long-term system assessment project update

December 15, 2008Regional Planning Group

Long-Term System AssessmentProject Update

Warren LasherManager, System Assessment

Regional Planning GroupDecember 15, 2008 2

Purpose

To Inform Near-Term Planning with Potential Solutions that Meet Long-Range System Needs

• Intent is not to select new circuits to recommend

• Rather, the intent is to provide a selection of alternatives through scenario analysis that can be considered when developing solutions for near-term congestion or reliability needs


Specific Focus

The focus of this study is to look for:

Long-Lead-Time Projects – projects that may require 5 or more years to bring on-line

Large Projects – projects that both solve short-term issues but also meet long-term system needs.


Scope

Study Year: 2018All generation currently on-line (and expected to

maintain operation) plus all units with signed IAs as of 7/1/2008

Base Case will include the CREZ Scenario 2 (selected by PUCT on 7/17/08)

Generation Expansion – by scenarioGas price – by scenarioEmissions allowance prices – by scenarioA report will be submitted to PUCT by end of 2008Analysis will continue next year


Methodology

Study Consists of Two Components1. Evaluation of Regional System Needs

– A/C contingency steady-state analysis – SC-UC Model Development

2. Evaluation of Economic Projects


A/C Contingency Analysis

Evaluated Five Areas• Northeast Region• Houston• South-Central• Valley

Using different local generation dispatches, evaluated the reliability needs of these areas under increasing amounts of import

Looked for thermal limit and voltage violations under contingency, primarily on the 345-kV network

Did not evaluate transient stability limits



Under peak load conditions, generation availability was reduced by up to 2,800 MW to determine import constraints (resulting in a net import of 2,550 MW)

Example: Northeast Region



Example: Houston RegionUnder peak load conditions, generation availability was reduced by up to 1,100 MW to determine import constraints (resulting in a net import of 6,760 MW)



Example: South-Central RegionUnder peak load conditions, generation availability was reduced by up to 1,900 MW to determine import constraints



Example: Valley RegionUnder peak load conditions, generation availability was reduced by up to 1,000 MW to determine import constraints (resulting in an import of 2,700 MW)



Results:• No reliability need for additional import capacity

in the Northeast and South-Central Regionso At high levels of unavailable generation, import

restrictions are noted in these areas

• A new import pathway into Houston will be required by the summer peak season of 2018

• Current connections to the Valley region appear to be adequate although imports over existing interconnections with CFE may be required


SC-UC Analysis

In order to build a 2018 model for economic analysis, small load-serving projects had to be added to the SCUC base-case model• Projects required to reliably serve load• Analyzing 8,760 hours using DC loadflows

These projects are not in the base-case, which is built off of the last year of the latest 5-Year Plan

In areas where several of these projects were required, a more cost-effective solution might be to build one larger (345-kV) project, rather than several smaller 138-kV upgrades


SC-UC Analysis

Based on this analysis, four areas were selected for further analysis:• Houston Import• Western Williamson County• West of Waco• North of Dallas (Cooke and Grayson County)

In addition, these areas were reviewed for reliability needs:• Brenham Area• Columbus Area


Options for Houston Import

The following options were evaluated for new pathways into the Houston area:• Fayette to Zenith• Salem to Zenith• Lufkin to Canal• Hillje to Parish, O’Brien or Zenith

Choice may depend on future base-load generation additions

Options further evaluated in the analysis of economic projects


North Dallas Area

Area around Cooke and Grayson Counties (north of Dallas near the Oklahoma border)

Load growth may stress existing 138-kV service345-kV Option: Tap into the CREZ line connecting

Oklaunion and West Krum, and build a new 345-kV right-of-way to the Valley substation. Potential new 345-kV substations at the Payne and Valley View substations with 345-kV/138-kV autos.


West Waco Area

Area west of Waco, in McLennan, Coryell, and Bosque County

Again, limited 345-kV service in this area345-kV Option: New 345-kV right of way from

Comanche Peak, south to the new Newton substation included in the CREZ plan. This would allow a new connection(s) into this area from the west. This option provided significant economic benefits if additional nuclear generation is developed at Comanche Peak.


Western Williamson County

Load growth around Leander up to Lampasas will require several 138-kV upgrades

Flow is generally from 345-kV lines in the east and southeast

Potential solution:• New 345-kV substation at Lampasas,

connecting to the CREZ line from Gillespie to Newton

• Upgrade the 138-kV circuits from Lampasas to Burnet13

• New 138-kV right-of-way from Burnet13 to Leander


Other Areas

The Brenham area is generally served radially from the Fayette to the Salem substations. Options were evaluated to provide network service for the Salem substation, including new right-of-way from Salem to Zenith, or from Salem to Sandow. These solutions were generally not cost-effective.

There is congestion in the Columbus area due to flows on the 69-kV system. One possible solution would be to convert some of the 69-kV circuits to 138-kV. This solution appears to be effective in eliminating congestion in the base-case, but with added base-load generation to the south (such as new nuclear units at STP or Victoria), a better solution may be to break the 69-kV system, reinforce the two ends and add reactive support.


Economic Analysis

Using Scenario Analysis, evaluate projects that increase system efficiency under potential future conditions. Scenarios include:• Additional Nuclear Generation (3 units, 6 units)• Natural Gas Prices ($7, $11, $15/MMBtu) with

Coal Gasification/IGCC• Carbon Constraints (Up to $100/ton)• Changes in Load Shape (Plug-In Hybrids, Energy

Storage)• Additional Renewable Generation (Wind, Solar)


Economic Analysis – Generation Expansion

Bus-bar analysis shows type of generation options that will be most cost-effective.

Bus-Bar Cost Of Generation Alternatives

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor

To

tal (

Bu

s-B

ar)

Co

st

($/M

Wh

)

Coal IGCC IGCC + Sq Adv CC Adv CT Nuc Wind Solar Thermal PV

Coal Price : $1.5/MMBtu

Nuclear Price: $0.75/MMBtu

Biomass: $0.5/MMBtu

Carbon Cost: $0/Ton

REC Price: $5/MWh

Gas Price: $11/MMBtu

Generation development will be driven by profit expectations.



Impact of Carbon Tax shown on this chart.Bus-Bar Cost Of Generation Alternatives

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor

To

tal (

Bu

s-B

ar)

Co

st

($/M

Wh

)

Coal IGCC IGCC + Sq Adv CC Adv CT Nuc Wind Solar Thermal PV

Coal Price : $1.5/MMBtu

Nuclear Price: $0.75/MMBtu

Biomass: $0.5/MMBtu

Carbon Cost: $50/Ton

REC Price: $5/MWh

Gas Price: $7/MMBtu


Economic Analysis – Generation ExpansionERCOT system has a significant amount of intermediate generation

Net Load Duration Curve - 2018Load Minus 18,456 MW of Wind Generation

-10,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

0.00% 10.00% 20.00% 30.00% 40.00% 50.00% 60.00% 70.00% 80.00% 90.00% 100.00%

Percentage of Hours

Ho

url

y L

oad

(M

W)

Load Duration Must Run Nuclear Coal CC Base Load Max

Gas Price: $11/MMBtu

Base Load Max Capacity = 40009 MW



At gas prices of $11/MMBtu or $15/MMBtu, additional base-load generation will likely be profitable.

Additional generation expansion, to meet 12.5% target reserve margin, will likely come from quick-start combustion turbines or very flexible combined-cycle plants.

Hourly marginal cost unit-commitment models will often underestimate the benefits from quick-start combustion turbines• Ancillary services (Non-spin)• Short-term price spikes


Economic Analysis – General Observations

Evaluating two levels of nuclear and coal (IGCC) expansion indicates that economic projects were generally not cost-effective unless they were specifically designed for scenario generation expansion (except in certain scenarios)

Backbone projects (such as 765-kV Navarro to Hillje, and Fayette to Zenith) were generally not cost-effective unless new generation was directly connected to the backbone

Carbon constraints did not significantly alter the locations of system congestion, although they change the congestion costs and likely generation expansion options


Economic Analysis – General Observations

No large projects in ERCOT between Dallas and Houston were found that were economically justified due to presence of CREZ wind. Import pathway into Houston from the west was cost-effective.

Analysis of up to 2,000 MW of solar generation in the McCamey area indicates limited increase in curtailment to wind or solar projects

Analysis of conventional Compressed Air Energy Storage indicates that 2,000 MW of CAES capacity can increase wind generation by 830 GWh (reducing wind generation curtailment by 1%); production costs reduced by $10 million


Conclusions

Reliability analysis indicates a need for additional import pathway into Houston area by 2018. Selection of most cost-effective solution will likely depend on generation expansion.

Options have been presented for additional reliability projects north of Dallas, near Waco, and north of Austin

Scenario analysis indicates that cost-effectiveness of economic projects depends heavily on locations of future generation development

Long-term analysis will continue in the new year:• CREZ implementation• > 10 year analysis


Questions?

long-term system assessment project update

Documents

mwregional planning

yearregional planning

nearterm planning

net import

generation availability

ac contingency analysisexample

ac contingency analysisresults

generation expansion