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The Effect of Energy Efficiency and Distributed Generation on T&D Planning

USAEE National Capital Area Chapter Lunch Series

Michael Goldman

Michael.Goldman@nu.com

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Northeast Utilities’ Massachusetts Operating Companies

NSTAR Gas & Electric Western Massachusetts Electric Company

Massachusetts Energy Efficiency Rankings

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#1 2011 ACEEE State Energy Efficiency Scorecard - Massachusetts #1 2012 ACEEE State Energy Efficiency Scorecard - Massachusetts #1 2013 ACEEE State Energy Efficiency Scorecard – Massachusetts #1 2013 ACEEE City Energy Efficiency Scorecard – Boston

NSTAR Electric, 2.49% WMECo, 2.48%

What Effects are Increased EE and DG Having on the T&D System?

� What are the effects and associated benefits/challenges of increased energy efficiency (EE) efforts and distributed generation (DG) installations on the transmission and distribution system?

� Potential implications can be massive

– updated transmission & distribution planning can lead to the deferment of projects resulting in cost savings of hundreds of millions of dollars or more

– Possibly negate the need for new generation sources

Why is this such an area of interest now? 4

Stakeholders are interested in understanding what additional benefits energy efficiency is providing

Investment in Energy Efficiency Has Been Rapidly Increasing

$-

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

EE P

rogr

am S

pend

ing

or B

udge

ts ($

Bill

ions

)

Gas Electricity 5

Annual Electric and Natural Gas Energy Efficiency Spending or Budgets

2013 ACEEE State Scorecard

Increased Pace of Oil/Coal Power Plant Retirements

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Age of Coal/Oil Generators in ISO New England

4,044

1,336 604

1,906

382

- 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

40-49 yrs 50-59 yrs 60+ yrs

Cap

acity

(MW

)

CoalOil

Approximately 8,300 MW of coal and oil capacity in New England is over 40 years old

Recent Retirements / Announcements • Brayton Point – 1,535 MW • Norwalk Harbor – 342 MW • Vermont Yankee – 604 MW • Salem Harbor – 749 Almost 3,300 MW will be gone in next 5 years

ISO New England 2014 Regional Electricity Outlook

Load Forecasting Ties EE to the T&D Planning Process

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Internal Process of Incorporating EE into Planning

Energy Efficiency

Load Forecasting

T&D Planning

Energy Efficiency

ISO Planning

Bottoms up forecast of measures to be installed and corresponding level of expected savings

Reduces anticipated system load by expected EE savings

Forecast of required infrastructure to meet load uses load forecast adjusted for EE

ISO develops its long term forecast

EE Dept ensures numbers are in accordance with submitted M&V plan

External Process of Incorporating EE into Planning

Load forecasting is the first place where EE and DG can have an effect on T&D planning

More Precisely Incorporating EE into Load Forecasts Has A Large Impact – ISO-NE

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ISO-NE forecast methodology is a good example of how altering EE assumptions can have a large impact on anticipated system wide load

Forecasting equations used for Yrs 4-10 (post-FCM) MWh = [ (1-BU) * Budget $ ] / [ $/MWh * PCINCR ] MW = MWh*PER

Where: BU = Budget uncertainty Budget $ = Estimated EE budget dollars $/MWh = Production cost PCINCR = Production cost increases PER = Peak to energy ratio

Final 2014 Energy-Efficiency Forecast 2018-2023, Energy Efficiency Working Group, 5/1/2014

Effects of EE and Other Demand Side Resources Show Up in ISO Forecasts

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ISO-NE 10 Yr Summer Peak (90/10) Forecast with EE

Approximately 3000 MW difference due to including EE in long term forecast

Business as usual With FCM With EE Forecast

Final 2013 Energy-Efficiency Forecast 2016-2022, Energy Efficiency Working Group, 2/22/2013

Forecast is used for long-term transmission planning studies, economic planning studies, CELT report and Regional System Plan

Difference due to known EE in FCM

Difference due to long term EE forecast

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Midwest ISO’s long term EE forecast reveals the sensitivity of peak demand savings to EE acquisition rates

Scenario Description Peak Demand Savings by 2030

GEP Scenario Declining avg EE savings from 1% in 2015, 0.9% in 2020, 0.3% in 2025, 0.1% in 2030

11,233 MW

Modified GEP Scenario 1% EE savings throughout forecast period 19,373 MW

Synapse State’s Avg Avg EE savings increases from 1% through 2015 to 1.4% from 2015-2030

23,392 MW

Synapse Best Practices Avg EE savings jumps to 2% from 2020-2030 29,618 MW

More Precisely Incorporating EE into Load Forecasts Has A Large Impact – MISO

Global Energy Partners. (Draft). 2010 Assessment of Demand Response and Energy Efficiency Potential for Midwest ISO, Report No. 1314 Peterson, Paul., Sabodash, Vladlena., Takahashi, Kenji. 2010. Demand Side Resource Potential A Review of Global Energy Partners’ Report for Midwest ISO

Altering a few EE assumptions resulted in a difference of over 18,000 MW in peak demand savings over the forecast period.

Hypothetical Example of Effect of Including Long Term EE Forecasts on PJM Loads

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Impact of EE Forecast on 2014 PJM Non-Coincident Peak Load Forecast

8,900 MW Difference due to including long term EE in forecast

Jeff Schlegel, Doug Hurley, and Ellen Zuckerman, “Accounting for Big Energy Efficiency on RTO Plans and Forecasts: Keeping the Lights on While Avoiding Major Supply Investments”. 2014 ACEEE Summer Study

Hypothetical Example of how Transmission Year of Need Shifts with Inclusion of EE in Forecast

12 Jeff Schlegel, Doug Hurley, and Ellen Zuckerman, “Accounting for Big Energy Efficiency on RTO Plans and Forecasts: Keeping the Lights on While Avoiding Major Supply Investments”. 2014 ACEEE Summer Study

Demonstration of Deferral of Transmission Project Year of Need in PJM

Transmission Projects are Being Delayed/Deferred Due to Lower Load Growth

Construction / Equipment

Related, 4%

Deferral Based on

Reassessment of Load

Growth, 44%

Other, 28%

Permitting / Siting or

Environmental Litigation / Opposition,

21%

Budget / Cost Issues, 3% 100-120kV

28%

121-150 kV 7%

151-199 kV 7% 200-299 kV

34%

300-399 kV 15%

400-599 kV 9%

Current Transmission Project Delays and Deferrals

Reasons for Transmission Project Delays and Deferrals

NERC 2012 Long-Term Reliability Assessment

Over 5,000 circuit miles of transmission projects were considered delayed or deferred in 2013 with the majority due to reassessment of load growth

Quantified Benefits of EE and DG

� Deferred projects – ISO-NE identified 10 projects in Vermont and New Hampshire that

could be deferred • Avoided/deferred line upgrades and capacitor additions resulted in cost

savings of $260 million • Deferred need for new 345 kV line resulted in $157 million savings

• Total ISO-NE savings of ~ $420 million

– Con Ed substation project serving Brooklyn and Queens • Total cost would be $1.1 billion to get it online by 2019

• If project can be deferred to 2024, savings of $400-$500 million

– Tiverton substation upgrade • Deferring construction of 3rd feeder at this substation through DR would result

in savings of $653,273

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Quantified Benefits

Less Congestion And Outages Could Result in Lower LMPs

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Real time LMPs from Midwest ISO, 2/17/2014 Real time LMPs from Midwest ISO, 2/18/2014

Increased DG, co-location of generation and demand, or more transmission infrastructure could help reduce congestion and line losses, smoothing prices across a region

Midwest ISO (MISO) Contour Map and Table, accessed 2/17/2014 and 2/18/2014

Effects of Transmission Constraints – ERCOT 2012

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2012 CREZ Infrastructure

• 577 instances of negative wholesale prices

• Average negative price was -$2.74

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2013 CREZ Infrastructure

• 144 instances of negative wholesale prices

• Average negative price was -$2.20

Effects of Transmission Constraints – ERCOT 2013

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2014 CREZ Infrastructure

• 21 instances of negative wholesale prices

• Average negative price was -$0.70

Effects of Transmission Constraints – ERCOT 2014

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Effects of Transmission Constraints – ERCOT

EE Effect on Energy vs. Demand

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ISO- NE Energy Efficiency Forecast through 2023 reveals the different effects that EE has on energy growth and demand growth

Demand Energy

Final 2014 Energy-Efficiency Forecast 2018-2023, Energy Efficiency Working Group, 5/1/2014

Energy forecast is flat while demand forecast is still increasing – suggests system is becoming “peakier”.

Growth in System Demand is Declining

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The NERC-wide 10-year compound annual growth rate (CAGR) for on-peak summer demand is expected to fall for the 11th consecutive year

Peak demand is still increasing – but at a decreasing rate. This national trend is in line with the trends seen in the New England area.

NERC 2013 Long-Term Reliability Assessment

EE and DG May Be Able to Offset the Need for Some Transmission But Not All

Renewable Integration, 18%

Reliability, 59%

Economic or Congestion

Related, 11%

Other, 12%

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Primary Drivers for New Transmission Projects

2013 NERC Long-Term Reliability Assessment

It is important to understand where EE and DG may be able to offset new transmission projects and where it cannot

Yes No Maybe

• Economic / Congested Related

• Renewable Integration

• Other • Reliability

Where Can EE/DG Make a Difference?

Reliability is key driver – is it due to load growth or contingencies?

� Transmission build out and capital spend is often driven by concerns other than load in short term:

– Reliability

– Compliance (satisfy N-1-1 conditions)

– Hardening the infrastructure against weather events

– Compensate for generation retirements

Energy Efficiency is unlikely to have an effect on transmission planning or capital expenditures in the short term

As load grows on Cape Cod, existing distribution infrastructure needs to be supplemented with transmission to ensure reliability

Drivers of T&D Construction Pose Challenges for EE and T&D

Demand Side Resources May Not Be Able to Meet Contingency Requirements for Planning Purposes

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Sub-area Sub-area Load* (in MW)

Required MRA MW Reduction

Percentage of Reduction

Manchester/Barbour Hill

527 82 16%

Middletown 600 345 58%

Greater Hartford 1,283 614 48%

Northwestern Connecticut

484 310 64%

Total 2,894 1,350 47% *Sub-area Load= Remaining load after forecasted Energy Efficiency and cleared Demand Response reductions from FCA #1 – FCA #6 have been accounted for

Market Resources Alternative Analysis – Demand-side Results, Greater Hartford and Central Connecticut Area, ISO New England Demand Resource Working Group, January 30, 2013

ISO-NE Market Resource Alternative Analysis shows how large a load reduction would be necessary to meet contingencies

Load would have to be reduced by nearly 50% in the greater Hartford area to resolve all N-1 and N-1-1 issues

Greater Hartford Market Resource Alternative (MRA) Analysis

DG Interconnection Timing in Massachusetts

128

229

357

677

0

100

200

300

400

500

600

700

800

All Applications Requires SystemModification

Projects Above 2MW

Largest Project7.5 MW

Aver

age

Day

s to

Pro

cess

Distributed Generation Interconnection Application Time*

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The time necessary to process interconnection has implications for customers finances and system planning assumptions

53% of MW

47% of MW

MA DOER website – Distributed Generation and Interconnection in Massachusetts

* Will not total to 100% as projects can fall into multiple categories

Radial vs. Network Systems

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Network systems are normally utilized in densely populated urban areas, meaning that T&D will still be needed to get DG to major load centers

System engineers usually do not allow large DG systems on networked systems due to concerns over power backflow

Location Pop. Massachusetts 6,692,824

Boston 645,966

Bedford 95,078

Cambridge 107,289

Brockton 94,089

Fitchburg 40,383

Lynn 91,589

Pittsfield 44,057

Springfield 153,703

W. Springfield 28,684

Worcester 182,544

Total 22%

Network Distribution Systems in Massachusetts

DG vs. Transmission Comparison

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Technology Size (kW) $/MW Units to Displace 765 kV line

765 kV Line 2,770,000 $1,083,032 n/a

Microturbine 65 $3,100,000 42,615

Microturbine 185 $3,000,000 14,973

Fuel Cell 300 $5,600,000 9,233

Fuel Cell 1,200 $4,820,000 2,308

Gas Turbine 3,000 $2,450,000 923

Gas Turbine 10,000 $1,520,000 277

Reciprocating Engines 100 $2,750,000 27,700

Reciprocating Engines 3,000 $1,450,000 923

Residential Solar PV 5 $4,965,000 554,000

Commercial Solar PV 35 $4,475,000 79,143

Residential Small Wind 3 $6,983,000 923,333

Commercial Small Wind 35 $4,717,000 79,143

Large kV transmission lines are able to transport quantities of electricity equal to hundreds, thousands, and in some cases hundreds of thousands of DG units

• This is a simplified example but illustrates cost and scale

• In some instances, hundreds of thousands of DG units would need to be installed at 6-7x times the cost of comparable transmission

U.S. Energy Information Administration, (2013). Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants ICF International on behalf of the California Energy Commission, (2012). Combined Heat and Power: Policy Analysis and 2011-2030 Market Assessment PJM Media Website, (2006). AEP Interstate Project: Why 765KV AC?

Closer Integration and Collaboration with System Planning

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2014 Substation Loading Capacity 2016 Substation Loading Capacity

Does Not Exceed Firm Capacity

75% Firm Capacity

At Firm Capacity

Substation Loading Key • Bi-annual update from system planning of

substation loading limits • Focus EE and DG efforts in constrained

areas • Issues still remain with timing and step

loads

Illustrative example of how closer collaboration between system planning and energy efficiency could help promote geo-targeting

Rhode Island Demand Response Pilot

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Year 2014 2015 2016 2017 2018

Load Reduction Needed (kW)

150 390 630 860 1000

Year Unique Accounts

Central AC thermostats installed

Window AC plug load devices installed

% of 2014 savings goal achieved

% of total savings goal achieved

2012 158 35 0 31% 5%

2013 437 132 145 201% 30%

Total 595 167 145 233% 35%

National Grid is running a pilot in Rhode Island to determine if substation upgrades can be avoid using energy efficiency and demand response

kW Reduction Necessary to Defer Substation Upgrade

Abigail Anthony, and Lindsay Foley, “Energy Efficiency in Rhode Island’s System Reliability Planning”. 2014 ACEEE Summer Study

Progress to Date

How Can We Continue to Better Integrate EE into T&D Planning?

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Designing CHP incentives in a way that could increase reliability might lead to smaller planned loads

Technology Group Size Availability (%) Avg Mean Down Times (hrs)

Reciprocating Engines <100 kW 97.33 13.71

Reciprocating Engines 100-800 kW 95.99 50.66

Reciprocating Engines 800 kW – 3 MW 98.22 27.06

Gas Turbines 500 kW – 3 MW 97.13 65.38

Gas Turbines 3 -20 MW 94.97 68.63

Gas Turbines 20 -100 MW 93.53 75.3

Energy and Environmental Analysis, Inc. 2004. Distributed Generation Operational Reliability and Availability Database Oak Ridge, Tenn: Oak Ridge National Laboratory

Installing multiple, smaller units instead of one large unit, decreases the chances of a whole facility going offline and requiring full support from the grid

Final Thoughts

� Is EE and DG making a difference?

– Yes

� How big is the effect?

– Difficult to quantify

– It’s the result of a compounded effect, not discrete events

– No readily available counterfactual

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