ERCOT Changes and Challenges

Transcription

1 ERCOT Changes and Challenges Cheryl Mele Senior Vice President & COO September 17, 2018 RMEL Fall Executive Convention

2 What is ERCOT? In 1999 The Texas Legislature restructured the Texas electric market and assigned ERCOT four primary responsibilities: System reliability Competitive wholesale market Open access to transmission Competitive retail market The ERCOT interconnection serves most of Texas, with limited direct current (DC) external connections 90% of Texas electric load; 75% of Texas land More than 46,500 miles of transmission lines 570+ generation units ~1,250 MW of DC ties, 430 MW to CENACE and 820 MW to SPP 2

3 Capacity, Demand and Reserves (CDR) Report The December 2017 CDR reported a 9.3% reserve margin going into Summer The latest CDR, May 2018, was looking at peak demand for Expectations for the next five year period reflect continued demand growth in Texas, with reserves similar to what we expect in Planning reserve margins can shift quickly as the ERCOT energy only market experiences cycles of new investments, retirement of aging resources, and growing demand for power. 3

4 Summer Reserve Margin Changes before May [VALUE] -[VALUE] -[VALUE] Market decisions to increase available generation improved the reserve margin expectation to 11.0%. -[VALUE] -[VALUE] 18.9% -[VALUE] +[VALUE] +[VALUE] +[VALUE] 11.0% 9.3% Summer 2018 Reserve Margin (May CDR 2017) New Load Forecast (Oct. 2017) (1,175 MW) Emergency Response Service (ERS) Update (764 MW) Retirements: Monticello, Sandow, Big Brown, Pearsall (4,334 MW) Delayed Renewable Projects (881 MW Peak Contribution) Delayed Gas Projects (1,193 MW) Extended Outages and Mothballs (1,025 MW) Other Factors (-73 Load Resources, +230 Gen) Summer 2018 Reserve Margin (Dec CDR 2017) Load Forecast Adjustments & Other (-251 MW) Additional Generation Capacity (+1,039 MW) Summer 2018 Reserve Margin (as of 4/20/2018) 4

5 Forward ERCOT Prices Comparison of ICE forward curves March 2018 May

6 Summer 2018 the 5 th hottest on record in Texas* Summer 2018 temperatures surpassed by only 2011, 1934, 1998 and 1980 Dallas experienced 23 days of temperatures at or above 100 F Austin experienced 52 days of temperatures at or above 100 F *Since

7 Peak hour temperatures at major load centers between July 18 th and July 23 rd were at or above 90 th percentile levels New peak demand record set on July 19 th 73,308 MW. Higher percentiles temperatures on Sunday July 22 nd, but weekend loads reduced system-wide demand, set a new weekend record of 71,445 MW. July 23 rd had high percentile values except for Dallas/Fort Worth, that difference was sufficient to not surpass the July 19 th peak demand record. Dallas/Fort Worth Houston Austin San Antonio Load Percentile of Historic Temperatures HE17 HE17 HE17 HE17 HE17 HE17 73,500 73,000 72,500 72,000 71,500 71,000 70,500 70,000 69,500 Load (MW) Wed, Jul 18 Thu, Jul 19 Fri, Jul 20 Sat, Jul 21 Sun, Jul 22 Mon, Jul 23 * Historic data includes summer months from 1950 through

8 2018 peak demand day July 19 th Hourly Average Demand, Capacity, and Reserves on 7/19/2018 A, B, C, D, E and F (MW) 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, A: Outages D: Renewable HSL G: PRC PRC = Hour Ending B: Quick-Start Resources C: Off-Line E: Non-renewable HSL F: Load H: Wind I: Solar 14,000 12,000 10,000 8,000 6,000 4,000 2,000 *Off-line capacity is a summation of capacity from resources that were off-line and those providing non-spinning reserves as an off-line resource. 0 G, H, and I (MW) 8

9 Increased occurrences of high system-wide prices Month 2018 Avg. Hub Avg. Settlement Point Price in Real-Time 2017 Avg. Hub Avg. Settlement Point Price in Real-Time June $32.56/MWh $28.71/MWh July $47.20/MWh $30.83/MWh August $38.17/MWh $28.50/MWh 9

10 Intermittent Renewable Resources produced more MW on average in June, July and August of 2018, relative to 2017 Average wind generation during peak hours in summer 2018 was ~2,100 MW higher than summer Average solar generation during peak hours in summer 2018 was ~400 MW higher than summer ,000 10,500 Summer-18 Wind Summer-17 Wind Summer-18 Solar Summer-17 Solar Avg. ERCOT IRR Generation 9,000 ERCOT Peak Hours 7,500 MW 6,000 4,500 3,000 1, Hour Ending *At the end of summer 2018, ERCOT s wind installed capacity was 21,704 MW and grid-scale solar installed capacity was 1,422 MW. At the end of summer 2017, ERCOT s wind installed capacity was 20,193 MW and grid-scale solar installed capacity was 1,043 MW. 10

11 Summer 2018 Seasonal Assessment of Resource Adequacy vs. Actuals at Peak Demand 2018 Actual Peak Demand Final 2018 Summer SARA Total Resources, MW 77,558 78,184 Thermal and Hydro 65,200 66,457 Private Use Networks, Net to Grid 3,019 3,298 Switchable Generation Resources 3,057 2,727 Wind Capacity Contribution 4,229 4,193 Solar Capacity Contribution 1,136 1,120 Non-Synchronous Ties Peak Demand, MW 73,308 72,756 Reserve Capacity, MW 4,250 5,428 Reserve Margin 5.8% 7.5% Total Outages, MW 2,411 4,349 Extreme Outage Scenario 6,915 Capacity Available for Operating Reserves, MW 1,839 1,079 Source: Final 2018 Summer SARA 11

12 Other than Summer ERCOT Challenges & Opportunities Adapting to the Changing Resource Mix Operate reliably with increasing inverter-based technologies Improve comprehensive real-time stability assessments Visibility of Distributed Energy Resources Establish visibility needed for reliability and pricing consistency Transmission improvements Support load growth and changing grid Digital Engagement Public Utility Commission Projects 12

13 Energy Use Comparison Total energy consumed: 347,617,436 MWh Total energy consumed: 351,523,351 MWh *includes solar, hydro, petroleum coke, biomass, landfill gas, distillate fuel oil, net DC Tie and Block Load Transfer imports/exports, and an adjustment for Wholesale Storage Load 13

14 ERCOT Installed Capacity ( July 2018) 40,000 35,000 Cumulative Installed Generation Capacity by Fuel Wind and solar values are based on nameplate capacity (not adjusted for peak capacity contribution) [SERIES NAME] [VALUE] MW 30,000 25,000 [SERIES NAME] [VALUE] MW MW 20,000 15,000 [SERIES NAME] [VALUE] MW 10,000 [SERIES NAME] [VALUE] MW 5, Coal Gas CC Gas CT/IC Gas Steam Nuclear Other Solar Wind 14

15 Wind Generation Capacity August 2018 Steady growth continues, with some spikes. Largest annual increase: 3,294 MW in 2015 (A close second: 3,220 MW in 2008) Incentives, uncertainty and other factors affect construction decisions and schedules. Not all planned projects will get built. Texas continues to lead U.S. in wind capacity. Future outcomes uncertain 15

16 Utility Scale Solar Generation Capacity August 2018 Future outcomes uncertain 16

17 Integrating and Managing Renewables New Desk: Added Reliability Risk Desk in the Control Room in 2017 Inertia: Tracking system inertia against Critical Inertia levels and monitoring sufficiency of Responsive Reserves in Real-Time & Day-Ahead markets Net Load: Assessing available generation capacity and Non-Spin reserves to serve expected variability in net load Ancillary Services: Review and adjust methodology to procure enough reserves to operate reliably during hours with high risk of net load ramp. 17

18 ERCOT Grid-Scale Solar Resources (as of July 2018) Operational Capacity Cumulative Capacity Year (MW) 2010 and earlier , (through July) 1,487 Planned Capacity* Year and Quarter Cumulative Planned Capacity (MW) 2018 Q Q Q Q4 2, Q4 2,551 * Capacity based on planned units with signed Interconnection Agreements 18

19 ERCOT Goals for Managing Distributed Energy Resources (DERs) on the Grid Improve reporting Map larger DERs to the transmission grid Requires cooperation among TSPs, DSPs, REs and the ISO Will improve situational awareness Nodal pricing for larger DERs Registered Distributed Generation (>1 MW) currently paid Load Zone price Local price signals would enhance reliability and align DER behavior with overall market design 19

20 Based on information currently available, estimated some level of DER response to price With inputs from Market Participants, ERCOT is currently tracking ~100 DERs located at 93 unique transmission-level loads. ERCOT does not receive telemetry from these DERs. DER response estimated based on changes in transmission-level load consumption. MW Estimated Distributed Energy Resource Response for July 19 th, $/MWh Likely includes some demand reduction (4CP) response during this Operating Day Estimated Load w/o DER Deployed Load w/ DER Deployed System Lambda Aggregation of ~100 DERs located behind 93 unique transmission-level loads 20

21 Far West Texas: Growing Load Expectations Permian Basin Rig Count Culberson Loop Load Forecast Year/ Vintage 2021 as Studied in 2017 Latest 2019 Forecast Committed Load 553 MW 880 MW Latest 2022 Forecast 1013 MW +/- indicates change between April 2017 and April

22 Transmission Planning Summary Endorsed transmission projects totaling $393.5 million in 2018 ($890 million in 2017). As of June 30, tracking 379 active generation interconnection requests totaling 77,020 MW (includes 34,376 MW of wind) Projects in engineering, routing, licensing and construction total about $6.5 billion. Projects energized in 2018 total about $1.12 billion. Brazos Valley Connection image courtesy of CenterPoint Energy 22

23 Maintaining ERCOT s Jurisdictional Status ERCOT is connected to primary Mexican grid via 3 DC Ties Proposed interconnection projects involving Mexico Nogales interconnection in Arizona Baja interconnection in Baja California Recent FERC Order ensures ERCOT maintains jurisdictional status quo after new projects constructed 23

24 Digital Engagement Strategy: Better Ways to Share Information Consistent, simple user experience for entry and retrieval of information Improved authentication and access management for data and applications Reduced time and cost to make changes to ERCOT systems 24

25 Active Public Utility Commission Projects Market design Real Time Co-optimization Marginal losses Summer lookback and scarcity pricing effectiveness Grid Technology issues Storage ownership and other emerging assets Substations and endpoints Economically optimal reserve margin study 25