Wind ELCC Calculation Comparisons and ERCOT’s NERC LTRA Capacity ForecastsGATF Meeting,June 24, 2014

2

Summer Season Wind ELCC Calculation Comparisons

3

Wind ELCC Calculation Comparisons• Two peak-hour averaging methods

– “Annual Top 20 Peak Hours” approach (NPRR 611): For top 20 peak hours for a given year, divide the sum of all unit HSLs by the sum of the installed capacities.

– “Summer Daily Peak Hours” approach: Sum the HSLs for summer peak season days for hours ending 15:00-18:00, where the summer peak season = June 1 through September 30; divide the sum of the HSLs by the sum of the installed capacities.

• Multi-year averaging:– Computed average annual wind ELCC for several time periods:

• Two years, 2012-2013• Three years, 2011-2013• Four years, 2010-2013• Five years, 2009-2013

• ERCOT-wide vs. regional breakdown, Coastal and Non-coastal.

Note: All calculations use units that are commercially operating as of January 1 of the given year.

4

Annual ELCC Variability for the Two Peak-hour Averaging Methods, Summer Non-coastal

Summer Daily Peak Hour Method

Annual Top 20 Peak Hour Method

15%

19% 19% 19% 20%

0%

5%

10%

15%

20%

25%

2009 2010 2011 2012 2013

Summer Non-Coastal ELCC, 2009-2013

16%

5%

12%

9%

13%

0%2%4%6%8%

10%12%14%16%18%

2009 2010 2011 2012 2013

Summer Non-Coastal ELCC, 2009-2013

5

Summer Daily Peak Hour Method

Annual Top 20 Peak Hour Method

Annual ELCC Variability for the Two Peak-hour Averaging Methods, Summer Coastal

35%42%

49% 51% 50%

0%

10%

20%

30%

40%

50%

60%

2009 2010 2011 2012 2013

Summer Coastal ELCC, 2009-2013

54%

26%

65%

54%

79%

0%10%20%30%40%50%60%70%80%90%

2009 2010 2011 2012 2013

Summer Coastal ELCC, 2009-2013

6

Annual ELCC Variability for the Two Peak-hour Averaging Methods

Year Non-coastal Coastal2013 9,109 1,270 2012 8,511 1,066 2011 8,239 1,066 2010 7,754 866 2009 7,038 585

Installed Capacity (MW)

Yr Non-coastal Coastal Year Non-coastal Coastal Top 20 Peak Season2013 13% 79% 2013 20% 50% 21% 23%2012 9% 54% 2012 19% 51% 14% 23%2011 12% 65% 2011 19% 49% 18% 23%2010 5% 26% 2010 19% 42% 8% 21%2009 16% 54% 2009 15% 35% 19% 16%

ERCOT-Wide AvgDaily Peak Hours (HE 1500-1800) for Summer Peak Season (June-Sept.)

Top Twenty Peak Hours

7

Wind ELCC Computation Comparison

• Table below compares (1) the two methods of selecting peak hours, (2) different averaging periods, and (3) regional disaggregation vs. ERCOT wide:

Non-coastal Coastal ERCOT-wide Non-coastal Coastal ERCOT-wide1-yr, 2013 13% 79% 21% 20% 50% 23%2-yrs, 2012-2013 11% 66% 18% 19% 51% 23%3-yrs, 2011-2013 11% 66% 18% 19% 50% 23%4-yrs, 2010-2013 10% 56% 15% 19% 48% 22%5-yrs, 2009-2013 11% 56% 16% 18% 45% 21%

Period for AveragingTop Twenty Peak Hours

Daily Peak Hours (HE 1500-1800) for Summer Peak Season (June-Sept.)

8

Yearly ELCC Averaging Comparison

0%

5%

10%

15%

20%

25%

1-yr, 2013 2-yrs, 2012-2013

3-yrs, 2011-2013

4-yrs, 2010-2013

5-yrs, 2009-2013

Non-Coastal ELCC, Comparison

Top Twenty Peak Hours

Daily Peak Hours (HE 1500-1800) for Summer Peak Season (June-Sept.)

0%

20%

40%

60%

80%

100%

1-yr, 2013 2-yrs, 2012-2013

3-yrs, 2011-2013

4-yrs, 2010-2013

5-yrs, 2009-2013

Coastal ELCC, Comparison

Top Twenty Peak Hours

Daily Peak Hours (HE 1500-1800) for Summer Peak Season (June-Sept.)

9

Capacity Forecasts for the 2014 NERC Long Term Reliability Assessment

10

LTRA Resource Categories

• Existing-Certain– “Where energy-only markets exist, unit must be a designated

market resource eligible to bid into the market”

• Planned, Tier 1– “Resource construction is underway or complete (not in

commercial operation)”, or– “Resource has been designated or approved by a market

operator and an Interconnection Service Agreement has been signed”

• Planned, Tier 2– ...“Generation Interconnection has been requested”, and

apply a confidence factor up to 50%

• Planned, Tier 3– “Capacity that does not meet the requirements of Tier 2”, and

apply a confidence factor up to 10%

11

How ERCOT Addresses Each Resource Category

• Existing-Certain– Includes CDR (1) operational resources, (2) hydro capacity

contribution, (3) PUN capacity contribution, (4) available switchable capacity, (5) summer/winter available mothball capacity

– DC tie capacity contribution treated as imports– Unavailable mothball capacity is categorized as “Existing-Other”, and

contributes to NERC’s Prospective Planning Reserve Margin• Planned, Tier 1

– All CDR-eligible new resource capacity• Planned, Tier 2

– Derived and applied (1) annual commercial operation success rates to capacity in the interconnection request queue that is not CDR-eligible, and (2) assumptions concerning timing of those capacity additions through 2024; approach summarized in the next few slides.

• Planned, Tier 3– Derived and applied a 5% annual commercial operation success rate

to ERCOT’s list of “conceptual” projects

12

Project Commercial Operations Success RatesCapacity

Request Year Yrs in Queue Total Capacity Cancelled OperationalOperational Success Rate

2004 9 7,867 4,993 2,672 34.0%2005 8 11,169 2,801 5,365 48.0%2006 7 54,074 47,932 4,456 8.2%2007 6 60,071 51,562 4,019 6.7%2008 5 34,787 32,588 910 2.6%2009 4 19,841 14,732 202 1.0%2010 3 7,335 5,034 137 1.9%2011 2 9,786 6,193 346 3.5%2012 1 18,521 8,228 60 0.3%2013 0 24,831 5,738 50 0.2%

2005-13 784 495 94 12.0%

Weighted Average, based on years in queue (2011-2004) = 19%

• Data pulled from ERCOT’s GINR database on May 14, 2014

Number of Projects

Request Year Yrs in Queue Total Projects Cancelled OperationalOperational Success Rate

2004 9 31 17 13 41.9%2005 8 51 31 20 39.2%2006 7 100 67 25 25.0%2007 6 132 104 24 18.2%2008 5 112 100 9 8.0%2009 4 94 71 4 4.3%2010 3 53 37 2 3.8%2011 2 61 37 4 6.6%2012 1 64 28 2 3.1%2013 0 112 20 1 0.9%

2005-13 784 495 94 12.0%

Weighted Average, based on years in queue (2004-2011) = 24%

13

Operations Success Rates by Interconnection Study Phase

Number of Projects (Requests since 1/1/2007)

Phase# still in Phase

# Cancelled

Cancellation Rate

Retention Rate

Retention Rates, Scaled

to Sum to 100%

Final Retention Rates, Scaled

to 19% Maximum

IA * 46 6 12% 88% 53% 19% <- Set to Total Success RateFIS ** 299 185 38% 62% 37% 13% <- 19% x (37% / 53%)SS *** 42 198 83% 18% 10% 5% <- 19% x (10% / 37%)* IA signed** Full Interconnect Study underway or completed*** Screening Study underway or completed

• Derived annual operations success rates reflecting each project’s status in the interconnection study queue

• Interpretation: – 19% of projects with a signed IA will enter commercial operations in any given

year during the 10-year LTRA assessment period– 13% of projects in the FIS phase will enter commercial operations in any

given year during the 10-year LTRA assessment period– 5% of projects in the SS phase will enter commercial operations in any given

year during the 10-year LTRA assessment period

14

Planned Tier 2 Capacity Derivation• Applied study phase retention rates to applicable project capacity

for years 2015-2018 (no projects have CODs beyond 2018). This new capacity totals 2,681 MW by 2018.

• Assumed that 19% of all non-CDR-eligible capacity in the interconnection request queue was eventually placed in service by 2024; this amount is 4,905 MW.– Deducting capacity additions for years 2015-2018 leaves 2,224 MW to

allocate to years 2019 through 2024; assumed that this amount was distributed equally (371 MW for each year).

• Reasonableness check: LTRA Planned Tier 1 and 2 capacity more than keeps pace with the CDR load increase from 2015 through 2024– Need 9,254 MW by 2024 to keep pace with the CDR forecasted load

increase plus make up for DT Deely plant loss in 2019.– LTRA Planned Tier 1 plus Tier 2 totals 10,555 MW.

15

Planned Tier 2 Capacity Derivation• Table below shows year by year derivation of the Planned Tier 2

confidence factors and resulting capacity amounts

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024SS Capacity = 1,063.7 5,662.3 10,145.3 12,207.3 12,207.3 12,207.3 12,207.3 12,207.3 12,207.3 12,207.3 FIS Capacity = 3,017.1 7,029.1 8,452.1 9,802.1 9,802.1 9,802.1 9,802.1 9,802.1 9,802.1 9,802.1 IA Capacity = 288.4 1,335.4 2,762.4 3,804.4 3,804.4 3,804.4 3,804.4 3,804.4 3,804.4 3,804.4 Total Capacity = 4,369.2 14,026.8 21,359.8 25,813.8 25,813.8 25,813.8 25,813.8 25,813.8 25,813.8 25,813.8

SS Adjusted Capacity (@ 5% adj factor) 57.2 304.8 546.0 657.0 657.0 657.0 657.0 657.0 657.0 657.0 FIS Adjusted Capacity (13% adj factor) 400.3 932.7 1,121.5 1,300.6 1,300.6 1,300.6 1,300.6 1,300.6 1,300.6 1,300.6 IA Adjusted Capacity (19% adj factor) = 54.8 253.7 524.9 722.8 722.8 722.8 722.8 722.8 722.8 722.8 Total Adjusted Capacity = 512.4 1,491.2 2,192.4 2,680.5 2,680.5 2,680.5 2,680.5 2,680.5 2,680.5 2,680.5

Annual Capacity Additions = 512.4 978.8 701.2 488.1 370.7 370.7 370.7 370.7 370.7 370.7Max Capacity Additions, 2015-2024 = 4,904.6 Available Capacity Additions, 2019-2024 2,224.1 Annual Capacity Allocation, 2019-2024 = 370.7

LTRA Confidence Factor = 11.7% 10.6% 10.3% 10.4% 11.8% 13.3% 14.7% 16.1% 17.6% 19.0%LTRA Planned Tier 2 Capacity 512.4 1491.2 2192.4 2680.5 3051.2 3421.9 3792.5 4163.2 4533.9 4904.6

16

LTRA Capacity Summary• The table below is an extract of the LTRA data form showing the resource

capacity section; the data is considered “draft”.• Final data is due June 27, 2014.

CAPACITY Year(s) Unit 2015 (S) 2016 (S) 2017 (S) 2018 (S) 2019 (S) 2020 (S) 2021 (S) 2022 (S) 2023 (S) 2024 (S)Capacity Adjustments 2015-2024 MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Existing-Certain 2015-2024 MW 73606.76 73606.76 73606.76 73606.76 72766.76 72766.76 72766.76 72766.76 72766.76 72766.76Existing-Other 2015-2024 MW 2643.00 2643.00 2643.00 2643.00 3483.00 3483.00 3483.00 3483.00 3483.00 3483.00Planned - Tier 1 2015-2024 MW 2801.17 3723.59 4528.21 5410.21 5650.21 5650.21 5650.21 5650.21 5650.21 5650.21Tier 2 Confidence Factor (0%-50%) 2015-2024 % 11.7% 10.6% 10.3% 10.4% 11.8% 13.3% 14.7% 16.1% 17.6% 19.0%Planned - Tier 2 2015-2024 MW 512.37 1491.15 2192.38 2680.47 3051.16 3421.85 3792.54 4163.23 4533.92 4904.62Tier 3 Confidence Factor (0%-10%) 2015-2024 % 0% 5% 5% 5% 5% 5% 5% 5% 5% 5%Planned - Tier 3 2015-2024 MW 0.00 102.45 181.05 218.55 278.55 278.55 278.55 278.55 278.55 278.55

RESOURCE CATEGORIES Year(s) Unit 2015 (S) 2016 (S) 2017 (S) 2018 (S) 2019 (S) 2020 (S) 2021 (S) 2022 (S) 2023 (S) 2024 (S)Existing-Certain & Net Firm Transfers 2015-2024 MW 73949.76 73949.76 73949.76 73949.76 73109.76 73109.76 73409.76 73409.76 73409.76 73409.76Anticipated 2015-2024 MW 76750.93 77673.35 78477.97 79359.97 78759.97 78759.97 79059.97 79059.97 79059.97 79059.97Prospective 2015-2024 MW 79906.30 81807.50 83313.35 84683.44 85294.13 85664.82 86335.51 86706.20 87076.89 87447.58Adjusted-Potential 2015-2024 MW 79906.30 81909.95 83494.40 84901.99 85572.68 85943.37 86614.06 86984.75 87355.44 87726.13

PLANNING RESERVE MARGINS Year(s) Unit 2015 (S) 2016 (S) 2017 (S) 2018 (S) 2019 (S) 2020 (S) 2021 (S) 2022 (S) 2023 (S) 2024 (S)Existing-Certain & Net Firm Transfers Margin 2015-2024 % 10.14% 8.59% 7.24% 5.81% 3.06% 1.73% 0.85% -0.41% -1.64% -2.84%Anticipated Margin 2015-2024 % 14.31% 14.06% 13.81% 13.55% 11.02% 9.59% 8.61% 7.25% 5.93% 4.64%Prospective Margin 2015-2024 % 19.01% 20.13% 20.82% 21.17% 20.23% 19.20% 18.60% 17.62% 16.67% 15.74%Adjusted-Potential Margin 2015-2024 % 19.01% 20.28% 21.09% 21.48% 20.62% 19.59% 18.99% 18.00% 17.05% 16.11%

NERC REFERENCE MARGIN LEVEL Year(s) Unit 2015 (S) 2016 (S) 2017 (S) 2018 (S) 2019 (S) 2020 (S) 2021 (S) 2022 (S) 2023 (S) 2024 (S)Assessment Area Target Margin (NERC Reference Margin Level) 2015-2024 % 13.75 13.75 13.75 13.75 13.75 13.75 13.75 13.75 13.75 13.75