1. EE379K/EE394V Smart Grids: The Retail Perspective
Paul Wattles
Senior Analyst,
Market Design & Development
ERCOT
Ross Baldick, Department of Electrical and Computer Engineering
Spring 2017

2. Outline ERCOT Overview Advanced Metering
15-Minute Data & 15-Minute Settlement
Retail Smart Grid Product Offerings
Impacts on:
ISO Grid Operations
Wholesale Market Prices
Load Forecasting
Consumers

3. The ERCOT Region
The interconnected electrical system serving most of Texas, with limited external connections
90% of Texas electric load; 75% of Texas land
71,093 MW peak, August 11, 2016
More than 46,500 miles of transmission lines
550+ generation units
220 MW with SPP
600 MW with SPP
ERCOT connections to other grids are limited to ~1250 MW of direct current (DC) ties, which allow control over flow of electricity
30 MW with CFE
at Eagle Pass
100 MW with CFE
at Laredo
300 MW with CFE at Mc Allen

4. U.S./Canada ISOs and RTOs
Independent System Operators and Regional Transmission Organizations are the ‘air traffic controllers’ of the bulk electric power grids

5. ERCOT Inc.
The Texas Legislature restructured the Texas electric market in and assigned ERCOT four primary responsibilities:
Maintain system reliability
Facilitate competitive wholesale market
Ensure open access to transmission
Facilitate competitive retail market
ERCOT is regulated by the Texas Public Utility Commission (PUC) with oversight by the Texas Legislature
Because the ERCOT grid is intrastate, the ERCOT markets are not jurisdictional to the Federal government (i.e., FERC)
Unique among ISOs/RTOs
ERCOT is not a market participant and does not own generation or transmission/distribution wires

6. Texas Competitive Model
Applies to formerly vertically-integrated investor-owned utilities
(Municipally-owned Utilities and Electric Cooperatives also own generation and T&D)
• Generators are owned by privately owned (merchant) companies, who compete in the ERCOT market to sell to Load Serving Entities
• T&D facilities are owned and operated by Transmission & Distribution Service Providers (TDSPs), which are regulated by the PUC
• Load is served by Retail Electric Providers, who compete to sell power to end-use customers
Parent companies may own both generation and retail

7. Share of total ERCOT Load
2 models within ERCOT
Municipals & Cooperatives
Competitive Choice
AKA Non-Opt in Entities (NOIEs) are still vertically integrated
Many have existing and developing smart grid initiatives:
-- AMI
-- Smart thermostats
-- Demand response
Possible triggers: Demand charge avoidance, real-time prices, congestion management
‘Utility’ a mostly obsolete term
Dozens of REPs competing for residential and commercial accounts
Terms typically range from 3-24 months
Some pre-paid, renewable options
>99% advanced metering
26%
74%
Share of total ERCOT Load
The two worlds have very different smart grid incentives (more on this later)

8. Competitive areas & NOIEs
Competitive Retail Area
Municipally Owned Utilities and Electric Co-Ops (NOIEs)
26%
74%
Source: Texas Solar Power Association
Share of total Load

9. Nodal Energy Market
ERCOT clears the real-time energy market every five minutes, dispatching generation with the lowest offers to serve the load, subject to transmission constraints
Locational marginal prices (LMPs) are produced every 5 minutes at >11,000 nodes, including >550 Generation Resource Nodes
If there is no congestion on the system, all LMPs will be equal (set by the marginal unit)
Generators are paid the LMP at their specific Resource Node
Loads are billed the weighted-average price at the Load Zone

10. Annual Energy and Peak Demand

11. Nameplate capacity by unit type, 1999 thru 2016
Evolving Resource Mix
Nameplate capacity by unit type, 1999 thru 2016
(Does not account for retirements)

12. Current Records June: 64,896 MW (June 15) July: 67,469 MW (July 14)
Peak Demand Record: 71,110 megawatts (MW)
Aug. 11, 2016, 4-5 p.m.
Weekend Record: 66,921 MW
Sunday, Aug. 7, 2016, 5-6 p.m.
Winter Peak Record: 57,265 MW
59,650 MW, Jan. 6, 2017
Wind Generation Records (instantaneous)
15,033 MW, Nov. 27, 2016, 12:36 p.m.
Non-Coastal Wind Output = 11,100 MW
Coastal Wind Output = 3,800 MW
Supplying 45% of the load
Active Wind Capacity = 17,150 MW
48.28% Wind Penetration, March 23, 2016, 1:10 a.m.
Total Wind Output = 13,154 MW
Total Load = 27,245 MW
Summer 2016 Monthly Peaks
June: 64,896 MW (June 15)
June Record: 66,548 MW – 6/26/12
July: 67,469 MW (July 14)
July Record: 67,650 MW – 7/30/15
August: 71,110 MW (Aug. 11)
August Record: 71,110 MW – 8/11/16
September: 66,853 MW (Sept. 19)
Sept. Record: 66,853 MW – 9/19/16

13. Weather Impacts on Load by Customer Type
Thursday, Aug. 11, 2016
5:00 PM
ERCOT Load: 71,093 MW
Temperature in Dallas: 106°
Thursday, March 24, 2016
5:00 PM
ERCOT Load: 33,597 MW
Temperature in Dallas: 62°
>37,000 MW of weather-sensitive load -- 53% of peak
Customer class breakdown is for competitive choice areas; percentages are extrapolated for municipals and co-ops to achieve region-wide estimate
Large C&I are IDR Meter Required (>700kW)
Hourly integrated demand values

14. Fuel Mix on Those Same Days
Power Dispatch Summary by Fuel Type
March 24, 2016
August 11, 2016
Max Gen: 71,636 MW at 03:55:19 PM
Max Gen: 34,593 MW at 07:20:21 AM
Wind (MW)
Wind (MW)

15. Wholesale Market Price Caps
Escalating offer caps in the energy-only market
2002: $1,000
2007 $1,500
2008 $2,250
2011: $3,000
2012: $4,500
2013: $5,000
2014: $7,000
2015: $9,000
Applies to offers for energy (MWh) and Ancillary Services (MW per hr)
The energy market has never cleared at the $9,000/MWh cap $0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
ERCOT System-Wide Offer Caps

16. Peaker Net Margin (PNM)
The PNM is a calculation designed to measure the annual net revenue of a hypothetical peaking unit
If the PNM for a year reaches a cumulative total of $315,000 per MW, the system-wide offer cap is then reduced to the higher of $2,000 per MWh or 50 times the daily natural gas price index
This threshold (defined in PUC Subst. Rule §25.505) has never been met
2016 PNM = $29,991
Source: Potomac Economics (ERCOT Independent Market Monitor) 2015 State of the Market Report

17. HUB Avg 15-min. Settlement Point Prices 2015 and 2016
Real-Time Energy Prices
Intervals
2015
2016
<$0
238
569
$0-$30
31,287
31,562
>$30-$75
3,110
2,605
>$75
405
400
HUB Avg 15-min. Settlement Point Prices 2015 and 2016

18. Tale of two peaks Summer peak days: Aug. 10, 2015 Aug. 11, 2016
ERCOT Load was >1,700 MW higher on the peak day in 2016

19. Tale of two peaks Summer peak days: Aug. 10, 2015 Aug. 11, 2016
Day-Ahead Market energy prices

20. Tale of two peaks Summer peak days: Aug. 10, 2015 Aug. 11, 2016
Real-Time Market energy prices

21. Tale of two peaks Summer peak days: Aug. 10, 2015 Aug. 11, 2016
WIND OUTPUT: 2016 peak day was >2,700 MW higher than 2015 peak day

22. In this example, wind reduced price volatility
Tale of two peaks
Summer peak days:
Aug. 10, 2015
Aug. 11, 2016
NET LOAD:
Actual system Load minus wind was >1,000 MW lower in 2016 than 2015
In this example, wind reduced price volatility

23. Wholesale market prices
Prices can spike for reasons other than scarcity of generation
Unit trips, ramp rate limitations, inaccurate forecasting of weather or Load
LSEs hedge their risk against price spikes through forward contracts and/or Day-Ahead Market procurement
Another tool is the ability to reduce Load in real time (demand response)
If the LSE is short, DR can reduce exposure to the high price
If the LSE is long, DR allows it to ‘sell the power back at the real-time price’

24. Advanced Metering origins
House Bill 2129 (2005 Legislature) amended Sec of the Utilities Code:
(h)  The commission shall establish a nonbypassable surcharge for an electric utility or transmission and distribution utility to use to recover reasonable and necessary costs incurred in deploying advanced metering and meter information networks to residential customers and nonresidential customers other than those required by the independent system operator to have an interval data recorder meter.
Surcharge = accelerated cost recovery

25. Advanced Metering origins
PUC Substantive Rule § Advanced Metering (2007)
Purposes of the rule:
to implement the Legislation by authorizing the surcharge;
increase the reliability of the regional electrical network;
encourage dynamic pricing and demand response;
improve the deployment and operation of generation, transmission and distribution assets, and
provide more choices for electric customers

26. Advanced Metering origins
Key elements of the Rule:
Applies to investor-owned TDSPs only (NOIEs not affected)
Implementation optional for TDSPs, but deployments eligible for accelerated cost recovery via special surcharge
AMI meters must measure consumption in 15-minute intervals
Interval data shall be used in wholesale market settlement at the ESI ID level

27. Energy data points per month
15-minute metering
Pre-AMI
AMI
Energy data points per month 1
2,880
Applies to residential premises without on-site distributed generation.

28. Advanced Metering benefits
>7 million advanced meters now active in the competitive choice areas of ERCOT
>99% of ERCOT Load is now settled on 15-minute interval data (includes AMI, competitive IDR, and NOIE IDR)
TDSP benefits:
Reduced meter-reading costs
Advanced outage detection
Faster switching and move-ins/move-outs

29. Advanced Metering benefits
Retail Electric Provider (REP) benefits:
Settlement accuracy (no more load profiles; see next slide)
Real money if customers reduce load during high-priced periods
ISO benefits:
Settlement timeliness & accuracy
Customer benefits:
Access to granular energy usage data
A wider selection of REP products to choose from

30. Why settlement is important
In settlement, LSE purchases are reconciled with generators’ sales
Prior to the AMI implementation, REP obligations for residential and small commercial customers were based on Load Profiles
Profiles are estimates of average individual usage, based on statistical samples of data from ‘like’ customers
A Profile for each customer type was created for each Operating Day, using weather & other inputs
Interval-level values were then assigned to each customer according to their Profile type, scaled based on monthly kWh usage

31. Profile example
A profile assumes customers of this type on average have the profiled Load shape
The load magnitude is adjusted (scaled) based on the customer’s monthly kWh consumption
Prior to AMI, REP Load was settled based on this estimate
Residential High Winter Ratio Profile Type for North Central Weather Zone, Aug. 11, 2016

32. Why settlement is important
Settlement based on Load Profiles would be accurate at the REP aggregate load level only if its customers were not deviating significantly from the profiled shapes
The REP would have to accept the settlement outcome even if its customers were making significant changes to their load shapes
In other words…
Profiles are oblivious to intelligent load management
Profiles are hard barriers to price elasticity of demand
Profiles kill demand response

33. Why settlement is important
Settlement on actual 15-minute data cures this problem
When customers are settled on their actual usage, the benefits of any action taken to reduce Load during a period of high wholesale prices will accrue directly to the LSE
This gives the LSE (in this case, the REP) an incentive proportional to real time prices to promote intelligent load management and demand response for its customers

34. New product options

35. Retail price/demand response
If retail DR and price response penetration are a key metric in measuring the success of the ERCOT retail market and the AMI investment, how are we doing?
PUC Subst. Rule §25.505(e)(5): Load serving entities (LSEs) shall provide ERCOT with complete information on load response capabilities that are self-arranged or pursuant to bilateral agreements between LSEs and their customers.
Leveraging this Rule language, ERCOT has worked with REPs since to collect data on various product offerings, including:
Time of Use
Peak Rebates
Real-Time Pricing
Block & Index Pricing
Other Load Control Products

36. Total residential ESI IDs ~6.17 million
Residential Time of Use
Time of Use prices vary across different blocks of hours, with pre-defined prices and schedules; examples: Free Nights, Free Weekends
ESI IDs
289,848
321,504
331,138
Total residential ESI IDs ~6.17 million
ESI ID = Electric Service Identifier: “The basic identifier assigned to each Service Delivery Point used in the registration and settlement systems managed by ERCOT ...” (In vast majority of cases, equates to a meter.)

37. Total non-residential ESI IDs ~946,000
C&I Indexed Pricing
‘Indexed pricing’ includes:
Real-Time Pricing (tied to 15-minute wholesale market prices), and
Block & Index (fixed pricing for a defined volume of usage coupled with indexed pricing for usage exceeding the block)
This slide does not include 1,326 residential ESI IDs on RTP in 2016
ESI IDs
16,493
14,146
22,850
Large drop-off in 2014 likely due to reporting inconsistency
Total non-residential ESI IDs ~946,000

38. Total residential ESI IDs ~6.17 million
Residential Peak-Time Rebate
Customers on Peak Rebate plans are eligible for financial incentives for load reductions taken during periods defined by the REP and communicated to the customer in advance
ESI IDs
409,434
465,527
478,243
Total residential ESI IDs ~6.17 million

39. Total non-residential ESI IDs ~946,000
C&I Peak-Time Rebate
ESI IDs
Total non-residential ESI IDs ~946,000
30,185
32,289
35,369

40. Effects on system Load
Since 2011, the ERCOT real-time market has had very few sustained high-price events
Price spikes tend to be short-term (1-2 SCED intervals), often related to ramp rate constraints
ERCOT has analyzed data from the events we have
ERCOT has also analyzed self-initiated events as reported by REPs, although this data is also sub-optimal
In many cases, REPs deployed only a fraction of total customers in the program

41. Examples of real-time price response
Combined Electric Service Identifiers (ESI IDs) reported on Real-Time Pricing and Block & Index offerings
Analyzed days with 4 or more consecutive intervals of prices >$200
Note MW scales are different
March 3, 2014
10,046 ESI IDs
Maximum reduction: 119 MW
Maximum price: $4,991/MWh
August 13, 2016
13,503 ESI IDs
Maximum reduction: 129 MW
Maximum price: $1,089/MWh

42. Demand charges (4CP)
The Four Coincident Peaks (4CP) in ERCOT are the peak system-wide 15-minute settlement intervals in each of the four summer months
June, July, August, September
Simple average of energy usage across these four intervals is the basis of various T&D charges for much of the ERCOT Load
NOIEs, at the boundary meter level
Retail Choice customers with peak demand ≥700 kW (Interval Data Recorder meter required)
Retail choice load
“Large C&I” = IDR Required
Combined, >44% of ERCOT Load is subject to 4CP charges

43. 4CP charges as a DR incentive
4CP was not designed as an incentive for demand response, but…
Reducing Load during these intervals yields considerable savings
NOIEs can reduce their 4CP Load Ratio Share, lowering their share of Transmission Cost of Service obligation
Retail Choice Loads can directly reduce charges on their bills for the following year
Many Loads and NOIEs have acquired 4CP predictors or developed 4CP prediction capability in-house
Predictor services are available by subscription from LSEs and third parties
Entities then plan demand response around potential 4CP intervals

44. 4CP Tariffs: Hypothetical case study
Let’s assume an industrial customer:
Has 10 MW of Load and is capable of interrupting all of it
Is connected at transmission voltage
Is in Oncor service territory, where the Summer 2016 Transmission Cost Recovery Factor tariff for such Loads was $ per 4CP kW
Correctly anticipated and reduced Load to zero for all four 4CP intervals in 2016
Our customer’s transmission charge line item would be $0.00 per month for each month of 2017
If he had been consuming his usual 10 MW during those 4 intervals, his charge would be:
$3.485 x 1000 (kW to MW) x 10 (MW) = $34,850 per month
x 12 (months) =$418,200 in savings for the year

45. NOIE 4CP example
These are 4 of 15 Energy Rush Hour events from summer of 2016
June (1)
July (5)
August (4)
Sept. (5)
(screenshot from my cell phone)
Source: Nest.com

46. 4CP incentives are accelerating
Source: PUCT Dockets
Currently $52.91
Postage Stamp Transmission Rates
($ per 4CP kW)
Postage Stamp rate for Transmission Cost of Service has more than tripled since 2002
>$7B in Competitive Renewable Energy Zone (CREZ) transmission investment
$4.9B of CREZ activated in 2013 alone
>$2B in projects activated in 2016
The postage stamp rate (per 4CP kW) is assessed on DSPs by multiplying the rate by their average Load across the 4CP intervals. DSPs then reimburse TSPs for their transmission investments.
ERCOT’s analyses of numerous 4CP and near-CP days indicate:
MW of industrial load 4CP response
MW of NOIE 4CP response
Level of response varies depending on how obvious the 4CP day is

47. Transmission additions over time
Looking back….
And looking ahead….
Source: ERCOT Report on Existing & Potential Constraints and Needs, 2016
Source: ERCOT Transmission Project & Information Tracking report, Feb. 2017

48. Impacts on resource adequacy
How does economic DR (price and 4CP response) affect the load forecast?
From the June 2012 Brattle Group report to the PUC on Resource Adequacy:
‘Price-based load reductions were likely a major contributor to the 1,700 MW ERCOT load forecasting error in 2011 when prices reached $3,000/MWh. The error may also be attributable in part to 4CP response, voluntary public response to conservation appeals, and load forecast model error.’
This was based on a rerun of the long-term load forecast using actual 2011 weather
In general, price and 4CP response behavior is continually being baked into ERCOT’s load forecasts
2011 was a outlier year, to say the least
ERCOT has revised its long-term load forecast methodology
Load growth has mostly decoupled from economic growth
Previous econometric model replaced by neural networks
New methodology better incorporates demand-side behavior

49. Load forecast impacts A couple examples of the changing landscape THEN
NOW
55” Plasma (circa 2000)
690 Watts
Annual cost to operate:
$148.63
55” LED
37 Watts
Annual cost to operate:
$7.97
Costs to operate based on current Energy Star standards
Incandescent
100 Watts
LED
100 Watt equivalent
15 Watts

50. Questions?
‘Relativity’
M.C. Escher, 1953

51. Summary
The ERCOT region consists of two types of ‘utilities’ with different business models and incentives:
Competitive choice areas (unbundled)
Non-Opt In Entities (muni’s and coops)
Peak demand in ERCOT is driven heavily by residential air conditioning Load
Energy prices are low, impacted by low-cost natural gas and zero fuel-cost wind generation
Near 100% AMI deployment in competitive choice areas
Interval metering combined with settlement on actual data is enabling growth in dynamic pricing and DR-related retail product offerings
Largest financial incentive for DR is demand-charge avoidance (4CP)

52. Homework Exercises: Due Month/Day
A Retail Electric Provider with 8 MW of demand response capability in the North Load Zone purchases power in the Day Ahead Market for $40/MWh across the hours of 4-6 PM (Hours ending 1700 and 1800)
The next operating day, North Load Zone real-time prices at 4:15 PM rise from $40 to $2,300/MWh for three five-minute SCED runs (SCED intervals ending at 4:20, 4:25 and 4:30) -- a full 15-minute settlement interval
The REP accurately predicts the price spike and successfully deploys its 8 MW of DR across the full settlement interval
What is the REP’s financial outcome (net of the Day-Ahead purchases) for the 15-minute interval ending at 4:30 p.m.?

53. Homework Exercises: Due Month/Day
A residential customer in a retail choice area switches REPs and signs up for a ‘Free Weekends’ time-of-use (TOU) price offering
The new plan charges $.15/kWh (includes all T&D charges) for weekday hours -- 6 AM Monday thru 10 PM Friday
The new plan charges $.00 for weekend hours (including $.00 for T&D)
His previous plan charged a flat $.09/kWh for all energy and T&D
When on the previous plan, in November 2016 he used 800kWh during the weekday hours, and 200 kWh during weekend hours
Assuming the customer had been on the TOU plan in November 2016, how much energy usage would he have needed to shift to the weekend hours in order to break even financially?