Copyright 2014 The Brattle Group, Inc.

This report was prepared for the Texas Clean Energy Coalition with the support of the Cynthia and George Mitchell Foundation. All results and any errors are the responsibility of the authors and do not represent the opinion of the projects sponsors, The Brattle Group, Inc. or its clients.

Exploring Natural Gas and Renewables in ERCOT The Role of Demand Response, Energy Efficiency And Combined Heat and Power

Peter Fox-Penner Ira Shavel Jurgen Weiss

Ryan Hledik Pablo Ruiz Yingxia Yang Rebecca Carroll Jake Zahniser-Word

June 3rd, 2014

PREPARED BY

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Agenda

Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price and Environmental Impacts

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Key Findings Natural gas and renewable dominate the supply addi7ons across all scenarios

Natural gas and renewable addiAons dominate the supply picture, with gas providing both low-cost base load energy and ancillary services that integrate wind and solar energy. The original forms of complementarity discussed in prior reports for the TCEC conAnue to occur, albeit in a more nuanced manner with the introducAon of the increased opAons of EE, DR, and CHP.

Energy eciency and demand response provide substan7al opportuni7es to displace future capacity addi7ons and lower overall electricity costs.

Our program porSolio was designed to be moderate in size and use well-established approaches primarily driven by ERCOT energy prices. Even so, 3 GW of peak reducAon could be achieved by new EE programs and 2 to 4 GW of new DR programs are idenAed as economically achievable in our modeling scenarios.

In total, this represents a 40%-50% reducAon in projected peak demand growth.

Large CHP are very economical but not small CHP units New large CHP installaAons at petrochemical faciliAes are very economical; the

simulaAon indicates that the full potenAal of these opportuniAes will be realized by 2032 in all scenarios. However, the high capital costs and rapid payback required for smaller CHP units inhibits any further CHP adopAons in our scenarios.

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Key Findings Real energy prices in Reference scenarios remain within the band of prices actually experienced in ERCOT between 2010 and 2012

The highest annual average price for a converged year is about $67/MWh ($2012) for the Strong Federal Carbon Policy/high gas price scenario. However, even this extreme scenario price is $3/MWh lower than its counterpart scenario in Phase II.

Carbon emissions are slightly below all comparable Phase II scenarios. These lower emissions are the net eect of reduced sales (including from

EE programs) and higher renewables penetraAon, partly oset by partly oset by increased generaAon share of coal capacity.

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Agenda Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price and Environmental Impacts

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Overview of Modeling Scenarios

No. Case* Gas Price Renewable Cost

Load forecast Carbon Policy

1 Phase III Reference AEO 2014 Reference

Base Brattle Phase III forecast

No

2 Enhanced Energy Efficiency AEO 2014 Reference

Base Brattle Phase III forecast adjusted with enhanced EE portfolio

No

3 Moderate Federal Carbon Policy

AEO 2014 Reference

Base Brattle Phase III forecast adjusted with enhanced EE portfolio

In 2025 coal units require 50% carbon reduction

4 Strong Federal Carbon Policy AEO 2014 Low Oil and Gas Resource Case

Approx. 15% reduction in capital cost by 2025

Brattle Phase III forecast adjusted with enhanced EE portfolio

In 2025 coal units require 90% carbon reduction

* In all cases, existing DR, new DR programs, and CHPs are all available with the same economic characeristics. * In all cases, there is no reserve margin requirement modeled.

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Agenda

Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price Impacts and Environmental Impacts

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Natural Gas Prices Update

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Load Forecast and Adjustment

Energy Forecast Peak Forecast

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Agenda

Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price Impacts and Environmental Impacts

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An expanded EE portfolio could cost-effectively reduce demand by 3 GW

Codes & standards and planned uAlity EE iniAaAves could reduce peak demand by around 4 GW by 2032

We conservaAvely idenAfy an addiAonal 3 GW of demand reducAon that could be achieved through an expanded porSolio of EE programs

These programs include residenAal cooling, commercial lighAng, and industrial pumping

The porSolio is cost-eecAve under all scenarios, with a benet-cost raAo between 1.1 and 1.3

AccounAng for benets such as avoided T&D capacity costs or reduced emissions would further improve the benet-cost raAo

Bo&om-up EE potenAal studies in Texas are very dated this is a clear area where new research is needed

Peak Demand Growth, 2014 - 2032

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As early as 2017 we idenAfy between 450 and 760 MW of economic, achievable DR in ERCOT, represenAng a 20% to 30% increase over the exisAng porSolio

By 2032, economic new DR grows to between 2.3 and 3.8 GW, more than doubling the current porSolio

The porSolio could be expanded further; for example, it could include default dynamic pricing coupled with automaAon technologies

The analysis could also be extended to explore the ability of DR 2.0 to facilitate the integraAon of renewables around-the-clock

ERCOTs existing DR portfolio could be roughly doubled through new initiatives

Size of cost-eec7ve DR Resource (2032)

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Agenda

Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price and Environmental Impacts

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Reference Case With Required Reserve Margin Phase II

4.4 GW of gas steam reArements and 8 GW of Northwestern wind reAres by 2032 (we assume that wind faciliAes reAre when 20 years old)

Aner 2028 PV becomes economical and 5.4 GW is added

Apart from PV and 4.5 GW wind, almost all new capacity is CCGT (21.3 GW)

32.7 GW of total new construcAon occurs and total net capacity reaches 101.9 GW (22% increase)

No signicant addiAons or reArements of coal

2032 GeneraAon Share

Gas 47.8%

Renewables 7.3%

Coal 34.7%

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Reference Case with new DR and new CHP Phase III

2032 GeneraAon Share

Gas 44.1%

Renewables 10.7%

Coal 34.9%

10.8 GW of wind is added by 2032 , 6.3 GW more than Phase II due to high natural gas prices, higher load factor, and no required reserve margin

Our results understate wind builds between now and 2017 (vs. ERCOTs queue) because we dont reect a current upsurge in Panhandle wind builds. This would likely not aect our results, but may result in slightly overstated new CCGT addiAons.

2.8 GW solar is added, 2.6 GW less than whats added in Phase II due to the peak load reducAon and new DR penetraAon

3.8 GW new DR is added by 2032, 2.3 GW more penetraAon than Phase II

11.4 GW of CCGT and 3 GW of CHP are added by 2032. In total, 7 GW fewer gas units are added than Phase II.

Overall 4 GW less new capacity construcAon by 2032 with more wind and less CC and solar

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Reference Case with new DR, new CHP, and Enhanced EE Phase III

2032 GeneraAon Share

Gas 43.5%

Renewables 11.0%

Coal 35.0%

11.9 GW of wind is added by 2032 , 1.1 GW more than Phase III Reference without enhanced EE due to higher load factor

1.4 GW solar is added, which is 1.4 GW less than whats added in Phase III reference due to the peak load reducAon

3.3 GW DR is added by 2032, slightly lower DR market penetraAon relaAve to reference case without new EE

11.3 GW of CCGT and 3 GW of CHP are added by 2032. Very similar gas units to reference without enhanced EE

Overall 1 GW fewer new capacity addiAons by 2032 and 1.7 GW more reArements due to the new energy eciency programs impacts on peak reducAon and total load reducAon

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Moderate Federal Carbon Policy Phase III

3.5 GW less coal capacity by 2032 due to the assumed 16% derate when retrorng with 50% CCS

8.7 GW out of 11 GW of steam gas also reAres because of no required reserve margin

3.6 GW of new DR installed by 2032, a comparable amount to the installments in the reference case

Total capacity buildout of by 2032 is 1.8 GW more than the Reference Case:

q 12.1 GW Gas CCGT and 3 GW of CHP, in total 0.7 GW more than Reference Case

q 14.5 GW Wind, in total 3.6 GW more than Reference Case

q 0.5 GW PV, which is 2.3 GW less than the Reference Case

2032 GeneraAon Share

Gas 48.4%

Renewables 13.2%

Coal 28.4%

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Strong Federal Carbon Policy Low Renewable Cost High Gas Prices Phase III

9.6 GW out of 19.2 GW of coal capacity reAres by 2032, 6.5 GW less than Phase II due to higher gas prices and no required reserve margin.

9.5 GW out of 11GW of steam gas also reAres because of no required reserve margin

2.3 GW of new DR installed by 2032, 1.5 GW less than reference case, due to more solar PV penetraAon.

Largest 2032 capacity buildout:

q 10 GW Gas CCGT and 3 GW of CHP, in total 12 GW less than Phase II

q 47 GW Wind, in total 11GW more than Phase II

q 14 GW PV, 2 GW more than Phase II

2032 GeneraAon Share

Gas 27.3%

Renewables 46.3%

Coal 15.9%

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Agenda

Key Findings Overview of Modeling Scenarios Major Inputs Updates Review of Modeling Results

OpportuniAes for Demand Response (DR ) and Energy Eciency (EE)

Future Resource AddiAons Price and Environmental Impacts

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Price Impacts

Average wholesale electricity market prices have risen across the board in our Phase III scenarios due to higher natural gas prices, parAally oset by the price-reducing eects of DR, CHP, and EE.

Importantly, the inclusion of EE, DR, and CHP in the Phase III scenario reduces the higher-priced carbon rule scenarios, than what otherwise would have been. In Phase II, 2032 prices in the carbon rule cases topped out at almost $70/MWh, $3/MWh more than the same scenario in Phase III

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Environmental Impacts

Carbon Emission Savings Carbon Emission Savings

ScenariosAnnual Savings in 2032, MMT

% Change vs. Phase 2

Reference

Phase 3 Reference with CHP and DR 7 3.1%

Phase 3 Reference with CHP, DR, and EE 10 4.7%

Phase 3 Moderate Federal Carbon Rule 74 34.6%

Phase 3 Strong Federal Carbon Rule 171 79.9%

The combined eects of higher gas prices, lower load growth, enhanced DR and CHP installaAons lower CO2 emissions about 4% by 2032 versus the Phase II Reference Case, or about 143 million metric tons. This is the equivalent of closing one 600 MW coal plant for 30 years.

New EE programs further reduce CO2 by 10 MMT, the equivalent of one years emissions from an 800 MW coal plant.