a specified source and sink associated with SPP

Transmission Service.

Reserve Sharing Event

A request for assistance to deploy Contingency Reserve by any signatory to the Reserve Sharing

Group Agreement following the sudden loss of a Resource.

Reserve Sharing Group

A group whose members consist of two or more Balancing Authorities that collectively maintain,

allocate, and supply operating reserves required for each Balancing Authority’s use in recovering

from contingencies within the group.

Reserve Sharing Group Agreement

The Agreement detailing the rights and obligations of the Reserve Sharing Group members for

use in recovering from contingencies within the group.

Reserve Zone

A zone containing a specific group of Price Nodes for which a minimum and maximum

Operating Reserve requirement is calculated.

Residual Load

Settlement Area Net Load less all other directly metered Reported Load within the Settlement

Area.

Resource

An asset that injects energy into the transmission grid or reduces the withdrawal of energy from

the transmission grid including a Demand Response Resource, a Variable Energy Resource, a

Dispatchable Resource, External Resource, External Dynamic Resource and a Quick-Start

Resource.

Resource Offer

For a Resource, the combination of its Start-Up Offer, No-Load Offer, Energy Offer Curve,

Regulation-Up Service Offer, Regulation-Down Service Offer, Spinning Reserve Offer,

Supplemental Reserve Offer and Resource physical operating parameters.

1.1 Definitions U

Uninstructed Resource Deviation (“URD”)

The Megawatt amount by which a Resource’s actual output in a Dispatch Interval is above or

below that Resource’s average Setpoint Instruction in the Dispatch Interval.






A. Each Market Participant must offer sufficient Resources to the Day-Ahead Market to

cover its load plus Operating Reserve obligation to the extent its Resources are available.

(1) A Market Participant’s load for purposes of this section shall be equal to that

Market Participant’s maximum hourly Reported Load for the Operating Day.

(2) A Market Participant’s daily Operating Reserve obligation shall be equal to the

sum of that Market Participant’s maximum daily Regulation-Up Service,

Regulation-Down Service and Contingency Reserve obligations as estimated by

the Transmission Provider in accordance with Section 3.1.4(3) of this Attachment

AE.

(3) A Market Participant may satisfy this requirement only by offering Resources

with a commitment status indicating either that the Market Participant is self-

committing the Resource or that the Resource may be committed by the

Transmission Provider, as specified in Section 4.1.(10)(a) and (b) of the

Attachment AE.(4) A Market Participant’s net resource capacity, for purposes

of this section shall include:

i. Offered capacity by Resources identified in Section 2.11.1.A(3) of

Attachment AE less the Operating Reserve obligation identified in Section

2.11.1.A(2) of Attachment AE; and

ii. Firm power purchases less firm power sales. For purposes of this Section

2.11.1 of this Attachment AE firm power purchases and firm power sales

shall mean sales and purchases that are deliverable with transmission

service comparable to Firm Point-To-Point Transmission Service or Firm

Network Integration Transmission Service and the capacity and energy is

supplied under standards of reliability and availability equivalent to

supply of native load customers with the supplier assuming the obligation

to provide both capacity and energy.

B. Market Monitor shall monitor offered Resources, self-committed Resources, firm power

purchases, firm power sales, and Reported Load for the Operating Day.

(1) Market Participants who have offered and/or self-committed 100% of their net

resource capacity, as determined in Section 2.11.1.A(4) of this Attachment AE,

are deemed to be in compliance with the must offer requirement.

(2) Market Participants who have offered and/or self-committed less than 100% of

their net resource capacity, as determined in Section 2.11.1.A(4) of this

Attachment AE, and less than 90% of the Market Participant’s maximum hourly

Reported Load for the Operating Day shall be deemed resource deficient and may

be subject to sanctions as determined in Attachment AF, Section 3.9 of this Tariff.


The Transmission Provider shall calculate Day-Ahead Market and RTBM LMPs

for Energy at each Settlement Location.

The Transmission Provider shall calculate the Reserve Zone Market Clearing

Prices (“MCPs”) for Regulation-Up Service, Regulation-Down Service, Spinning

Reserve and Supplemental Reserve for the Day-Ahead Market and RTBM and Market

Clearing Prices for Expected Regulation-Up Mileage and Expected Regulation-Down

Mileage for the RTBM.

The Transmission Provider shall calculate annual and monthly Auction Clearing

Prices (“ACPs”) at each Settlement Location.

4.1 Offer Submittal

Beginning seven (7) days prior to the Operating Day, Market Participants may

begin to submit Offers for use in the Day-Ahead Market and Offers for use in the RTBM.

Day-Ahead Market Offers may be updated up to 1100 hours Day-Ahead and RTBM

Offers may be updated thirty (30) minutes prior to each Operating Hour. Offer

submittals shall conform to the following:

(1) Offers submitted in the Day-Ahead Market are independent from Offers

submitted in the RTBM except that, if Regulation-Up Service and/or Regulation-

Down Service is cleared in the Day-Ahead Market, submitted Regulation-Up


Resources submitted for use in the RTBM must be equal to the Regulation-Up


Resources submitted for use in the Day-Ahead Market;

(2) Market Participants may specify that the Offers submitted in the Day-Ahead

Market also apply in the RTBM;

(a) Such an Offer shall be rejected in the RTBM if the Market Participant has

submitted a Resource commitment status of “not participating” as

described in Section 4.1(10)(e) of this Attachment AE and the Resource is

not participating in the Day-Ahead Market.

(3) Submitted Resource Offers will automatically roll forward hour to hour until

changed within each respective market;

(4) Offers may be submitted that vary for each hour of the Operating Day, except the

Offer parameters related to unit commitment as defined in the Market Protocols

for which a single value is submitted. These unit commitment Offer parameters

will automatically roll forward in each hour until updated;

(5) Offers submitted for use in the RTBM are also used in the RUC;

(6) Resource Offers may only be submitted at Resource Settlement Locations, Import

Interchange Transaction Offers may only be submitted at External Interface

Settlement Locations and Virtual Energy Offers may be submitted at any

Settlement Location, including a Market Hub;

(7) For Regulation Qualified Resources and Regulation-Up Qualified Resources,

Market Participants may submit Resource Offers for Regulation-Up Offers,

Regulation-Up Mileage Offers, Spinning Reserve Offers and Supplemental

Reserve Offers provided that if the Regulation-Up Offer is negative, the

Regulation-Up Mileage Offer must equal zero. For Regulation-Down Qualified

Resources and Regulation Qualified Resources, Market Participants may submit

Resource Offers for Regulation-Down Offers and Regulation-Down Mileage

Offers provided that if the Regulation-Down Offer is negative, the Regulation-

Down Mileage Offer must equal zero. For Spin Qualified Resources, Market

Participants may submit Resource Offers for Spinning Reserve and Supplemental

Reserve. For Supplemental Qualified Resources, Market Participants may submit

Resource Offers for Supplemental Reserve. Resource qualifications are verified

by the Transmission Provider as part of the registration process as follows:

(a) A Regulation Qualified Resource, Regulation-Up Qualified Resource or

Regulation-Down Qualified Resource must pass a specific regulation test

as defined in Section 2.10.3 of this Attachment AE and must be capable of

deploying one hundred percent (100%) of cleared Regulation-Up and/or

Regulation-Down within the Regulation Response Time for a continuous

duration of sixty (60) minutes and provide telemetered output data that

meets the technical requirements specified in the Market Protocols.

(b) A Spin Qualified Resource must self-certify that the Resource is capable

of deploying one hundred percent (100%) of cleared Spinning Reserve or

cleared Supplemental Reserve within the Contingency Reserve

Deployment Period for a continuous duration of sixty (60) minutes and

provide telemetered output data that meets the technical requirements

specified in the Market Protocols.

(c) A Supplemental Qualified Resource must self-certify that the Resource is

capable of deploying one hundred percent (100%) of cleared

Supplemental Reserve from an off-line state within the Contingency

Reserve Deployment Period for a continuous duration of sixty (60)

minutes and provide telemetered output data that meets the technical

requirements specified in the Market Protocols.

(8) Resource Offers are limited by the Offer caps and floors specified in Section 4.1.1

of this Attachment AE;

(9) The Resource Offer parameters that constitute a valid Offer for use in either the

Day-Ahead Market or RTBM are submitted using the data formats, procedures,

and information defined in the Market Protocols and will include the following

(as further defined in the Market Protocols):

Resource Name

Resource Type

Start-up Offer

No-Load Offer

Energy Offer Curve

Regulation–Up and Regulation-Down Offers

Regulation-Up Mileage and Regulation-Down Mileage Offers

Spinning and Supplemental Reserve Offers

Sync-To-Min and Min-To-Off Times

Start-Up Time

Hot to Intermediate and Hot to Cold Times

Maximum Daily and Weekly Starts

Maximum Daily Energy

Maximum and Minimum Run Times

Minimum Down Time

Minimum Emergency Capacity Operating Limit and Run Time

Minimum Normal, Economic, and Regulation Capacity Operating Limits

Maximum Normal, Economic, and Regulation Capacity Operating Limits

Maximum Emergency Capacity Operating Limits and Run Time

Maximum Quick-Start Response Limit

Ramp-Rate-Up and Ramp-Rate-Down

Turn-Around Ramp Rate Factor

Regulation Ramp Rate

Contingency Reserve Ramp Rate

Resource Status

JOU Ownership Share

(10) Market Participants must specify a Resource commitment status as part of the

Resource Offer using the data formats, procedures, and information defined in the

Market Protocols. Market Participants use the commitment status to indicate;

(a) Whether they are self-committing a Resource;

(b) Whether the Resource may be committed by the Transmission Provider;

(c) Whether the Resource may be committed by the Transmission Provider

only to alleviate an anticipated Emergency Condition or local reliability

issue;

(d) Whether the Resource is on an outage; or

(e) Whether the Resource is not participating in the Day-Ahead Market.

(11) Market Participants must specify a Resource dispatch status as part of the

Resource Offer using the data formats, procedures and information defined in the

Market Protocols. Market Participants use the dispatch status to notify the

Transmission Provider whether the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

(12) Resource limits submitted as part of the Resource Offer must pass the validation

rules defined in the Market Protocols, otherwise, the Resource Offer will be

rejected; and

(13) The Market Participant must comply with the must-offer requirements as defined

in Section 2.11 of this Attachment AE.


Submission of Energy Offer Curves, Start-Up Offers, No-Load Offers, and

Operating Reserve Offers by Market Participants for use in the Day-Ahead Market and

the RTBM shall be limited by the following Offer caps and floors:

(1) Safety-net Energy Offer cap = $1,000/MWh;

(2) Regulation-Up Service Offer cap = $500/MW;

(3) Regulation-Down Service Offer cap = $500/MW;

(4) Contingency Reserve Offer cap = $100/MW;

(45) Energy Offer floor = Negative $500/MWh;

(56) Regulation Service Offer floor = Negative $500/MW;

(7) Regulation-Up Mileage Offer floor = $0/MW;

(8) Regulation-Down Mileage Offer floor = $0/MW;

(69) Contingency Reserve Offer floor = Negative $100/MW;

(710) Start-Up Offer floor = $0;

(811) No-Load Offer floor = $0.

In addition to these Offer caps and floors, submission of Offers may be limited by

the requirements of Attachment AF of this Tariff.


The Transmission Provider will employ a simultaneous co-optimization

methodology to perform the following tasks in order to clear the Day-Ahead Market for

each hour of the upcoming Operating Day:

(1) Commit Offered Resources, Import Interchange Transaction Offers and Virtual

Energy Offers using the SCUC algorithm to meet the Demand Bids, Virtual

Energy Bids, Export Interchange Transactions Bids and Operating Reserve

requirements on a least cost basis for each hour of the upcoming Operating Day.

(a) The Day-Ahead Market SCUC algorithm will initially consider

commitment of Resources not specified for reliability only use as

described in Section 4.1(10)(c) of this Attachment AE, including

Resources committed in the Multi-Day Reliability Assessment, up to the

Resources’ Maximum Economic Capacity Operating Limit or Maximum

Regulation Capacity Operating Limit if selected for Regulation-Up

Service, and down to the Resources’ Minimum Economic Capacity

Operating Limit or Minimum Regulation Capacity Operating Limit if


(i) If this capacity is not sufficient to meet the fixed Demand Bids and

fixed Export Interchange Transaction Bids plus Operating Reserve

requirements on a system-wide basis, the Day-Ahead Market



eliminated; and (2) incorporate capacity up to Resources’

Maximum Emergency Capacity Operating Limits and/or commit

Resources designated as reliability only use, as described in

Section 4.1(10)(c) of this Attachment AE, on an economic basis

until the capacity shortage is eliminated while attempting to

maintain the Regulation-Up requirement to the extent possible .

(ii) If there is a capacity surplus on a system-wide basis calculated as

the sum of self-committed capacity at minimum output, fixed

Import Interchange Transaction Offers and the Regulation-Down

requirement that is in excess of the sum of fixed Demand Bids and

fixed Export Interchange Transaction Bids, the Day-Ahead Market


Import Interchange Transaction Offers until the capacity surplus is

eliminated; and (2) incorporate capacity down to Resources’

Minimum Emergency Capacity Operating Limits until the capacity

surplus is eliminated while attempting to maintain the Regulation-

Down requirement.

(b) To the extent that a particular reliability issue cannot be directly addressed

within the Day-Ahead Market SCUC algorithm as described under

Subsections (i) and (ii) above, the Transmission Provider may manually

commit Resources to alleviate such reliability issues. The Transmission

Provider will re-run the Day-Ahead SCUC algorithm after such manual

commitments, time permitting, and will notify the Market Participants that

units were manually committed.

(2) Using the Resource commitment results from the SCUC, clear Resource Offers,

Virtual Energy Offers and Import Interchange Transaction Offers to meet

Demand Bids, Virtual Energy Bids, Export Interchange Transaction Bids and

Operating Reserve requirements on a least cost basis for each hour of the

upcoming Operating Day using the SCED algorithm.

(a) The SCED algorithm includes marginal loss sensitivity factors that

approximate the change in marginal system losses for a change in Energy

dispatch.

(b) In certain situations, enforcing constraints may result in a solution that is

not feasible at a Shadow Price less than an appropriately priced VRL. In

such cases, the Transmission Provider must apply VRLs in SCED as


(c) The SCED algorithm will include product substitution logic as follows to

clear Operating Reserve Offers:

(i) Any Regulation-Up Offers remaining once the Regulation-Up

Requirement is satisfied may be used to meet Contingency Reserve

requirements if Regulation-Up Offer is more economic or is

required to meet the overall Operating Reserve requirement;

(ii) Any Spinning Reserve Offers remaining once the Spinning

Reserve Requirement is satisfied may be used to meet

Supplemental Reserve requirements if Spinning Reserve Offer is

more economic or is required to meet the overall Operating

Reserve requirement; and

(iii) The product substitution logic ensures that the MCP for

Regulation-Up Service is always greater than or equal to the

Spinning Reserve MCP and that the Spinning Reserve MCP is

always greater than or equal to the Supplemental Reserve MCP.

(d) Use of co-optimization logic will provide, through the Shadow Price

calculation, MCPs for Operating Reserve that include any lost opportunity

costs incurred as a result of Operating Reserve clearing.

5.1.2.1 Clearing During Capacity Shortage

(1) In the event of an Operating Reserve shortage in any hour that is not due to ramp

limitations, Scarcity Pricing shall be implemented.

(2) In the event of a capacity shortage to meet the fixed Demand Bids and fixed firm

Export Interchange Transactions in any hour, the fixed Demand Bids and fixed

firm Export Interchange Transactions will be reduced on a pro-rata reduction

basis based on the fixed MW amounts to match the available capacity and

Scarcity Pricing shall be implemented.

(3) The Transmission Provider may implement sharing of ramping capability

between Energy and Operating Reserve product clearing to ensure, to the extent

possible, that short-term ramping deficiencies from hour to hour do not initiate

Scarcity Pricing as described in Section 8.3.4.2(2) of this Attachment AE. To the

extent that ramp sharing is implemented, it shall remain in effect in all hours of

the Day-Ahead Market, in order to clear sufficient amounts of Energy,

Regulation-Up Service and Spinning Reserve to meet the requirements. The

Transmission Provider will not implement ramp sharing that will result in the

inability to meet applicable NERC reliability standards and control performance

requirements.

(4) If a transmission constraint cannot be relieved due to a shortage of capacity in any

hour, the SCED algorithm will clear the bid-in demands on a pro-rata basis based

upon the impact on relieving the constraint.

5.1.2.2 Clearing During Excess Generation Conditions

In the event the sum of the Minimum Emergency Capacity Operating Limits on

self-committed Resources plus the Regulation-Down requirement is in excess of the

cleared bid-in demands in any hour, the SCED algorithm will reduce Resources on a pro-

rata reduction basis such that the resulting sum of minimum limits matches the bid-in

demand. LMPs will be set by the Offer prices associated with Energy down to the

Minimum Emergency Capacity Operating Limit to the extent that the Regulation-Down

requirement can be maintained. If the actions under Section 5.1.2(1)(a)(ii) above create a

Regulation-Down Service shortage during any hour either on a system-wide basis or

Reserve Zone basis, the MCPs for Regulation-Down Service will reflect Scarcity Prices

and LMPs will reflect negative Scarcity Prices as set by the Regulation-Down Service

Demand Curve price described under Section 8.3.4.2 of this Attachment AE.


No later than 1600 hours Day-Ahead, the Transmission Provider will notify each

Market Participant of the Day-Ahead Market results for each hour of the Operating Day.

The following results are communicated to each Market Participant for only its

specific Resources:

(1) Cleared Resource Offers for Energy, Regulation-Up Service, Regulation-Down

Service, Spinning Reserve or Supplemental Reserve;

(a) Cleared Offers for Energy associated with Resource Offers represent a

physical Resource commitment.

(b) Resources committed by the Transmission Provider in the Day-Ahead

Market that incur one or more start-up costs within the Operating Day as a

result of the Transmission Provider Day-Ahead Market commitment are

guaranteed to receive revenues that are at least equal to the Resource Offer

costs for the cleared amount of Energy, Regulation-Up Service,

Regulation-Down Service, Spinning Reserve or Supplemental Reserve for

that Resource.

(2) Cleared Virtual Energy Offers;

(3) Cleared Import Interchange Transaction Offers;

(4) Cleared Demand Bids;

(5) Cleared Virtual Energy Bids;

(6) Cleared Export Interchange Transaction Bids; and

(7) Cleared Through Interchange Transactions.

The following results are communicated to all Market Participants:

(1) LMPs for each Settlement Location, the marginal Energy component (“MEC”) of

the LMP, the Marginal Congestion Component (“MCC”) of the LMP and the

Marginal Loss Component (“MLC”) of the LMP for each Settlement Location;

and

(2) MCPs for Regulation-Up Service, Regulation-Down Service, Spinning Reserve

and Supplemental Reserve for each Reserve Zone.


The Transmission Provider will perform a capacity adequacy analysis for the

upcoming Operating Day using the SCUC algorithm with the objective of committing

Resources to meet the Transmission Provider load forecast and Operating Reserve

requirements over the Operating Day such that commitment costs are minimized while

adhering to Transmission System security constraints and the Resource operating



Offer and incremental cost to operate at minimum output as defined in the

submitted Energy Offer Curve.



Attachment AE, up to the Resources’ Maximum Economic Capacity Operating

Limit or Maximum Regulation Capacity Operating Limit if selected for

Regulation-Up Service, and down to the Resources’ Minimum Economic

Capacity Operating Limit or Minimum Regulation Capacity Operating Limit if



Transmission Provider load forecast plus Operating Reserve requirements,

the SCUC algorithm will, in priority order: (1) Curtail non-firm fixed


eliminated; and (2) Incorporate capacity up to Resources’ Maximum





(b) If there is a capacity surplus on a system-wide basis calculated as the sum

of self-committed capacity at minimum output, fixed Import Interchange



Interchange Transaction Bids, the SCUC algorithm will, in priority order:

(1) curtail non-firm fixed Import Interchange Transaction Offers until the

capacity surplus is eliminated; (2) incorporate capacity down to

Resources’ Minimum Emergency Capacity Operating Limits until the

capacity surplus is eliminated while attempting to maintain the

Regulation-Down requirement; (3) de-commit Resources that were

committed by the Transmission Provider in the Day-Ahead Market that

were not self-committed until the capacity surplus is eliminated; and (4)

de-commit self-committed Resources until the capacity surplus is

eliminated.

(3) To the extent that a particular Transmission System security constraint cannot be

directly addressed within the SCUC algorithm, the Transmission Provider may

manually commit Resources and/or decommit Resources, including self-

committed Resources to alleviate such a Transmission System security constraint

in accordance with its authority as Reliability Coordinator.

(a) A reliability issue may arise within the operating area of a local

transmission operator during the Day-Ahead Reliability Unit Commitment

process. Such reliability issues may require out of merit commitment,

decommitment, or dispatch instructions to be issued to one or more

Resources to resolve the reliability issue. In such cases, the local

transmission operator shall request the Transmission Provider to issue

such instructions. To the extent that the Transmission Provider, at the

request of a local transmission operator, issues instructions to a Resource

to address a reliability issue, such Resource shall be eligible for

compensation in the same manner as any other Resource. Recovery of

such compensation shall be collected regionally as described under

Section 8.6.7(A) of this Attachment AE, unless the Transmission Provider

determines that the instructions were required for a Local Reliability

Issue; in such case recovery of such compensation shall be collected



Using the inputs described in Section 6.1.1, the Transmission Provider will

perform a capacity adequacy analysis using the SCUC algorithm with the objective of

committing Resources to meet the Transmission Provider’s load forecast and Operating

Reserve requirements over the Operating Day such that commitment costs are minimized

while adhering to Transmission System security constraints and the resource operating



Offer and incremental cost to operate at minimum output as defined on the

submitted Energy Offer Curve. Incremental Energy costs above minimum output

and Operating Reserve Offers are not considered by the SCUC in making

commitment decisions.



Attachment AE, only including capacity up to the Resources’ Maximum

Economic Capacity Operating Limits (or Maximum Regulation Capacity

Operating Limits if selected for Regulation-Up Service) and down to the

Resources’ Minimum Economic Capacity Operating Limits (or Minimum

Regulation Capacity Operating Limits if selected for Regulation-Down Service).


Transmission Provider’s load forecast plus Operating Reserve

requirements, the SCUC algorithm will, in priority order: (1) Curtail non-

firm fixed Export Interchange Transaction Bids until the capacity shortage

is eliminated; and (2) Incorporate capacity up to Resources’ Maximum





(b) If there is a system-wide capacity surplus calculated as the sum of self-

committed capacity at minimum output, fixed Import Interchange



Interchange Transaction Bids, the Day-Ahead Market SCUC algorithm

will, in priority order: (1) Curtail non-firm fixed Import Interchange

Transaction Offers until the capacity surplus is eliminated; (2) Incorporate

capacity down to Resources’ Minimum Emergency Capacity Operating

Limits until the capacity surplus is eliminated while attempting to

maintain the Regulation-Down requirement; (3) De-commit Resources

that were committed by the Transmission Provider in the Day-Ahead

Market that were not self-committed until the capacity surplus is

eliminated; and (4) De-commit self-committed Resources until the

capacity surplus is eliminated.

(3) To the extent that a particular reliability issue cannot be directly addressed within

the SCUC algorithm as described under subsections (a) and (b) above, the

Transmission Provider or local transmission operator may manually commit

Resources and/or decommit Resources, including self-committed Resources to

alleviate such reliability issues.

(4) A Local Reliability Issue may arise within the operating area of a local

transmission operator during the Intra-Day Reliability Unit Commitment Process.

Such Local Reliability Issues may require out of merit commitment,

decommitment, or dispatch instructions to be issued to one or more Resources to

resolve the Local Reliability Issue. Time permitting, the local transmission

operator shall request the Transmission Provider to issue such instructions. To

the extent time does not permit, the local transmission operator may issue such

instructions to the Resource. In such cases, the following shall take place:

(a) If initial instructions are issued by a local transmission operator, the

transmission operator shall notify the Transmission Provider of the

instructions given to the Resource.

(b) The transmission operator and Transmission Provider will coordinate to

ensure subsequent instructions are provided by the Transmission Provider.

(c) The transmission operator shall log such instructions, and shall notify the

Transmission Provider of such action. The Transmission Provider shall

log such instructions as manual commitment, decommitment, or OOME

Dispatch instruction, as appropriate, as if it gave such instruction to the

Resource.

(d) The Resource shall be eligible to receive the compensation for such

instructions in the same manner as if it had been committed by the

Transmission Provider; provided that the Transmission Provider

determines that the Resource selected in response to such instructions was

selected in a non-discriminatory manner. Such determination shall be

made using the standards and procedures set forth in Section 6.1.2.1 of

this Attachment AE. If the Transmission Provider determines that

instructions were issued to resolve a Local Reliability Issue, recovery of

such compensation shall be collected locally as described under Section

8.6.7(B) of this Attachment AE.

(5) In the event that the local transmission operator issues instructions to a Resource

to resolve an issue other than a Local Reliability Issue, the Resource will be

compensated in the same manner as if it had been committed by the Transmission

Provider; provided that the Transmission Provider determines that the Resource

selected in response to such instructions was selected in a non-discriminatory

manner. Such determination shall be made using the standards and procedures

set forth in Section 6.1.2.1 of this Attachment AE. Recovery of such compensation

shall be collected regionally as described under Section 8.6.7(A) of this

Attachment AE.


the request of a local transmission operator to resolve a Local Reliability Issue,

the Resource will be compensated in the same manner as if it had been committed

by the Transmission Provider. Recovery of such compensation shall be collected



the request of a local transmission operator to resolve an issue other than a Local

Reliability Issue, the Resource will be compensated in the same manner as if it

had been committed by the Transmission Provider. Recovery of such

compensation shall be collected regionally as described under Section 8.6.7(A) of

this Attachment AE.

6.1.2.1 Determination of Non-Discriminatory Resource Selection by a Local

Transmission Operator

The Transmission Provider shall verify that the process used by the local

transmission operator to select Resources in the Intra-Day Reliability Unit

Commitment process in response to a reliability issue was performed in a non-

discriminatory manner. Such verification shall be performed as follows:

(i) The Transmission Provider’s evaluation of whether the selection process

was non-discriminatory shall consider the cost, ownership, resource

operating parameters, availability of non-selected Resources relative to the

selected Resources and any prior instances where the local transmission

operator committed Resources.

(ii) When the Transmission Provider determines that a Resource was selected

in a discriminatory manner, the Transmission Provider shall notify the

local transmission operator of the best practice should the situation arise

again.


Inputs into the RTBM will include the data provided prior to each Operating Hour

and data provided within each Operating Hour.

6.2.1.1 Pre-Operating Hour Inputs

Pre-Operating hour inputs to the RTBM will include the following:

(1) RTBM Resource Offers;

(2) Approved and tagged Export Interchange Transactions, Import Interchange

Transactions and Through Interchange Transactions;

(3) Operating Reserve requirements (system-wide and Reserve Zone minimum and

maximum);

(4) Resources selected to provide Regulation-Up Service or Regulation-Down

Service from the most recent RUC. This set of Resources will remain on

regulation control for the Operating Hour and will be used by SCED to clear

Regulation-Up and Regulation-Down on a five (5) minute basis to meet the

regulation requirements;

(5) Resource commitment from the Current Operating Plan. The Current Operating

Plan includes Resource commitments and Resource de-commitments from the

Multi-Day Reliability Assessment, Day-Ahead Market, Day-Ahead RUC and

Intra-Day RUC;

(6) Maximum Emergency Capacity Operating Limits on Resources identified in the

Day-Ahead RUC or Intra-Day RUC; and

(7) Minimum Emergency Capacity Operating Limits on Resources identified in the

Day-Ahead RUC or Intra-Day RUC.

6.2.1.2 Intra-Operating Hour Inputs

Intra-operating hour inputs to the RTBM will include the following:

(1) Latest State Estimator solution for:

(a) Distribution of load forecast throughout the Network Model;

(b) Latest transmission topology for the Network Model; and

(c) Backup initial Energy injection of Resources if SCADA not available;

(2) Actual Resource output from latest SCADA snapshot to determine initial Energy

injection of Resources and Generator outages;

(3) Active transmission constraints;

(4) Intra-operating hour adjustments to Interchange Transactions due to curtailments

or initiation of a Reserve Sharing Event involving external Balancing Authorities;

(5) Intra-operating hour adjustments to Resource Offer physical operating parameters

due to changes in a Resource’s capability. Market Participants shall notify the

Transmission Provider of a change in a Resource Offer physical operating

parameter during an Operating Hour. For the current Operating Hour the

Transmission Provider will make the requested modification to the Resource

Offer physical operating parameter. For subsequent hours the Market Participant

shall remain responsible for accurately reflecting Resource operating parameters

in its Resource Offer submissions;

(6) Intra-hour adjustments to selection of Resources to provide Regulation-Up

Service or Regulation-Down Service to the extent that Resources selected as

described under Section 6.2.1.1(4) become unavailable to provide regulation

service;

(7) Transmission Provider load forecast;

(8) The Transmission Provider’s wind Resource MWh output forecast; and

(9) The Transmission Provider’s estimate of Parallel Flows.


The Transmission Provider will execute the RTBM every five (5) minutes for the

next Dispatch Interval based on the inputs described above.

(1) A simultaneous co-optimization methodology utilizing a SCED algorithm is

employed to calculate Resource Dispatch Instructions and clear Regulation-Up

Service, Regulation Down Service, Spinning Reserve and Supplemental Reserve

to meet the Transmission Provider load forecast and Operating Reserve

requirements at minimum costs based upon submitted Offers while respecting

Resource operating constraints and transmission constraints.

(2) The SCED algorithm includes marginal loss sensitivity factors that approximate

the change in marginal system losses for a change in Energy dispatch.

(3) In certain situations, enforcing constraints may result in a solution that is not

feasible at a Shadow Price less than an appropriately priced VRL. In such cases,

the Transmission Provider must apply VRLs in SCED.

(4) To ensure rational pricing of cleared Operating Reserve products, the SCED

algorithm will include product substitution logic as follows:

(a) Any Regulation-Up Offers remaining once the Regulation-Up

Requirement is satisfied will be used to meet Contingency Reserve

requirements if Regulation-Up Offer is more economic or is needed to

meet the overall Operating Reserve requirement;

(b) Any Spinning Reserve Offers remaining once the Spinning Reserve

Requirement is satisfied will be used to meet the Supplemental Reserve

requirements if the Spinning Reserve Offer is more economic or is needed

to meet the overall Operating Reserve requirement.

(5) The co-optimization logic will provide through the Shadow Price calculation,

MCPs for Operating Reserve that include lost opportunity costs incurred as a

result of Operating Reserve clearing.

(6) Additionally, the Transmission Provider will execute a look-ahead SCED prior to

the RTBM SCED process. The look-ahead SCED will perform at least these two

functions: (1) anticipate the need to adjust Dispatch Instructions for the current

Dispatch Interval to prepare to meet forecasted changes in the load several

Dispatch Intervals into the future and (2) determine commitment of Quick-Start

Resources within the Operating Hour. The look-ahead period is at least two

Dispatch Intervals, one of which is the next Dispatch Interval following the

current Dispatch Interval.

6.2.2.1 Emergency Operations – Capacity Shortage

(1) In addition to the incorporation of the capacity up to Resources’ Maximum

Emergency Capacity Operating Limits prior to the Operating Hour as described

under Sections 5.1.2(1)(a)(i) and 5.2.2(2)(a) of this Attachment AE, the

Transmission Provider may incorporate any remaining emergency capacity limits

as needed during the Operating Hour. The Transmission Provider shall continue

implementation of emergency procedures which may have been implemented

prior to the Operating Hour or shall begin implementation of emergency

procedures within the Operating Hour, as needed, in accordance with its authority

as Reliability Coordinator.

(a) If there is an actual Operating Reserve shortage during a Dispatch Interval,

either on a system-wide or a Reserve Zone basis, the system-wide or

Reserve Zone Scarcity Prices will be implemented as specified in Sections

8.3.1 and 8.3.4.2 of this Attachment AE.

(b) If there is a shortage of available capacity to meet Energy requirements on

a system-wide, LMPs will be set through Scarcity Pricing procedures as

specified in Section 8.3.1 of this Attachment AE.

(2) Ramp sharing will continue to be applied consistent with its application in the

Day-Ahead Market as described under Section 5.1.2.1(3) of this Attachment AE.

6.2.2.2 Emergency Operations – Excess Generation

(1) The Transmission Provider will take any or all of the following actions, as time

permits, within the Operating Hour to address excess generation conditions on

either a system-wide or Reserve Zone basis:

(a) Notify any remaining Resources not cleared for Regulation-Down Service

and not notified prior to the Operating Hour that they will be dispatched

down to their Minimum Emergency Capacity Operating Limits;

(b) De-commit any remaining Resources that were self-committed following

the Day-Ahead RUC;

(c) Pro-rata curtail, on a MW basis, any remaining fixed non-firm Import

Interchange Transactions;

(d) Pro-rata curtail, on a per MW basis, any fixed firm Import Interchange

Transactions;

(e) Reduce Resources with cleared Regulation-Down Service economically,

as needed, down to Minimum Emergency Capacity Operating Limit; and

(f) Coordinate with generation Operators, SPP Balancing Authority Operator

and SPP Reliability Coordinator to de-commit generation to meet power

balance.

(2) If actions taken under (1) above are not sufficient to relieve the excess generation

condition in any Dispatch Interval either on a system-wide or Reserve Zone basis,

LMPs will be set to the lesser of zero (0) or the Offer prices associated with

Energy down to the Minimum Emergency Capacity Operating Limit, to the extent

that the Regulation-Down requirement can be maintained. If the actions under (1)

above create a Regulation-Down Service shortage during any Dispatch Interval

either on a system-wide or Reserve Zone basis, the MCPs for Regulation-Down

Service will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices.

(3) In parallel with the actions under (1) above, if there is a transmission constraint

within a Reserve Zone occurring simultaneously with a Reserve Zone excess

capacity event, the Transmission Provider may take any or all of the following

additional actions:

(a) Identify and communicate with the Market Participant concerning

Resources with greater than a five percent (5%) generation shift factor on

the constraint and fixed Import Interchange Transactions with greater than

a three percent (3%) transfer distribution factor on constraint;

(b) Issue Transmission Loading Relief (“TLR”) provisions, in accordance

with Attachment R, to curtail any Interchange Transactions that may be

contributing to the loading;

(c) Commit Quick Start Resources in the constrained area if they can be re-

dispatched with other Resources in the constrained area to relieve

constraint without contributing to the excess capacity situation.

6.2.2.3 Seams Coordination

The Transmission Provider shall use the following process to coordinate the

operations of the RTBM to manage congestion between the SPP Balancing Authority

Area and external Balancing Authority Areas:

(a) The Transmission Provider shall submit the Market Flow impact on each

Coordinated Flowgate and Reciprocal Coordinated Flowgate to the NERC

IDC.

(b) The Transmission Provider shall assign curtailment priorities to the

Market Flow on each flowgate in the following priority categories:

(i) Curtailment priorities for flowgates that have not been defined as a

Coordinated Flowgate or a Reciprocal Coordinated Flowgate shall

be assigned in accordance with NERC TLR procedures.

(ii) For Coordinated Flowgates, the Transmission Provider will assign

Market Flow in the firm priority up to the firm limit with any

excess Market Flow assigned as non-firm network.

(iii) For Reciprocal Coordinated Flowgates, the Transmission Provider

will divide its Market Flows into firm, non-firm network, and non-

firm hourly curtailment priorities. The Transmission Provider will

first assign Market Flow in the firm priority up to the firm limit,

then assign remaining Market Flow in the non-firm network

priority up to the non-firm network limit, and finally assign any

excess Market Flow as non-firm hourly.

(c) The Market Flow associated with operation of the RTBM shall be

determined by the Transmission Provider. For Coordinated Flowgates,

any Market Flow from RTBM operation in excess of that assigned to the

firm priority shall be assigned a non-firm priority. For Reciprocal

Coordinated Flowgates, any Market Flow from RTBM operation in

excess of amounts assigned to firm or non-firm network priorities shall be

assigned a non-firm hourly priority.

(d) When congestion occurs on a flowgate that requires a TLR event, the

NERC IDC will identify the amount of relief required from Market Flows

on the Coordinated Flowgate or Reciprocal Coordinated Flowgate.

(e) The Transmission Provider shall achieve the required reduction in Market

Flows provided by the NERC IDC using its security constrained dispatch

software in the following order until the desired reduction in Market

Flows is achieved:

(i) To the extent that Market Flows are contributing to the constrained

condition, the Transmission Provider shall restrict the ability of the

market operating system from contributing further to the

constrained condition by binding the Coordinated Flowgate or

Reciprocal Coordinated Flowgate constraint. The security

constrained dispatch of Dispatchable Resources shall continue

within each priority level until the Market Flows within that

priority level have been reduced to zero or the flowgate constraint

is eliminated, whichever comes first.


Following execution of the RTBM SCED, the Transmission Provider shall

communicate the results to Market Participants prior to the start of the applicable

Dispatch Interval.

(1) The following results are communicated to each Market Participant for only its

specific Resources:

(a) Resource Dispatch Instructions. The Dispatch Instruction is a MW output

target for the end of the applicable Dispatch Interval.

(b) Cleared Regulation-Up Service, Regulation-Down Service, Spinning

Reserve and Supplemental Reserve MW by Resource.

(2) The following results are communicated to all Market Participants and are used

for settlement purposes;

(a) LMPs for each Settlement Location, the MCC of LMP for each Settlement

Location and the MLC of LMP for each Settlement Location.

(b) MCPs for Regulation-Up Service, Expected Regulation-Up Mileage,

Regulation-Down Service, Expected Regulation-Down Mileage, Spinning

Reserve and Supplemental Reserve for each Reserve Zone.


The Transmission Provider will deploy Energy, Regulation-Up Service,

Regulation-Down Service, Spinning Reserve and on-line Supplemental Reserve

simultaneously through the issuance of Setpoint Instructions to each Resource in

accordance with the technical requirements specified in the Market Protocols.

Deployment of Supplemental Reserve from off-line Quick-Start Resources is

accomplished through the Transmission Provider issuance of a Commitment Instruction

to start-up following a Contingency Reserve event.

(1) The Setpoint Instruction for a Resource that has indicated that it is dispatchable is

equal to the sum of:

(a) The Resource MW Dispatch Instruction for the current Dispatch Interval

either as developed by SCED or by Manual Dispatch Instruction;

(b) Regulation-Up Service deployment instruction for Resources with cleared

Regulation-Up Service;

(c) Regulation-Down Service deployment instruction for Resources with

cleared Regulation-Down Service;

(d) Spinning Reserve deployment instruction for Resources with cleared

Spinning Reserve; and

(e) On-Line Supplemental Reserve deployment instruction for Resources with

cleared on-line Supplemental Reserve.

(2) The Setpoint Instruction for a Resource that has indicated that it is non-

dispatchable shall be equal to the most recently recorded actual telemetered

Resource output.


Regulation Deployment is limited to Resources that have cleared Regulation-Up

Service or Regulation-Down Service. Regulation-Up Service and Regulation-Down

Service are deployed on specific Resources through Setpoint Instructions via the

automatic generation control system on a pro-rata basis based upon Regulation-Up

Service or Regulation-Down Service cleared MW, adjusted as needed to ensure

deliverability. No Regulation Deployment will occur on Resources that have not cleared

Regulation-Up Service or Regulation-Down Service. Market Participants providing

Regulation-Up Service or Regulation-Down service Service during the Operating Hour

are obligated to report to the Transmission Provider when their Resources are no longer

capable of providing the service due to physical problems.


In any Dispatch Interval, if the URD of a Resource with cleared Regulation-Up

Service, Regulation-Down Service or both is outside of the Resource’s Operating

Tolerance, that Market Participant will incur a Regulation Deployment failure charge as



The MCP represents the cost of supplying an increment of Operating Reserve,

taking into account lost opportunity cost and is composed of the marginal Operating

Reserve costs and marginal costs associated with Operating Reserve scarcity. The Day-

Ahead Market and RTBM MCPs at a Reserve Zone for Resources with cleared

Regulation-Up Service, Regulation-Down Service, Spinning Reserve and/or

Supplemental Reserve in that Reserve Zone are equal to the summation of the applicable

Shadow Prices associated with the constraints as described in subsections (1) and (2)

below. Calculation of MCPs for Expected Regulation-Up Mileage and Expected

Regulation-Down Mileage are calculated as described in subsections (3) and (4) below:

(1) There are four sets of constraints which apply on both a system-wide basis and a

Reserve Zone basis:

(a) A contingency reserve plus regulation-up constraint is equal to the sum of

the Contingency Reserve requirement and the Regulation-Up requirement;

(b) A regulation-up plus spinning reserve constraint is equal to the sum of the

Regulation-Up requirement and the Spinning Reserve requirement;

(c) A regulation-up constraint is equal to the Regulation-Up requirement; and

(d) A regulation-down constraint is equal to the Regulation-Down

requirement.

(2) Operating Reserve MCPs for each Reserve Zone are calculated as follows:

(a) The Regulation-Up Service MCP is equal to sum of the Shadow Prices for

the system-wide and zonal regulation-up constraints, system-wide and

zonal regulation-up plus spinning reserve constraints and the system-wide

and zonal contingency reserve plus regulation-up constraints;

(b) The Spinning Reserve MCP is equal to the sum of the Shadow Prices for

the system-wide and zonal regulation-up plus spinning reserve constraints

and the system-wide and zonal contingency reserve plus regulation-up

constraints;

(c) The Supplemental Reserve MCP is equal to the sum of the Shadow Prices

for the system-wide and zonal contingency reserve plus regulation-up

constraints; and

(d) The Regulation-Down Service MCP is equal to the Shadow Price for the

system-wide and zonal regulation-down constraint.

(3) RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest

Regulation-Up Mileage Offer of all Resources economically cleared to provide

Regulation-Up Service in a particular Dispatch Interval, multiplied by the

Regulation-Up Mileage Factor. For Resources submitting a Regulation-Up


AE, the cleared amount of Regulation-Up Service MW must be greater than the

submitted self-schedule MW in order to be considered economically cleared;

(4) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest

Regulation-Down Mileage Offer of all Resources economically cleared to provide

Regulation-Down Service in a particular Dispatch Interval, multiplied by the

Regulation-Down Mileage Factor. For Resources submitting a Regulation-Down


AE, the cleared amount of Regulation-Down Service MW must be greater than

the submitted self-schedule MW in order to be considered economically cleared;

(5) In the event a system-wide failure of the RTBM systems results in a loss of the

ability to calculate MCPs, RTBM Operating Reserve will continue to be settled

financially under this Tariff based upon estimated MCPs. The Transmission

Provider shall notify Market Participants if RTBM Operating Reserve is to be

settled using estimated prices.

(a) If the failure of the RTBM systems occurs for twelve (12) Dispatch

Intervals or less, the estimated MCPs shall be the most recently calculated

MCPs for each affected Reserve Zone and shall be utilized for settlement

purposes for each of the Dispatch Intervals in which MCP pricing data is

missing.

(b) If the failure of the RTBM systems occurs for more than twelve (12)

Dispatch Intervals, the Transmission Provider shall calculate MCPs using

mitigated Offers for the RTBM in a manner that reflects, as closely as

practicable, the MCPs that would have resulted but for the RTBM systems

failure, and shall use such MCPs for settlement purposes for each of the

Dispatch Intervals in which MCP pricing data is missing. To the extent

that the Transmission Provider is unable to calculate RTBM MCPs, the

Transmission Provide shall use the MCPs generated in the Day-Ahead

Market for RTBM settlement.

(46) If for any reason a portion of generation and load within the SPP Balancing

Authority Area becomes isolated from the rest of the SPP Balancing Authority

Area (“Island”), RTBM MCPs will not be calculated and procurement of

Operating Reserve within the Island will not be performed.

8.3.4.1 Impact of Violation Relaxation Limits on Market Clearing Prices

When the Shadow Price of the regulation-up plus spinning reserve constraint is

exceeded, the Spinning Reserve requirement will be relaxed such that the Shadow Price

of the regulation-up plus spinning reserve constraint is less than or equal to the

regulation-up plus spinning reserve constraint VRL value.

8.3.4.2 Impact of Scarcity Pricing on Market Clearing Prices

(1) The Transmission Provider shall use Demand Curves to limit Shadow Prices of

the Operating Reserve constraints described under Section 8.3.4 of this

Attachment AE in both the Day-Ahead Market and RTBM during times of

Operating Reserve shortages, either on a system-wide and/or Reserve Zone basis.

(2) Operating Reserve shortages caused by insufficient ramping capability shall not

be subject to Scarcity Pricing.

(3) Shadow Prices are limited using the following Demand Curves that apply on a

system-wide and Reserve Zone basis as follows:

(a) Operating Reserve Demand Curve – Shadow Prices of the system-wide

and/or zonal Contingency Reserve plus Regulation-Up constraint are

limited to the sum of the safety-net Energy Offer cap and the Contingency

Reserve Offer cap as specified in Section 4.1.1 of this Attachment AE.

(b) Regulation-Up Demand Curve – Shadow Prices of the system-wide

Regulation-Up constraint are limited to the sum of the Regulation-Up



(c) Regulation-Down Demand Curve – Shadow Prices of the system-wide

Regulation-Up constraint are limited to the sum of the Regulation-Down




A Day-Ahead Market payment for cleared Regulation-Up Service and cleared

Regulation-Down Service will be calculated at each Settlement Location for each Asset


(1) Regulation-Up Service

Day-Ahead Regulation-Up Service Hourly Amount =

[(Day-Ahead MCP) * (Day-Ahead Cleared Regulation-Up Service Hourly

Quantity)] * (-1)


Regulation-Up Service associated with the Reserve Zone in which the


(b) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service Hourly

Quantity is the MW quantity associated with cleared Regulation-Up


(2) Regulation-Down Service

Day-Ahead Regulation-Down Service Hourly Amount =

[(Day-Ahead MCP) * (Day-Ahead Cleared Regulation-Down Service Hourly

Quantity)] * (-1)




(b) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service Hourly

Quantity is the MW quantity associated with cleared Regulation-Down



A Day-Ahead Market charge for Regulation-Up Service procurement costs



Day-Ahead Regulation-Up Service Hourly Distribution Amount =

[(Day-Ahead Regulation-Up Service Obligation) * (Day-Ahead Regulation-Up

Procurement Rate)]

(1) An Asset Owner’s Day-Ahead Regulation-Up Service Obligation in each Reserve

Zone is equal to the system wide total of all cleared Regulation-Up Service

multiplied by the Asset Owner Reserve Zone Load Ratio Share, adjusted up or

down to account for any Bilateral Settlement Schedules for Regulation-Up

Service.

(2) For a Reserve Zone that clears more Regulation-Up Service than the sum of Asset


the zone is deemed an exporting zone and the Day-Ahead Regulation-Up Service

Procurement Rate is equal to the Regulation-Up Service MCP for that Reserve

Zone.

(3) For a Reserve Zone that clears less Regulation-Up Service than the sum of Asset


the Day-Ahead Regulation-Up Service Procurement Rate is as follows:

Day-Ahead Regulation-Up Service Procurement Rate =

{(Reserve Zone Regulation-Up Service MCP * Total of cleared

Regulation-Up Service for that Reserve Zone) + [(Weighted Average

Regulation-Up Service MCP of all Exporting Zones) * (Sum of Asset

Owners’ Day-Ahead Regulation-Up Service Obligations for that Reserve

Zone - Total of cleared Regulation-Up Service for that Reserve Zone)]} /

(Sum of Asset Owners’ Day-Ahead Regulation-Up Service Obligations

for that Reserve Zone).


A Day-Ahead Market charge for Regulation-Down Service procurement costs



Day-Ahead Regulation-Down Service Hourly Distribution Amount =

[(Day-Ahead Regulation-Down Service Obligation) * (Day-Ahead Regulation-

Down Service Procurement Rate)]

(1) An Asset Owner’s Day-Ahead Regulation-Down Service Obligation in each

Reserve Zone is equal to the system wide total of all cleared Regulation-Down

Service multiplied by the Asset Owner Reserve Zone Load Ratio Share, adjusted

up or down to account for any Bilateral Settlement Schedules for Regulation-

Down.

(2) For a Reserve Zone that clears more Regulation-Down Service than the sum of


Zone, the zone is deemed an exporting zone and the Day-Ahead Regulation-

Down Service Procurement Rate is equal to the Regulation-Down Service MCP

for that Reserve Zone.

(3) For a Reserve Zone that clears less Regulation-Down Service than the sum of


Zone, the Day-Ahead Regulation-Down Service Procurement Rate is as follows:

Day-Ahead Regulation-Down Service Procurement Rate =

{(Reserve Zone Regulation-Down Service MCP * Total of cleared

Regulation-Down Service for that Reserve Zone) + [(Weighted Average

Regulation-Down Service MCP of all Exporting Zones) * (Sum of Asset

Owners’ Day-Ahead Regulation-Down Service Obligations for that

Reserve Zone - Total of cleared Regulation-Down Service for that Reserve

Zone)]} / (Sum of Asset Owners’ Day-Ahead Regulation-Down Service

Obligations for that Reserve Zone).


(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner

and is calculated for each Resource with an associated Day-Ahead Market

Commitment Period that was committed by the Transmission Provider with a

Day-Ahead Market Resource Offer commitment status as defined under Sections

4.1(10)(b) and (c) of this Attachment AE, or was committed as part of the Multi-

Day Reliability Assessment as defined under Section 4.5.3 of this Attachment AE.

A payment is made to the Asset Owner when the sum of the Resource’s costs is

greater than the Day-Ahead Market revenues received for that Resource over the

Resource’s Day-Ahead Market make whole payment eligibility period. The make

whole payment is equal to this difference between these costs and revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal

to a Resource’s Day-Ahead Market Commitment Period except as defined herein.

For Resources with an associated Day-Ahead Market Commitment Period that

begins in one Operating Day and ends in the next Operating Day, two (2) Day-

Ahead Market make whole payment eligibility periods are created. The first

period begins in the first Operating Day in the hour that the Day-Ahead Market

Commitment Period begins and ends in the last hour of the first Operating Day.

The second period begins in the first hour of the next Operating Day and ends in

the last hour of the Day-Ahead Market Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole

payment eligibility period. Offer costs are calculated using the Day-Ahead

Market Offer prices in effect at the time the commitment decision was made

except under the situation described under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment

eligibility period for a Resource in a single Operating Day for which a

charge or payment is calculated. A single Day-Ahead Market make whole


(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for

recovery in the following Day-Ahead Market make whole payment

eligibility periods:

(i) For any Day-Ahead Market make whole payment eligibility period

that is adjacent to the end of a RUC make whole payment

eligibility period except as described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that

contains a Day-Ahead Market self-commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for

which a Resource is a Synchronized Resource prior to this

commitment period at a time one (1) hour prior to that Resource’s

Day-Ahead Market Commit Time less the Resource’s Sync-To-

MinTime.

(c) For each Day-Ahead Market make whole payment eligibility period

within an Operating Day, a Resource’s Day-Ahead Market Start-Up Offer

is divided by the lesser of (1) the Resource’s Minimum Run Time rounded

down to the nearest hour or (2) twenty-four (24) hours, and that portion of

the Start-Up Offer is included as a cost in each hour of the Day-Ahead

Market make whole payment eligibility period until the sum of these

hourly costs are equal to the Day-Ahead Market Start-Up Offer or until the

end of the Day-Ahead Market make whole payment eligibility period,

whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up

Offer is not accounted for in the last Day-Ahead Market make whole

payment eligibility period in the Operating Day, any remaining Day-

Ahead Market Start-Up Offer costs are carried forward for recovery in the

first Day-Ahead Market make whole payment eligibility period of the

following Operating Day.


given Day-Ahead Market make whole payment eligibility period is calculated as

follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment

Cost Amount in the Day-Ahead Market Make Whole Payment Eligibility

Period) + (Day-Ahead Make Whole Payment Revenue Amount in the

Day-Ahead Market Make Whole Payment Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for

each eligible Resource is equal the sum for all hours in the Day-Ahead

Market Make Whole Payment Eligibility Period of:

(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Energy cost associated with cleared Resource Energy from


Attachment AE, as calculated by multiplying cleared Resource

Energy by the cost of such Energy as calculated from the

Resource’s Day-Ahead Market Energy Offer Curve,

(iv) Regulation-Up Service cost associated with cleared Regulation-Up

Service from Regulation-Up Service Offers as described under


Regulation-Up Service by the cost of such Regulation-Up Service

as calculated from the Resource’s Day-Ahead Market Regulation-

Up Service Offer,

(v) Regulation-Down Service cost, associated with cleared

Regulation-Down Service from Regulation-Down Service Offers

as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying Regulation-Down Service by the cost of

such Regulation-Down Service as calculated from the Resource’s

Day-Ahead Market Regulation-Down Service Offer,

(vi) Spinning Reserve cost, associated with cleared Spinning Reserve

from Spinning Reserve Offers as described under Section 5.1.3 of

this Attachment AE, as calculated by multiplying Spinning

Reserve by the cost of such Spinning Reserve as calculated from

the Resource’s Day-Ahead Market Spinning Reserve Offer, and

(vii) Supplemental Reserve cost, associated with cleared Supplemental

Reserve from Supplemental Reserve Offers as described under


Supplemental Reserve by the cost of such Supplemental Reserve

as calculated from the Resource’s Day-Ahead Market

Supplemental Reserve Offer

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount

for each eligible Resource is equal to the sum for all hours in the Day-

Ahead Market Make Whole Payment Eligibility Period of:

(i) Energy revenue associated with cleared Resource Energy from


Attachment AE, calculated by multiplying Resource Energy by

Day-Ahead LMP at that Resource Settlement Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and

8.5.4 for that eligible Resource.



RTBM Regulation-Up Service and cleared Day-Ahead Market Regulation-Up,

(ii) Excess Regulation-Up Mileage and (iii) Unused Regulation-Up Mileage, will

be calculated at each Settlement Location for each Asset Owner for each Dispatch

Interval and hour as follows:

(a) Real-Time Regulation-Up Service Dispatch Interval Amount =

[[(Real-Time MCP) * ((Real-Time Cleared Regulation-Up Service

Dispatch Interval Quantity) - (Day-Ahead Regulation-Up Hourly

Quantity)) / 12] - Unused Regulation-Up Mileage Dispatch Interval

Amount + Excess Regulation-Up Mileage Dispatch Interval Amount] * (-

1)


AE, for Regulation-Up Service associated with the Reserve Zone

in which the applicable Resource is located.

(ii) An Asset Owner’s Real-Time Cleared Regulation-Up Service


cleared RTBM Regulation-Up Service Offers as described under


(iii) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service


Ahead Market Regulation-Up Service Offers as described under


(iv) An Asset Owner’s Unused Regulation-Up Mileage Dispatch




AE, divided by 12. An Asset Owner’s Unused Regulation-Up

Mileage is equal to the amount by which Expected Regulation-Up

Mileage exceeds Actual Regulation-Up Mileage except that, if

Actual Regulation-Up Mileage is greater than or equal to

Instructed Regulation-Up Mileage multiplied by a factor equal to

one minus Regulation Mileage Operating Tolerance, then Unused

Regulation-Up Mileage is equal to the amount by which Expected

Regulation-Up Mileage exceeds Instructed Regulation-Up

Mileage.

(v) An Asset Owner’s Excess Regulation-Up Mileage Dispatch

Interval Amount is equal to the Asset Owner’s Excess Regulation-



AE, divided by 12. An Asset Owner’s Excess Regulation-Up

Mileage is the amount by which Actual Regulation-Up Mileage

exceeds Expected Regulation-Up Mileage except that, if Actual

Regulation-Up Mileage is greater than or equal to Instructed

Regulation-Up Mileage multiplied by a factor equal to one minus

Regulation Mileage Operating Tolerance, Excess Regulation-Up

Mileage is equal to the amount by which Instructed Regulation-Up

Mileage exceeds Expected Regulation-Up Mileage.

(b) Real-Time Regulation-Up Service Hourly Amount =

Sum of Real-Time Regulation-Up Service Dispatch Interval Amount over

all Dispatch Intervals in the Hour.


RTBM Regulation-Down Service and cleared Day-Ahead Market Regulation-

Down, (ii) Excess Regulation-Down Mileage and (iii) Unused Regulation-Down

Mileage, will be calculated at each Settlement Location for each Asset Owner for

each Dispatch Interval and hour as follows:

(a) Real-Time Regulation-Down Service Dispatch Interval Amount =

[[(Real-Time MCP) * ((Real-Time Cleared Regulation-Down Service

Dispatch Interval Quantity) – (Day-Ahead Regulation-Down Service

Hourly Quantity)) / 12] - Unused Regulation-Down Mileage Dispatch

Interval Amount + Excess Regulation-Down Mileage Dispatch Interval

Amount] * (-1)


AE, for Regulation-Down Service associated with the Reserve

Zone in which the applicable Resource is located.

(ii) An Asset Owner’s Real-Time Cleared Regulation-Down Service


cleared Regulation-Down Service Offers as described under


(iii) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service


Ahead Market Regulation-Down Service Offers as described under


(iv) An Asset Owner’s Unused Regulation-Down Mileage Dispatch


Down Mileage multiplied by the MCP for Expected Regulation-

Down Mileage, as defined under Section 8.3.4.3(4) of this

Attachment AE, divided by 12. An Asset Owner’s Unused


Expected Regulation-Down Mileage exceeds Actual Regulation-

Down Mileage except that, if Actual Regulation-Down Mileage is

greater than or equal to Instructed Regulation-Down Mileage

multiplied by a factor equal to one minus Regulation Mileage

Operating Tolerance, then Unused Regulation-Down Mileage is

equal to the amount by which Expected Regulation-Down Mileage

exceeds Instructed Regulation-Down Mileage.

(v) An Asset Owner’s Excess Regulation-Down Mileage Amount is

equal to the Asset Owner’s Excess Regulation-Down Mileage

multiplied by the MCP for Expected Regulation-Down Mileage, as

defined under Section 8.3.4.3(4) of this Attachment AE, divided by

12. An Asset Owner’s Excess Regulation-Down Mileage is the

amount by which Actual Regulation-Down Mileage exceeds

Expected Regulation-Down Mileage except that, if Actual

Regulation-Down Mileage is greater than or equal to Instructed

Regulation-Down Mileage multiplied by a factor equal to one

minus Regulation-Mileage Operating Tolerance, Excess


Instructed Regulation-Down Mileage exceeds Expected

Regulation-Down Mileage.

(b) Real-Time Regulation-Down Service Hourly Amount =

Sum of Real-Time Regulation-Down Service Dispatch Interval Amount

over all Dispatch Intervals in the Hour.


(1) Asset Owners of Resources committed by the Transmission Provider with an

RTBM Resource Offer commitment status as defined under Sections 4.1(10)(b)

and (c) of this Attachment AE or committed by a local transmission operator that

the Transmission Provider determines were selected in a non-discriminatory

manner by the local transmission operator, as determined pursuant to Section

6.1.2.1 of this Attachment AE, are eligible to receive a RUC make whole payment.

A RUC make whole payment is made to the Asset Owner when the sum of a

Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy

Offer Curve and Operating Reserve Offer costs associated with actual Energy and

cleared RTBM Operating Reserve is greater than the Energy and Operating

Reserve RTBM revenues received over the Resource’s RUC make whole

payment eligibility period. Recovery of such compensation shall be collected in

accordance with Section 8.6.7 of this Attachment AE. Resources that are

committed by a local transmission operator that the Transmission Provider

determines were selected in a discriminatory manner by the local transmission

operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE, are

not eligible to receive a RUC make whole payment.

(2) A Resource’s RUC make whole payment eligibility period is equal to that

Resource’s RUC Commitment Period. For Resources with a RUC Commitment

Period that begins in one Operating Day and ends in the next Operating Day, two

RUC make whole payment eligibility periods are created. The first period begins

in the first Operating Day in the Dispatch Interval associated with the Resource’s

RUC Commit Time and ends at the last Dispatch Interval of the first Operating

Day. The second period begins in the first Dispatch Interval of the next Operating

Day and ends in the Dispatch Interval associated with the Resource’s RUC De-

Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment

eligibility period. Offer costs are calculated using the RTBM Offer prices in

effect at the time the commitment decision was made.

(a) If the Transmission Provider cancels a Commitment Instruction prior to

the start of the associated RUC make whole payment eligibility period and

the Resource is not a Synchronized Resource, the Asset Owner will

receive reimbursement for a time-based pro-rata share of the Resource’s

RTBM Start-Up Offer. Asset Owners may request additional

compensation through submittal of actual cost documentation to the

Transmission Provider. The Transmission Provider will review the

submitted documentation and confirm that the submitted information is

sufficient to document actual costs and that all or a portion of the actual

costs are eligible for recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a

RUC make whole payment eligibility period, the Resource must be a

Synchronized Resource in at least one Dispatch Interval in the RUC make

whole payment eligibility period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch

Interval in the RUC make whole payment eligibility period, the Resource

must be a Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period

for a Resource in a single Operating Day. A single RUC make whole


(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in

the following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period that is adjacent

to the end of a Day-Ahead Market make whole payment eligibility

period;

(ii) Any RUC make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment

period at a time one (1) hour prior to that Resource’s RUC Commit

Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a

RUC Commitment Period that contains an hour for which the

Resource was self-committed.

(f) For each RUC make whole payment eligibility period within an Operating

Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the

Resource’s Minimum Run Time multiplied by twelve (12), rounded down

to the nearest whole interval, or (2) twenty-four (24) hours multiplied by

twelve (12), and that portion of the Start-Up Offer is included as a cost in

each interval of the RUC make whole payment eligibility period until the

sum of these interval costs are equal to the RTBM Start-Up Offer or until

the end of the RUC make whole payment eligibility period, whichever

occurs first.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not

accounted for in the last RUC make whole payment eligibility period in

the Operating Day, any remaining RTBM Start-Up Offer costs are carried

forward for recovery in the first RUC make whole payment eligibility

period of the following Operating Day provided that the Resource has not

been committed in the Day-Ahead Market in any hour of the first RUC

make whole payment eligibility period as described in (h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period

adjacent to and following a RUC make whole payment eligibility period to

the extent that the full amount of the RTBM Start-Up Offer is not

accounted for in the RUC make whole payment eligibility period, any

remaining RTBM Start-Up Offer costs are carried forward for recovery in

the Day-Ahead make whole payment eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any





(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating

point is not eligible for recovery for that Dispatch Interval where such cost

is calculated as described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the

Resource’s minimum operating limit that was used to make the

commitment decision, the increase is greater than the Resource’s

Operating Tolerance and the Resource remains dispatchable in any






given RUC make whole payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the

RUC Make Whole Payment Eligibility Period + RUC Make Whole Payment

Revenue Amount in the RUC Make Whole Payment Eligibility Period –

Uninstructed Resource Deviation Cost Disallowance – Non-Dispatchable Cost

Disallowance – Minimum Limit Cost Disallowance)]

(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each


Make Whole Payment Eligibility Period of (i) Start-Up Offer used to

make commitment decision, (ii) No-Load Offer used to make commitment

decision, (iii) Energy cost at minimum output as calculated from the

Energy Offer Curve used to make commitment decision, (iv) Energy cost

above minimum output as calculated from the Energy Offer Curve that

applied to the current Dispatch Interval, and (v) Operating Reserve cost

associated with cleared Real-Time Operating Reserve as calculated from

the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-

schedules are less than or equal to the amount of Operating Reserve

cleared shall be set equal to zero.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each

eligible Resource is equal the sum for all hours Dispatch Intervals in the

RUC Make Whole Payment Eligibility Period of (i) revenue associated

with Energy calculated by multiplying actual Energy by Real-Time LMP

(ii) the sum of the revenues calculated under Section 8.6.2, 8.6.3 and 8.6.4

of this Attachment AE for that eligible Resource (iii) Energy revenue

associated with payments made under Section 8.6.6 of this Attachment AE

and (iv) amounts associated with settlement made under Section 8.6.15 of

this Attachment AE (v) Unused Regulation-Up Mileage Make Whole

Payment as calculated under Section 8.6.19 of this Attachment AE and

(vi) Unused Regulation-Down Mileage Make Whole Payment as

calculated under Section 8.6.20 of this Attachment AE.

(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance,

Non-Dispatchable Cost Disallowance, or Minimum Limit Cost

Disallowance is equal to the positive difference between the Resource’s

Energy cost at actual output as calculated from the Resource’s current

Dispatch Interval Energy Offer Curve and the Resource’s Energy cost at

the Resource’s economic operating point as calculated from the

Resource’s current Dispatch Interval Energy Offer Curve.

(d) A Resource’s economic operating point is the MW output where the cost

on the Resource’s current Dispatch Interval Energy Offer Curve is equal

to the Real-Time LMP for that Resource.


An RTBM charge will be calculated for each Asset Owner at each Settlement

Location for each hour for the purposes of funding payments made under Section 8.6.2 as

follows:

(1) Real-Time Regulation-Up Service Distribution Amount =

[(Real-Time Regulation-Up Service Amount) * (Real-Time Load Ratio Share)] *

(-1)

(a) The Real-Time Regulation-Up Service Amount shall be equal to the sum

of the all payments made under Section 8.6.2(1) for Regulation-Up


8.6.19 for Unused Regulation-Up Mileage Make Whole Payments for the

hour.


Attachment AE.

(2) Real-Time Regulation-Down Service Distribution Amount =

[(Real-Time Regulation-Down Service Amount) * (Real-Time Load Ratio Share)]

* (-1)

(a) The Real-Time Regulation-Down Service Amount shall be equal to the

sum of the all payments made under Section 8.6.2(2) for Regulation-Down


8.6.20 for Unused Regulation-Down Mileage Make Whole Payments for

the hour.


Attachment AE.


An RTBM charge will be calculated at each Resource Settlement Location for

each Asset Owner for each Dispatch Interval when a Resource with cleared RTBM

Regulation-Up Service, Regulation-Down Service or both operates outside of its

Operating Tolerance. The amount will be determined as follows:

Real-Time Regulation Service Non-Performance Amount =

[[{Maximum of [Either Zero or ((Day-Ahead MCP for Regulation-Up Service) * (Day-

Ahead Cleared Regulation-Up Service Hourly Quantity) + (Real-Time MCP for

Regulation-Up Service) * (Real-Time Cleared Regulation-Up Service Dispatch Interval

Quantity – Day-Ahead Cleared Regulation-Up Service Hourly Quantity))]} +

{Maximum of [Either Zero or ((Day-Ahead MCP for Regulation-Down Service) * (Day-

Ahead Cleared Regulation-Down Service Hourly Quantity) + (Real-Time MCP for

Regulation-Down Service) * (Real-Time Cleared Regulation-Down Service Dispatch

Interval Quantity – Day-Ahead Cleared Regulation-Down Hourly Quantity))]}] / 12] -

Unused Regulation-Up Mileage Dispatch Interval Amount + Excess Regulation-Up

Mileage Dispatch Interval Amount - Unused Regulation-Down Mileage Dispatch Interval

Amount + Excess Regulation-Down Mileage Dispatch Interval Amount.













(5) An Asset Owner’s Day-Ahead Cleared Regulation-Up Service Hourly Quantity is

the MW quantity associated with cleared Regulation-Up Service Reserve Offers

as described under Section 5.1.3 of this Attachment AE.

(6) An Asset Owner’s Day-Ahead Cleared Regulation-Down Service Hourly


Reserve Offers as described under Section 5.1.3 of this Attachment AE.

(7) An Asset Owner’s Real-Time Cleared Regulation-Up Service Dispatch Interval

Quantity is the MW quantity associated with cleared Regulation-Up Service


(8) An Asset Owner’s Real-Time Cleared Regulation-Down Dispatch Interval



(9) An Asset Owner’s Unused Regulation-Up Mileage Dispatch Interval Amount is

the amount calculated under Section 8.6.2(1)(a)(iv) of this Attachment AE.

(10) An Asset Owner’s Excess Regulation-Up Mileage Dispatch Interval Amount is


(11) An Asset Owner’s Unused Regulation-Down Mileage Dispatch Interval Amount

is the amount calculated under Section 8.6.2(2)(a)(iv) of this Attachment AE.

(12) An Asset Owner’s Excess Regulation-Down Mileage Dispatch Interval Amount is



An RTBM payment will be calculated for each Asset Owner at each Settlement

Location for each hour in order to distribute the funds collected under Section 8.6.11.

The Asset Owner amount is calculated as follows:

Real-Time Regulation Service Non-Performance Distribution Amount =

[(Real-Time Regulation Service Non-Performance Amount) * (Real-Time Load Ratio

Share)] * (-1)

(1) The Real-Time Regulation Service Non-Performance Amount shall be equal to

the sum of all charges made under Section 8.6.11 for hour.

(2) Real-Time Load Ratio Share is as defined under Section 1 of this Attachment AE.


A Real-Time regulation deployment adjustment amount charge or payment will

be calculated for each Asset Owner for each Dispatch Interval when a Resource with

cleared Real-Time Regulation-Up Service and/or Regulation-Down Service is deployed.

The amount will be determined as one-twelfth of the sum of:

(1) For Regulation-Up Service deployment, the amount is equal to the difference

between (1) actual Regulation-Up Service deployment MW multiplied by Real-

Time LMP at that Resource Settlement Location, and (2) Energy Offer Curve cost

of actual Regulation-Up Service deployment MW.

The actual Regulation-Up Service deployment MW is calculated as the

difference between the lesser of (1) Dispatch Instruction plus the average

Regulation-Up Service deployment or (2) Absolute value of actual Resource

output, and the Resource’s average Dispatch Instruction for Energy. If the

absolute value of the Resource’s actual output is less than or equal to the


Up Service deployment MW is equal to zero (0).

(2) For Regulation-Down Service deployment, the amount is equal to the difference

between (1) Energy Offer Curve cost of actual Regulation-Down Service

deployment MW, and (2) actual Regulation-Down Service deployment MW

multiplied by RTBM LMP.

The actual Regulation-Down Service deployment MW is calculated as the

difference between the Resource’s average Dispatch Instruction for Energy and

the greater of (1) Average Dispatch Instruction minus the average Regulation-

Down Service deployment or (2) Absolute value of actual Resource output. If the

absolute value of the Resource’s actual output is greater than or equal to the


Down Service deployment MW is equal to zero (0).

Distribution of such charges and recovery of such payments shall be made

in accordance with Section 8.8 of this Attachment AE.



charged for Unused Regulation-Up Mileage at a rate that is in excess of that Resource’s

Regulation-Up Mileage Offer. The amount will be calculated on a Dispatch Interval

basis as follows:

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount =

[Minimum of [zero or (Regulation-Up Mileage Offer - Expected

Regulation-Up Mileage MCP)] ] * Unused Regulation-Up Mileage

Where Regulation-Up Mileage Offer is defined under Section 1 of this Attachment AE,

Unused Regulation-Up Mileage is calculated under Section 8.6.2(1)(a)(4) of this

Attachment AE and Expected Regulation-Up Mileage MCP is defined under Section




charged for Unused Regulation-Down Mileage at a rate that is in excess of that

Resource’s Regulation-Down Mileage Offer. The amount will be calculated on a

Dispatch Interval basis as follows:

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount =

[Minimum of [zero or (Regulation-Down Mileage Offer - Expected

Regulation-Down Mileage MCP)]] * Unused Regulation-Down Mileage

Where Regulation-Down Mileage Offer is defined under Section 1 of this Attachment

AE, Unused Regulation-Down Mileage is calculated under Section 8.6.2(2)(a)(4) of this

Attachment AE and Expected Regulation-Down Mileage MCP is defined under Section
