Study Results

High EE/DG/DR Study

This slide deck contains results from the 2011 TEPPC Study Program. This study shows the results of an increase of EE/DG/DR policy and it impact on the interconnection.

2

2022 PC4 – High EE, DSM, DG

Central Question: What impact do aggressive EE, DSM, and DG policies have

on transmission and capacity needs relative to the 2022 Common Case?

Assumptions

Loads – decreased to reflect the assumption that “all cost-effective EE potential” is achieved throughout the West

Transmission System – None

Generation – DG resources increased based on ‘interconnection potential’ of distributed PV and ‘technical

potential’ of distributed CHP as estimated by E3 (link to E3 report)

RPS resources adjusted for lower loads due to EE and behind-the-meter DG, and for increased PV DG

DSM increased based on LBNL analysis of demand response potential estimated using an updated FERC DR Potential Estimates model

Link to all SPSC input provided for this case

3

1) Perform EE load adjustments;

+

2) Add DG resources, adjust RPS;

+

3) Add DR and “tune”

Study ExecutionBuild and run study in steps…

PC4

Results in similar order…

Summary of Aggressive EE Load Adjustments

AE

SO

A

PS

A

VA

B

CH

B

PA

C

FE

CH

PD

D

OP

D

EP

E

FAR

EA

ST

GC

PD

IID

LD

WP

M

AG

IC V

LY

NE

VP

N

WM

T P

AC

E_I

D

PA

CE

_UT

PA

CE

_WY

P

AC

W

PG

&E

_BA

Y

PG

&E

_VLY

P

GN

P

NM

P

SC

P

SE

S

CE

S

CL

SD

GE

S

MU

D

SP

P

SR

P

TEP

TI

DC

TP

WR

TR

EA

S V

LY

WA

CM

W

ALC

W

AU

W

0

5,000

10,000

15,000

20,000

25,000

Peak and Energy Load AdjustmentsPC4 High EE/DG/DR vs. PC1 Common Case

PC1 Energy (aMW) PC4 Energy (aMW) PC1 Peak (MW) PC4 Peak (MW)

En

erg

y -

aMW

Pea

k -

MW

5

• Incremental DG (PV and CHP) modeled in the Common Case was first removed from the total potential DG estimates developed for PC4

• Incremental DG added to 2022 PC4 was scaled up for avoided transmission and distribution system losseso 6% for all areas except CA, 7% for CA (consistent with assumptions used to develop

RPS requirements)

• DG was distributed proportionally (to load) amongst largest area load busses

Distributed Generation Modeling Approach

Common Case DG

Potential DG

Losses, 6%

Distributed proportionally

6

• The following categories of distributed solar PV were modeledo Residential rooftop – modeled using NREL rooftop solar

profiles (fixed tilt of 20º)o Commercial rooftop – modeling using solar profiles

developed by E3 using PVWattso Ground-mounted – modeled using NREL single-axis

tracking solar profiles

• Distributed CHP was modeled as follows:o Flat outputo Heat rate = 6,000 Btu/kWho Capacity factor = 85%

Distributed Generation Modeling Approach, continued

All DG has behind-the-meter (BTM) and wholesale

component (50/50 split)

7

2022 Incremental Distributed PV in PC1 and PC4 – Big Picture

AB AZ BC CA CO ID MT NM NV OR TX UT WA WY WECC -

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Incremental Distributed PV in 2022 PC4 (MW)Added DG Scaled Up for Avoided T&D Losses

Incremental PV in the Common Case Incremental PV to be Added in the High DG Case

WECC total ~ 25,000 MW

8

2022 Incremental Distributed CHP in PC1 and PC4 – Big Picture

AB AZ BC CA CO ID MT NM NV OR TX UT WA WY WECC -

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Incremental Distributed CHP in 2022 PC4 (MW)Added DG Scaled Up for Avoided T&D Losses

Incremental CHP in the Common Case Incremental CHP to be Added in the High DG Case

WECC total ~ 9,900 MW

9

High EE and High DG Impacts to RPS Requirements

State/ Province

Total RPS Energy (GWh) in Common Case

Total RPS Energy (GWh) in

High EE% Diff

Total RPS Energy (GWh) in

Common Case

Total RPS Energy (GWh) in High EE

plus High DG% Diff

AB            AZ 6,772 5,902 -13% 6,772 5,655 -17%BC            CA 88,180 85,701 -3% 88,180 81,393 -8%CO 13,208 12,153 -8% 13,208 11,548 -13%ID            

MEX            MT 994 948 -5% 994 900 -9%NV 5,541 4,646 -16% 5,541 4,348 -22%NM 3,046 2,926 -4% 3,046 2,710 -11%OR 9,853 8,789 -11% 9,853 8,218 -17%TX 449 422 -6% 449 407 -9%UT 5,732 5,090 -11% 5,732 4,754 -17%WA 12,054 10,599 -12% 12,054 9,991 -17%WY            Total 145,829 137,177 -6% 145,829 129,923 -11%

Top 3 % change in Red

10

• Planned/future RPS resources removed as needed to meet adjusted RPS targetso After EE load adjustmentso Again, after high DG adjustments

• Ran out of planned/future resources to remove during the high DG adjustments o Increased PV counts towards RPSo Behind-the-meter PV and CHP reduces retail sales, hence reduces

RPS targets

Overbuild of RPS Resources

StateRPS Requirement (GWh)

RPS Energy in Dataset (GWh)

% Over Requirement

Arizona 5,655 6,689 18%

Nevada 4,348 8,912 105%

Utah 4,754 4,888 3%

11

Interruptible DR• Bus assignment assumptions:

o Based on generator sizeo Based on bus size (real load)

• Modeling technique – high cost CTo ~20 dispatch hours per yearo 4-6 hours per dispatch, 4-5 times

per yearo Min down time: 4 hourso Min up time: 3 hourso Modify heat rate (MMBtu/MWh)

• Monthly availability specified

DR Modeling Approach

More info

Economic DR• Bus assignment assumptions:

o Based on generator sizeo Based on bus size (real load)

• Modeling technique - fixed-shape transaction (i.e. like wind)• 50-80 dispatch hours per year• Hours per dispatch, frequency –

varies• LBNL uses area loads and load

weighted LMPs to calculate dispatch

• Monthly availability specified

12

DR Modeling Implementation

PC4 w/ EE and DG

Add Economic DR

Add Interruptible DR

Results to LBNL

Run study

Tune Interruptible DR

Run study

Check results

Yes

OK? No

Run study

PC4 Done!

Note: Same process for PC1

DR Capacity chart

NI_DR_A

ESO

NI_DR_A

PS

NI_DR_A

VA

NI_DR_B

CH

NI_DR_B

PA

NI_DR_C

HPD

NI_DR_D

OPD

NI_DR_E

PE

NI_DR_F

AR EAST

NI_DR_G

CPD

NI_DR_I

ID

NI_DR_L

DWP

NI_DR_M

AGIC V

LY

NI_DR_N

EVP

NI_DR_N

WM

T

NI_DR_P

AC_ID

NI_DR_P

AC_UT

NI_DR_P

AC_WY

NI_DR_P

ACW

NI_DR_P

GE_BAY

NI_DR_P

GE_VLY

NI_DR_P

GN

NI_DR_P

NM

NI_DR_P

SC

NI_DR_P

SE

NI_DR_S

CE

NI_DR_S

CL

NI_DR_S

DGE

NI_DR_S

MUD

NI_DR_S

PP

NI_DR_S

RP

NI_DR_T

EP

NI_DR_T

IDC

NI_DR_T

PWR

NI_DR_T

REAS VLY

NI_DR_W

ACM

NI_DR_W

ALC

NI_DR_W

AUW

-

500

1,000

1,500

2,000

2,500

Economic DR Capacity (MW) ComparisonPC4 Capacity (MW) PC1 Capacity (MW)

AESOAPS

AVABCH

BPA

CHPD

DOPDEPE

FAR EAST

GCPD IID

LDW

P

MAGIC

VLY

NEVP

NWM

T

PACE_ID

PACE_UT

PACE_WY

PACW

PG&E_BAY

PG&E_VLY

PGNPNM

PSCPSE

SCESCL

SDGE

SMUD

SPPSRP

TEPTID

C

TPWR

TREAS VLY

WACM

WALC

WAUW

-

100

200

300

400

500

600

700

Interruptible DR Capacity (MW)

PC4 Capacity (MW) PC1 Capacity (MW)

15

Interruptible DR Energy Dispatch by Month

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

WECC Interruptible DR Energy (MWh) by Month

PC4

PC1

16

Economic DR Energy Dispatch by Month

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

WECC NID Energy (MWh) by Month

PC4

PC1

17

Total DR Energy Dispatch by Month

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

WECC Total DR Energy (MWh by Month)

PC4

PC1

18

Total DR Average Hourly Dispatch (PC4)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 240

50

100

150

200

250WECC Average Hourly DR Use (aMW)

DSMNID

19

Takeaways

Combined cycle - lower loads, CA/AB

Cogen/Solar - study assumptions

Wind - RPS impacts from study

Dump – lower loads, BC hydro

PC4 Generation Results

Conventional Hydro

Pumped Storage

Steam - Coal

Steam - Other

Nuclear

Combined Cycle

Combustion Turbine

Cogeneration

IC

Negative Bus Load

Biomass RPS

Geothermal

Small Hydro RPS

Solar

Wind

(150,000,000) (100,000,000) (50,000,000) 0 50,000,000 100,000,000

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

GWh

Changes in Total Annual Generation

Production Cost Summary

Category2022 PC1

Common Case2022 PC4 High

EE-DG-DRDifference Diff %

Dump Energy 397,104 1,515,266 1,118,162 281.579%Emergency Energy 2,676 1,372 (1,305) -48.742%CO2 Emissions (MMetricTons)

359 310 (49) -13.680%

CO2 Adder ($/metric ton) 0.000 0.000

Variable Production Cost (thermal units excl DSM)

CO2 Adder (Total M$) 0 0 0 0.000%

Other Variable Costs (M$) 14,851 11,902 (2,949) -19.858%

Total Var. Prod. Cost (M$) 14,851 11,902 (2,949) -19.858%

22

Changes in Generation by State

Alberta

Arizon

a

British

Colu

mbia

Califo

rnia

Colora

do

Idah

o

Mex

ico

Mon

tana

Nevad

a

New M

exico

Orego

n

South

Dak

ota

Texas

Utah

Was

hingt

on

Wyo

ming

-50,000,000

-40,000,000

-30,000,000

-20,000,000

-10,000,000

0

10,000,000

20,000,000

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

Hydro+PS Steam - Boiler Combined Cycle Combustion Turbine

Cogeneration Renewable Other

GWh

23

(60,000,000)

(50,000,000)

(40,000,000)

(30,000,000)

(20,000,000)

(10,000,000)

0

10,000,000

20,000,000

30,000,000

40,000,000

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

CANADA

Northwest

BASIN

RMPP

California

AZNMNV

GWh

Annual Generation Difference by Energy Type

24

Transmission Expansion Results – Changes in Dump Energy by State

Alberta

Arizona

British

Columbia

Californ

ia

Colorado

Idaho

Mexico

Montana

Nebras

ka

Nevad

a

New M

exico

Oregon

South Dak

otaTe

xas

Utah

Wash

ington

Wyo

ming-200,000

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

Change in Dump Energy Hydro+PS Steam - Boiler Combined Cycle Combustion TurbineCogeneration Renewable Other

MWh

Path 3 congested?

25

Takeaways

NW/CAN to CA - inexpensive NW resource free to meet CA load. COI and Path 3 congested as a result.

Path 8 utilization

Path 26 utilization

PC4 Transmission Results

26

Comparison with PC1

Largest Increase U99 Largest Increase U90P29 Intermountain-Gonder 230 kV 27.65% P66 COI 45.49%

P03 Northwest-British Columbia 26.67% P03 Northwest-British Columbia 33.95%

P66 COI 25.21% P29 Intermountain-Gonder 230 kV 32.05%

P27 Intermountain Power Project DC Line 17.40% P27 Intermountain Power Project DC Line 20.68%

P45 SDG&E-CFE 10.00% P25 PacifiCorp/PG&E 115 kV Interconnection 18.77%

Largest Decrease U99 Largest Decrease U90P26 Northern-Southern California -9.58% P08 Montana to Northwest -17.42%

P08 Montana to Northwest -9.30% P26 Northern-Southern California -11.86%

P01 Alberta-British Columbia -5.67% P60 Inyo-Control 115 kV Tie -11.32%

P60 Inyo-Control 115 kV Tie -5.03% P22 Southwest of Four Corners -9.16%

P61 Lugo-Victorville 500 kV Line -4.36% P01 Alberta-British Columbia -6.48%

27

Transmission Expansion Results – Changes in Path Utilization

P45 SDG&E-CFE*

P29 Intermountain-Gonder*

P26 Northern-Southern California*

P03 Northwest-British Columbia*

P66 COI

Name PC4 U99 PC1 U99 ChangeP45 SDG&E-CFE 44.38% 34.38% 10.00%P03 Northwest-British Columbia 42.93% 16.27% 26.66%P29 Intermountain-Gonder 230 kV 41.77% 14.12% 27.65%P66 COI 29.99% 4.78% 25.21%P27 Intermountain Power Project DC Line 24.12% 6.72% 17.40%

Utilization Max Inc. Max Dec.U75 P66 (51.74%) P11 (-28.30%)U90 P66 (45.49%) P16 (-17.42%)U99 P29 (27.65%) P26 (-9.58%)

Table 1 Five most congested paths

Table 2 Greatest change in path utilization

p66 coip29 intermountain-gop26 northern-southern P16 idaho-sierrap11 west of crossover

P08 Montana - Northwest*

P16 Idaho-Sierra *

P11 West of Crossover

P27 Intermountain Power Project DC Line

28

Changes in Generation by State

Alberta

Arizon

a

British

Colu

mbia

Califo

rnia

Colora

do

Idah

o

Mex

ico

Mon

tana

Nevad

a

New M

exico

Orego

n

South

Dak

ota

Texas

Utah

Was

hingt

on

Wyo

ming

-50,000,000

-40,000,000

-30,000,000

-20,000,000

-10,000,000

0

10,000,000

20,000,000

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

Hydro+PS Steam - Boiler Combined Cycle Combustion Turbine

Cogeneration Renewable Other

GWh

P03 N

orth

west-B

ritish

Colu

mbia

P14 Id

aho

to N

orth

west

P26 N

orth

ern-

South

ern

Califo

rnia

P28 In

term

ount

ain-M

ona

345

kV

P49 E

ast o

f Colo

rado

Rive

r (EOR)

P66 C

OI

(15,000)

(10,000)

(5,000)

-

5,000

10,000

15,000

Average Flow (aMW) - DirectionalSelect WECC Paths

Pos Flow Limit (MW) Neg Flow Limit (MW) PC1 Avg Pos Flow (aMW)

PC1 Avg Neg Flow (aMW) PC4 Avg Pos Flow (aMW) PC4 Avg Neg Flow (aMW)

Questions or thoughts on this study?

31

• Hourly region to region transfers

Additional Material

32

P45 SDG&E-CFE Hourly Flow

Back to presentation

9 387 765 114315211899227726553033341137894167454549235301567960576435681371917569794783258703

-1000

-800

-600

-400

-200

0

200

400

600

P45

LDC

Upper Limit

Lower Limit

33

P27 Intermountain Power Project DC Line Hourly Flow

Back to presentation

9 387 765 114315211899227726553033341137894167454549235301567960576435681371917569794783258703

-2000

-1500

-1000

-500

0

500

1000

1500

2000

2500

3000

P27

LDC

Upper Limit

Lower Limit

34

P03 Northwest-British Columbia Hourly Flow

Back to presentation

9 387 765 114315211899227726553033341137894167454549235301567960576435681371917569794783258703

-4000

-3000

-2000

-1000

0

1000

2000

3000

4000

P03

LDC

Upper Limit

Lower Limit

35

P66 COI Hourly Flow

Back to presentation

9 369 729 1089144918092169252928893249360939694329468950495409576961296489684972097569792982898649

-6000

-4000

-2000

0

2000

4000

6000

P66

LDC

Upper Limit

Lower Limit

36

P29 Intermountain-Gonder 230 kV Hourly Flow

Back to presentation

9 369 729 1089144918092169252928893249360939694329468950495409576961296489684972097569792982898649

-250

-200

-150

-100

-50

0

50

100

150

200

250

P29

LDC

Upper Limit

Lower Limit

37

Transmission Expansion Results – Changes in Un-utilized Generation

-5,000,000

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

45,000,000

Change in Un-utilized GenerationHydro+PS Steam - Boiler Combined Cycle Combustion Turbine Cogeneration Renewable OtherGWh

38

Changes in Energy by Region

CANADA Northwest BASIN RMPP California AZNMNV WECC(100,000,000)

(80,000,000)

(60,000,000)

(40,000,000)

(20,000,000)

0

20,000,000

40,000,000

60,000,000

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

Conventional Hydro

Pumped Storage

Steam - Coal

Steam - Other

Nuclear

Combined Cycle

Combustion Turbine

Cogeneration

IC

Biomass RPS

Geothermal

Total

GWh

39

WECC Peak Impact

9 333 657 981 1305162919532277260129253249357338974221454548695193551758416165648968137137746177858109843387570

20000

40000

60000

80000

100000

120000

140000

160000

180000

-25.0%

-20.0%

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

DR Impact on WECC Load Profile

Total Load - PC4 Total Load - PC1 Delta (%)