ARPA-ETransmission Planning

Dale OsbornSeptember 29,2016

Road Map

MISO Transmission Expansion Plan (MTEP)Value Base Planning Process

Carbon and Other EffluentsMax Renewables Optimal Economic Generation Mix Forecastin lieu of Integrated Resource Plans

Location of Generation-Renewable Energy Zones input in lieu of exact site informationValue of Optimal Transmission Optimal Inter MISO Regional Transmission

Road MAP Scope

Definition of the future(s) with variable and alternatives, Existing MISO inter regional power transfer capability Generation alternativesTransmission alternativesSolution Constraints

1 Yr.

6 Yrs.

Transmission approved for constructionGeneration Adequacy ( LOLP) Informational studies answering pertinent questions

Balancing the mix of renewable siting and transmission build-out

3

• RGOS found there is a balance between siting renewables in resource rich areas and building transmission to deliver them.

• MISO’s mid-term analysis uses a new co-optimization technique to reevaluate this conclusion given current resource trends.

– Transmission interface capacity between the MISO Local Resource Zones (LRZ) is examined.

Results for MISO’s Mid-Term Analysis of EPA's Final Clean Power Plan (Mar. 16, 2016)

MISO’s Local Resource Zones

Co-optimization Generation Forecast and Transmission

• Three carbon dioxide reduction levels since 2005 were used– 30% by 2030– 50% by 2036– 80 % by 2050

• Optimal mixes of gas, wind and solar generation were sited for each carbon dioxide reduction level

• Cost of future energy was calculated-50% carbon reduction was the least cost scenario

• Inter-MISO regional transmission was identified

Results shown are from the load matching optimization which does not consider economics.

Study finding: an increase in transmission allows for more renewables to be built-out, while minimizing thermal generation

5

*RGOS = Regional Generator Outlet Study, see https://www.misoenergy.org/Planning/Pages/RegionalGenerationOutletStudy.aspx

Model not allowed to pick transmission as an expansion alternative

2050 CapacityNG = 182 GWCoal = 0 GW

Wind = 161 GWSolar = 119 GW

2050 Generation NG = 233 TWHCoal = 0 TWH

Wind & Solar = 648 TWHOther = 111 TWHLosses = 31 TWJ

Curtailments = 57 TWH

Model allowed to pick transmission as an expansion alternative

2050 CapacityNG = 182 GWCoal = 0 GW

Wind = 217 GWSolar = 125 GW

2050 Generation NG = 123 TWHCoal = 0 TWH

Wind & Solar = 861 TWHOther = 104 TWH

Losses = 185 TWHCurtailments = 0 TWH

Results for MISO’s Mid-Term Analysis of EPA's Final Clean Power Plan (Mar. 16, 2016)

This study identified cumulative potential for wind and solar build-out in MISO, which represents the upper limit of renewable expansion

6

Constraining transmission expansion (left) drives a more distributed solar build-out; allowing transmission expansion (right) shifts renewable build-out to MISO North and replaces some solar expansion with wind.

Both maps shows results of the load-matching optimization which does not consider economics.

*RGOS = Regional Generator Outlet Study, see https://www.misoenergy.org/Planning/Pages/RegionalGenerationOutletStudy.aspx

Model allowed to pick transmission as an

expansion alternative

Results for MISO’s Mid-Term Analysis of EPA's Final Clean Power Plan (Mar. 16, 2016)

Future Substation LocationsLinked by TransmissionFor the 2010 Road Map

-20

-10

0

10

20

30

40

50

Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 North toSouth

Zone 8 Zone 9 Zone 10

Inte

rfac

e Tr

ansf

er C

apac

ity (G

W)

2016 2030 2036 2050

MISO North Hub MISO South Hub

(80%)

Results for MISO’s Mid-Term Analysis of EPA's Final Clean Power Plan (Mar. 16, 2016) 7

Study finding: High levels of wind build-out in Zone 1 by 2050 are facilitated by a large increase in export capacity

(30%)

Export to hub

Import from hub

(50%)

Load Forecast

• Utility bus by hour for the year• Wind pattern matching the load pattern for a

year• Solar pattern matching the load pattern for a

year• Demand Response hourly for a year

EGEAS Generation Forecast

• Establish futures- 4• Optimal selection of generation using a set of

the road map alternatives• Output is and input to the PROMOD

production cost simulation program

Top Congested Flowgates in PROMOD Run*

11

* Based on 2017 and 2022 BAU future PROMOD simulation** Historically congested flowgates

Flowgate NameMonitored Element

Area (From - To)

2017 BAU 2022 BAU 2017 and 2022 BAU Combined

Binding Hours

Shadow Price

(k$/MWh)

Congestion Cost

($)

Binding Hours

Shadow Price

(k$/MWh)

Congestion Cost

($)

Binding Hours

Shadow Price

(k$/MWh)

Congestion Cost

($)

10NTVL13 253581 SIGE 10NTVL16 253580 SIGE ** SIGE 3857 368.23 64,808 4443 493.26 86,814 8300 861.49 151,622 10802288 253552 SIGE 10ELOT13 253526 SIGE SIGE 1051 85.95 24,667 962 82.35 23,633 2013 168.30 48,300 4NASON P 348835 AMIL 4INA 347280 AMIL AMIL 843 134.19 21,335 636 101.12 16,078 1479 235.31 37,413 7JOPPA T 347325 AMIL 5JOPPA T 351003 EEI AMIL-EEI 693 30.96 18,577 568 29.55 17,731 1261 60.52 36,308 16PETE 254529 IPL YBUS702 99296 IPL IPL 631 47.70 14,310 596 47.00 14,100 1227 94.70 28,410 08WHITST 249529 DUK-IN 16GUION 254523 IPL ** DEI-IPL 151 6.54 6,251 463 22.75 21,750 614 29.29 28,001 10ABBRWN 253505 SIGE 10ABB345 253620 SIGE ** SIGE 1386 20.32 9,552 1559 30.15 14,170 2945 50.48 23,722

Market Efficiency Planning Study 3rd TRG October 30, 2012

Summary of Historically Congested Flowgates

12

Flowgate Common NameMonitored Element

Area(From - To)

Day-Ahead Real-TimePROMOD Simulation

2017 BAU 2022 BAU

Binding Hours

Ranking

Shadow Price

Ranking

Binding Hours

Ranking

Shadow Price

Ranking

Binding Hours

Shadow Price

(k$/MWh)

Binding Hours

Shadow Price

(k$/MWh)

AB Brown 138/345KV Xfmr FLO Gibson-Francisco 345KV SIGE 27 73 117 623 1386 20.32 1559 30.15

Adams 161/69kV Xfmr FLO Adams-Beaver Creek-Harmony/Rice 161kV ALTW 14 24 76 21 2 0.06

Baldwin-Mt Vernon 345KV FLO St. Francois-Lutesville 345KV AMIL 19 107 19 220 382 4.41 247 3.34

Benton Harbor-Palisades 345KV FLO Cook-Palisades 345KV AEP 18 132 43 61 1 -

Bunsonville-Eugene 345KV FLO Casey-Breed 345 KV AEP-AMIL 9 58 32 213 989 12.65 77 1.07

Crete-East Frankfort 345kV FLO Dumont-Wilton Center 765kV CE 172 410 4 51 201 0.94

Crete-St Johns Tap 345kV FLO Dumont-Wilton Center 765kV NIPS-CE 155 313 3 15 125 0.57 191 2.46

Market Efficiency Planning Study 3rd TRG October 30, 2012

Difference of Constrained and Unconstrained Production Cost Cases

• Potential production cost savings– By area– MISO and neighboring areas

Market Efficiency Planning Study 3rd TRG October 30, 2012 14

15

Energy Sources and Sinks MISO – using Ventyx, Velocity Suite © 2012

Market Efficiency Planning Study 3rd TRG October 30, 2012

West to East Interface Flows OH-PA

0

5000

10000

15000

20000

25000

0 720 1440 2160 2880 3600 4320 5040 5760 6480 7200 7920 8640

Hour of the Year

MW

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Transmission Overlay Design WorkshopExample Interface Duration CurveInterface Flow

-2000

-1500

-1000

-500

0

500

1000

1500

2000

2500

3000

3500

1

245

489

733

977

1221

1465

1709

1953

2197

2441

2685

2929

3173

3417

3661

3905

4149

4393

4637

4881

5125

5369

5613

5857

6101

6345

6589

6833

7077

7321

7565

7809

8053

8297

8541

Hours

MW

Flo

w

WAPA-MINN

Transmission Capacity designed to deliver 80% of desired energy flow

Transmission and Substation Costs per Mw-mile by Transmission Voltage And Type of Construction

0400800

1,2001,6002,0002,4002,8003,2003,6004,000

345 kVSteel

WoodedAreas

2-345kkVon Steel

500 kV 765 kV 765 HSIL 800 kV GIL 1200 mile-800kVHVDC

$/M

w-M

ile

Lowest cost options

600 1200 1300 2600 5400 5300 6400

345 kV - 765 kv Delivery Capacitywith a 5% voltage drop

on a losseles line

0

0.5

1

1.5

2

2.5

3

3.5

0 50 100 150 200 250 300 350Miles

PU S

IL

21

Power Transfer Breakover by Voltage

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

200

1,20

02,

200

3,20

04,

200

5,20

06,

200

7,20

08,

200

9,20

010

,200

11,2

0012

,200

13,2

00Power Transfer MW

Cos

t/Mile

345 kV AC+600 Mw1-765kV AC1-800 kV HVDC345 kV AC+1000 Mw

22

Interface Contour: Annual Energy DifferenceUnconstrained Case Minus Constrained Case

MISO – using Ventyx, Velocity Suite © 2012Market Efficiency Planning Study 3rd TRG October 30, 2012

Interface AC Flows without an OverlayInterface Flows with an Overlayincluding HVDC

Loop Flow Patterns

Benefit Components

Market Efficiency Planning Study 3rd TRG October 30, 2012 24

Robust Transmission Plan

• Then tested for reliability• Cost allocated• Sent to Board of Directors for Approval

Average LMPs for Base, 765kv Overlay, and WIND

$30

$35

$40

$45

$50

$55

ON

HY

NY

PP

SU

NC VP

PJM

EV

AC

AR

WP

SC

PJM

SM

IDW

WE

PLK

PJM

WC

EC

STH

RN

DE

TED FE

LBW

LS

OLA

ES

PP

WA

EP

SO

LAW

DP

&L

SA

SK

CG

ELG

&E

EM

DE

DQ

ED

PC

AR

LMH

EC

IP&

LP

SI

TVA

SP

CIU

TW

RI

NIP

SB

RE

CM

GE

GR

ES

MM

PH

UC

WP

LS

IGE

WP

PI

NS

PM

PC

AS

EC

IND

NA

LWS

TC

OE

DK

CP

LM

IPU

WP

SK

AC

YW

EP

MP

WO

TPM

PL

MID

AM

CIL

EE

IN

WP

SIL

PC

SIP

CM

HS

PC

IPS

WA

BN

IS

PR

ILW

AB

DA

UE

PM

DU

NP

PD

LES

OP

PD

Avg LMP - 765kV Overlay Avg LMP - Base Case Avg LMP - WIND

MISO26%

SERC21%PJM

Interconnection

16%

Southwest Power Pool

13%

Entergy8%

TVA6%

New York4%

MRO4%

TVA -Other

1%

IESO (Ontario)1%

Chart Title

MISO Pays 100%, 34% Benefits For MISO Central to Entergy Transmission

Without Overlay

With AC Overlay

With HVDC Overlay

PRI

CE

Distance

GenRevenueDifference

LoadSavings

Capacity Diversity

• Between Balancing Areas• Time zone differences is the main driver• North-South load pattern differences is a

secondary driver• Study

– Determine the economic potential• Generation displacement• Energy payment and market product premium

displacements– Design a transmission system to capture the value for

a targeted benefit/cost ratio

31

5.9 GW

7.9 GW

3.8 GW

5.6 GW

4.6 GW

7.5 GW

Load Diversity Between Areas

Total = 35 GWof load diversity Valued at $700k/MW of

displaced capacity

Frequency Response

• Sharing frequency response reserves through interregional secure power transmission– ~950 MW of local reserve, ~2750 total reserves– 2x900 MW of secure transmission– Net benefit 5400 MW of displaced capacity (3x1800 MW)

• Approximately 1 in 30 years there will be an outage in two regions simultaneously

32

900MW

900MW

900MW Zone Reserves (MW)

East 4500

MISO+ 2900

WECC 2740

ERCOT 2750

MISO+(1100MW)

ERCOT(950MW)

WECC(940MW)

Frequency Response (cont.)• Improved frequency response performance

– Current governor control responds in 3-5 seconds– VSCs allow for response in 0.1 seconds– Raises frequency event nadir

33

Time

Nadir(w/ HVDC)

Nadir(w/out HVDC)

Freq

uenc

y Frequency Response Event

900MW

900MW

900MW MISO+(1100 MW)

ERCOT(950 MW)

WECC(940 MW)

HVDC Network Concept

Wind Energy Benefits for WECC

35

Reduced peak ramp rate

2011: x2.0

• Add all wind generation across MISO, ERCOT, and WECC• Re-distribute wind based on peak capacity

• Benefits– Reduced ramp rate– Reduced variability (and thereby potentially increased capacity credit)

Effect on Capacity Credit: TBD

Costs allocated by % of benefits

36

Example:

SERC Load Cap. Cost = $36.2B * 9% = $3.3B

SERC Freq Reg Cost = 36.2B * 3% = $1.1B

Value Drivers

Load diversity 46%

Frequency response 22%

Wind diversity 5%

Other Energy Based Products

27%

37

High Solar Generation Impact

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Load

/Net

Loa

d (M

W)

Hours

Southern California Edison and HVDC load and net loadfor off-peak day: 11/25/2012

SoCalEd Normalized Load

SoCalEd Normalized Net Load

HVDC Normalized Load

HVDC Normalized Net Load

SoCalEd Reduced Ramp

S. CA Edison peak load: 22,400 MWHVDC Network peak load: 316,000 MW

HVDC Network Conceptwith Some Gas Fields

Cost to Deliver Wind Energy with the Macro Grid is 25% of the cost of individual HVDC lines proposed currently because of sharing the cost

and more fully utilizing the lines.

Questions

• Dale Osborn• MISO Policy and Economic Studies• Phone 651-632-8471• Email dosborn@misoenergy.org