NERC LTRA Update / CDR Capacity Counting Issues

GATF Meeting,November 10, 2014

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NERC LTRA and LOLE Study Update

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2014 Long Term Reliability Assessment• Release expected November 11, 2014

• Mentions status of the Frontera switchable resource

• TRE-ERCOT Reserve Margins:

Anticipated – CDR resources onlyProspective – Anticipated capacity plus forecast of other capacity in the interconnection queue expected to become operable plus mothballed capacity that could potentially be bought back under RMR arrangementsAdjusted-Potential – Prospective capacity plus forecast of announced projects not currently in the interconnection request queue expected to become operable

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2014 LTRA Probabilistic Assessment• ERCOT’s final study results submitted to NERC on November 3,

2014; public release of report in March 2015• All assessment regions provide Loss of Load Hours (LOLH),

Expected Unserved Energy (EUE), and EUE as a percentage of Net Energy for Load for years 2016 and 2018 based on loads and resources used for the 2014 LTRA

• The purpose of the assessment project is not to establish reserve margin targets or assess reliability standard criteria, such as one LOL event in 10 years

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Loads in SCED

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Loads in SCED

• Status update (Sai Moorty)

• Potential impact to the CDR, and timing of when to consider the impact

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Revisions to ERS Capacity Forecasting Methodology

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Proposed Change to ERS Methodology

• ERCOT would like to add the following wording to the existing ERS capacity estimation methodology in Section 3.2.6.2.1:

“The estimate may be adjusted to account for program modifications, procurement methodology changes, changes in the seasonal risk assessment, and ERS time period expenditure limits.”

• Also, change the compound period from two years to three years.

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Proposed Change to ERS Methodology

• Recent changes in the ERS Procurement Methodology (implemented for the Feb-May 2014 SCT) creates incentive to increase participation during the Summer and Winter peak hours.

• Growth rate for Business Hours 3 during the summer Standard Contract term from 2013 to 2014 was 47.44%. Previous years from 2011 to 2012 was -11.3% and from 2012 to 2013 was 13.8%.

• Escalation rates based on compounding annual growth rates (CAGR) vary significantly depending on number of periods used in computation

• CAGR 2012, 2013, 2014 (Current Protocols) = 29.5 %

• CAGR 2011, 2012, 2013, 2014 = 14.18%

• Some additional growth is still expected but not sustainable under the $50 million/yr ERS expenditure limit.

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Solar Capacity Contribution

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Solar Capacity Contribution• Application of top-20 peak load hour methodology yields

the following preliminary results:

• Small resource population for the calculations: – Summer: four resources in 2014, two in 2013, one in 2012

– Winter: two resources in 2013-14, one in 2012-13

Year Solar Year Solar2014 67% 2013-2014 3%2013 78% 2012-2013 9%2012 80%

Annual Peak Ave. Percentages - Top 20 HoursSummer Season

Annual Peak Ave. Percentages - Top 20 HoursWinter Season

0

1

2

3

4

5

6

7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Freq

uenc

y

Hour Ending

Frequency of Top 20 Peak Load Hours for 2013/2014 Winter

• Winter results driven by predominance of morning peak loads (mainly HE 7-8) and peaks occurring after sunset (HE 19-21)

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PUN Capacity Forecasting

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Current PUN Capacity Reporting Requirements• Protocol Section 3.2.6.2.2

– Private Use Network Capacity—The Private Use Network capacities as provided to ERCOT pursuant to Section 3.10.7.3, Modeling of Private Use Networks.

• Section 3.10.7.3: A Generation Entity with a Resource located within a Private Use Network shall provide data to ERCOT, for use in the Network Operations Model, for each of its individual generating unit(s) located within the Private Use Network in accordance with Section 3.3.2.1, Information to Be Provided to ERCOT

• Protocol Section 10.3.2.4– All Generation Resource Facilities with associated Load shall

report to ERCOT before February 1st of each year their projected Net Generation capacity available to the ERCOT Transmission Grid for use by others during the June to August time period for the current calendar year and ten subsequent years.

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PUN Capacity Forecasting for the CDR

• May 2014 CDR method:– Same method used for hydro and DC tie capacity: the

average telemetered HSL for the highest 20 peak Load hours for each preceding three year period for Peak Load Season s and year i

• Method does not account for expected trends in process load requirements and generation capacity additions; may be overestimating net output to the grid for future years

• To improve the PUN capacity forecast, recommend surveying PUNs for forecasted annual changes in Expected Typical Private Network Net Interchange (MW), a current RARF field

• Annual Net Interchange amounts are added to the historical average capacity to create the forecast series

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PUN Capacity Forecasting for the CDR (continued)

• Two approaches to acquiring the data:1. Informal Request for Information (RFI)

2. Modify the language in Section 10.3.2.4 to require formal submission of Net Interchange forecast information• Request other PUN information that may be

useful for operations planning?

• Modify PUNCAP definition in section 3.2.6.2.2 to reflect use of 20 top peak hour historical settlement data and Net Interchange forecasts

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Example of PUN Notice/RFI Language

Forecast Period

Annual Change in Expected Typical Private Network Net Interchange

(MW)August 1, 2014 August 1, 2015  August 1, 2015 August 1, 2016  August 1, 2016 August 1, 2017  August 1, 2017 August 1, 2018August 1, 2018 August 1, 2019 August 1, 2019 August 1, 2020 August 1, 2020 August 1, 2021 August 1, 2021 August 1, 2022 August 1, 2022 August 1, 2023 August 1, 2023 August 1, 2024

To supplement the historical settlement data used for forecasting PUN capacity in the Report on Capacity, Demand and Reserves (CDR), ERCOT requests that PUNs provide the forecasted annual changes in the RARF field, Expected Typical Private Network Net Interchange. The annual changes should reflect the actual and expected capacity amounts as of August 1st of each year. If forecasted capacity amounts are not available for certain periods, enter n/a. Any information collected will be treated as confidential per ERCOT Protocol Section 1.3, Confidentiality.

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Counties to be Considered Coastal for Nodal Protocol 3.2.6.2.2

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Non-Coastal (NC) & Coastal Wind Resources• Definition of Coastal Resources (NPRR 611) includes 11

southern counties adjacent to Gulf Coast• Recent historical correlation data (Summer ’13-’14) for existing

resources supports current definition

• Webb County data stands out among NC resources with higher correlation with coastal resources; may consider revisions in future years

• ERCOT staff supports current definition of Coastal and NC wind resources for planning purposes (no change)

Correlation Correlation Capacityw/ Load (1) w/ TGW (2) MW

Non-Coastal Resources -13% 15% 9,764 Coastal Resources (3) 42% 86% 1,671

Nolan County - NC -13% 17% 1,533 Webb County - NC 5% 48% 165 Kenedy County - C 43% 93% 686 Cameron/Willacy Co - C 43% 81% 605 San Patricio County - C 39% 81% 380

(1) Correlation of wind production data with ERCOT system-wide load for all summer hours.(2) Correlation of wind production data with Texas Gulf wind production for all summer hours.(3) Coastal Resources as defined in NPRR 611 for wind capacity contribution in CDR report.

CAMERON

WILLACY

KENEDY

KLEBERG

NUECES

SAN PATRICIO

REFUGIO

ARANSAS

CALHOUN

MATAGORDA

BRAZORIA

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Wind Correlation w/ ERCOT Load – Summer 2013-2014

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Wind Correlation w/ TX Gulf Coast Wind Production ‘13-’14