ERCOT Update

Trip DoggettPresident & CEOERCOT

Texas Public Power AssociationJuly 23, 2014

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Current Records Jul 15, 2014

Peak Demand Record: 68,305 megawatts (MW)68,305 MW, August 3, 2011

Weekend Record65,159 MW, Sunday, August 28, 2011

Winter Peak Record: 57,265 MW57,265 MW, February 10, 2011

Wind Generation Records (instantaneous)10,296 MW, March 26, 2014, 8:48 p.m.-­ Non-Coastal Wind Output = 8,863 MW-­ Coastal Wind Output = 1,433 MW-­ Supplying 28.78% of the 35,768 MW Load-­ Installed Commercial Capacity = 11,055 MW

39.40% Wind Penetration, March 31, 2014, 2:12 a.m.-­ Total Wind Output = 9,699 MW-­ Total Load = 24,618 MW

Summer 2013 Demand64,418 MW, June 2764,814 MW, July 3167,245 MW, August 763,388 MW, September 3No new records

2013-2014 Winter DemandRecord monthly peak demand in November, December, January and March, due primarily to extremely cold and often windy weather conditions.

The March peak was about 11,500 MW higher than the previous March record.Energy use during each of the winter months exceeded previous levels, even 2011

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Energy Use Comparison

Total energy consumed:333,885,158 MWh

Total energy consumed:324,859,701 MWh

Total energy consumed:331,624,102 MWh

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Wind Generation Capacity June 2014

Texas is #1 in the U.S. in wind capacity.Our capacity is more than twice the amount of #2 (California)

#6 in the world in wind generation capacity.

2014 Summer

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2014 Summer SARA (Final)

Item Summer 2014Forecasted

Season Peak Load

Extreme Load/Typical Generation

Outages

Extreme Load/Extreme

Generation Outages

1 Total Resources 73,910

2 Peak Demand 68,096

3 Uses of Reserve Capacity 2,854 5,167 7,862

4 Capacity Available for Operating Reserves* (1-2-3) 2,960 647 (2,048)

5 Capacity Available for Operating Reserves** after August 1 5,113 2,800 105

Tight reserves at start of summer

Reduced likelihood of scarcity conditions by late summer

*Less than 2,300 MW indicates risk of EEA 1**Additional 2,153 MW to be operational by Aug. 1

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Long Term Climate Influencing FactorsLong Term Forecast Contributing Factors

Variations in SST ( Sea Surface Temps)El Niño (+) & La Niña (-) (ENSO)Pacific Decadal Oscillation (PDO)Atlantic Multidecadal Oscillation (AMO)

Certain shorter term phenomena (e.g. North Atlantic Ocean Blocking) can only be forecasted 10-14 days out such effects are not included in longer term forecasts

Tropical Pacific La Nina or El Nino (ENSO)

North Pacific (PDO)North Atlantic (AMO)

El Niño likely

Drought Patterns

El Niño

La Niña

Increased opportunity for cooler, wetter weather. Less hurricanes

Increased opportunity for warmer, drier weather.More hurricanes TX has lower sensitivity to

ENSO during summer months

Pattern flipped to +PDO/-AMO in January. This presents opportunities to lessen (not necessarily end) the drought. Flip is likely temporary.

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Temperature and Precipitation Outlooks (May 28, 2014)

Overall, slightly hotter than normal* for ERCOT as a wholeMore opportunities for above normal temperatures West rather than East. Not hotter than any of the past four summers (all were top 25)More potential for cooler rather than warmer.

Below normal precipitation expected for the majority of the western half to two-thirds of the state.Best opportunities for above normal rainfall within ERCOT will fall within the East, Coast, and eastern North zones.

*10 year normal (2004-2013)

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Hurricane Forecast and Drought Projection

Hurricane Arthur was the first cyclone of the season.Only the second time in the past 10 years with no named storm prior to July. Forecast on track.Normal: 11/6/2*2013: 14/2/02014 Forecast: 9/5/3Texas Landfall: 0 or 1 Named Storm

Some improvement over the past couple of months.Drought still in place for most (over 60%) and July is showing minimal rainfall opportunity.El Niño may have a wetter impact late-summer into fall.Lake Travis is at 37% of capacity. Buchanan Lake at 41%.

*Total Named Storms / Hurricanes / Major Hurricanes

July 1, 2014

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Lake Levels Risk Analysis

Transmission Projects

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CREZ Transmission Update January 30, 2014

Transmission Plan designed to serve approximately 18.5 GW:

~3600 right-of-way miles of 345 kV$6.8 billion project cost

Lines are open-access; use not limited to wind

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ERCOT Panhandle Grid CharacteristicsMinimal to no nearby synchronous generationNo local loadThese conditions lead to voltage stability and grid strength challengesCurrent wind generation development:

~5.3 GW of wind capacity in the Panhandle with signed interconnection agreements~6.0 GW of additional wind generation in the interconnection study process

Long Term Studies show a continued expansion of wind resources in the Panhandle under a range of future outcomes.CREZ Reactive Study Recommendations were designed to accommodate 2,400 MW of wind generation in the Panhandle CREZ regions

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Cotton Wood

Tule Canyon Tesla

DermottLong Draw

Windmill

Alibates

Gray

Ogallala

Panhandle Renewable Energy Zones (PREZ) Study

An initial set of recommended transmission upgrades includes:

New 345-kV circuits on existing towers from Alibates to Windmill, Windmill to Ogallala, and Ogallala to Tule Canyon (towers were designed to accommodate these additional circuits).

Synchronous condenser at the Windmill substation

A potential future set of upgrades includes:

New 345-kV circuit from Ogallala to Long Draw

Additional synchronous condensers at Windmill, Alibates, and Gray substations

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Eagle Ford and Cline Shale

Oil and natural gas related demand has caused a significant amount of load growth in west Texas and south Texas

Six of the top ten transmission constraints on the ERCOT System in 2013 were related to serving the increased demand in west Texas

A significant number of transmission projects have been implemented in west Texas within the past two years, and more than 60 are planned over the next four years to meet the oil and natural gas related needs

More than $330 million in transmission projects have been approved by the ERCOT Regional Planning Group since 2012 in order to meet Eagle Ford Shale load growth in south Texas (Expected in-service 2013 through 2016)

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Eagle Ford Shale Projects I

Driver Reliability Need to support new oil and gas loadProject Components:

1. Glidden-Colorado-Nada 69 kV upgrade project July 14

2. Karnes Electric Cooperative-Medina Electric Cooperative load addition project Aug. 16

3. Coy City load addition project Aug. 14

4. El Campo-Vanderbilt load addition project Sept. 14

5. Karnes Electric Cooperativeload addition project June 16

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Eagle Ford Shale Projects II

Driver Reliability Need to support new oil and gas loadProject Components

1. Sinton - Beeville - Kenedy Area Improvements Project May 15

2. Kenedy Switch Guadalupe Project June 15

3. Kenedy Switch to Nixon to Seguin upgrade and conversion from 69 kV to 138 kV June 16

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Lower Rio Grande Valley project

Driver Reliability NeedProject Components

Energized reconductor of Lon Hill-N. Edinburg and Lon Hill-Rio Hondo 345 kV lines. Reconfigure N. Edinburg and Rio Hondo series capacitors (Expected to be completed Jan. 2016)Lobo-Rio Bravo-N. Edinburg 163 mile single circuit 345 kV line on double circuit structures with 50% series compensation (Expected in service June 2016)

Cost Estimate - $527 million

Rio Bravo

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Cross Valley 345kV Project

Driver Reliability NeedProject Components:

New La Palma-Palo Alto 138 kV line (~12 miles) with a rating of at least 215 MVANew North Edinburg-Loma Alta 345 kV line (double circuit capable with one circuit in place) routed in proximity to the existing South McAllen Substation (~106.5 miles) New 345kV bus at the Loma Alta station with one 345/138kV autotransformer

Cost estimate = $274.7MExpected in-service June 2016

Load Forecast

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National trends

Source: Energy Trends Benchmarking Survey 2013, Mark Quan, November, 2013

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Changing Relation Between Load and Nonfarm Employment

Price responsive load

System-Wide Offer Caps is changing behavior:Commercial & industrial loads with prices indexed to the ERCOT wholesale market are increasing their price response flexibilityLoad-serving entities (LSE) are investing in demand response as insurance against wholesale market exposure

ERCOT Staff, working with LSEs, are attempting to quantify this behavior; starting with summer 2013 data4 CP impact

Energy efficiency upgradesEnergy Star appliancesConversions to CFL and LED lighting

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2012 Summer Peak - 4 CP & Price Response Impacts (June 26)

4 CP & Price Response Impacts

Impacts shown are based on aggregated transmission load values for ~430 premises

Not estimated based on an analysis of individual premises

Difference represents the 4 CP & Price Response impacts of up to 900 MW on an aggregated basis

Transmission charges based on 4CP usage apply to Munis, Co-ops, and Loads with >700 kW of peak demand in retail choice areas.

This data is an example of observed 4CP and price response impacts.

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Load Forecasting Review Process

ERCOT staff developed a methodology for the load forecast that is different from what has been used in recent years

The new methodology is different from what any other ISO is using today

The new methodology represented a significant change and was thoroughly reviewed by the Board and stakeholders before it was incorporated into our Capacity, Demand and Reserves (CDR) Report.

Joint review by the Reliability & Operations Subcommittee (ROS) and Wholesale Market Subcommittee (WMS) of the Technical Advisory Committee (TAC).

ERCOT retained an independent consultant to review the methodology and

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Comparison of historical peak demand forecasts

Oil and Gas Boom begins 2010

15% increase over the previous

ten years

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Comparison of historical energy forecasts

18% increase over the previous

ten yearsOil and Gas Boom begins 2010

Resource Adequacy &Demand Response

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Annual Energy and Peak Demand (2003-2013)

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Capacity, Demand and Reserves (CDR) May 2014

*ERCOT has been analyzing the operational characteristics of wind generation to determine whether it can depend on a higher percentage of installed capacity during periods of peak demand.

Wind generation is included at 8.7 percent*Firm Load = Peak Demand Demand Response

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Generation Interconnection Activity by Fuel

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Recent Implementations & Work in ProgressImplemented

NPRR 568 RT Reserve Price Adder Based on Operating Reserve Demand Curve (ORDC) in June 2014

NPRR 555 Loads in SCED in June 2014

30 minute ERS and Weather Sensitive ERS in 2014

Completed

Calculation of retail price/demand response using data collected from Load Serving Entities final report provided to Demand Side Working Group in June 2014.

In Progress

The Voltage Reduction Task Force final report on the Summer 2013 and Winter voltage reduction testing to be finalized and presented to the Reliability and Operations Subcommittee in August 2014

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On-peak DR Potential by Customer Type

Based on customer class breakdown in competitive choice areas and extrapolated to ERCOTLarge C&I are IDR Meter Required (>700kW)

3/9/2011  IE  17:15 8/3/2011  IE  17:00

BUSIDRRQ BUS  (IDR  not  required) RES

3/9/2011  IE  17:15 8/3/2011  IE  17:00

BUSIDRRQ BUS  (IDR  not  required) RES

Large C&I23.7%

Residential51.2%

(~35,000 MW)

Residential 27.4% (~8,500 MW) Small Commercial

25.2%

Small Commercial 28.9%

Large C&I 43.7%

Wed., Aug. 3, 20115:00 PMERCOT Load: 68,416 MWTemperature in Dallas: 109°

WednesdayMarch 9, 20115:15 PMERCOT Load: 31,262 MWTemperature in Dallas: 64°

ERCOT staff is working on Aggregated Load Response (ALR) enablement with market participants in both NOIE and competitive choice areas

Approx. 37,000 MW of weather sensitive load (54% of peak)

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Ancillary Services Rethink

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Current Ancillary Services (AS) Framework

Regulation UpRegulation DownResponsive ReserveNon-Spinning Reserve

Offers are Resource specificA single Resource may be offered into

Multiple AS marketsEnergy and AS

Ancillary Services are procured in the Day Ahead Market (DAM)

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Drivers for new AS FrameworkCurrent AS Framework has performed well but has issues

Resources could provide some services more efficiently if the requirements were decoupled (Primary Frequency Response / Fast Frequency Response / Contingency Reserve)

New service needed to ensure technical requirements are met that used to be provided, inherently, by generators (e.g. inertia)

Awkward to fit capabilities of new technologies (e.g. wind turbines) that could provide services efficiently

Changes in market design and control systems (e.g. 5 minute dispatch, HRUC) have reduced the need for other services

New regulatory requirements (BAL-003)

Need for changes has been highlighted in discussion of Fast Responding Regulation Service (FRRS), NPRR 524 (Resource Limits in Providing Ancillary Service), etc.

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Regulation UpFast-Responding Regulation Up

Current Proposed

Fast Frequency Response 1

Primary Frequency Response

Contingency Reserves 1

Synchronous Inertial Response

Supplemental Reserves 1

Mostly unchanged

59.8 Hz, Limited duration

59.7 Hz, Longer durationFast Frequency Response 2

Contingency Reserves 2

SCED-dispatched

Manually dispatched

Supplemental Reserves 2

SCED-dispatched

Manually dispatched

Ongoing development

Non-Spin

Responsive

Transition to Future Ancillary Services

Regulation DownFast-Responding Regulation Down

Regulation UpFast-Responding Regulation Up

Regulation DownFast-Responding Regulation Down

Social Media Update

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Improving communications with consumersERCOT website added features

Hourly generation and load informationWeather page: Daily, seasonal

Social media join us!Twitter: 5,800 followersFacebook: 1,500 friendsLinkedIn: 2,700 followers

ERCOT Energy Saver mobile app System conditions hourly and real-time updatesWholesale pricing information Hubs and Load ZonesOther improved features and information sharing