VIA ELECTRONIC FILING Secretary Federal Energy Regulatory ... Docket No. ER19-915-000315136.pdfJan 30, 2019 · MISO s Outage Process timeline was established to promote reliability

Midcontinent Independent System Operator, Inc. 317.249.5400 www.misoenergy.org

720 City Center Drive Carmel, IN 46032

2985 Ames Crossing Road Eagan, MN 55121

3850 N. Causeway Blvd., Two Lakeway, Suite 442 Metairie, LA 70002

1700 Centerview Drive Little Rock, AR 72211

Michael Kessler Assistant General Counsel Direct Dial: 317-249-5290 E-mail: [email protected]

January 30, 2019

VIA ELECTRONIC FILING

The Honorable Kimberly D. Bose Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426

Re: Midcontinent Independent System Operator, Inc. Filing to Enhance Generator Planned Outage Scheduling Docket No. ER19-____-000

Dear Secretary Bose:

The Midcontinent Independent System Operator, Inc. (“MISO”), through this filing,1 proposes to revise certain generator outage provisions of its Open Access Transmission, Energy, and Operating Reserve Markets Tariff (“Tariff”). This proposal is one of the first steps in a more extensive plan to implement improvements identified through MISO’s Resource Availability and Need (“RAN”) program and is submitted following two related filings that address Load Modifying Resource (“LMR”) accreditation and requirements and Demand Resource (“DR”) testing.2 The proposal will further support MISO’s ability to meet operational challenges by enhancing outage scheduling practices to facilitate forward planned outage scheduling and resource availability when needed most by MISO operations. MISO requests an effective date for this filing of April 1, 2019 to allow for the implementation of these requirements in time for the Spring 2019 outage season.

1 MISO makes this filing pursuant to Section 205 of the Federal Power Act (“FPA”), 16 U.S.C. § 824d, and

Part 35 of the regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 18 C.F.R. § 35.1, et seq. All capitalized terms in this filing that are not otherwise defined have the same meaning as they have under the current MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff.

2 Docket Nos. ER19-650-000 and ER19-651-000, filed December 21, 2018. While all three filings are important to MISO’s RAN program, they include Tariff revisions that can be implemented independent of the others without diminishing the expected benefits of each individual proposal.

The Honorable Kimberly D. Bose January 30, 2019 Page 2

I. BACKGROUND

The MISO Region is transitioning from a generation portfolio dominated by coal and nuclear generation resources to a portfolio that relies on an increasing quantity of intermittent and emergency only resources – even to meet MISO’s planning reserve requirements. Base load generation retirements have increased the pace of this transition and have caused MISO to operate with actual capacity margins that have consistently been decreasing towards minimum resource requirements. As a result, MISO has experienced a decrease in operational flexibility as capacity margins continue to diminish.

Operating at or near minimum reserve margin requirements exposes the MISO Region to

greater impacts from correlated risks (e.g., extreme weather events and natural gas availability). These risks are exacerbated by ongoing trends, which have caused more non-summer resource risk. Specifically, increasing forced outage rates for generation in the MISO Region together with a significant correlation in the timing of planned generator outages and de-rates, have caused resource risk outside of the traditional summer peak times. This has created a new paradigm, where Generator Owners3 can no longer simply schedule their outages around peak load times to avoid operating risk.

While MISO and its stakeholders have been able to successfully serve firm load through

the voluntary rescheduling of generation outages in the days or hours prior to predicted Emergency events, this practice may not be sufficient for the future. There has been a significant increase in the number of Maximum Generation Emergencies (e.g., alerts, warnings, and events), and these events are driven at least in part by highly correlated planned outages which can enhance resource risk. As described in MISO’s September 10, 2018 RAN Whitepaper, there is a disconnect between the idealized timing for planned outages and their actual implementation4:

In planning studies, including the [Loss of Load Expectation (“LOLE”)] analysis, MISO assumes generators optimize planned outages regionally to minimize risk. For example, the outage shapes modeled in the LOLE study are shown in the figure on the next page, with the modeled risk represented by the blue highlight compared to the past five years of actual planned outage data (shown as the green line). Key gaps occurred in January, March, April, May, July, and October, corresponding to the months with high numbers of MaxGen [E]mergencies in MISO operations.

3 For purposes of this filing the term “Generator Owner(s)” includes Generator operators and entities acting as

agent for a Generator owner. 4 Resource Availability and Need, Evaluation Whitepaper, September 10, 2018, at 4 -5.


This resource risk can be exacerbated by a lack of forward forecasts into planned outage schedules. Currently, approximately 30% of MWs from generator planned outages are scheduled 120 days or more in advance.5 Additionally, most planned de-rates occur only days/weeks in advance. These circumstances have prompted MISO to determine how today’s processes can be improved to ensure the reliable and efficient conversion of procured capacity to energy throughout the year.6

Although MISO’s RAN evaluation is ongoing, MISO has identified four initial goals to

address both immediate needs and bolster the eroding available reserve margin.7 These goals include:

1. Improving planned generation outage scheduling and coordination; 2. Linking Resource accreditation and requirements with an initial focus on Load

Modifying Resources (LMRs); 3. Aligning Planning Resource Auction (“PRA”) commitments with energy needs all

year; and, 4. Ensuring flexible resource availability to address changing fleet character. The generator outage planning proposal submitted with this filing is expected to enhance

outage coordination by providing additional incentives to schedule planned outages and de-rates well in advance of the requested start time. This enhanced information will then be used to improve forecasts of near to mid-term generation margins, allowing for Generator Owners to more accurately identify and avoid times of risk when scheduling subsequent planned outages and for MISO to have additional information needed to ensure resource availability during times of need.

5 Smith Testimony at 4. 6 Bladen Testimony at 13. 7 Id. at 4-5.


II. OVERVIEW OF MISO’S OUTAGE PLANNING PROPOSAL

MISO’s existing generator outage planning process (“Outage Process”) establishes a timeline during which generation resources are expected to submit planned outage information. As discussed in Mr. Smith’s testimony, the current Outage Process established in Section 38.2.5.g of the Tariff requires nuclear generation resources to submit planned outages at least three years in advance of the start of the outage and non-nuclear resources to submit planned outages at least two years in advance.8 Changes to such submissions may be made up to one year following the initial submission. Outages submitted consistent with this timeline are considered “timely.” Failure to submit planned outages consistent with this timeline could result in Generator Owners being subject to an accreditation adjustment equal to three times the outage duration, if the outage is projected to cause defined emergency events.9

MISO’s Outage Process timeline was established to promote reliability and allow MISO

to coordinate planned outage schedules, providing sufficient time for MISO and Generator Owners to re-schedule, as necessary, outages which may, through their schedule, cause a reliability risk. Although MISO does not have direct authority over generator outages during non-emergency conditions, generators that take untimely outages may face economic consequences. More specifically, generators that refuse to move their planned outage, when requested by MISO due to a demonstrated reliability harm, may face the accreditation adjustment described above in subsequent capacity accreditation calculations.10

In this filing, MISO is proposing incremental changes to the existing Outage Process to

improve planned outage transparency through forward signals and incentives. These changes are in addition to the existing Outage Process and are intended to provide MISO with additional information about resource availability, and provide generation owners with further transparency about system needs, as well as incentives to be available during periods of low margins. Specifically, MISO’s proposal focuses on:

1. Providing additional incentives for timing of submittals relating to both planned

generator outages and de-rates; and, 2. Partnering with Generator Owners to identify times with increased system risk due

to correlation of outages and de-rates.

As discussed in Mr. Smith’s testimony, the proposed Tariff changes will incentivize additional forward generator planned outage and derate submittals by imposing new generator accreditation penalties for planned outages taken during low margin, high risk periods, while also providing a “safe harbor” from such penalties for requests received “well in advance.”11 The proposal is consistent with NERC’s Planned Outage definition, i.e., requiring that such outages be

8 Smith Testimony at 3. 9 Id. at 5. 10 Id. 11 Id. at 9 - 10.


planned “well in advance” and occur only once or twice a year.12 To support this incremental outage scheduling process, MISO will improve transparency by providing enhanced generator planned outage information as well as sub-regional forecasts of planned outages and generator de-rates through its existing maintenance margin tool.13

The proposed Tariff changes will create incentives for generators to submit their outages

well in advance of the operating day and to avoid times with projected high resource risk. More specifically, the proposed changes will create a new accreditation adjustment for generator planned outages and de-rates scheduled less than 14 days in advance and occurring during a declared Maximum Generation Emergency (“MaxGen”) alert, warning or event impacting the sub-region in which the generator is located. The adjustment for these outages will affect the generator’s capacity accreditation by considering the outage as “forced” for purposes of that generator’s forced outage rate. The duration of the deemed “forced” outage will not exceed the length of the emergency (but no less than one day), to avoid being unduly burdensome on long duration outages.14

For planned outages and de-rates submitted between 14 and 120 days in advance, outages may receive an exemption from this accreditation adjustment (“safe harbor exemption”) if the outages are scheduled entirely within a projected period of low risk, with a sufficient resource margin.15 Periods of adequate margin will be represented by a non-zero maintenance margin value and able to accommodate the MW of the request.16 If the requests are scheduled at a time with high risk, and such risk materializes into a MaxGen alert, warning, or event, the generator would be subject to the forced outage penalty described above.

Planned outages and planned de-rates submitted with at least 120 days advance notice of

the outage will be granted an exemption from this accreditation adjustment. However, a generator will only be eligible for the automatic safe harbor exemption for the first outage or de-rate submitted during the same 120 day period. Any subsequent outage or de-rate requests made during this period will only be exempt from the accreditation adjustment if the outage or de-rate is scheduled to occur during a period when MISO is projecting an adequate margin.

Some additional provisions will provide flexibility for generator outages within these

guidelines, including:

• Allowing safe harbor provisions if the outage is adjusted at MISO’s request. • Providing the ability for generator to make adjustments to existing requests up to 14

days prior to the start of its outage, so long as such adjustments are scheduled for a 12 NERC’s Generating Availability Data System, Data Reporting Instructions. Effective January 1, 2018. See

https://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/2019GADSDataReportingInstructions.pdf 13 Smith Testimony at 16 - 17. 14 Id. at 10 - 11. 15 Id. at 11. 16 Id. at 10.


projected period of low risk, (in an equivalent manner to a new outage scheduled in the same timeframe).

This proposal will supplement existing generator outage processes. The existing Outage

Process requirements will continue to apply, including the possibility for MISO to request the outage be adjusted if a reliability concern is identified, as set forth in Section 38.2.5.g of the Tariff.17

In order to permit a transition to these new requirements, MISO is proposing a phased

approach as described below:

1. Outages submitted prior to April 1, 2019 will not be subject to the proposed penalty. 2. Requests and revisions submitted on or after April 1 for outages starting April 15

through July 29, 2019 would gain safe harbor if the request is submitted no later than 14 days in advance and there is adequate projected margin at the time of the request.

3. The complete process as described above will apply to outages scheduled to start on or after July 30.

This transition plan will allow the changes to be implemented and be impactful starting in the Spring 2019 outage season.18

To further enhance transparency, MISO has worked closely with its stakeholders and is

committed to improving its existing maintenance margin tool, which currently provides an estimate of available margin by region as well as Local Resource Zone. Going forward, MISO proposes to increase the frequency of the posting of this information from monthly to twice weekly, providing the information on a regional and sub-regional basis (i.e., for the MISO North, Central, and South regions).19 This change will align the provision of maintenance margin information with the regions in which recent MaxGen alerts, warnings and/or events have been called on by MISO operators, and will align with the proposed generator planned outage and planned derate accreditation adjustments described above.20 Focus group stakeholder discussions on improvements to the maintenance margin tool and information commenced in January 2019, with discussions feeding into training and process improvements. MISO’s Outage Operations Business

17 Id at 12. If the planned outage is not submitted in accordance with the existing Tariff requirements set forth in

Section 38.2.5.g (i.e., three years for nuclear generators and two years for all other fuel types) and an emergency occurs, the generator will be subject to the existing Tariff prescribed penalty: a three times XEFORd accreditation adjustment in the next Planning Year. These existing Tariff requirements are not being modified in the instant filing and remain applicable to all generator planned outages in addition to the proposed changes set forth in this filing.

18 Id at 15. 19 Id. at 16. 20 Id. at 17.


Practices Manuals (BPM-008) has been updated to reflect the revised maintenance margin determination process,21 which will be implemented in March 2019.22

As described above, the maintenance margin information can be used by Generator Owners

to qualify for a safe harbor exemption from the proposed accreditation penalty under defined conditions. Importantly, however, the maintenance margin on its own does not create or impose any new penalty or other financial consequences. Rather, the use of the maintenance margin information only provides a tool that Generator Owners can use to plan outages. The Generator Owner will only be subject to the accreditation penalty if it fails to timely schedule an outage and the outage occurs during a MaxGen alert, warning or event. The maintenance margin tool and processes are therefore appropriately described in MISO’s BPM-008 as an implementation detail that does not directly affect rates, terms or conditions of service.23

III. STAKEHOLDER PROCESS

MISO worked with stakeholders to create a balanced proposal with multiple viewpoints represented. This work began in 2015, when a Market Roadmap item was created to track issues associated with the seasonal procurement of capacity. The topic was discussed in the Resource Adequacy Subcommittee (“RASC”), and the subject matter was expanded to capture the range of concerns surrounding the availability of resources throughout the year and discussed at the Steering Committee for subsequent assignment. Throughout 2018, MISO led stakeholders through discussions on the overall problem to be addressed by Resource Availability and Need in the Reliability Subcommittee (“RSC”), as well as through the Advisory Committee and with the MISO Board of Directors through two Hot Topics discussions. These discussions ultimately resulted in a phased filing approach, with MISO pursuing near term filings to moderate current operational concerns while continuing to work with stakeholders in parallel towards a more holistic set of solutions. This filing represents a portion of the near term improvements suggested.

As discussed by Mr. Bladen in his testimony and as detailed in Exhibit A to that testimony,

MISO engaged stakeholders in discussions related to the instant proposal beginning with the posting of RAN whitepaper on September 10, 2018 and requests for stakeholder feedback on two key areas: 1) how should lead time impact how outages are classified and accredited; and, 2) how can MISO improve transparency through improved forward signals.24 Stakeholder feedback and the direction from the MISO Advisory Committee were considered and the proposed solutions were discussed further in the November 1, 2018 RSC.

MISO also hosted a workshop on November 16, 2018 to perform a detailed walkthrough

of the proposal. MISO also discussed the proposal with stakeholders at the November 29, 2018

21 See https://cdn.misoenergy.org/DRAFT%20BPM-008%20Outage%20Operations148459.pdf 22 Smith Testimony at 16. 23 See Cal. Indep. Sys. Operator Corp., 122 FERC ¶ 61,271, at 62,579 (2008); see also Cal. Indep. Sys. Operator

Corp. 147 FERC ¶ 61,231 at P 95 (2014). 24 Bladen Testimony at 19 - 22.


RSC and a subsequent RSC conference call on December 7, 2018. Based on stakeholder feedback received during these meetings MISO delayed the planned filing date from December 21, 2018 to late January 2019 to give stakeholders additional time to review the updated proposal. During this time, MISO solicited stakeholder feedback and requested stakeholder proposals. Stakeholders led discussions at the January 3, 2019 RSC meeting. At this time stakeholders suggested modifications to the proposal to allow exemptions for shorter lead time requests when such requests are scheduled at a time of adequate projected margin. MISO reviewed this feedback and incorporated it into an updated proposal discussed with stakeholders on January 14, 2019. Two maintenance margin focus group meetings were also held in January, resulting in improvements to the maintenance margin forecasts.

As a result of these stakeholder meetings, MISO amended its proposal to:

• Add allowances for high risk exemptions for outages scheduled between 14 and 120 days in advance;

• Allow exemptions for multiple outage requests for the same unit within a specified period;

• Decreased the penalty assessed to the overlap of the outage and the emergency condition, instead of the duration of the outage;

• Clarified that outages moved per MISO’s request will receive an exemption; and, • Allowed for flexibility for outages to adjust previous submissions up to 14 days in

advance.

IV. DOCUMENTS SUBMITTED WITH THIS FILING

In addition to this Transmittal Letter, this submission includes:25

• Tab A – Clean Tariff Sheets effective 4/1/2019

• Tab B – Redline Tariff Sheets effective 4/1/201926

• Tab C – Testimony of Jeff Bladen

• Tab D – Testimony of Jameson T Smith

V. PROPOSED EFFECTIVE DATE

MISO requests that the Commission make the proposed revisions effective on April 1, 2019.

25 18 C.F.R. § 35.13(b)(1) (2017). 26 Language currently pending before the Commission in the following, unrelated dockets is highlighted in

yellow: ER19-34-000. MISO requests that the Commission treat such highlighted language as subject to the outcomes of those pending proceedings. MISO commits to file any revisions to this highlighted language as necessary to comply with any Commission orders in those proceedings.


VI. COMMUNICATIONS

MISO respectfully requests waiver of Rule 203(b)(3) of the Commission’s Rules of

Practice and Procedure, 18 C.F.R. § 385.203(b)(3) (2017), to the extent necessary to permit the designation of more than two persons for service on behalf of MISO in this proceeding and requests all communications related to this filing be directed to:

Michael Kessler Assistant General Counsel Midcontinent Independent System Operator, Inc. 720 City Center Drive Carmel, Indiana 46032 Telephone: (317)249-5400 mailto:[email protected]

James C. Holsclaw Kyle Swick The Holsclaw Group, LLC 303 E. Main St. Plainfield, IN 46168 Telephone: 317.839.1140 [email protected] [email protected]

VII. NOTICE AND SERVICE

MISO has served a copy of this filing electronically, including attachments, upon all Tariff Customers, MISO Members, Member representatives of Transmission Owners and Non-Transmission Owners, as well as all state commissions within the region. The filing has been posted electronically on MISO’s website currently at https://www.misoenergy.org/legal/ferc-filings/ for other parties interested in this matter.

VIII. CONCLUSION

For all of the foregoing reasons, MISO respectfully requests that the Commission accept this filing, effective April 1, 2019, and grant waiver of any Commission regulations not addressed herein that the Commission may deem applicable to this filing.

Respectfully submitted, /s/ Michael Kessler Michael Kessler Midcontinent Independent System Operator, Inc. Attorney for the Midcontinent Independent System Operator, Inc.

Attachments

Tab A

MISO 38.2.5

FERC Electric Tariff Market Participant Obligations

MODULES 40.0.0, 41.0.0

Effective On: April 1, 2019

a. Standards. In performing its obligations under this Tariff, a Market Participant shall, at

all times, conduct its operations pursuant to the following standards.

i. Each Market Participant shall at all times: (i) follow Good Utility

Practice; (ii) comply with all applicable laws and regulations; (iii) comply

with the applicable principles, guidelines, standards and requirements of

the Commission, ERO and the applicable Regional Entities ; (iv) comply

with the procedures established for operation by the Transmission

Provider; and (v) cooperate with the Transmission Provider as necessary

pursuant to the terms of this Tariff, for the operation of the facilities in the

Transmission Provider Region in a safe, reliable manner, consistent with

Good Utility Practice.

ii. Each Market Participant shall operate, or shall cause to be operated, any

Resources supplying Energy and/or Operating Reserve owned or

controlled by such entity within the Transmission Provider Region or

otherwise supplying Energy to, through, or out of, the Transmission

Provider Region in a manner consistent with the standards, requirements

or directions of the Transmission Provider, pursuant to the terms of this

Tariff. Such standards and requirements shall be established in

accordance with industry standards, Applicable Reliability Standards,

Commission regulation, Good Utility Practice and applicable law. The

directions of the Transmission Provider shall be consistent with those

directions authorized under this Tariff; provided, however, no Market

MISO 38.2.5


MODULES 40.0.0, 41.0.0


Participant shall be required to take any action inconsistent with Good

Utility Practice or applicable law.

iii. Each Market Participant shall notify the Transmission Provider of any

changes to the availability of, changes in quantity of, and/or changes in the

Resources it has committed for Energy, Operating Reserve, Up Ramp

Capability, and/or Down Ramp Capability as the Operating Day

approaches in accordance with timing specified in Business Practices

Manuals.

iv. Each Market Participant shall obtain and maintain all permits, licenses, or

approvals required for it to participate in the Energy and Operating

Reserve Markets in the manner contemplated by this Tariff.

v. Any Market Participant that seeks to transfer control of its generating unit

or load to (or from) the MISO Balancing Authority Area from (or to) a

specified external Balancing Authority Area on or after September 1, 2018

must execute and abide by the terms of the Pseudo-tie Agreement included

as Attachment FFF-1 or Attachment FFF-2 to this Tariff prior to

transferring control of the generating unit or load specified. The Market

Participant shall conform to all standards, specifications, and requirements

of Attachment FFF-1 or Attachment FFF-2, as applicable, at all times the

Pseudo-tie Agreement is in effect for that Market Participant.

b. Scheduling. Each Market Participant shall provide, or cause to be provided to the

Transmission Provider, scheduling and other information specified in this Tariff, and

MISO 38.2.5


MODULES 40.0.0, 41.0.0


such other information as the Transmission Provider reasonably requires. Such

information shall be provided in accordance with the deadlines established by this Tariff

or by the Transmission Provider. Any Market Participant that executes the Pseudo-tie

Agreement in Attachment FFF-1 or Attachment FFF-2 shall conform to all standards,

specifications, and requirements regarding scheduling and providing information to

MISO as outlined in Attachment FFF-1 and Attachment FFF-2, as applicable.

The Transmission Provider shall abide by appropriate requirements for the non-disclosure

and protection of any Confidential Information given to the Transmission Provider by a

Market Participant as specified in Section 38.9. Each Market Participant shall maintain,

or cause to be maintained, compatible information and communications systems, as

specified by the Transmission Provider, required to transmit scheduling, dispatch, or

other time-sensitive information to the Transmission Provider in a timely manner. Any

Market Participant that executes the Pseudo-tie Agreement in Attachment FFF-1 or

Attachment FFF-2 shall maintain or cause to be maintained all communications and other

systems necessary to convey data to the MISO Balancing Authority and external

Balancing Authority as required under Attachment FFF-1 or Attachment FFF-2, as

applicable.

c. Fees and Charges. Each Market Participant shall be responsible for all fees and charges

to the Transmission Provider for operation of the Energy and Operating Reserve Markets

as determined by the Transmission Provider and allocated to the Market Participant in

accordance with Schedule 17 of this Tariff.

MISO 38.2.5


MODULES 40.0.0, 41.0.0


In addition, each Market Participant shall be responsible for all fees and charges of the

Transmission Provider for administration of Financial Transmission Rights as determined

by the Transmission Provider and allocated to the Market Participant in accordance with

Schedule 16 of this Tariff.

d. Communications.

i. Each Market Participant shall have, or shall arrange to have: (i) its operations

staffed and equipped with communications systems capable of real-time

communication with the Transmission Provider during normal and Emergency

conditions; and (ii) systems to permit the Market Participant to control its Load or

facilities sufficient to meet the requirements of its Market Activities.

ii. A Market Participant selling Energy, Operating Reserve, Up Ramp Capability,

and/or Down Ramp Capability from Resources within the Transmission Provider

Region shall: (a) report to the Transmission Provider sources of Energy,

Operating Reserve, Up Ramp Capability, and Down Ramp Capability available

for operation; (b) supply to the Transmission Provider all applicable Offer data;

(c) report to the Transmission Provider those Resources that are Self-Scheduled

Resources; (d) confirm with the Transmission Provider any Interchange

Schedules; (e) respond to the Transmission

Provider’s directives to start, shutdown, or change output levels of Resources, in

accordance with the terms specified in the Offer or change scheduled voltages or

reactive output levels; (f) continuously maintain all Offers consistent with the

Offer rules and obligations for Market Participants in the Day-Ahead Energy and

MISO 38.2.5


MODULES 40.0.0, 41.0.0


Operating Reserve Market, as specified in Section 39, and/or Real-Time Energy

and Operating Reserve Market, as specified in Section 40 concurrently with on-

line operating information; and (g) ensure that, where so equipped, Resources are

operated with control equipment, functioning as specified in the Business

Practices Manuals.

iii. A Market Participant selling Energy from Resources outside the Transmission

Provider Region shall comply with the Transmission Provider’s requirements for

Interchange Schedules provided herein.

iv. The Market Participant shall furnish the Transmission Provider with the

information specified in the Offer as set forth in Section 39 and Section 40 of this

Tariff for new Resources including default unit ratings, default Start-Up Offers or

Shut-Down Offers, time parameters, and default No-Load Offers or Hourly

Curtailment Offers. The information must be furnished no less than thirty (30)

days before a Market Participant’s initial Offer to sell Energy from a given

Resource in the Day-Ahead Energy and Operating Reserve Market or the Real-

Time Energy and Operating Reserve Market.

v. A Market Participant that is a Load Serving Entity or is purchasing on behalf of a

Load Serving Entity shall respond to Transmission Provider directives as set forth

in Section 40.2.20 this Tariff.

vi. To make purchases in the Energy and Operating Reserve Markets, a Market

Participant that is not a Load Serving Entity or purchasing on behalf of a Load

Serving Entity shall provide to the Transmission Provider requests to purchase

MISO 38.2.5


MODULES 40.0.0, 41.0.0


specified amounts of Virtual Energy for each Hour of the Day-Ahead Energy and

Operating Reserve Market.

vii. Any Market Participant that executes the Pseudo-Tie Agreement included as

Attachment FFF-1 or Attachment FFF-2 to this Tariff shall provide the

Transmission Provider information and data in the manner and form specified in

Attachment FFF-1 or Attachment FFF-2, as applicable.

e. Metering.

i. Market Participants shall meet the minimum metering specifications and

standards described in this Section 38.2.5.e for all meters that are used as a data

source by the Transmission Provider, and the Transmission Provider shall make

these specifications and standards available in the Business Practices Manuals.

ii. A Market Participant shall either install and operate, or otherwise arrange for,

appropriate metering and related equipment capable of recording and transmitting

all data communications, as specified in this Section 38.2.5.e, reasonably

necessary for the Transmission Provider to perform the services specified in this

Tariff.

iii. Where available, a Market Participant or MDMA shall provide the Transmission

Provider with Metered data that meets the Transmission Provider’s requirements

by one of the following means: (a) direct transmission to the Transmission

Provider; (b) direct transmission to the Transmission Provider through the Local

Balancing Authority, Transmission Owner, ITC or LSE within whose area the

Load is located; or (c) indirectly through metering provided by the Local

MISO 38.2.5


MODULES 40.0.0, 41.0.0



Load is located. The Transmission Provider shall make this data available to the

Local Balancing Authority upon request. The Market Participant or MDMA shall

also provide its Metered data to the Transmission Owner, Local Balancing

Authority, ITC or LSE within whose area the Load is located to the extent such

information is needed to implement the Transmission Provider’s system operation

and planning functions, to provide billing services to the Market Participant, to

allow for data to be verified and agreed to by Transmission Owner, Local

Balancing Authority, ITC, or LSE, or to permit the performance of calculations

required by the Transmission Provider.

iv. A Market Participant whose metering services are provided by an MDMA shall

itself be responsible for ensuring that all data described in this Section 38.2.5 are

provided accurately.

v. All Market Participants must use their best efforts to provide the Transmission

Provider with Metered values for purposes of settlement in the form requested by

the Transmission Provider.

(a.) Market Participants shall report injection and withdrawal of Energy

at each Commercial Pricing Node where they have injections or

withdrawals. If the Market Participant does not have available

actual meter data at these locations, the Market Participant is

required to estimate Hourly injections and withdrawals based on

their possible information and make the data available to the

MISO 38.2.5


MODULES 40.0.0, 41.0.0


Transmission Provider by submitting the meter data according to

the timeline established in the Business Practices Manuals. If no

meter data is provided to the Transmission Provider by the Market

Participant, or the submitted data is unreasonable or erroneous, the

Transmission Provider shall estimate the Hourly injections and

withdrawals based on the information it has available to be used in

Settlements for the Market Participant.

(b.) Market Participants must register any Internal Commercially

Pseudo-Tied Load, identifying for each such Load: (1) the

Commercial Pricing Node representing such Load, (2) the Local

Balancing Authority where the Load is physically located, and (3)

the Elemental Pricing Node(s) comprising the Internal

Commercially Pseudo-Tied Load. Market Participants shall report

injection and withdrawal of Energy for each Internal Commercially

Pseudo-Tied Load where they have injections or withdrawals. If the

Market Participant does not have available actual meter data at

these locations, the Market Participant is required to estimate

Hourly injections and withdrawals based on its possible information

and make the data available to the Transmission Provider by

submitting the meter data according to the timeline established in

the Business Practices Manuals. If no meter data is provided to the

Transmission Provider by the Market Participant, or the submitted

MISO 38.2.5


MODULES 40.0.0, 41.0.0


data is unreasonable or erroneous, the Transmission Provider shall

estimate the Hourly injections and withdrawals for an Internal

Commercially Pseudo-Tied Load as the product of: (i) the sum of

the weighting factors for the Elemental Pricing Node(s) comprising

the Internal Commercially Pseudo-Tied Load that were used in the

calculation of the Day-Ahead and Real-Time LMPs of the

Commercial Pricing Node representing such Load; and (ii) the

Meter data submitted or estimated for that Commercial Pricing

Node.

vi. Market Participants shall submit withdrawal data for each Commercial Pricing

Node where they represent Load, including consumption information for

Commercial Pricing Nodes defined as Aggregate Load Zones. The Transmission

Provider will, for Settlement purposes apply any calculated Residual Load in each

Local Balancing Authority to the withdrawal data for the Load Zone applicable to

the Residual Load in that Local Balancing Authority.

vii. All Market Participants shall maintain metering equipment that meets the

following minimum standards:

a. All metering equipment must use megawatt-hour (MWh) as the

standard unit of service measurement. Service may be measure in

kilowatt-hours (kWh) if required by specific service, local or state

regulations, host utilities, service providers, or as are mutually

agreed upon by the parties involved, provided that KWh

MISO 38.2.5


MODULES 40.0.0, 41.0.0


information is converted to fractional MWh information before it

is transmitted to the Transmission Provider.

b. All metering equipment must have bi-directional capability (the

ability to measure power flows in both directions).

c. All metering equipment must be capable of storing a minimum of

35-days of hourly intervals for each measured value.

d. Test switches or other means must be used to allow independent

testing and/or replacement of each meter or transducer using a

secondary circuit so as not to interrupt the operation of other

devices using the same secondary circuit.

e. Current transformers and voltage transformers used for metering

shall meet or exceed an accuracy class of 0.3%, and secondary

connected burdens shall not exceed rated burdens of any voltage

transformer. The same accuracy standards shall apply to optical

metering transducers.

f. Metering equipment shall be tested periodically in accordance with

the ANSI Standard requirement for the particular meter type as

stated in ANSI C12.1 Appendix D – Periodic Testing Schedules.

If any such test identifies any deficiency or inaccuracy in any

metering equipment, the deficient or inaccurate equipment must be

restored to correct operation as soon a reasonably possible, but in

no case any later than 30 days from the date of discovery.

MISO 38.2.5


MODULES 40.0.0, 41.0.0


g. All Market Participants must maintain meter and equipment

records, and associated documentation that demonstrates

compliance with the requirements of this Section (including

documentation of the appropriate periodic testing of metering

equipment). Such records must be maintained for a period of

seven years and be made available for inspection by the

Transmission Provider upon request.

h. All Market Participants must maintain all meter and equipment

records, and associated documentation in a form that insures the

Transmission Provider’s ability to obtain the metering data it needs

to reliably and efficiently operate the Transmission System. The

Transmission Provider must file all additional metering standards

proposed by the Metering Standards Working Group unless, in its

own independent judgment, the Transmission Provider determines

that the additional standards proposed by the Metering Standards

Working Group, if implemented, could adversely impact the

reliable or efficient operation of the Transmission System.

f. Energy Delivery Outside of the Transmission Provider Region.

i. An Interchange Schedule for delivery outside of the Transmission Provider

Region shall be priced at and delivered to an Interface. Any transmission service

required on transmission systems beyond the Transmission Provider Region shall

be the responsibility of the Parties to the transaction. External resources can

MISO 38.2.5


MODULES 40.0.0, 41.0.0


supply Energy through Interchange Schedules in the Day-Ahead Energy and

Operating Reserve Market and Real-Time Energy and Operating Reserve Market.

ii. A Market Participant may enter into a transaction for the purchase or sale of

Energy to or from another Market Participant or any other entity, outside of the

Energy and Operating Reserve Markets, subject to the obligations of the Market

Participant pursuant to RAR. Market Participants shall report to and coordinate

with the Transmission Provider in accordance with this Tariff all Interchange

Schedules, including Pseudo-Tie transactions, that include a physical transfer of

Energy to or from an entity external to the Transmission Provider Region. All

sales of Energy, Capacity, Operating Reserve, Up Ramp Capability, and Down

Ramp Capability from resources located in Canada and all purchases of Energy,

Capacity, Operating Reserve, Up Ramp Capability, and/or Down Ramp

Capability under this Tariff to serve load in Canada shall be deemed to have a

point-of-delivery at the U.S/Canada border. Sales of Operating Reserve from

resources located in Canada may be provided from qualified Pseudo-tied External

Resources or qualified External Asynchronous Resources. Pseudo-Tie transaction

may utilize Day Ahead Virtual Transaction to align the Transmission Usage

Charge and available congestion hedges, i.e. FTRs and ARRs.

iii. A Market Participant may Pseudo-tie all or part of its generation or load as

specified in the Pseudo-tie Agreement included as Attachment FFF-2 to this

Tariff, as applicable, subject to the approval of the Transmission Provider. The

Market Participant shall be subject to all the standards, specifications, and

MISO 38.2.5


MODULES 40.0.0, 41.0.0


requirements of Attachment FFF-2, as applicable, for the generation and load

identified as subject to any executed Pseudo-tie Agreement under Attachment

Attachment FFF-2.

g. Generation Outage Schedule. The Transmission Provider shall coordinate all

Generator Planned Outages of a Market Participant’s Generation Resource within the

Transmission Provider Region, as appropriate, to the extent such Generator Planned

Outage impacts the Transmission Provider Region, as follows:

i. All Market Participants owning or controlling Generation Resource(s) within the

Transmission Provider Region affecting transmission capability or reliability shall

submit their Generator Planned Outage schedules to the Transmission Provider

for a minimum of a rolling two (2) Year period, however Market Participants with

nuclear Generation Resources shall submit nuclear Generator Planned Outage

schedules for a minimum of a rolling three (3) Year period. Outages schedules

submitted within these parameters will be considered by the Transmission

Provider as timely submitted. The Generator Planned Outage schedules shall be

presumed to be current unless updated. Market Participants may modify

previously submitted planned outages at any time up until twelve (12) months

prior to the time of the previously scheduled outage for non-nuclear Generation

Resources and twenty-four (24) months prior to the outage for nuclear Generation

Resources.

If a Market Participant modifies a previously submitted planned outage, then the

queue position in which the Generator Planned Outage schedule was received will

MISO 38.2.5


MODULES 40.0.0, 41.0.0


be reset to the time such modified planned outage schedule is received by the

Transmission Provider.

ii. The Transmission Provider shall analyze a Generator Planned Outage schedule to

determine its effect on Available Transfer Capability (ATC), the reliability of the

facilities within the Transmission Provider Region, and any other relevant

material effects. The Transmission Provider shall inform a Market Participant if

its schedule is expected to have a material impact on the reliability of the facilities

within the Transmission Provider Region within three (3) Months after Generator

Planned Outage schedules are submitted.

iii. As part of the review process, the Transmission Provider shall identify

opportunities and associated costs for rescheduling the Generator Planned Outage

to enhance the reliability of the facilities within the Transmission Provider

Region. Prior to making any rescheduling decision, the Transmission Provider

shall attempt to minimize the economic consequences of rescheduling including

direct costs (excluding Opportunity Costs), to consider physical feasibility, and to

coordinate with the affected Market Participants.

The Transmission Provider will re-schedule outages consistent with Good Utility

Practice when faced with, in real-time or in any time horizon for which NERC

standards require planning, a documented reasonable expectation of an

Emergency, or a documented reasonable expectation of any of the following

circumstances that compromise the reliability of the Transmission System, as

determined by the Transmission Provider: (a) the inability to maintain voltage

MISO 38.2.5


MODULES 40.0.0, 41.0.0


required by nuclear Generation Resources, or to meet any other Nuclear Plant

Interface Requirement, as that term is defined by NERC, including the provision

of off-site power supply; (b) the inability to maintain the Transmission System

within System Operating Limits using normal (non-emergency) operating

procedures or restore the Transmission System to normal operating conditions

following a single contingency with the use of normal (non-emergency) operating

procedures; or (c) the potential for contingencies to significantly affect

Transmission System reliability of metropolitan areas.

The Transmission Provider will coordinate with affected Market Participants to

attempt to voluntarily reschedule Generator Planned Outages to minimize direct

costs, which do not include Opportunity Costs, of such outages. If the

Transmission Provider is unable to resolve scheduling conflicts voluntarily with

the affected Market Participants, the Transmission Provider will assign priority to

Generator Planned Outage schedules based upon the chronological order in which

the Generator Planned Outage schedules were received to reschedule the outage.

Provided that the Generator Planned Outage is timely submitted, no rescheduling

will occur within twelve (12) Months of a Generator Planned Outage (twenty-four

(24) Months for nuclear Generation Resources), except where there is a

documented reasonable expectation of an Emergency or a documented reasonable

expectation of any of the circumstances (a)-(c) described supra in Subsection

38.2.5.g.iii that compromise the reliability of the Transmission System, due to the

MISO 38.2.5


MODULES 40.0.0, 41.0.0


following unexpected conditions: (1) severe weather; or (2) unplanned (urgent,

emergency, or forced) outages.

Market Participants whose Generator Planned Outage(s) have been rescheduled

shall be compensated for reasonable and explicit additional costs associated with

rescheduling such Generator Planned Outage pursuant to Attachment BB of this

Tariff and will be applied on a non-discriminatory basis to all Market Participants

assuming the following conditions:

(1) the Generator Planned Outage was timely submitted; or (2) the

Generator Planned Outage was not timely submitted and the following

occurred: (a) the Transmission Provider approved (accepted) the

Generator Planned Outage in the outage scheduling application; and (b)

the Transmission Provider was forced to re-schedule such planned outage

within twelve (12) Months of the planned outage (twenty-four (24)

Months for nuclear Generation Resources) date due to a documented

reasonable expectation of an Emergency or a documented reasonable

expectation of any of the circumstances (a)-(c) described supra in

Subsection 38.2.5.g.iii that compromise the reliability of the Transmission

System, that were caused by the following unexpected conditions: (1)

severe weather; or (2) unplanned (urgent, emergency, or forced) outages.

The Market Participant shall not be compensated for any opportunity costs

associated with such rescheduling.

MISO 38.2.5


MODULES 40.0.0, 41.0.0


iv. The Transmission Provider shall be responsible for documenting all Generator

Planned Outage schedules, all schedule changes, and all studies and services

performed with respect to any Generator Planned Outage. If a Generator Planned

Outage has been rescheduled, the Transmission Provider shall issue a report to a

stakeholder group, after the date that the originally scheduled outage has passed.

v. For Market Participants who are operators of nuclear Generation Resources

within the Transmission Provider Region, the Transmission Provider shall enter

into written agreements that define scheduling criteria, limitations and restrictions

necessary to ensure the safety and reliability of such facilities.

vi. The Transmission Provider may not reschedule Generator Planned Outages, if

doing so would contravene applicable laws, regulations, judicial orders, agency

orders, or where rescheduling is not feasible (voided warranty or equipment

damage).

vii. If: (1) a Market Participant does not provide the Transmission Provider with at

least one year advance notice of a Proposed Generator Planned Outage for

Generation Resources located within the Transmission Provider Region; (2) the

Transmission Provider determines that the proposed outage would cause a

scheduling conflict as specified in this Section 38.5.2.g; and (3) the Market

Participant refuses to reschedule the proposed Generator Planned Outage as

requested by the Transmission Provider, then during the next Planning Year, the

Transmission Provider shall calculate the XEFORd used to determine the

Unforced Capacity value for such Generation Resource under RAR by (1) adding

MISO 38.2.5


MODULES 40.0.0, 41.0.0


to the numerator of the XEFORd equation a number equal to three times the

duration of the outage, and (2) adding to the denominator of the XEFORd

equation a number equal to the duration of the outage.

viii. In addition to the provisions set forth in Section 38.2.5.g.vii, a Market Participant

providing notice of a Proposed Generator Planned Outage for a Generation

Resource located within the Transmission Provider Region will be subject to the

forced outage rate adjustment described below unless the Market Participant

provides Transmission Provider with: (1) at least one hundred and twenty (120)

Calendar Days’ advance notice; or, (2) between fourteen (14) and one hundred

and nineteen (119) Calendar Days’ advance notice of a Proposed Generator

Planned Outage to occur entirely during a time of adequate projected margin, at

the time the outage is provided to the Transmission Provider. There is adequate

projected margin when the maintenance margin, defined in the Business Practices

Manual for Outage Operations, is at or above zero (0) MW after subtracting the

MW of the requested Proposed Generator Planned Outage. The forced outage

rate adjustment applies if the Generator Planned Outage occurs during a period

when the Transmission Provider has declared a Maximum Generation

Emergency, as set forth in the Transmission Provider’s emergency operating

procedures, in the area where the Generation Resource is located. The forced

outage rate adjustment shall be applied in the next applicable Planning Year as

follows: the forced outage rate used to determine the Unforced Capacity value for

such Generation Resource under RAR and the Generator Forced Outage rates

MISO 38.2.5


MODULES 40.0.0, 41.0.0


used in the PRM analysis outlined in Section 68A.2 will be adjusted by adding to

the forced outage hours in both the numerator and denominator of the forced

outage rate equations a number equal to the greater of (1) the period during which

the outage overlaps with the Maximum Generation Emergency or (2) one Day.

Further, the outage will increase the number of forced outage occurrences by one

in the forced outage rate equations. If the Generator Planned Outage is a derate,

the greater of the period during which the derate overlaps with the Maximum

Generation Emergency or one Day will be converted into equivalent forced

derated hours.

ix. A Market Participant will be able to make changes to its Generator Planned

Outage and be exempt from the forced outage rate adjustment set forth in Section

38.2.5.g.viii by submitting a new outage request for any increased outage duration

provided: (1) the schedule change is requested not less than fourteen (14)

Calendar Days prior to the start of such outage; and, (2) the increased duration

must occur entirely during a time of adequate projected margin, at the time the

change is submitted. Any schedule change(s) made one hundred and twenty

(120) Calendar Days in advance or more will not be subject to the forced outage

rate adjustment described in Section 38.2.5.viii.

x. If a Market Participant provides at least one hundred and twenty (120) Calendar

Days’ notice for more than one Generator Planned Outage for the same unit to be

taken in whole or in part within the same one hundred and twenty (120) Calendar

Day period, the first request submitted will be eligible for exemption from the

MISO 38.2.5


MODULES 40.0.0, 41.0.0


forced outage rate adjustment set forth in Section 38.2.5.g.viii without further

review. The 120 Calendar Day period begins with the end date of the higher

queued request. Any subsequent Generator Planned Outage requests for the same

unit to be taken in whole or in part within the same one hundred and twenty (120)

Calendar Day period will be granted an exemption from the forced outage rate

adjustment only if there is adequate projected margin, at the time the request is

submitted.

xi. If the Market Participant reschedules its Generator Planned Outage at the

Transmission Provider’s request, the outage will not be subject to the forced

outage rate adjustment set forth in Section 38.2.5.g.viii.

h. Continuing Creditworthiness. Market Participants shall continue to comply with the

Credit Policy and creditworthiness criteria established by the Transmission Provider.

i. Grandfathered Agreements. A Market Participant that is party to a Grandfathered

Agreement(s) may choose to terminate such contracts and receive or provide

Transmission Service under this Tariff. Market Participants that intend to maintain

service under Grandfathered Agreements shall inform the Transmission Provider of their

selection of the treatment of transactions pursuant to such agreements under the Energy

and Operating Reserve Markets as described in Section 38.8. Market Participants may

request a change of treatment of such agreements annually as provided under those

options available to parties under Grandfathered Agreements described in Section 38.8.3;

provided, that, only Market Participants that settled the initial treatment of the

Grandfathered Agreement with the Transmission Provider prior to July 28, 2004, may

MISO 38.2.5


MODULES 40.0.0, 41.0.0


request such a change of treatment to any of Option A, Option B or Option C; and

provided, further, that Market Participants that did not settle the initial treatment of the


request such a change of treatment only to select either Option A or Option C. Requests

for such change of treatment may be made and granted only during the period designated

by the Transmission Provider for the annual redistributions of FTRs. In addition, the

Market Participants shall provide the information listed below. Information to be

provided to the Transmission Provider includes:

i. The GFA Responsible Entity.

ii. The GFA Scheduling Entity.

iii. The source and sink points applicable under the Grandfathered Agreement(s).

iv. The maximum MW Capacity permissible under the Grandfathered Agreement(s).

Tab B

MISO 38.2.5


MODULES 41.0.0


a. Standards. In performing its obligations under this Tariff, a Market Participant shall, at

all times, conduct its operations pursuant to the following standards.

i. Each Market Participant shall at all times: (i) follow Good Utility

Practice; (ii) comply with all applicable laws and regulations; (iii) comply

with the applicable principles, guidelines, standards and requirements of

the Commission, ERO and the applicable Regional Entities ; (iv) comply

with the procedures established for operation by the Transmission

Provider; and (v) cooperate with the Transmission Provider as necessary

pursuant to the terms of this Tariff, for the operation of the facilities in the

Transmission Provider Region in a safe, reliable manner, consistent with

Good Utility Practice.

ii. Each Market Participant shall operate, or shall cause to be operated, any

Resources supplying Energy and/or Operating Reserve owned or

controlled by such entity within the Transmission Provider Region or

otherwise supplying Energy to, through, or out of, the Transmission

Provider Region in a manner consistent with the standards, requirements

or directions of the Transmission Provider, pursuant to the terms of this

Tariff. Such standards and requirements shall be established in

accordance with industry standards, Applicable Reliability Standards,

Commission regulation, Good Utility Practice and applicable law. The

directions of the Transmission Provider shall be consistent with those

directions authorized under this Tariff; provided, however, no Market

MISO 38.2.5


MODULES 41.0.0


Participant shall be required to take any action inconsistent with Good

Utility Practice or applicable law.

iii. Each Market Participant shall notify the Transmission Provider of any

changes to the availability of, changes in quantity of, and/or changes in the

Resources it has committed for Energy, Operating Reserve, Up Ramp

Capability, and/or Down Ramp Capability as the Operating Day

approaches in accordance with timing specified in Business Practices

Manuals.

iv. Each Market Participant shall obtain and maintain all permits, licenses, or

approvals required for it to participate in the Energy and Operating

Reserve Markets in the manner contemplated by this Tariff.

v. Any Market Participant that seeks to transfer control of its generating unit

or load to (or from) the MISO Balancing Authority Area from (or to) a

specified external Balancing Authority Area on or after September 1, 2018

must execute and abide by the terms of the Pseudo-tie Agreement included

as Attachment FFF-1 or Attachment FFF-2 to this Tariff prior to

transferring control of the generating unit or load specified. The Market

Participant shall conform to all standards, specifications, and requirements

of Attachment FFF-1 or Attachment FFF-2, as applicable, at all times the

Pseudo-tie Agreement is in effect for that Market Participant.

b. Scheduling. Each Market Participant shall provide, or cause to be provided to the

Transmission Provider, scheduling and other information specified in this Tariff, and

MISO 38.2.5


MODULES 41.0.0


such other information as the Transmission Provider reasonably requires. Such

information shall be provided in accordance with the deadlines established by this Tariff

or by the Transmission Provider. Any Market Participant that executes the Pseudo-tie

Agreement in Attachment FFF-1 or Attachment FFF-2 shall conform to all standards,

specifications, and requirements regarding scheduling and providing information to

MISO as outlined in Attachment FFF-1 and Attachment FFF-2, as applicable.

The Transmission Provider shall abide by appropriate requirements for the non-disclosure

and protection of any Confidential Information given to the Transmission Provider by a

Market Participant as specified in Section 38.9. Each Market Participant shall maintain,

or cause to be maintained, compatible information and communications systems, as

specified by the Transmission Provider, required to transmit scheduling, dispatch, or

other time-sensitive information to the Transmission Provider in a timely manner. Any

Market Participant that executes the Pseudo-tie Agreement in Attachment FFF-1 or

Attachment FFF-2 shall maintain or cause to be maintained all communications and other

systems necessary to convey data to the MISO Balancing Authority and external

Balancing Authority as required under Attachment FFF-1 or Attachment FFF-2, as

applicable.

c. Fees and Charges. Each Market Participant shall be responsible for all fees and charges

to the Transmission Provider for operation of the Energy and Operating Reserve Markets

as determined by the Transmission Provider and allocated to the Market Participant in

accordance with Schedule 17 of this Tariff.

MISO 38.2.5


MODULES 41.0.0


In addition, each Market Participant shall be responsible for all fees and charges of the

Transmission Provider for administration of Financial Transmission Rights as determined

by the Transmission Provider and allocated to the Market Participant in accordance with

Schedule 16 of this Tariff.

d. Communications.

i. Each Market Participant shall have, or shall arrange to have: (i) its operations

staffed and equipped with communications systems capable of real-time

communication with the Transmission Provider during normal and Emergency

conditions; and (ii) systems to permit the Market Participant to control its Load or

facilities sufficient to meet the requirements of its Market Activities.

ii. A Market Participant selling Energy, Operating Reserve, Up Ramp Capability,

and/or Down Ramp Capability from Resources within the Transmission Provider

Region shall: (a) report to the Transmission Provider sources of Energy,

Operating Reserve, Up Ramp Capability, and Down Ramp Capability available

for operation; (b) supply to the Transmission Provider all applicable Offer data;

(c) report to the Transmission Provider those Resources that are Self-Scheduled

Resources; (d) confirm with the Transmission Provider any Interchange

Schedules; (e) respond to the Transmission

Provider’s directives to start, shutdown, or change output levels of Resources, in

accordance with the terms specified in the Offer or change scheduled voltages or

reactive output levels; (f) continuously maintain all Offers consistent with the

Offer rules and obligations for Market Participants in the Day-Ahead Energy and

MISO 38.2.5


MODULES 41.0.0


Operating Reserve Market, as specified in Section 39, and/or Real-Time Energy

and Operating Reserve Market, as specified in Section 40 concurrently with on-

line operating information; and (g) ensure that, where so equipped, Resources are

operated with control equipment, functioning as specified in the Business

Practices Manuals.

iii. A Market Participant selling Energy from Resources outside the Transmission

Provider Region shall comply with the Transmission Provider’s requirements for

Interchange Schedules provided herein.

iv. The Market Participant shall furnish the Transmission Provider with the

information specified in the Offer as set forth in Section 39 and Section 40 of this

Tariff for new Resources including default unit ratings, default Start-Up Offers or

Shut-Down Offers, time parameters, and default No-Load Offers or Hourly

Curtailment Offers. The information must be furnished no less than thirty (30)

days before a Market Participant’s initial Offer to sell Energy from a given

Resource in the Day-Ahead Energy and Operating Reserve Market or the Real-

Time Energy and Operating Reserve Market.

v. A Market Participant that is a Load Serving Entity or is purchasing on behalf of a

Load Serving Entity shall respond to Transmission Provider directives as set forth

in Section 40.2.20 this Tariff.

vi. To make purchases in the Energy and Operating Reserve Markets, a Market

Participant that is not a Load Serving Entity or purchasing on behalf of a Load

Serving Entity shall provide to the Transmission Provider requests to purchase

MISO 38.2.5


MODULES 41.0.0


specified amounts of Virtual Energy for each Hour of the Day-Ahead Energy and

Operating Reserve Market.

vii. Any Market Participant that executes the Pseudo-Tie Agreement included as

Attachment FFF-1 or Attachment FFF-2 to this Tariff shall provide the

Transmission Provider information and data in the manner and form specified in

Attachment FFF-1 or Attachment FFF-2, as applicable.

e. Metering.

i. Market Participants shall meet the minimum metering specifications and

standards described in this Section 38.2.5.e for all meters that are used as a data

source by the Transmission Provider, and the Transmission Provider shall make

these specifications and standards available in the Business Practices Manuals.

ii. A Market Participant shall either install and operate, or otherwise arrange for,

appropriate metering and related equipment capable of recording and transmitting

all data communications, as specified in this Section 38.2.5.e, reasonably

necessary for the Transmission Provider to perform the services specified in this

Tariff.

iii. Where available, a Market Participant or MDMA shall provide the Transmission

Provider with Metered data that meets the Transmission Provider’s requirements

by one of the following means: (a) direct transmission to the Transmission

Provider; (b) direct transmission to the Transmission Provider through the Local


Load is located; or (c) indirectly through metering provided by the Local

MISO 38.2.5


MODULES 41.0.0



Load is located. The Transmission Provider shall make this data available to the

Local Balancing Authority upon request. The Market Participant or MDMA shall

also provide its Metered data to the Transmission Owner, Local Balancing

Authority, ITC or LSE within whose area the Load is located to the extent such

information is needed to implement the Transmission Provider’s system operation

and planning functions, to provide billing services to the Market Participant, to

allow for data to be verified and agreed to by Transmission Owner, Local

Balancing Authority, ITC, or LSE, or to permit the performance of calculations

required by the Transmission Provider.

iv. A Market Participant whose metering services are provided by an MDMA shall

itself be responsible for ensuring that all data described in this Section 38.2.5 are

provided accurately.

v. All Market Participants must use their best efforts to provide the Transmission

Provider with Metered values for purposes of settlement in the form requested by

the Transmission Provider.

(a.) Market Participants shall report injection and withdrawal of Energy

at each Commercial Pricing Node where they have injections or

withdrawals. If the Market Participant does not have available

actual meter data at these locations, the Market Participant is

required to estimate Hourly injections and withdrawals based on

their possible information and make the data available to the

MISO 38.2.5


MODULES 41.0.0


Transmission Provider by submitting the meter data according to

the timeline established in the Business Practices Manuals. If no

meter data is provided to the Transmission Provider by the Market

Participant, or the submitted data is unreasonable or erroneous, the

Transmission Provider shall estimate the Hourly injections and

withdrawals based on the information it has available to be used in

Settlements for the Market Participant.

(b.) Market Participants must register any Internal Commercially

Pseudo-Tied Load, identifying for each such Load: (1) the

Commercial Pricing Node representing such Load, (2) the Local

Balancing Authority where the Load is physically located, and (3)

the Elemental Pricing Node(s) comprising the Internal

Commercially Pseudo-Tied Load. Market Participants shall report

injection and withdrawal of Energy for each Internal Commercially

Pseudo-Tied Load where they have injections or withdrawals. If the

Market Participant does not have available actual meter data at

these locations, the Market Participant is required to estimate

Hourly injections and withdrawals based on its possible information

and make the data available to the Transmission Provider by

submitting the meter data according to the timeline established in

the Business Practices Manuals. If no meter data is provided to the

Transmission Provider by the Market Participant, or the submitted

MISO 38.2.5


MODULES 41.0.0


data is unreasonable or erroneous, the Transmission Provider shall

estimate the Hourly injections and withdrawals for an Internal

Commercially Pseudo-Tied Load as the product of: (i) the sum of

the weighting factors for the Elemental Pricing Node(s) comprising

the Internal Commercially Pseudo-Tied Load that were used in the

calculation of the Day-Ahead and Real-Time LMPs of the

Commercial Pricing Node representing such Load; and (ii) the

Meter data submitted or estimated for that Commercial Pricing

Node.

vi. Market Participants shall submit withdrawal data for each Commercial Pricing

Node where they represent Load, including consumption information for

Commercial Pricing Nodes defined as Aggregate Load Zones. The Transmission

Provider will, for Settlement purposes apply any calculated Residual Load in each

Local Balancing Authority to the withdrawal data for the Load Zone applicable to

the Residual Load in that Local Balancing Authority.

vii. All Market Participants shall maintain metering equipment that meets the

following minimum standards:

a. All metering equipment must use megawatt-hour (MWh) as the

standard unit of service measurement. Service may be measure in

kilowatt-hours (kWh) if required by specific service, local or state

regulations, host utilities, service providers, or as are mutually

agreed upon by the parties involved, provided that KWh

MISO 38.2.5


MODULES 41.0.0


information is converted to fractional MWh information before it

is transmitted to the Transmission Provider.

b. All metering equipment must have bi-directional capability (the

ability to measure power flows in both directions).

c. All metering equipment must be capable of storing a minimum of

35-days of hourly intervals for each measured value.

d. Test switches or other means must be used to allow independent

testing and/or replacement of each meter or transducer using a

secondary circuit so as not to interrupt the operation of other

devices using the same secondary circuit.

e. Current transformers and voltage transformers used for metering

shall meet or exceed an accuracy class of 0.3%, and secondary

connected burdens shall not exceed rated burdens of any voltage

transformer. The same accuracy standards shall apply to optical

metering transducers.

f. Metering equipment shall be tested periodically in accordance with

the ANSI Standard requirement for the particular meter type as

stated in ANSI C12.1 Appendix D – Periodic Testing Schedules.

If any such test identifies any deficiency or inaccuracy in any

metering equipment, the deficient or inaccurate equipment must be

restored to correct operation as soon a reasonably possible, but in

no case any later than 30 days from the date of discovery.

MISO 38.2.5


MODULES 41.0.0


g. All Market Participants must maintain meter and equipment

records, and associated documentation that demonstrates

compliance with the requirements of this Section (including

documentation of the appropriate periodic testing of metering

equipment). Such records must be maintained for a period of

seven years and be made available for inspection by the

Transmission Provider upon request.

h. All Market Participants must maintain all meter and equipment

records, and associated documentation in a form that insures the

Transmission Provider’s ability to obtain the metering data it needs

to reliably and efficiently operate the Transmission System. The

Transmission Provider must file all additional metering standards

proposed by the Metering Standards Working Group unless, in its

own independent judgment, the Transmission Provider determines

that the additional standards proposed by the Metering Standards

Working Group, if implemented, could adversely impact the

reliable or efficient operation of the Transmission System.

f. Energy Delivery Outside of the Transmission Provider Region.

i. An Interchange Schedule for delivery outside of the Transmission Provider

Region shall be priced at and delivered to an Interface. Any transmission service

required on transmission systems beyond the Transmission Provider Region shall

be the responsibility of the Parties to the transaction. External resources can

MISO 38.2.5


MODULES 41.0.0


supply Energy through Interchange Schedules in the Day-Ahead Energy and

Operating Reserve Market and Real-Time Energy and Operating Reserve Market.

ii. A Market Participant may enter into a transaction for the purchase or sale of

Energy to or from another Market Participant or any other entity, outside of the

Energy and Operating Reserve Markets, subject to the obligations of the Market

Participant pursuant to RAR. Market Participants shall report to and coordinate

with the Transmission Provider in accordance with this Tariff all Interchange

Schedules, including Pseudo-Tie transactions, that include a physical transfer of

Energy to or from an entity external to the Transmission Provider Region. All

sales of Energy, Capacity, Operating Reserve, Up Ramp Capability, and Down

Ramp Capability from resources located in Canada and all purchases of Energy,

Capacity, Operating Reserve, Up Ramp Capability, and/or Down Ramp

Capability under this Tariff to serve load in Canada shall be deemed to have a

point-of-delivery at the U.S/Canada border. Sales of Operating Reserve from

resources located in Canada may be provided from qualified Pseudo-tied External

Resources or qualified External Asynchronous Resources. Pseudo-Tie transaction

may utilize Day Ahead Virtual Transaction to align the Transmission Usage

Charge and available congestion hedges, i.e. FTRs and ARRs.

iii. A Market Participant may Pseudo-tie all or part of its generation or load as

specified in the Pseudo-tie Agreement included as Attachment FFF-2 to this

Tariff, as applicable, subject to the approval of the Transmission Provider. The

Market Participant shall be subject to all the standards, specifications, and

MISO 38.2.5


MODULES 41.0.0


requirements of Attachment FFF-2, as applicable, for the generation and load

identified as subject to any executed Pseudo-tie Agreement under Attachment

Attachment FFF-2.

g. Generation Outage Schedule. The Transmission Provider shall coordinate all

Generator Planned Outages of a Market Participant’s Generation Resource within the

Transmission Provider Region, as appropriate, to the extent such Generator Planned

Outage impacts the Transmission Provider Region, as follows:

i. All Market Participants owning or controlling Generation Resource(s) within the

Transmission Provider Region affecting transmission capability or reliability shall

submit their Generator Planned Outage schedules to the Transmission Provider

for a minimum of a rolling two (2) Year period, however Market Participants with

nuclear Generation Resources shall submit nuclear Generator Planned Outage

schedules for a minimum of a rolling three (3) Year period. Outages schedules

submitted within these parameters will be considered by the Transmission

Provider as timely submitted. The Generator Planned Outage schedules shall be

presumed to be current unless updated. Market Participants may modify

previously submitted planned outages at any time up until twelve (12) months

prior to the time of the previously scheduled outage for non-nuclear Generation

Resources and twenty-four (24) months prior to the outage for nuclear Generation

Resources.

If a Market Participant modifies a previously submitted planned outage, then the

queue position in which the Generator Planned Outage schedule was received will

MISO 38.2.5


MODULES 41.0.0


be reset to the time such modified planned outage schedule is received by the

Transmission Provider.

ii. The Transmission Provider shall analyze a Generator Planned Outage schedule to

determine its effect on Available Transfer Capability (ATC), the reliability of the

facilities within the Transmission Provider Region, and any other relevant

material effects. The Transmission Provider shall inform a Market Participant if

its schedule is expected to have a material impact on the reliability of the facilities

within the Transmission Provider Region within three (3) Months after Generator

Planned Outage schedules are submitted.

iii. As part of the review process, the Transmission Provider shall identify

opportunities and associated costs for rescheduling the Generator Planned Outage

to enhance the reliability of the facilities within the Transmission Provider

Region. Prior to making any rescheduling decision, the Transmission Provider

shall attempt to minimize the economic consequences of rescheduling including

direct costs (excluding Opportunity Costs), to consider physical feasibility, and to

coordinate with the affected Market Participants.

The Transmission Provider will re-schedule outages consistent with Good Utility

Practice when faced with, in real-time or in any time horizon for which NERC

standards require planning, a documented reasonable expectation of an

Emergency, or a documented reasonable expectation of any of the following

circumstances that compromise the reliability of the Transmission System, as

determined by the Transmission Provider: (a) the inability to maintain voltage

MISO 38.2.5


MODULES 41.0.0


required by nuclear Generation Resources, or to meet any other Nuclear Plant

Interface Requirement, as that term is defined by NERC, including the provision

of off-site power supply; (b) the inability to maintain the Transmission System

within System Operating Limits using normal (non-emergency) operating

procedures or restore the Transmission System to normal operating conditions

following a single contingency with the use of normal (non-emergency) operating

procedures; or (c) the potential for contingencies to significantly affect

Transmission System reliability of metropolitan areas.

The Transmission Provider will coordinate with affected Market Participants to

attempt to voluntarily reschedule Generator Planned Outages to minimize direct

costs, which do not include Opportunity Costs, of such outages. If the

Transmission Provider is unable to resolve scheduling conflicts voluntarily with

the affected Market Participants, the Transmission Provider will assign priority to

Generator Planned Outage schedules based upon the chronological order in which

the Generator Planned Outage schedules were received to reschedule the outage.

Provided that the Generator Planned Outage is timely submitted, no rescheduling

will occur within twelve (12) Months of a Generator Planned Outage (twenty-four

(24) Months for nuclear Generation Resources), except where there is a

documented reasonable expectation of an Emergency or a documented reasonable

expectation of any of the circumstances (a)-(c) described supra in Subsection

38.2.5.g.iii that compromise the reliability of the Transmission System, due to the

MISO 38.2.5


MODULES 41.0.0


following unexpected conditions: (1) severe weather; or (2) unplanned (urgent,

emergency, or forced) outages.

Market Participants whose Generator Planned Outage(s) have been rescheduled

shall be compensated for reasonable and explicit additional costs associated with

rescheduling such Generator Planned Outage pursuant to Attachment BB of this

Tariff and will be applied on a non-discriminatory basis to all Market Participants

assuming the following conditions:

(1) the Generator Planned Outage was timely submitted; or (2) the

Generator Planned Outage was not timely submitted and the following

occurred: (a) the Transmission Provider approved (accepted) the

Generator Planned Outage in the outage scheduling application; and (b)

the Transmission Provider was forced to re-schedule such planned outage

within twelve (12) Months of the planned outage (twenty-four (24)

Months for nuclear Generation Resources) date due to a documented

reasonable expectation of an Emergency or a documented reasonable

expectation of any of the circumstances (a)-(c) described supra in

Subsection 38.2.5.g.iii that compromise the reliability of the Transmission

System, that were caused by the following unexpected conditions: (1)

severe weather; or (2) unplanned (urgent, emergency, or forced) outages.

The Market Participant shall not be compensated for any opportunity costs

associated with such rescheduling.

MISO 38.2.5


MODULES 41.0.0


iv. The Transmission Provider shall be responsible for documenting all Generator

Planned Outage schedules, all schedule changes, and all studies and services

performed with respect to any Generator Planned Outage. If a Generator Planned

Outage has been rescheduled, the Transmission Provider shall issue a report to a

stakeholder group, after the date that the originally scheduled outage has passed.

v. For Market Participants who are operators of nuclear Generation Resources

within the Transmission Provider Region, the Transmission Provider shall enter

into written agreements that define scheduling criteria, limitations and restrictions

necessary to ensure the safety and reliability of such facilities.

vi. The Transmission Provider may not reschedule Generator Planned Outages, if

doing so would contravene applicable laws, regulations, judicial orders, agency

orders, or where rescheduling is not feasible (voided warranty or equipment

damage).

vii. If: (1) a Market Participant does not provide the Transmission Provider with at

least one year advance notice of a Proposed Generator Planned Outage for

Generation Resources located within the Transmission Provider Region; (2) the

Transmission Provider determines that the proposed outage would cause a

scheduling conflict as specified in this Section 38.5.2.g; and (3) the Market

Participant refuses to reschedule the proposed Generator Planned Outage as

requested by the Transmission Provider, then during the next Planning Year, the

Transmission Provider shall calculate the XEFORd used to determine the

Unforced Capacity value for such Generation Resource under RAR by (1) adding

MISO 38.2.5


MODULES 41.0.0


to the numerator of the XEFORd equation a number equal to three times the

duration of the outage, and (2) adding to the denominator of the XEFORd

equation a number equal to the duration of the outage.

viii. In addition to the provisions set forth in Section 38.2.5.g.vii, a Market Participant

providing notice of a Proposed Generator Planned Outage for a Generation

Resource located within the Transmission Provider Region will be subject to the

forced outage rate adjustment described below unless the Market Participant

provides Transmission Provider with: (1) at least one hundred and twenty (120)

Calendar Days’ advance notice; or, (2) between fourteen (14) and one hundred

and nineteen (119) Calendar Days’ advance notice of a Proposed Generator

Planned Outage to occur entirely during a time of adequate projected margin, at

the time the outage is provided to the Transmission Provider. There is adequate

projected margin when the maintenance margin, defined in the Business Practices

Manual for Outage Operations, is at or above zero (0) MW after subtracting the

MW of the requested Proposed Generator Planned Outage. The forced outage

rate adjustment applies if the Generator Planned Outage occurs during a period

when the Transmission Provider has declared a Maximum Generation

Emergency, as set forth in the Transmission Provider’s emergency operating

procedures, in the area where the Generation Resource is located. The forced

outage rate adjustment shall be applied in the next applicable Planning Year as

follows: the forced outage rate used to determine the Unforced Capacity value for

such Generation Resource under RAR and the Generator Forced Outage rates

MISO 38.2.5


MODULES 41.0.0


used in the PRM analysis outlined in Section 68A.2 will be adjusted by adding to

the forced outage hours in both the numerator and denominator of the forced

outage rate equations a number equal to the greater of (1) the period during which

the outage overlaps with the Maximum Generation Emergency or (2) one Day.

Further, the outage will increase the number of forced outage occurrences by one

in the forced outage rate equations. If the Generator Planned Outage is a derate,

the greater of the period during which the derate overlaps with the Maximum

Generation Emergency or one Day will be converted into equivalent forced

derated hours.

ix. A Market Participant will be able to make changes to its Generator Planned

Outage and be exempt from the forced outage rate adjustment set forth in Section

38.2.5.g.viii by submitting a new outage request for any increased outage duration

provided: (1) the schedule change is requested not less than fourteen (14)

Calendar Days prior to the start of such outage; and, (2) the increased duration

must occur entirely during a time of adequate projected margin, at the time the

change is submitted. Any schedule change(s) made one hundred and twenty

(120) Calendar Days in advance or more will not be subject to the forced outage

rate adjustment described in Section 38.2.5.viii.

x. If a Market Participant provides at least one hundred and twenty (120) Calendar

Days’ notice for more than one Generator Planned Outage for the same unit to be

taken in whole or in part within the same one hundred and twenty (120) Calendar

Day period, the first request submitted will be eligible for exemption from the

MISO 38.2.5


MODULES 41.0.0


forced outage rate adjustment set forth in Section 38.2.5.g.viii without further

review. The 120 Calendar Day period begins with the end date of the higher

queued request. Any subsequent Generator Planned Outage requests for the same

unit to be taken in whole or in part within the same one hundred and twenty (120)

Calendar Day period will be granted an exemption from the forced outage rate

adjustment only if there is adequate projected margin, at the time the request is

submitted.

xi. If the Market Participant reschedules its Generator Planned Outage at the

Transmission Provider’s request, the outage will not be subject to the forced

outage rate adjustment set forth in Section 38.2.5.g.viii.

h. Continuing Creditworthiness. Market Participants shall continue to comply with the

Credit Policy and creditworthiness criteria established by the Transmission Provider.

i. Grandfathered Agreements. A Market Participant that is party to a Grandfathered

Agreement(s) may choose to terminate such contracts and receive or provide

Transmission Service under this Tariff. Market Participants that intend to maintain

service under Grandfathered Agreements shall inform the Transmission Provider of their

selection of the treatment of transactions pursuant to such agreements under the Energy

and Operating Reserve Markets as described in Section 38.8. Market Participants may

request a change of treatment of such agreements annually as provided under those

options available to parties under Grandfathered Agreements described in Section 38.8.3;

provided, that, only Market Participants that settled the initial treatment of the


MISO 38.2.5


MODULES 41.0.0


request such a change of treatment to any of Option A, Option B or Option C; and

provided, further, that Market Participants that did not settle the initial treatment of the


request such a change of treatment only to select either Option A or Option C. Requests

for such change of treatment may be made and granted only during the period designated

by the Transmission Provider for the annual redistributions of FTRs. In addition, the

Market Participants shall provide the information listed below. Information to be

provided to the Transmission Provider includes:

i. The GFA Responsible Entity.

ii. The GFA Scheduling Entity.

iii. The source and sink points applicable under the Grandfathered Agreement(s).

iv. The maximum MW Capacity permissible under the Grandfathered Agreement(s).

Tab C

1

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

PREPARED DIRECT TESTIMONY OF JEFF BLADEN

I. PROFESSIONAL BACKGROUND AND QUALIFICATIONS 1

Q. Please state your name, current position, and business address. 2

A. My name is Jeff Bladen. I am the Executive Director of Market Development for 3

the Midcontinent Independent System Operator, Inc. (“MISO”). My business 4

address is 720 City Center Drive, Carmel, Indiana. 5

Q. Please describe your educational background and professional experience. 6

A. I have a Bachelor of Arts degree from the Maxwell School of Public Affairs at 7

Syracuse University and a Masters of Business Administration from New York 8

University. Prior to joining MISO, I served as the North American division head 9

and leader of DNV GL Energy’s (formerly KEMA) Markets, Policy & Strategy 10

Development practice. Before joining DNV GL, I previously served as head of 11

strategy for Gamesa North America’s wind farm development business. In 12

addition, I was the General Manager for market strategy at PJM Interconnection 13

through 2008. My work at PJM included a leading role in the reforms to its 14

capacity market that became known as the Reliability Pricing Model. I began my 15

career in the energy business as one of the original team members at New Energy 16

Ventures; one of the first and among the most successful competitive retail energy 17

firms in the world and which today is the competitive retail energy provider 18

subsidiary of Exelon. 19

2

Q. Please describe your job responsibilities as they relate to this filing. 1

A. As the Executive Director of Market Development, I am responsible for the 2

overall planning for and execution of MISO’s market design. Changes that affect 3

key elements of energy price formation and the conversion of capacity to energy, 4

including design principles discussed in the Resource Availability and Need 5

(“RAN”) effort, are a core element of those responsibilities. 6

II. PURPOSE OF TESTIMONY AND RAN PROGRAM OVERVIEW 7

Q. What is the purpose of your testimony? 8

A. My testimony supports MISO’s proposed revisions to the generation outage 9

scheduling requirements in Module C of MISO’s Open Access Transmission, 10

Energy and Operating Reserve Markets Tariff (“Tariff”). If accepted, the 11

proposal will create enhanced transparency for MISO personnel and Stakeholders 12

with regard to planned Generator Planned Outages1, as well as incentivize 13

generators to avoid lower-margin, higher-risk periods when taking planned 14

outages. 15

Q. What is the genesis of the outage coordination proposal presented in this 16 filing? 17

A. The outage coordination proposal was identified through MISO’s RAN efforts as 18

an initial improvement to address imminent operational challenges in MISO. 19

These operational challenges are driven by several concurrent trends, including: 20

1. The evolution of the generation portfolio from a coal and nuclear 21

dominant fleet to a mix of generation with a higher proportion of 22 1 Per Module A of MISO’s Tariff, Generator Planned Outage definition includes both full and partial

outages. This definition will be referred to commonly as planned outages throughout this testimony.

3

intermittent and emergency only resources, increasing the importance of 1

transparency for such resources. 2

2. An increase in generation retirements that have caused MISO to operate 3

increasingly closer to minimum reserve margin requirements, diminishing 4

the operational flexibility historically provided by greater levels of 5

capacity. 6

3. An increase in forced outage rates and a high correlation in the timing of 7

planned generator outages and derates, creating resource risk outside of 8

Summer peak time. 9

If accepted, the outage coordination proposal will be a step towards addressing 10

these operational challenges and will significantly increase forward information 11

on generator outage scheduling for MISO operators. The expected benefits from 12

these changes include: 13

1. Improved forward signals will provide Generator Owners2 better 14

guidance on what timeframes in which to schedule planned outages, 15

leading to less correlated outage risks. 16

2. Near term signals will provide better guidance to Generator Owners as 17

they finalize the details of necessary nearer term planned outage 18

schedules between 14 and 120 days in advance of the operating day. 19

3. MISO will be able partner with Generator Owners to address potential 20

resource concerns further in advance. 21

2 For purposes of this testimony, the term “Generator Owner(s)” includes Generator operators and

entities acting as agent for a Generator owner.

4

As discussed in the testimony of Mr. Jameson Smith in support of this filing, 1

MISO has observed a significant amount of units with planned outages when 2

maximum generation or capacity sufficiency alerts have been issued, increasing 3

stress on operating the system and requiring MISO and Generator Owners to 4

coordinate over a very short timeframe to minimize these stresses. The proposal 5

incentivizes and allows Market Participants to be proactive, scheduling planned 6

outages and limiting adjustments to times with less resource risks and minimizing 7

future planned outages during emergency conditions. Seasonal derates also 8

should be planned in advance, which will provide further information for 9

consideration in outage projections and analysis. 10

Q. Please describe MISO’s RAN program and goals. 11

A. MISO’s RAN program is rooted in issues shared with stakeholders as early as 12

2015 and gained momentum in 2017 and 2018 through discussions in the MISO 13

stakeholder process. As part of this process, MISO published three separate 14

“white-papers” culminating in an evaluation whitepaper that presented a range of 15

short and long term improvement options.3 My testimony today supports one of a 16

small number of short term “fixes” that were discussed in the stakeholder process 17

in the last half of 2018, focusing on improvements to the generator outage 18

coordination process. On December 21, 2018, MISO submitted additional near-19

term solutions related to the availability and testing requirements of Load 20

3 Resource Availability and Need, Evaluation Whitepaper, September 10, 2018, available at:

https://cdn.misoenergy.org/Resource%20Availability%20and%20Need%20RAN%20Evaluation%20Whitepaper274537.pdf

5

Modifying Resources (“LMR”) that were also identified through the RAN 1

program.4 2

The RAN program initially identified four goals: 3

1) Improve planned outage scheduling and expectations; 4

2) Link resource accreditation and requirements with initial focus on 5

LMRs; 6

3) Align Planning Resource Auction (“PRA”) commitments with energy 7

needs all year; and, 8

4) Ensure flexible resource availability to address changing fleet 9

characteristics. 10

Each goal corresponds to a group of potential solutions discussed with 11

stakeholders that address related gaps, such as a lack of transparency in outage 12

scheduling or limited access to LMRs. For the purposes of today’s filing, MISO 13

is focused on the improvement of generator planned outage scheduling and 14

expectations through the submission of tangible, near-term improvements that are 15

urgently needed to address the operational challenges regarding correlated 16

outages. The measures proposed in this filing are specifically designed to provide 17

stakeholders with enhanced information about MISO expected system conditions 18

to support decisions about when to schedule planned outages. In addition, a new 19

accreditation penalty will apply where such outages meet the following criteria: 1. 20

the outage is not timely scheduled, and 2. the outage occurs during a high risk 21

period. Taken together, the proposed new measures are designed to reduce the 22

4 See MISO submittals in Docket Nos. ER19-650-000 and ER19-651-000, December 21, 2018.

6

influence of one factor (i.e., correlation of generator planned outages) to recent 1

maximum generation conditions. Complementary, longer-term improvements 2

will be designed to holistically address all the goals identified above, and will be 3

submitted in subsequent filings. MISO has committed to stakeholders to work 4

through these longer-term holistic improvements during the course of 2019, but is 5

filing these near term improvements to ensure reliability in the interim. 6

Q. Please describe the industry trends MISO has identified through its RAN 7 efforts that will continue to impact MISO’s operational challenges. 8

A. At least five important trends are impacting the MISO system. These trends are 9

increasingly difficult to manage in the operating timeframe throughout the year, 10

and it is expected that they will become more challenging in upcoming years, to 11

the point of threatening reliability. Continuation of these trends is expected and 12

will increase the potential to impact reliability going forward as a result of 13

potential mismatches in resource availability and need. As a result, reforms to the 14

processes through which capacity resources are converted to available energy are 15

necessary at this time. 16

Trend 1: Aging and retirement of the portfolio’s generating units and the 17 resulting impact on MISO’s operations. 18

Retirements and increasing generator outage levels (both planned and forced) 19

require MISO to operate with less available capacity than in the past. The effect 20

of this trend is to reduce the redundancy provided by greater levels of resource 21

availability. For example, daily average energy offers were down 8 GW in 22

Planning Year 2016/17 over Planning Year 2015/16. This reduction reflects a 4 23

GW net resource retirement and a 4 GW (23%) increase in the average MWs on 24

outage during those Planning Years. 25

7

Trend 2: Generator outage correlation. 1

2

The MISO Region has year-round load and supply needs that have historically 3

been served by a Summer-focused capacity commitment. Recently, lower overall 4

capacity levels and higher generator outage rates have reduced available capacity 5

in non-Summer periods. As a result, MISO has seen emergency conditions tied to 6

both planned and forced outages increase during non-Summer periods. This trend 7

imposes a growing challenge to ensure sufficient available capacity in those non-8

Summer periods.5 9

Trend 3: Growth in demand side and other emergency-only capacity as a 10 percent of the overall portfolio. 11

As shown by the graph below, nearly 12 GW of emergency-only Planning 12

Resources were cleared to meet MISO’s capacity needs in 2017 in the form of 13

LMRs. This represents a substantial increase over prior years and equals 9% of 14

the Summer peak load forecast and can exceed 15% of the non-Summer 15

“shoulder” period load when non-emergency resources traditionally plan their 16

maintenance. 17

5 Data as reported in Generator Availability Data System (GADS).

8

1

As discussed further below, these approximately 12 GW of resources are 2

generally not offered to MISO’s operators during non-Summer critical system 3

conditions, leading to increased operational risk. 4

Trend 4: Growing reliance on intermittent or unscheduled resources. 5

As the resource fleet has evolved, the MISO Region has become more reliant on 6

uncertain, uncommitted resources during tight operating periods. The chart below 7

describes the recent reliance on non-dispatchable and non-committed supply 8

resources. The circled events show times when the margin for operational 9

balance between supply and demand was nearly zero and resources to serve load 10

would have been below zero, but for energy delivery from these uncertain supply 11

sources. 12

Emergency only

Metered BTMG

Targeted Reduction DR

Firm Service Level DR

DR

BTMG

12 hrs

4.25 to 8 hrs

1.5 to 4 hrs

0 to 1 hrs

0

2,000

4,000

6,000

8,000

10,000

12,000

Lead Time Product Type Meas.Method

ResourceType

11.8 GW UCAP of Registered LMRs

9

1

This volatility places an increasing premium on resource flexibility and intra-day 2

scheduling in the operating timeframe 3

Trend 5: Growth of variable energy resources as a major element of the 4 fleet. 5

Trend 4 will be further exacerbated by the projected growth in variable energy 6

resources, as shown in the chart below. This resource category, by its very nature, 7

has different characteristics than the legacy Planning Resources they are 8

replacing. 9

10

1

Understanding and planning for the implications of renewable resources will 2

require further assessment to explore how best to manage operational reliability 3

while depending on a larger fleet of capacity resources that must be forecast for 4

operations rather than dispatched. 5

Q. Have these trends impacted MISO’s operations? 6

A. Yes. The effect of these trends is a substantial increase in declared emergencies 7

in the past few years. Specifically, in the two and a half years since June 1, 2016 8

there have been nineteen (19) Maximum Generation Emergencies, including 9

alerts, warnings, or events (“MaxGen declarations”), substantially all of which 10

have occurred during non-Summer periods. By contrast, there were zero (0) 11

MaxGen declarations in the two and a half years prior to June 1, 2016. 12

11

III. MISO OPERATIONAL CHALLENGES1

Q. Please describe MISO’s current resource adequacy construct. 2

A. In accordance with MISO’s Resource Adequacy Tariff provisions in Module E-1, 3

Load Serving Entities (“LSEs”) procure sufficient resources to meet their forecast 4

system-wide coincident peak load, plus a reserve margin, for the coming Planning 5

Year. MISO works with relevant regulatory authorities and Market Participants 6

to establish a Planning Reserve Margin (“PRM”), which defines the percentage 7

volume of resources required by each LSE above its peak load to reliably meet 8

that demand when considering risk factors such as generator forced outages and 9

weather uncertainty.6 By procuring resources to meet this margin above peak 10

load expectations, MISO and LSEs intend to ensure the MISO Region is resource 11

adequate in all time frames. 12

Q. How is the capacity cleared in the Planning Resource Auction converted into 13 energy in for daily operations? 14

A. Capacity Resources that clear the PRA generally must submit offers for the 15

Installed Capacity value of the resource into the Day-Ahead energy market and 16

certain Reliability Assessment and Commitment (“RAC”) processes for each 17

Hour of each day during the Planning Year.7 This requirement is commonly 18

referred to as the “must offer” requirement. There are some limited exceptions 19

when the must offer requirement does not apply; for example, when a Capacity 20

Resource is unavailable due to a forced or scheduled outage or its output is de-21

6 Section 68A.2 of the Tariff. 7 Section 69A.5 of the Tariff.

12

rated due to temporal, operational or seasonal conditions it is not required to offer 1

its capacity into the Day-Ahead or Real-Time energy market. 2

Q. How much advanced notice does MISO have of planned outages? 3

A. Pursuant to the MISO Tariff, planned outages are considered “timely” if they are 4

submitted at least three years in advance of the planned outage for nuclear 5

resources; and, at least two years in advance of the planned outage for other fuel 6

types. The Tariff also allows for changes to that plan to occur through one year 7

prior to the start time without being at risk for penalties. MISO is not proposing 8

to change these requirements. These requirements, as well as related 9

consequences of non-compliance, are described in further detail in Mr. Smith’s 10

testimony. 11

Q. What authority does MISO have over the generator outage process? 12

A. MISO coordinates outage requests in the MISO Region and works with Generator 13

Owners to reschedule outages that raise reliability concerns; however, as 14

discussed in more specific detail in Mr. Smith’s testimony, MISO does not have 15

specific authority to require rescheduling or prevent a generator from taking an 16

outage unless MISO is faced with an emergency or circumstance that would 17

compromise the reliability of the Transmission System. 18

Q. Please describe the operational challenges MISO is experiencing. 19

A. MISO’s resource adequacy and capacity conversion mechanisms date to a time 20

when the region had generation capacity well in excess of the Planning Reserve 21

Margin Requirements. To date, demonstration of capacity based on the forecast 22

coincident Summer peak plus a reserve margin has enabled Load Serving Entities 23

to serve firm load throughout every Planning Year. Changing market conditions 24

13

and fleet evolution have resulted in a resource portfolio with altered operational 1

characteristics and less available capacity overall. Among other things, these 2

changes include an increase in generator planned outages during non-Summer 3

periods. Under these evolving conditions, MISO has seen an increase in MaxGen 4

declarations, including an emerging trend for emergency conditions outside the 5

traditional Summer peak period. Given these changes, MISO must evaluate 6

alignment of resource availability and need to determine how today’s processes 7

for the conversion of committed capacity to energy enables reliable and efficient 8

operation of the Bulk Electric System today and in the foreseeable future. 9

Q. How does MISO’s existing generator outage coordination process impact 10 these operational challenges? 11

A. Both MISO and Generator Owners share a desire to plan generator outages 12

outside of the Summer and Winter peaks, which leads to a high correlation in the 13

timing of planned outages and complicates outage scheduling. As explained in 14

greater detail in Mr. Smith’s testimony, existing tools and processes have been 15

limited in managing this correlation given MISO’s limited authority over the 16

generator outage process and the significant effort required to reschedule an 17

outage. This, coupled with a large number of planned outages and derating of 18

units below their full capacity rating being submitted near the Operating Day that 19

results in limitations in the accuracy of forward forecasts, is causing the situation 20

to become increasingly problematic. This has led to a growing number of 21

Emergency events during “shoulder” seasons. 22

14

IV. MISO’s PROPOSED SOLUTIONS 1

Q. What is MISO focusing on in the near-term? 2

A. This filing, along with the LMR availability and testing proposals pending 3

Commission action in Docket Nos. ER19-650 and ER19-651, respectively, is 4

expected to reduce the frequency and severity of emergency events, allowing 5

MISO and stakeholders sufficient time to design more holistic, long-term 6

solutions. 7

Q. Why is MISO proposing these solutions now instead of waiting to file a 8 longer-term, holistic solution? 9

A. As noted above, MISO is committed to working with Stakeholders through the 10

RAN, and related, processes to develop holistic, long-term solutions to address 11

the operational challenges associated with the industry trends I describe above. 12

However, there is also the immediate need to improve MISO’s reliability posture 13

in the interim. This filing, in conjunction with the LMR availability and testing 14

filings, are the first steps towards meeting those goals. A primary objective of 15

this outage coordination filing is to reduce the influence of one contributor (i.e., 16

correlation of planned outages) to recent maximum generation conditions. 17

Because MISO has experienced an increase in such conditions, and expects such 18

conditions will continue to degrade without the measures being proposed in this 19

filing, MISO believes it is both prudent and necessary that it take action now. 20

Q. What are the key components of MISO’s proposal, as contained in this 21 filing? 22

A. MISO’s proposal has two key elements. First, MISO proposes to incentivize 23

additional forward planned outage submittals by creating new generator 24

accreditation penalties for planned outages taken during low margin, high risk 25

15

periods, while also providing a “safe harbor” from such penalties for requests 1

received sufficiently in advance. The proposal specifically exempts planned 2

outages submitted with at least 120 days’ notice and is consistent with NERC’s 3

Planned Outage definition (i.e., requiring that such outages be planned well in 4

advance and occur only once or twice a year).8 In addition, the proposal 5

addresses shorter lead time “maintenance” outages (i.e., those submitted with at 6

least 14 days’ notice) as long as such outages are not requested during forecasted 7

high risk periods as indicated by non-zero margin projections from MISO’s 8

maintenance margin analysis. 9

Second, MISO will utilize the increased forward information around forward 10

planned outages to support Stakeholder’s outage scheduling processes and 11

improve transparency through more accurate regional forecasts of generator 12

planned outages and derates. The specific details and implementation plan for 13

MISO’s proposal are provided in Mr. Smith’s testimony. 14

Q. How will these process improvements provide value? 15

A. To reliably serve customers in all hours of the year, MISO relies on efficient 16

conversion of committed capacity to energy, which is especially critical in light of 17

the narrowing gap between load and the increasingly intermittent resource supply. 18

However, the increased occurrences of emergency operations over the past two 19

and a half years (nineteen since June 2016, with the majority of these occurrences 20

outside the Summer months) underscore the importance of near-term action. An 21 8 NERC’s Generating Availability Data System, Data Reporting Instructions. Effective January 1, 2018.

See https://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/2019GADSDataReportingInstructions.pdf

16

increase of 5 to 10 GWs of available capacity, which equates to 3 – 6% of the 1

capacity committed in the MISO Region, would have avoided or dramatically 2

reduced the severity of all of the recent emergency events, as shown for events 3

from June 2016 through May 2018 in the figure below. 4

5

The proposed process improvements, in aggregate, will provide necessary relief 6

by increasing forward knowledge to predict and avoid more emergency conditions 7

by better coordinating planned outages to avoid such situations. Specifically, 8

stakeholders will have better projections of riskier timeframes to avoid taking 9

outages and MISO should have better information to address any potential risks 10

due to overlapping outages. 11

Q. Are both aspects of the proposal needed? 12

A. Yes. Forecasts cannot be improved without improved forward information from 13

Generator Owners around planned outages. Through pairing improvements to 14

forecasts with incentives for forward information, MISO and Generator Owners 15

can more effectively reduce correlated planned outage risk. 16

17

Q. How does the current behavior impact resource risk? 1

A. MISO’s current Loss of Load Expectation (“LOLE”) process makes several 2

assumptions in regards to planned outages and Load Modifying Resources. The 3

LOLE model optimizes the way planned outages are scheduled throughout the 4

year as part of the methodology and utilizes LMRs based on their availability, as 5

reported9 by Market Participants. Based on these assumptions, LOLE risk would 6

occur solely in the Summer, during times with the highest load. This risk is shown 7

in the green bars in the chart below and results in the current 7.9% resource 8

requirement. 9

10

These resource calculations also assume optimal availability of generation 11

resources, through efficient outage scheduling, and they assume no limitations to 12

the reported availability of LMRs. However, by modeling sub-optimal outages 13

9 Information gathered from Market Participants in the Module E Capacity Tracking Tool (“MECT”).

18

scheduling, similar to current Generator Owner behavior, and assuming the worst 1

case scenario that LMRs are not available or have insufficient lead time to support 2

emergency events in non-Summer months, the LOLE risk shifts from the Summer 3

to several Winter months as well as September. This is documented in the blue 4

bars of the chart and results in a 10.3% resource requirement. 5

Without modifications to outage scheduling behavior, and the improved use of 6

Load Modifying Resources, the resource requirement could increase by nearly 7

2.5% assuming the additional resources would not also become unavailable at 8

crucial times. The RAN process improvements—including the LMR related 9

changes filed in December 2018 and the changes to outage scheduling filed 10

today—are intended to address these concerns without increasing resource 11

requirements. 12

Q. How will these process improvements enhance transparency around the 13 availability of resources? 14

A. The proposed changes will address each of the goals identified at the beginning of 15

my testimony. Specifically, they will result in the following benefits: 16

1. Improved forward signals will provide Generator Owners better 17

guidance on what timeframes in which to schedule planned outages, 18

leading to less correlated outage risks; 19

2. Near term signals will provide better guidance to Generator Owners as 20

they finalize the details of necessary nearer term outage schedules 21

between 14 and 120 days in advance of the operating day; and, 22

3. MISO will be able to partner with Generator Owners to address 23

potential resource concerns further in advance. 24

19

Q. Will MISO’s forecasts help stakeholders evaluate the risk of shorter lead-1 time outages occurring over high risk periods? 2

A. Yes. The enhanced generator outage information to be provided by MISO will 3

provide stakeholders the opportunity to plan outages in a manner that enhances 4

system reliability. 5

V. STAKEHOLDER ENGAGEMENT 6

Q. How has MISO addressed RAN with stakeholders? 7

A. As previously referenced, RAN discussions are rooted in issues that have been 8

shared with stakeholders as early as 2015. Discussions about the causes of these 9

issues gained momentum in 2017 and 2018 with assignment through the MISO 10

stakeholder process and the publication of three “whitepapers” the first in Q1 11

2018 and including an evaluation whitepaper in the Fall 2018 that described a 12

gamut of short and long term potential solutions. Discussions early on in the 13

process informed two detailed issues whitepapers that described key trends and 14

their impacts on operational sufficiency. Subsequently, MISO published and 15

continued stakeholder discussions through a RAN focused “solutions” whitepaper 16

that laid out a range of improvements to address the identified issues for short 17

term and long term future filings. Key topics were also discussed during the 18

Spring and Fall of 2018 at two sessions of the most senior stakeholder committee; 19

the MISO Advisory Committee in their Hot Topics sessions attended by the 20

MISO Board of Directors. This allowed MISO, including Board Members, to 21

hear and collect advice and feedback directly from the stakeholder sectors on 22

energy sufficiency and generation outages. Additionally, multiple Reliability 23

Subcommittee (“RSC”) meetings and workshops further refined these potential 24

20

solutions into a near term proposal, with discussions over detailed design and 1

Tariff language spanning four formal and many more informal meetings with 2

stakeholders. Although the four month stakeholder process on detailed short-term 3

fixes may be considered by some to have been “compressed,” the nature and 4

urgency of the issues being addressed, and the need to implement at least the short 5

term solutions in advance of the 2019/2020 PRA, supports the urgency of these 6

filings at this time. 7

8 A complete list of this stakeholder outreach is included as Exhibit A to my 9

testimony. 10

Q. Please describe the stakeholder process specific to MISO’s outage 11 coordination proposal. 12

A. MISO posted its RAN evaluation whitepaper on September 10 which included a 13

broad set of potential solutions to address the key trends causing outage 14

correlation. MISO then focused the October 4 RSC discussion on the near-term 15

improvement options of the paper, which for outage coordination were 16

transparency and improved forward signals. MISO asked stakeholders several 17

questions to help refine potential solutions. These questions focused on two key 18

areas, 1) how should lead time impact how outages are classified and accredited, 19

and 2) how can MISO improve transparency through improved forward signals. 20

21

Stakeholder feedback and the direction from the MISO Advisory Committee was 1

considered and the proposed solutions were discussed further in the November 1 2

RSC. This discussion considered the broader set of potential solutions and then 3

focused on the solutions that MISO identified as the most reasonable approaches. 4

The limited nature of the changes, which build on existing processes and the 5

ability to make an impact for Spring, were the primary drivers for determining 6

reasonability. The primary focus was developing an approach to identify 7

penalties for scheduling short lead outages during times of high risk to incent 8

forward scheduling. Alternatives included 1) treating all planned outages 9

submitted less than a specific threshold, such as 30 days, as forced; 2) create total 10

outage rates, based on a simple measure of availability without consideration of 11

outage characteristics. These alternatives were not selected as neither would 12

incent both forward scheduling of planned outages and a reduction in total outage 13

rates. 14

MISO scheduled a November 16 workshop to perform a detailed walkthrough of 15

the proposal, with a 180 day safe harbor timeline and a high risk period defined 16

by conservative operations. Stakeholders provided feedback on the approach 17

which resulted refinements which were discussed in the subsequent November 29 18

RSC. In that meeting, MISO shared adjustments to the proposal which were 19

driven by stakeholder feedback from the workshop. These adjustments included 20

shortening the submittal requirement to 120 days and adding a limited schedule 21

refinement through 60 days. Additionally, the penalty was modified to be 22

effective only if a maximum generation alert was issued during the outage. 23

22

A December 7 RSC call was scheduled to allow stakeholders an opportunity to 1

seek clarification on proposed tariff edits supporting the proposal. In addition to 2

the preference to discuss any changes further before filing, another primary 3

concern stakeholders expressed was the desire to modify the proposal to address 4

planned outages that cannot be scheduled 120 days in advance. MISO decided it 5

was important to allow more time to discuss potential options and deferred the 6

filing until late January. Stakeholders developed proposals and presented them to 7

MISO on January 3. MISO considered these proposals and made changes to the 8

MISO proposal to incorporate key elements of the stakeholder refinement 9

proposals. 10

In a January 14 meeting MISO presented the updated proposal which adopted or 11

adapted many of the recommendations. The primary changes included 1) allowing 12

exemptions for short lead planned outages, including revisions, submitted 13

between 14 and 119 days if adequate margin is projected, 2) limiting the penalty 14

to the greater of 24 hours and the overlap of the planned outage and the Maximum 15

Generation Emergency condition instead of the planned outage duration, and 3) 16

removing the exemption limitation by allowing multiple exemptions for the same 17

unit within a defined timeframe. 18

The proposal submitted today is one designed to meet the objectives of increased 19

forward transparency and reducing overlapping outages while providing 20

stakeholders flexibility and better information to assist in their outage scheduling. 21

23

VI. CONCLUSIONS AND RECOMMENDATIONS 1

Q. How will this proposal enhance reliability and transparency? 2

A. As discussed previously, over the past five years, MISO has experienced an 3

evolution in its generation portfolio from a coal and nuclear dominant fleet to an 4

increased mix of intermittent and emergency only resources. At the same time, 5

generation retirements have caused MISO to operate with steadily decreasing 6

actual capacity margins each year, moving us closer to minimum reserve margin 7

requirements. This has led to diminished operational flexibility, which was 8

historically provided by greater levels capacity. Further, increasing forced outage 9

rates and high correlation in the timing of planned outages have created resource 10

risk outside of Summer peak. Operating near the minimum margin requirements, 11

along with an increased reliance on variable or emergency only resources, has 12

increased risks to the reliable and efficient operation of the Bulk Electric System 13

due to the conversion of capacity acquired through Resource Adequacy 14

Requirements to energy in real-time. 15

MISO’s proposal will improve the transparency of scheduled outages and allow 16

MISO and stakeholders to better coordinate generator planned outages. If 17

adopted, the MISO proposal will provide a number of important benefits: 1) 18

enhanced transparency and better projections of times of higher risk, low reserve 19

periods to support Generator Owner outage scheduling, 2) reduction in overlap of 20

outages which has been a contributor in recent emergencies, and 3) increase 21

MISO and Generator Owner collaboration during times of projected higher risk. 22

24

Q. Does this conclude your testimony? 1

A. Yes, it does. 2

AFFIDAVIT OF JEFF BLADEN

Jeff Bladen, being duly sworn, deposes and states that he prepared the Testimony of Jeff

Bladen, and the statements contained therein are true and accurate to the best of his knowledge

and belief.

SUBSCRIBED AND SWORN BEFORE ME, thisj)_Cf day of January, 2019.

State of Indiana, County oft\;(\ tu\)

.i...

RHIANNON RENA SHE.LLE.Y Clinton County.

My Commission El\plres September 27, 20j5

My Commission Expires: 9/Q1-/Joos ~µ ~ 1-Ds::rlJ-

Exhibit A

DATE OF MEETING

STAKEHOLDER GROUP

PRESENTATION LINK NOTES

5/31/18 Reliability Subcommittee

https://cdn.misoenergy.org/20180531%20RSC%20Item%2009%20LMR%20Issues%20Whitepaper206830.pdf https://cdn.misoenergy.org/20180531%20RSC%20Item%2009%20RAN206815.pdf

• Stakeholders provided guiding principles for MISO’s evaluation and solution development efforts, a focus for outage scheduling on: o Evaluate enhanced role for MISO in outage

coordination o Explore seasonal aspects in planning and

operations o Consider actual resource availability (total

availability rate) 8/2/18 Reliability

Subcommittee https://cdn.misoenergy.org/20180802%20RSC%20Item%2008%20RAN%20Overview262351.pdf

MISO outlined four near-term focus areas for RAN, with the following focusing on Outage Coordination: • Ensure outage process matches resource expectations

with commitments Outage processes should provide transparency while planning processes should reflect risk

9/19/18 Advisory Committee

https://cdn.misoenergy.org/20180919%20AC%20Item%2002%20MISO%20Intro%20to%20Hot%20Topic275328.pdf

Stakeholder “Hot Topic” discussions dealt with generation outages: • A desire for near-term (year end 2018) solutions was

expressed in conjunction with work on medium and long-term items.

• Some areas received broad support, such as seasonal Resource Adequacy, while others, such as outage coordination roles, had mixed views


https://cdn.misoenergy.org/20181004%20RSC%20Item%2005%20Generation%20Outage%20Coordination%20Hot%20Topic%20Recap280607.pdf https://cdn.misoenergy.org/20181004%20RSC%20Item%2006%20RAN%20Eval%20Whitepaper%20Summary28

• Discussion of stakeholder feedback on the solutions in the evaluation whitepaper and additional solution ideas

• Stakeholders inform our plan to deal with LMRs and outages in near-term at RSC with holistic longer term solutions occurring in 2019 in the RASC and MSC

• MISO requests formal feedback on: 1) LMRs 2) Outages, 3) Longer-term holistic solutions

Exhibit A

0609.pdf

o Outage Coordination feedback focused on improved forward signals, outage classification, and an outage scarcity product


https://cdn.misoenergy.org/20181101%20RSC%20Item%2005%20RAN%20Presentation%20-%20MR025288763.pdf

• MISO introduced a multi-phase approach with a goal of implementing short term fixes in early 2019

• Focus on near term improvements with desired impact by Spring 2019

• Near Term Objective: Improved availability of and access to 5 – 10 GWs will reduce risks

• Outage Coordination “transparency and high risk” proposal: o Provide enhanced transparency through historical

reporting, regional forecasts, and tool improvement o Incentivize forward outage scheduling with

potential penalty for those not scheduled well in advance

11/16/18 Reliability

Subcommittee (Workshop)

https://cdn.misoenergy.org/20181116%20RAN%20Workshop%20Presentation293288.pdf

Conducted a detailed discussion and gathered advice for RAN short term fix proposals. Stakeholders supported increased transparency and had mixed opinions on the lead time required for penalty exemptions.


https://cdn.misoenergy.org/20181129%20RSC%20Item%2003%20and%2004%20RAN%20Detail%20Review297415.pdf

• RAN Detail Review • Module C redline posted • Adjustments to both lead time and high risk definition

communicated, driven by stakeholder feedback from workshop

12/7/18 Reliability

Subcommittee Link to posted redlines: https://www.misoenergy.org/events/reliability-subcommittee-rsc---december-7-2018/

• Line by line discussion of posted redlines • Feedback, clarification requests, suggested changes • MISO communicated on 12/12 that the Outage

Coordination filing will be delayed to allow for additional stakeholder discussion and proposals

Exhibit A


https://cdn.misoenergy.org/20190103%20RSC%20Item%2002%20RAN%20Outage%20Coordination%20(RSC%20008)305623.pdf

• Reviewed current proposal and timeline to support January filing

• Three stakeholders presented proposals; focusing on: o Provide exemption for requests with less than

120 day lead times if adequate margin is projected from the maintenance margin process at the time of the request submittal

o Allow revisions to outages while retaining exemption

o Do not limit the number of exemptions within any particular period

o Modify the penalty, 1) set to greater of overlap with event and one day, or 2) duration of the event


https://cdn.misoenergy.org/20190114%20RSC%20Item%2002%20OC%20RAN%20Detailed%20Review%20and%20Tariff%20Jan%2014309237.pdf

MISO detailed how the proposal was modified based on suggestions, with the following key changes:

• Requests submitted with less than 120 days lead time but at least 14 days in advance will gain an exemption if at the time of submittal, maintenance margin projects adequate margin to accommodate the request

• Outage revisions can be made up to and including 14 days in advance. Any new days of the request will gain an exemption if maintenance margin projects adequate margin to accommodate at the time of the revision. Any unchanged days will maintain exemption.

• For requests submitted 120 days or more in advance: o Automatic exemption will be granted to the

first request o Additional long-lead requests which occur in

the same 120 day period in the will gain an exemption based on maintenance margin

Exhibit A

• All requests submitted with at least 14 days’ notice up to 119 days’ notice gain exemptions based on maintenance margin

• Penalty is the greater of 1) the overlap of the request and the event or 2) one day

1/10/19 and 1/24/19

Maintenance Margin Focus Group Meetings

N/A MISO established a focus group formed of interested parties of the Reliability Subcommittee to review potential improvements to the maintenance margin process.

Tab D

1

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

PREPARED DIRECT TESTIMONY OF JAMESON T. SMITH

I. PROFESSIONAL BACKGROUND AND QUALIFICATIONS 1

Q. Please state your name, current position, and business address. 2

A. My name is Jameson T. Smith. I am the Director of Operations Planning for the 3

Midcontinent Independent System Operator, Inc. (“MISO”). My business address is 4

3850 N. Causeway Blvd., Two Lakeway, Suite 442, Metairie, Louisiana. 5

Q. Please describe your educational background and professional experience. 6

A. I graduated from Mississippi State University with a Bachelor of Science degree in 7

Electrical Engineering. I received a Master of Business Administration degree from 8

Oklahoma State University. In January 2001, I was employed by American Electric 9

Power as a transmission planning engineer for its holdings located in the Southwest 10

Power Pool. I performed transmission planning studies for four states, and conducted 11

analyses for annual forward planning, generator interconnection, load interconnection, 12

and voltage stability. I have been employed by MISO since January 2006 and have had 13

various professional and managerial positions, including Resource Forecasting Engineer, 14

Manager of Policy Studies, Director of Policy Studies, and the Director of Economic and 15

Policy Planning. I was appointed to my current position, the Director of Operations 16

Planning in November 2018. 17

2

Q. Please describe your job responsibilities as they relate to this filing. 1

A. As the Director of Operations Planning, I am responsible for overseeing efforts that 2

support the development of the operating day plan. Specifically, I am responsible for 3

Seams Administration, Forecasting for load and renewable generation, and Outage 4

Coordination. 5

Q. What professional licenses or certifications do you hold? 6

A. I am a registered professional engineer in the State of Oklahoma, License No. PE22110. 7

II. INTRODUCTION AND PURPOSE OF TESTIMONY 8

Q. What is the purpose of your testimony? 9

A. My testimony supports MISO’s proposed revisions to the generation outage scheduling 10

requirements found in Module C of the MISO Open Access Transmission, Energy and 11

Operating Reserve Markets Tariff (“Tariff”), and specifically to Section 38.2.5.g of the 12

Tariff. If accepted by the Federal Energy Regulatory Commission (“FERC” or 13

“Commission”), the proposal will create enhanced transparency for MISO personnel and 14

Stakeholders with regard to planned outages and derates as well as incentivize generators 15

to avoid lower margin, higher risk periods when taking planned outages and derates. My 16

testimony builds on and expands the discussion of the need for the MISO proposal 17

described in the testimony of Mr. Jeff Bladen. I describe the principal Tariff revisions 18

included in MISO’s filing and explain how they will accomplish the desired reform 19

objectives. 20

Q. How is your testimony organized? 21

A. My testimony is organized as follows: 22

• Part I explains my professional background and qualifications. 23

3

• Part II provides a brief introduction and explains the purpose of my testimony. 1

• Part III explains the current outage coordination practices and related limitations. 2

• Part IV discusses the key elements of MISO’s proposal. 3

• Part V describes the benefits MISO expects from this proposal. 4

• Part VI contains my recommendation to the Commission to adopt the MISO 5

proposal as filed. 6

III. Current Generation Outage Scheduling Practices and Related Limitations 7

A. Current Generation Outage Practices 8

Q. When are generators currently required to notify MISO of a Generator Planned 9 Outage1? 10

A. As currently set forth in Section 38.2.5.g of the Tariff, in order to be considered “timely” 11

generators must submit advance notice of planned outages as follows: at least three years 12

in advance of the planned outage for nuclear resources; and, at least two years in advance 13

of the planned outage for other fuel types. The Tariff also allows for changes to that plan 14

to occur through one year prior to the start time without being at risk for penalties. MISO 15

is not proposing to change these requirements. 16

Q. What are the roles and responsibilities of MISO regarding the outage scheduling 17 process? 18

A. MISO coordinates and assesses the impact of all generator outage schedules in MISO’s 19

Reliability Coordinator Area that maintains system security and minimizes adverse 20

impacts on the available transmission capacity levels and adheres to agreed nuclear plant 21

1 Per Module A of MISO’s Tariff, Generator Planned Outage definition includes both full and partial outages.

This definition will be referred to commonly as planned outages throughout this testimony.

4

interface requirements. MISO works with Generator Owners2 to reschedule conflicting 1

generator outages for security and reliability reasons within the scope of its authority. 2

Q. How far in advance are most planned outages scheduled? 3

A. Approximately 30% of MWs from actual planned outages are scheduled more than 120 4

days in advance, according to CROW, the MISO Outage Scheduling system of record, 5

from June 1, 2016 to December 2, 2018. A negligible amount of derates are scheduled 6

120 days or more in advance. 7

Q. What are the key roles and responsibilities of generators regarding outage 8 scheduling as they relate to this filing? 9

A. Generator Owners must submit their planned outage schedules for Generation Resources 10

10 MW and above to MISO on a timely basis and update them on a daily basis. Generator 11

Owners, shall submit a derate schedule for all generation facilities when its available 12

output is reduced below the machine’s capability. 13

Q. What authority does MISO have to change a planned outage? 14

A. MISO can request that a generator voluntarily reschedule its planned outage if necessary 15

to address Bulk Electric System reliability events. Additionally, MISO has the authority 16

to reschedule a planned outage, consistent with Good Utility Practice, when faced with a 17

documented reasonable expectation of: 1) an Emergency; or, 2) any circumstances that 18

compromise the reliability of the Transmission System (including, a) the inability to 19

maintain the voltage required by a nuclear Generation Resource, b) the inability to 20

maintain the Transmission System within System Operating Limits using normal 21

2 For purposes of this testimony, the term “Generator Owner(s)” includes Generator operators and entities acting

as agent for a Generator owner.

5

operating procedures, and, c) the potential for contingencies to significantly affect 1

Transmission System reliability of metropolitan areas). 2

Q. What happens if a generator doesn’t plan its outage in a timely manner and refuses 3 reschedule during an expected emergency or time of compromised reliability? 4

A. A generator is subject to a forced outage rate penalty, equivalent to a forced outage of 5

three times the duration of the outage, which is applied to the applicable unit’s capacity 6

accreditation for the next Planning Year. 7

Q. Do generators usually move a planned outage if asked? 8

A. Generators have worked with MISO to move outages when necessary even in situations 9

where they are not required to do so under the Tariff. However, such voluntary 10

flexibility may be of limited use, especially if recurring emergency events cause such 11

requests to become regular. Also, forecasting tools require forward information. The 12

lack of availability of forward information in such forecasts limits the ability of 13

generators to rely on these signals to avoid times with lower margins. Finally, the ability 14

of generators to adjust their schedules is directly related to the amount of time they are 15

provided in which to respond. 16

Q. Is it a significant effort for MISO to coordinate outages? 17

A. Yes. In order to move a planned generator outage, MISO must contact generators that 18

have requested planned outages individually and wait for the generators’ response to the 19

reschedule request. Recent rescheduling requests, for example, have taken between 40-20

60 person-hours of time on behalf of MISO’s outage coordination staff for each projected 21

reliability concern. 22

Moreover, MISO staff require sufficient lead time to evaluate, coordinate, and manage 23

rescheduling requests. Specifically, more timely submission of outage requests allow 24

6

MISO the ability to more effectively coordinate planned outages by having a more 1

appropriate view of the generators planned out of service. 2

Q. What transparency do MISO and stakeholders have into the amount of resources 3 scheduled to be on outage at a given time? 4

A. MISO currently provides stakeholders with information through MISO’s maintenance 5

margin tool, which is posted monthly with forecasts for the next three years. The posted 6

data provides insight into the availability of periods during which generator outages can 7

be scheduled without potentially affecting system reliability. The maintenance margin 8

tool currently provides daily estimates of capacity margins for the MISO system and for 9

each of the ten Local Resource Zones (“LRZs”) within MISO. 10

Q. Do Generator Owners rely solely on MISO tools and inputs? 11

A. No. Generator Owners schedule their outages with consideration of many inputs, 12

including but not limited to information from MISO. This additional information may 13

include weather forecasts, outage crew scheduling and budgetary considerations. 14

B. Related Limitation 15

Q. Please describe any limitations of MISO’s current outage coordination transparency 16 and tools. 17

A. Current outage coordination processes are limited in three aspects: 1) the ability to 18

manage highly correlated outages, 2) the ability to provide forward forecasts of projected 19

planned outages during a given timeframe, and 3) the ability to incent generators to 20

reschedule from high-risk times. 21

1) Outages are highly correlated 22

A shared desire by both MISO and Generator Owners to plan the majority of 23

outages outside of the summer and winter peaks leads to a high correlation in the 24

timing of planned outages and complicates outage scheduling. These outages 25

7

generally include times when load is expected to be lower. Existing tools have 1

been limited in managing this correlation due to the limited timeframe between 2

when many outages are scheduled and a lack of incentives to respond to voluntary 3

rescheduling requests. 4

5

2) Late scheduling of planned outages limits the ability to provide accurate 6

forward forecasts 7

MISO outage coordination experiences difficulty in managing the highly 8

correlated planned outages, in part, due to the large number of planned outages 9

submitted with minimal advance notice. This reduces the time for MISO to 10

analyze and react to scheduled outages, and it also limits the accuracy of forward 11

forecasts. This situation is becoming increasingly problematic as MISO continues 12

to experience growing numbers of Emergency events during the “shoulder” 13

seasons. 14

3) Incentives do not sufficiently incent forward scheduling or rescheduling to 15

avoid potential resource sufficiency challenges 16

Additionally, and as noted previously, the existing Tariff provisions establishing 17

penalties, which can generally be avoided through forward scheduling, are 18

8

targeted only towards narrowly defined reliability concerns and do not apply for 1

resource adequacy concerns. 2

These factors combine to create risk that cannot be mitigated through rescheduling, in 3

large part because the rescheduling of outages is manual and dependent on stakeholders’ 4

willingness and ability to reschedule previously planned outages with relatively short 5

notice. 6

Q. How have these limitations impacted MISO operations? 7

A. Lower overall capacity levels and higher outage rates have reduced available capacity in 8

non-summer periods, and such periods have also seen increased risk due load variability 9

previously masked by abundant reserves on the system. As a result, MISO has seen 10

correlated outages, along with an increasing number of forced outages, during non-11

summer periods impose a growing challenge to ensuring sufficient capacity is available 12

to be converted to energy during those periods. 13

For example, forced outages increased an average of 1.6 GW during Planning Year 14

2015/16 and another 4.2 GW in Planning Year 2016/17. The combination of planned and 15

maintenance outages went from 5.56 percent in 2013 to 6.16 percent in 2016.3 This has 16

led MISO’s operators to implement Maximum Generation Emergency measures in order 17

to be able to access needed emergency-only resources. As noted in the testimony of Mr. 18

Bladen, there have been nineteen MaxGen declarations since June 1, 2016, whereas there 19

were zero MaxGen declarations in the two years before June 1, 2016. 20

3 Resource Availability and Need, Issue Statement Whitepaper, Marc 30, 2018, available at:

https://cdn.misoenergy.org/20180405%20RSC%20Item%2007%20RAN%20Issues%20Statement%20White%20Paper164746.pdf

9

IV. DISCUSSION OF PROPOSED REFORMS 1

A. Overview 2

Q. Please summarize the key elements of MISO’s proposal. 3

A. MISO’s proposal has two key elements. First, MISO proposes to incentivize additional 4

forward planned outage submittals by creating new generator accreditation penalties for 5

planned outages taken during low margin, high risk periods, while also providing a “safe 6

harbor” from such penalties for requests received sufficiently in advance. The proposal 7

specifically exempts planned outages submitted “well in advance” (i.e., those submitted 8

with at least 120 days’ notice) and is consistent with NERC’s Planned Outage definition, 9

i.e., requiring that such outages be planned well in advance and occur only once or twice 10

a year.4 In addition, the proposal specifically addresses shorter lead time outages (i.e., 11

those submitted with at least 14 days’ notice) to the extent such shorter-lead time outages 12

are not requested during high risk periods, as indicated by non-zero margin projections 13

from the maintenance margin analysis. 14

Second, MISO will utilize the increased forward information around planned outages to 15

support Generator Owners’ outage scheduling processes and improve transparency 16

through more accurate regional forecasts of planned outages. 17

B. Incentives for Forward Scheduling of Planned Outages 18

Q. How is MISO proposing to incentivize generators to schedule planned outages 19 further in advance? 20

A. As discussed in more detail below, MISO is proposing a sequenced approach to incent 21

forward outage scheduling. In addition to the existing penalties for the timely submission 22

4 NERC’s Generating Availability Data System, Data Reporting Instructions. Effective January 1, 2018. See

https://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/2019GADSDataReportingInstructions.pdf

10

of outages, MISO will create a new penalty for outages which are scheduled closer to the 1

operating day and occur during a MaxGen alert, warning, or event. Generators will then 2

be able to obtain an exemption from this penalty through; 3

1. Scheduling their planned outage no less than 120 days in advance 4

2. Scheduling their planned outage at least 14 days in advance and ensuring the 5

entire duration of the outage occurs in a time with sufficient projected margin 6

3. Moving outages scheduled within 14 days from periods with emergency 7

events 8

Q. Please describe this incentive. 9

A. The proposed Tariff changes create a new accreditation adjustment for planned outages 10

not meeting the submittal requirements of the proposal. These adjustments would be 11

applied if the outage occurs during a declared Maximum Generation Emergency alert, 12

warning, or event impacting the sub-region in which the generator is located. The 13

adjustment will affect the generator’s capacity accreditation beginning with the next 14

applicable Planning Year by considering the outage as “forced” for purposes of that 15

generator’s forced outage rate. The duration of the deemed “forced” outage will be equal 16

to the portions of the outage which overlaps with the Emergency alert, warning or event, 17

or at least one day, whichever is longer. 18

Q. How will MISO determine whether there is an adequate margin? 19

A. An adequate margin will be represented by a non-zero maintenance margin value, capable 20

of accommodating the MW of the requested planned outage. 21

Q. Why was the duration of the penalty set as described? 22

A. Initially, MISO had proposed that the penalty be applied to the duration of the outage. 23

However, following stakeholder feedback, the duration was adjusted to the proposed 24

11

approach described above. This duration was calculated to match the time in which the 1

outage increased stress on the MISO system (e.g., the overlap with the emergency 2

measure) while also providing meaningful signals through a minimum duration impact of 3

one day. 4

Q. How does MISO propose to treat derates? 5

A. Derates have contributed to recent Maximum Generation Emergencies, so the proposal 6

will treat them in a comparable manner to out of service outages. However, the penalty 7

will be adjusted to reflect the full amount of the unit that is out of service (e.g. the amount 8

of the derate) and an equivalent forced outage rate will be calculated and applied. 9

Q. How would a planned outage scheduled less than 14 days in advance be treated? 10

A. A generator that does not submit its planned outage at least 14 days in advance will be 11

subject to application of the forced outage rate adjustment described above if a Maximum 12

Generation Emergency alert, warning or event is declared during the outage. 13

Q. Can an outage submitted within 14 days avoid this penalty? 14

A. Yes. A generator outage will not be assessed a penalty if a Maximum Generation 15

Emergency does not occur during its duration. Additionally, generator outages that are 16

moved per MISO request will not be assessed a penalty; a generator may thus avoid a 17

penalty through being responsive to MISO emergency declaration and staff requests. 18

Q. How would a planned outage scheduled between 14 and 120 days in advance be 19 treated? 20

A. A generator that submits its planned outage between 14 and 120 days in advance and 21

schedules during a period with sufficient projected adequate margin will granted an 22

exemption to the penalty described previously, or a ‘safe harbor’. 23

12

Q. How would a planned outage scheduled at least 120 days in advance be treated? 1

A. In general, an exemption from the forced outage rate adjustment will also be granted to 2

planned outages submitted no later than 120 days in advance of the requested start time, 3

without consideration of the margin at the time of their scheduling. However, this safe 4

harbor provision without consideration of the margin would be limited to one issuance 5

per 120 day window, as discussed further below. 6

Q. How would a planned outage scheduled 120 days or more in advance be treated if it 7 occurs during a period with inadequate margin? 8

A. The proposed new accreditation adjustment would not apply; MISO would work with 9

generators as needed to reschedule outages and maintain reliability. This forward 10

scheduling provides an adequate amount of time to address any issues and provide 11

Generator Owners’ with the transparency that indicates this would not be an ideal time 12

for additional outages if forecasts do not change. 13

It should be noted that existing penalties will still apply to these units. More specifically, 14

if the planned outage was not submitted in accordance with the existing Tariff 15

requirements set forth in Section 38.2.5.g (i.e., three years for nuclear generators and two 16

years for all other fuel types), a reliability concern is anticipated, and the generator 17

refuses to reschedule at MISO’s request, the generator will be subject to the existing 18

Tariff prescribed penalty, viz., a three times XEFORd accreditation adjustment in the next 19

Planning Year. These existing Tariff requirements are not being modified in this filing 20

and remain applicable to all planned outages in addition to the proposed changes set forth 21

in this filing. 22

13

Q. How much can a generator change its scheduled outage? 1

A. To retain the safe harbor benefit proposed in this filing, a generator that submits its 2

schedule 120 days or more in advance will have the flexibility to adjust its schedule up to 3

14 days prior to the start of its outage. Any increase in the duration of the outage, 4

however, must occur entirely during a period when MISO projects there will be adequate 5

margins in order to gain the safe harbor benefit. Any new period of the revised request 6

which occurs during a time with inadequate margin will not gain an exemption. 7

Q. Why does MISO require at least 14 days notice for generator outage requests to be 8 eligible for safe harbor? 9

A. MISO’s role in the outage coordination process in its footprint requires it to perform 10

analysis for each individual outage request and identify potential reliability issues. If 11

reliability issues are identified, MISO may need to work with one or more Generator 12

Owner to identify a reasonable solution which may include rescheduling of generator 13

outages. This process could require an iterative feedback process taking multiple days to 14

perform. Additionally, the 14 day window will allow MISO to collect forecasted planned 15

outages to include in an updated forecast, which can guide Generator Owners as they 16

schedule outages that must occur within this short timeframe. 17

Q. What if a generator proposes to take more than one planned outage during a 120 18 day period? 19

A. A Generator Owner can schedule one planned outage 120 days or more in advance of the 20

requested start date period with an automatic safe harbor. The automatic exemption will 21

be limited to one within any 120 day period. Subsequent requests inside or outside of 120 22

days before the requested start date can gain exemptions if MISO is projecting adequate 23

margin when the request is submitted. 24

14

Q. What if a generator experiences consecutive planned outages? 1

A. Some stakeholders recommended that MISO consider allowing multiple instances of a 2

generator’s outage to receive safe harbor exemptions for outages planned outside of 120 3

days without consideration of forecasted margin, pointing to the potential need for 4

consecutive planned outages. For example, one proposal would allow unlimited safe 5

harbor if the prior request for that unit took place in a manner close to its original 6

schedule. This stakeholder proposal would address concerns around potential undesirable 7

behavior, specifically guarding against instances where Generator Owners have 8

incentives to request more planned outages than are needed to ensure flexibility, with 9

unneeded outages being cancelled. This potential hoarding of outage capacity would 10

introduce errors into the forecasts and could prevent other resources from receiving safe 11

harbor. However, MISO felt that a system which requires analysis of previous outages to 12

grant safe harbor provisions would be overly onerous and complex, opting instead to 13

maintain a single automatic safe harbor provision for each unit within a 120 day window. 14

Q. Why is only one planned outage eligible for the ‘safe harbor’ provision per 120 day 15 window? 16

A. The safe harbor provision was established to support planned outages, as defined in the 17

NERC GADs reporting instructions. These instructions specify that the planned outages 18

should only occur once or twice a year, and so the proposal was initially set up to 19

guarantee safe harbor for one outage per 120 days based on this criteria. 20

However, due to stakeholder feedback, MISO expanded the proposal to allow additional 21

exemptions to be gained for outages which schedule entirely within a time with adequate 22

margin. 23

15

Q. Why does MISO describe penalties by sub-region within MISO? 1

A. Currently, MaxGen Emergencies are generally implemented only on a sub-regional or 2

region wide basis, which will align with the enhanced maintenance margin information to 3

be provided on a sub-regional basis. In the future, however, MISO may increase the 4

granularity of its MaxGen Emergencies. MISO intends to maintain the alignment of 5

maintenance margin forecasts with MaxGen Emergencies in the future. 6

Q. How will MISO consider transmission outages in connection with planned outage 7 request scheduling? 8

A. MISO’s proposal focuses around the coordination of generator outages and is not 9

proposing changes to transmission outage scheduling. 10

Q. Is MISO proposing a transition period for this penalty? 11

A. Yes. MISO is proposing a phased approach as described below. 12

1. Outages submitted prior to April 1, 2019 will not be subject to the proposed 13

penalty. 14

2. Requests submitted on or after April 1 for outages starting April 15 through 15

July 29, 2019 would gain safe harbor if the request is submitted 14 days in 16

advance and there is adequate projected margin at the time of the request. 17

3. The proposed process will apply to outages scheduled to start on or after July 18

30. 19

This transition plan will allow the changes to be implemented and be impactful 20

starting within the Spring 2019 outage season. 21

C. Regional Forecast of Planned Outages 22 23

Q. What information does MISO currently provide to generators to assist them in 24 scheduling outages? 25

16

A. MISO provides a projection of the amount of MW available for additional outages while 1

still maintaining reliability through a tool called the maintenance margin. This tool was 2

created in response to concerns over resource sufficiency under environmental 3

restrictions with results being posted starting in 2014. The tool output is currently posted 4

monthly and contains forecasts for the next three years for the region and each of the ten 5

Local Resource Zones (“LRZs”). 6

Q. Is MISO proposing to create a new forecast tool for planned outages? 7

A. No. MISO is planning to use the existing maintenance margin tool, with some 8

incremental improvements. The information to be provided through this tool will be 9

enhanced, including improvements to input assumptions. MISO has commenced 10

discussions with stakeholders to develop these near-term enhancements and expects to 11

implement them by early March. 12

Q. How far in advance will MISO provide a forecast? 13

A. As noted previously, on a monthly recurrence, MISO currently produces maintenance 14

margin daily forecasts on a three-year forward, rolling basis. MISO is proposing to 15

increase the frequency of these forecasts to twice per week in an effort to give 16

stakeholders greater transparency to allow them to better schedule their planned outages, 17

while still providing forecasts which describe risk in the next three years. 18

Q. What geographic areas will be used to define the forecast? 19

A. MISO is proposing to provide this information on a MISO system wide view and sub-20

regional basis (i.e., MISO North, Central, and South). 21

17

Q. Why is MISO proposing to forecast subregionally rather than by Local Resource 1 Zone? 2

A. Recent Maximum Generation Emergency measures (including alerts, warnings and 3

events) have occurred on a sub-regional basis, rather than zonally. Thus, providing the 4

maintenance margin on a sub-regional basis will better align planned outage transparency 5

with sub-regional needs. 6

Q. How does MISO expect stakeholders to use this information? 7

A. Stakeholders will be able to use MISO’s compilation of planned outage risks, via the 8

maintenance margin tool, to make more informed, long lead outage scheduling decisions. 9

Additionally, stakeholders will be able to make adjustments to those requests closer to the 10

outage implementation date with a better understanding of the resource risk and use the 11

data for short lead-time outage scheduling decisions. In short, the information may be 12

used, in coordination with a Generator Owner’s internal data, to plan outages during 13

periods when MISO projects sufficient reserves and to reschedule outages, if necessary, 14

on the same basis. 15

V. Expected Benefits from Outage Coordination Changes 16

Q. How will these changes enhance transparency around the availability of resources? 17

A. The proposed changes will greatly increase the forward information on outage 18

scheduling, with the following benefits: 19

1. Improved forward signals over the next year will provide Generator Owners 20

better guidance on what timeframes in which to schedule, leading to less 21

correlated outage risks. 22

18

2. Near term signals will provide better guidance to Generator Owners as they 1

finalize the details of necessary outage schedules between 14 and 120 days in 2

advance of the operating day. 3

3. MISO will be able partner with Generator Owners to address potential 4

resource concerns further in advance. 5

MISO has observed a significant amount of units on outage when maximum generation 6

or capacity sufficiency alerts have been issued, demonstrating a shared desire by 7

Generator Owners to maintain resource sufficiency. The proposal incentivizes and 8

allows Generator Owners to be proactive, scheduling planned generator outages and 9

limiting adjustments to times with less resource risks. 10

Additionally, seasonal derates should be planned and known in advance and can be 11

provided in time for consideration in outage projections and analysis. 12

Q. How will these changes improve the ability of generators to schedule outages? 13

A. The enhanced generator outage information to be provided by MISO will provide 14

stakeholders the opportunity to plan outages in a manner that enhances system reliability. 15

Given the changing system conditions described in Mr. Bladen’s testimony, it is 16

imperative that MISO and Generator Owners work together to both improve forecasts of 17

low reserve, high risk periods and to adjust outage schedules to avoid these high risks 18

times in advance of their occurrence. The proposal submitted in this filing, as described 19

in my testimony, represents the initial means by which MISO proposes to address this 20

need. MISO will continue discussions with stakeholders to develop a holistic solution 21

and implement additional measures to address resource availability and need. 22

19

VI. Conclusion and Recommendation 1

Q. In your opinion, is the MISO proposal just and reasonable? 2

A. Yes. The filing addresses a concrete need that MISO, its stakeholders, and the MISO 3

Board of Directors agree must be addressed. The proposed Tariff revisions will 4

significantly improve the transparency of planned outages and allow MISO and 5

stakeholders to better coordinate planned outages. If adopted, the MISO proposal will 6

provide a number of important benefits described. Accordingly, I believe the proposal is 7

just and reasonable and that the Commission should accept this RAN proposal as 8

submitted. 9

Q. Does this conclude your testimony? 10

A. Yes, it does. 11

Documents

VIA ELECTRONIC FILING Secretary Federal Energy Regulatory ... Docket No. ER19-915-000315136.pdfJan 30, 2019 · MISO s Outage Process timeline was established to promote reliability