1 UFE Workshop Co-sponsored by RMS/COPS September 14, 2004.

1

UFE Workshop

Co-sponsored by

RMS/COPS

September 14, 2004

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Agenda• Antitrust Admonition. (Ernie Podraza)

• Agenda Review (Ernie Podraza)

• A Primer on UFE

• History of UFE Discussions in the ERCOT Market (Calculation, Allocation, and Analysis)

• What do Protocols say about UFE? (ERCOT Staff)

•Protocol Section 11 Calculation, Allocation and Analysis

•Protocol 13.4.2 Deemed Actual Transmission Losses for UFE Analysis

•Protocol 18.2.8.2 Models (… coordinate with … UFE analysis function…)

• 2002 UFE Analysis Report Review. (ERCOT Staff)

• Open brainstorming session. (Ernie Podraza)

• Confirm next meeting and review assignments of action items before adjourning.

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A Primer on UFE

4

• Unaccounted-For-Energy is the difference between the total generation supplied to a specific physical region and the total load plus losses in that same physical region during each settlement interval

• UFE may be positive or negative in any single settlement interval

Generation + Gen. Metered Inflows- Gen. Metered Outflows Total Generation

End-Use Load + Distribution Losses + Transmission Losses Total Load

UFE ( )

Negative UFE generally indicates load/loss overestimated

What is UFE?

( )

5

Interval DataMetered Accounts

Profiled Energy UsageNon-Interval Data

Non-Metered Accounts

Distribution Line Losses

ERCOT Wide (Postage Stamp)

Transmission Line Losses

UFE

Net Load (Generation) for

Settlement Interval

(Includes Actual Losses in

the UFE Zone)

GAP - - - - - - >

CALCULATION OF UFE

Net Generation

compared to

Retail LoadBuild-up

6

Assignment of following to correct zones: a. All Loadsb. All Generationc. Zonal Metered Inflows & Outflows

Any metering used to calculate UFE by zones will: • meet the same requirements for settlement as

generation metering (EPS Metering Protocols)

• be polled remotely by the ISO

• be capable of allowing the ISO to adjust time remotely

• collect interval data internally the meter

Requirements for UFE Zones

7

DISTRIBUTION UTILITY• Inaccuracy of method used to calculate distribution losses.

• Unrecorded services.

METERING AGENT • Incorrect meter data.

• Inaccuracy in calculation of un-metered service consumption.

• Meter reading errors.

• Errors in estimation of meter readings.

ERCOT SYSTEMS• Inaccuracy of load profiles on a settlement interval basis.

• Incorrect aggregation of retail load or zonal generation.

• Inaccuracy in method used to calculate transmission losses.

• Incorrect assignment of customer to profile type.

•Incorrect assignment of customers to UFE zone.

•Theft

Contributors to UFE

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UFE’s Effect on Settlements

9

History of UFE Zone Discussions

10

• Discussion began in Settlement Technical group in October 1999 and continued into March 2000 with a “UFE sub-team” formed in late December 1999.

• February 3rd and 10th, 2000 Settlement Technical Meetings focused on narrowing zone options and refining allocation data. Also started analysis of old control zone metering points to determine option feasibility for market open.

• February 24, 2000 Settlement Technical Meeting - Group developed alternative hybrid recommendation for individuals to present to their respective companies for future decision making.

• March 03, 2000 - Settlement Technical group detailed two options to be forwarded to the Retail Users Group for voting.

History of UFE Decisions

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1. What is the appropriate area for UFE administration?

• One zone versus many zones

• Value of multiple zones

• Market readiness concerns

2. What is the appropriate methodology for allocation of UFE

among REPs in a zone?

Original UFE Decision Points

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Pri

ncip

le:

Pri

ncip

le:

To the extent that energy consumption in an area can be measured, that energy should be paid for by the load serving entities in that area.

Eva

luat

ion

Obj

ecti

ves:

Eva

luat

ion

Obj

ecti

ves: • Facilitate market opening on time

• Seek cost effective solutions

• Facilitate the ISO’s investigation and correction of abnormal UFE

• Allow for audit to support and minimize dispute resolution

• Appropriate assignment of UFE cost causation under the new market structure

UFE Zone Principles and Evaluation Objectives

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Opt

ion

A:

Opt

ion

A:

Create zones based upon metering at distribution substations.

Opt

ion

B:

Opt

ion

B:

Use existing interchange metering to define zones that closely match existing control boundaries or where appropriate metering exists. (e.g. muni, coop, distribution utility area)

Opt

ion

C:

Opt

ion

C: Use existing interchange metering, where available, to create four

contiguous zones. Metering will be required to be installed in locations where it currently does not exist to accomplish zone closure.

Opt

ion

D:

Opt

ion

D:

ERCOT wide calculation and allocation of UFE with use of zonal UFE investigation (which may or may not include revenue quality metering) and analysis for UFE correction.

Options Defined

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Opt

ion

A:

Opt

ion

A:

Create zones based upon metering at distribution substations.

ProsPros ConsCons• Facilitates ISO investigation of UFE to the greatest extent of any option.

• Allows for Isolation of UFE to the most granular extent, thus facilitating dispute resolution and maximizing cost causation allocation.

• Potentially mitigates UFE associated to inaccuracy in transmission loss calculation.

• Difficult if not impossible to have meters installed by market open.

• Cost prohibitive due to current lack of metering at substations.

COMMENTS:

Requires estimated $270 million metering investment by market at distribution substation transformers.

• 4500 substations

• 2 transformers per station

• Approximately $30,000 per meter installation.

OPTION ELIMINATEDAS COST PROHIBITIVE& ADMINISTRATIVELY

DIFFICULT AT 02-10-00 MEETING

Option A

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Opt

ion

B:

Opt

ion

B:

Use existing interchange metering to define zones that closely match existing control boundaries or where appropriate metering exists. (e.g. muni, coop, distribution utility area)

ProsPros ConsCons• Facilitates market opening by using existing metering infrastructure.

• Low cost solution anticipating minor metering modifications.

• Allows for investigation and correction of UFE by providing moderate granularity.

• Allows for considerable audit-ability.

• Localizes cost causation to the existing utility service area.

• Potentially administratively troublesome as this option could create as many UFE zones as the number of distribution utility service areas.

• Market readiness concerns due to number of participants involved.

COMMENTS:

• This option is basically the “Utility Zone as the UFE zone” option.

• Requires investment in metering for upgrades to meet new “zone” requirements.

OPTION RE-DEFINED AT

02-24-00 MEETING SEE PAGE 19

Option B

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Opt

ion

C:

Opt

ion

C: Use existing interchange metering, where available, to create four

contiguous zones. Metering will be required to be installed in locations where it currently does not exist to accomplish zone closure.

ProsPros ConsCons• Facilitates market opening on time.

• Minimizes cost due to limited number of zones.

• Minimal audit capability due to combining utility service areas.

• The smaller number of zonal boundaries does not facilitate cost causation issues.

• Ignores the ability to use existing metering to better allocate cost to a specific area.

• Minimal granularity for investigation and correction of UFE.

COMMENTS:

• New metering locations not defined.

OPTION ELIMINATEDAT 02-10-00 MEETING

Option C

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Opt

ion

D:

Opt

ion

D:

ERCOT wide calculation and allocation of UFE with use of zonal UFE investigation (which may or may not include revenue quality metering) and analysis for UFE correction.

ProsPros ConsCons• Facilitates market opening on time by utilizing existing metering infrastructure.

• Allows for investigation and correction of abnormal UFE.

• Ignores the ability to use existing metering to better allocate cost to a specific area.

• May caused additional disputes where analysis area UFE is less than ERCOT wide UFE.

• A single UFE area does not allow for cost causation mitigation at all.

COMMENTS:

• Not acceptable to some participants due to perceived inadequacy for capturing and allocating UFE by a specific area.

OPTION DETAILED AT 03-02-00 MEETING

SEE PAGE 20

Option D

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Existing ERCOT control area interchange metering points shall be used to define mandatory zones for UFE calculation.

• Installation of appropriate metering, as specified by ERCOT, for mandatory UFE zones shall be in place by the ISO system test deadline.

• ERCOT may extend this deadline for mandatory UFE zones if just cause is demonstrated. However, areas with control area metering in place will be treated as zones for the pilot program and market open. These zones will be utilized for UFE settlement purposes.

Additionally, where appropriate metering exists or is installed, UFE zones of greater granularity may be created.

• Minimum level of UFE Zone definition is limited to muni, coop or distribution service area.

Zonal UFE Option

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Open the competitive electric market in ERCOT with an ERCOT wide UFE calculation and allocation (allocation methodology defined separately) and move to a different mechanism, possibly multiple UFE areas, if deemed necessary by the ERCOT ISO.

DETAILS:From the start of the Retail pilot (6/1/01) until June 1, 2003, UFE will be calculated on an ERCOT wide basis to be used for settlements.

Allocation of UFE will be ERCOT wide to REPs based on load ratio share as defined in the UFE Allocation Method.

Additionally, the ISO will perform investigation and analysis of UFE and this information will be used for UFE improvement. UFE areas will be defined and developed that facilitate the investigation of UFE improvement. To keep cost to a minimum, existing metering and SCADA data will be utilized to define “zones”. This includes revenue quality and relay quality metering and instrumentation. ISO will monitor UFE and formulate plans for improving the method for calculation and/or allocation of UFE.

The Settlement System developed for market operations should maintain the flexibility to manage UFE at a more granular level as it becomes necessary in the market.

By April 2003, the ISO will provide a report and make recommendations on UFE Calculation Process Improvement and changes; including moving to a zonal allocation methodology.

ERCOT Wide UFE Option

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ZonalZonal ERCOT WideERCOT Wide• Zonal UFE calculation is not imperative for market open.

• Facilitates market opening. - No additional metering required. - Least cost impact to market as a whole. - Easily understood and implemented.

• Use of zones does not reduce UFE.

• Defined zonal boundaries do not capture all UFE contributing factors within a zone therefore cost causation remains unknown.

• UFE in the future market is an unknown quantity therefore zones attempt to solve a problem without knowing the extent of the problem.

• Cost/benefit analysis has not proved zonal necessity.

• Difficult to have all zone meters installed by customer choice pilot.

• Utilizes existing metering infrastructure to its fullest extent for analysis of UFE.

• Allows for future decision making regarding zones based upon factual and historic data.

Some of the reasoning behind the Decision for an ERCOT Wide UFE Zone

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History of UFE Allocation Discussions

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Utility survey performed to determine estimate of percentage of UFE by each contributing factor.

• Nine companies responded to reformatted survey

• Categorized contributing factors to customer type

• Final allocation algorithms were developed based upon the survey results

UFE Allocation Discussion History

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Pri

ncip

le:

Pri

ncip

le:

Allocation methodology must recognize that high voltage customers and interval data recorders contribute less to UFE on an interval by interval basis.

UFE Allocation Principle

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FactorNumber Description

ResponseAverage Min Max

Associated with Methodology: 1 Inaccuracy of load profiles on a settlement interval basis 54.78 27.0 732 Inaccuracy of method used to model transmission losses 6.67 1.0 273 Inaccuracy of method used to model distribution losses 8.78 2.0 27

Incorrect aggregation of metered load data :4 Customers assigned to wrong UFE area 2.35 0.0 105 Double counting of meters 1.26 0.0 56 Bad load meter data (e.g. multipliers, C.T.s, etc) 4.67 0.1 107 Theft 3.07 0.1 7

Incorrect aggregation of generation metered data:8 Incorrect netting of generation in a zone 1.00 0.0 29 Double counting of meters 0.33 0.0 110 Estimated meter readings 2.22 0.0 9

11Bad generation meter data (e.g. multipliers, C.T.s, etc) 1.56 0.0 3

Inaccuracy in estimating loads:12 Inaccurate estimation of meter readings 6.33 2.0 1013 Inaccurate calculation of un-metered service consumption. 4.39 2.0 7

14Inaccurate or missing estimate of unrecorded services (services that are being provided before meter installation) 2.44 0.0 5

Total Percent: 99.9

February 08, 2000 Survey 2 Results

Factors that Contribute Toward UFE(Percent of Cost Contribution per Settlement Period)

Utility Survey of UFE Contributing Factors

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02/08/2000Attributed to

AllCustomers

Attributed to All

Distribution

Attributed to Distribution

Profiled

Total

Total 26.4 18.7 54.8 99.9

Factor # Contributing Factor: % from

New

Associated with Methodology: Survey

1 Inaccuracy of load profiles on a settlement interval basis - - 54.78 54.78

2 Inaccuracy of method used to model transmission losses 6.67 - - 6.67

3 Inaccuracy of method used to model distribution losses - 8.78 - 8.78

Incorrect aggregation of metered load data :4 Customers assigned to wrong UFE area 2.35 - - 2.35

5 Double counting of meters 1.26 - - 1.26

6 Bad load meter data (e.g. multipliers, C.T.s, etc) 4.67 - - 4.67

7 Theft - 3.07 - 3.07

Incorrect aggregation of generation metered data:8 Incorrect netting of generation in a zone 1.00 - - 1.00

9 Double counting of meters 0.33 - - 0.33

10 Estimated meter readings 2.22 - - 2.22

11 Bad generation meter data (e.g. multipliers, C.T.s, etc) 1.56 - - 1.56

Inaccuracy in estimating loads:12 Inaccurate estimation of meter readings 6.33 - - 6.33

13 Inaccurate calculation of un-metered service consumption. - 4.39 - 4.39

14Inaccurate or missing estimate of unrecorded services (services that are being provided before meter installation)

- 2.44 - 2.44

Totals 26.4 18.7 54.8 99.9

Allocation of UFE by Customer Hiearchy

UFE Allocation Factors by Delivery Point Type

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• Decision was made to accept the Allocation mechanism defined by a representative of Austin Energy as the output of the algorithm most closely matched the results of the UFE Allocation survey data

• Results were incorporated into Protocols

UFE Allocation Discussion History

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History of UFE Analysis Group

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• UFE Analysis Team was established in December 2000, once in January and one more time in February of 2001 (See Protocols Section 11.5.1)

• Analysis Team’s Pressing Objective11.5.2 …. Sub-divide ERCOT into a practical granularity of “UFE Analysis Zones,” but no more than ten (10) zones, which can provide reliable and accurate data to be used for Cost/Benefit Analysis and decision making purposes. …..

• Decision was made to survey utilities and determine extent on metering at “old control boundaries” – This information would be used to define the UFE Analysis Zones

•Excerpt from 11.5.2.1… The UFE analysis team will determine the initial set of UFE Analysis Zones to be used by January 1, 2001 to provide adequate time for installation of any required metering. …


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• Surveys were sent to the Old Control Areas requesting identification of existing “10”control area interchange metering points:

•Identify transmission stations on either side of the meter for potential zonal assignment•Identify metering upgrades required to ensure IDR, time synchronized, data is available

• At the February 2001 meeting, ERCOT reported it had completed responses from all areas with one area providing a partial response.


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1. Survey responses are inconsistent:

• Combination of Network Stations, Planning Stations and others used a utility naming identity.

• ERCOT will have to contact each entity individually to resolve issues and reconcile the meter locations to the new ESCA model.

2. ERCOT is in a transition state to the ESCA model as the standard.

• Transition will not be final until ????

• Planning model will be updated to ESCA Model or cross referenced to ESCA Model.

3. There is no mechanism to map the interconnect points to the existing transmission system model. (This is necessary for the working group to make determinations as to zonal breaks)

UFE Analysis Zonal Metering Issues

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4. Timing –

• It will be impossible for the Working Group to have the data necessary to define UFE Analysis zone any time in the near future.

• The January 01, 2001 deadline is already passed.

• ERCOT is focusing on testing and implementing systems necessary for successful pilot implementation on June 01.

5. Market participants in the UFE Working group and Metering Working Group have expressed concern at having to get UFE analysis metering in place by May 01, 2001 - especially with all the other timelines that have to be meet.

6. Is UFE Analysis necessary for a successful pilot?

UFE Analysis Zonal Metering Issues

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Modify Protocols to provide a more realistic implementation timeline for defining UFE Analysis Zones:

a. UFE Zone definition date be moved to July 01, 2001

b. TDSPs would have until December 01, 2001 to get required meter in place

c. UFE Analysis would begin on January 01, 2002

Reasoning:

a. We have already missed the January 01, 2001 deadline in the protocols.

b. Gives ERCOT time to reconcile survey data and implement mapping system.

c. Allows Market to focus on items critical to the pilot.

d. Allows UFE Working group to make a more informed decision.

Output of UFE Analysis Group

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• Redline of Section 11.5 was submitted and adopted:

• UFE Zone definition date be moved to July 01, 2001

• TDSPs would have until December 01, 2001 to get required meter in place

• UFE Analysis Team will Analyze UFE data from January 01, 2002 to December 31, 2002

• UFE Analysis Team will Provide a recommendation by April 2003 to the ERCOT Board

• Condition added to Protocols: A TDSP will not remove existing metering facilities that have the potential to be used to define UFE analysis zones until such time as UFE analysis zones have been defined according to this protocol section.


34

• Issues uncovered during the Pilot and Full implementation took precedence over further meetings - No further action by Working Group

• ERCOT placed mapping exercise on-hold until system was in place to provide adequate mapping for UFE Analysis Group decision making

• Although dates for zonal definition and analysis have not been met, Section 11.5 has not been revisited


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• Pilot and Start-up issues pushed the UFE Analysis discussion to a lower priority

• No further meeting were held and no Market Participants requested additional meetings

• Market Participants focused on correcting and addressing larger data and data model issues which would necessarily need to be corrected before addressing UFE further.


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UFE References in Protocols

37

Section 11.3.6 Unaccounted for Energy Calculation (UFE) and Allocation

The Data Aggregation System shall adjust the net loss adjusted Load for each aggregated group for Unaccounted for Energy (UFE).

The Data Aggregation process will calculate the difference between net loss adjusted Load for the entire ERCOT System, which has been adjusted for Distribution Losses and Transmission Losses, and the total system Load (generation) in order to determine the total UFE.

The calculated UFE for each Settlement Interval is then allocated to Loads.

Net flow out of ERCOT on a DC Tie will be deemed as Load, and net flow into ERCOT on a DC Tie will be deemed as a Resource

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Section 11.3.6.1 Calculation of ERCOT-Wide UFE

The Data Aggregation System will calculate ERCOT-wide UFE as the difference between the total generation supplied to a specific physical region (ERCOT) and the total Load, adjusted for losses in that same physical region (ERCOT) during each Settlement Interval.

UFE may be positive or negative in any single Settlement Interval.

UFEi (MWh) = ERCOT Generationi TotalERCOT Net Loss Adjusted Loadi Total

–

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ERCOT will allocate UFE to specific categories based upon adjusted Load Ratio Share. The adjusted Load Ratio Share will be determined using the following UFE category weighting factors:

(1) 0.00 - Transmission Voltage level IDR Non Opt-in Entities(2) 0.10 - Distribution Voltage level IDR Non Opt-in Entities(3) 0.10 - Transmission Voltage level IDR Premises(4) 0.50 - Distribution Voltage level IDR Premises(5) 1.00 - Distribution Voltage level Profiled Premises

The ERCOT Data Aggregation System shall provide a mechanism to change the UFE category weighting factors for specific transition periods.

Section 11.3.6.2 Allocation of UFE

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Section 11.5 UFE Analysis

ERCOT will establish a UFE Analysis Team chaired by ERCOT and consisting of Market Participants and ERCOT personnel who report to the Technical Advisory Committee.

The UFE Analysis Team will:(1) Analyze UFE data from January 01, 2002 to December 31,

2002(2) Post findings to the MIS on a monthly basis(3) Provide a recommendation by April 2003 to the ERCOT

Board

Prior to any recommendation from the UFE Analysis Team, ERCOT has one (1) UFE Zone, which encompasses all of ERCOT.

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Section 11.5.2 UFE Analysis Process

The UFE analysis team may request additional data from TDSPs to be provided to ERCOT for UFE analysis. Data that is confidential is to be deemed as such. ERCOT may request installation of additional meters for analysis, but TDSPs are not required to do so.

The UFE analysis process will:(1) Sub-divide ERCOT into a practical granularity of “UFE Analysis Zones,”

but no more than ten (10) zones, which can provide reliable and accurate data to be used for Cost/Benefit Analysis and decision making purposes;

(2) Identify factors that are contributing to UFE and work with the appropriate Entities to rectify problems causing UFE;

(3) Compare ERCOT-wide UFE to UFE within UFE Analysis Zones and investigate the differences;

(4) Determine if additional UFE Zones are necessary, and if so, identify the appropriate zones and the associated implementation cost;

(5) Post UFE analysis findings to Market Participants on a monthly basis; and

(6) Provide a recommendation to the ERCOT Board by April 2003

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Section 11.5.2.1

11.5.2.1 Sub-divide ERCOT into a practical granularity of “UFE Analysis Zones,” but no more than ten (10) zones, which can provide reliable and accurate data to be used for Cost/Benefit Analysis and decision making purposes

ERCOT shall make every effort possible during the design and implementation of market systems to implement mechanisms to capture data considered valuable in the UFE analysis effort. This will include but not be limited to integration and storage of “old” Control Area net Real Time Load signals on a Settlement Interval basis.

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Section 11.5.2.1 (con’t)

ERCOT will determine what data exists in the market and its location and attributes including:

(1) Load data(2) Generation data(3) Available import and export data(4) Sufficiency and relative accuracy of the data that exists for UFE analysis with:

(a) Revenue quality data preferred and(b) Acceptable SCADA integrated by ERCOT or the TDSP used on a temporary basis

(no more than one month)(c) Minimum installation requirements of new IDR meters for the sole purpose of UFE

Analysis

(5) Zonal criteria (TDSP areas, weather, profiling, etc.)

Based on the existing data, ERCOT will determine all zones that can be defined, and will determine which data is to be stored by ERCOT for UFE analysis purposes.

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Section 11.5.2.1 (con’t)

The UFE analysis team will determine the initial set of UFE Analysis Zones no later than December 01, 2001 but as soon as practical to provide adequate time for installation of any required metering.

The cost of installing any metering solely for UFE analysis purposes will be recovered through the ERCOT System Administration Fee.

A TDSP shall not remove and shall maintain existing metering facilities that have the potential to define UFE zones, as defined by ERCOT, until such time as UFE analysis zones have been defined according to this Protocol section.

45

Section 11.5.2.2

Section 11.5.2.2 The UFE analysis team will perform the following steps to identify factors that are contributing to UFE:

(1) Calculate UFE for UFE Analysis Zones as described above;(2) Compare ERCOT-wide UFE to UFE within UFE Analysis

Zones;(3) Determine possible causes of abnormal UFE;(4) Work with the appropriate Entities to rectify UFE problems

when possible;(5) Determine if UFE Analysis Zones need to be modified to

identify UFE problems;(6) Perform analysis going forward that will include the additional

UFE Analysis Zones;

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Section 11.5.2.3

11.5.2.3 Determine if UFE Zones are necessary, and if so, identify the appropriate zones and the associated implementation cost;

If UFE problems persist through the analysis phase, the UFE analysis team will make a recommendation of proposed UFE Zones according to the following guidelines:

(1) Cost-benefit analysis;(2) Installation requirements for Revenue Quality Meters;(3) Impact on the settlement system;(4) Impact on Market Participant systems;(5) Cost of UFE to Market Participants;

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Section 11.5.2.4

11.5.2.4 The UFE analysis team will provide an implementation plan for the proposed UFE Zone(s). Post UFE analysis findings to Market Participants on a monthly basis;

The UFE analysis team will determine the content of the monthly reports. The reports will be posted monthly for Market Participants.

ERCOT will post the following information on the MIS on the same date that other monthly system information is made available for each Settlement Interval during the month, which may include:

(1) Total ERCOT-wide UFE MWhs, UFE cost, and percent of total interval MWhs(2) ERCOT-wide UFE MWhs, UFE cost, and percent of total interval MWhs allocated to

UFE allocation categories(3) Each UFE allocation categories’ UFE MWhs, zonal UFE cost, and percent of total

interval MWhs for each UFE Analysis Zone(4) Results of any monthly UFE Analysis(5) Notice of any factors that may be contributing to UFE, by UFE Analysis Zone(6) Notice of any plan to rectify factors that may be contributing to UFE, by UFE Analysis

ZoneERCOT will facilitate quarterly Market Participant discussion groups to report

findings and gather input for areas of further analysis.

48

Section 11.5.2.5

Provide a recommendation to the ERCOT Board by April 2003

The UFE analysis team will present a recommendation to the ERCOT Board by April 2003.

By the end of April 2003, ERCOT will provide a report to the ERCOT Board and Market Participants, which provides the following:

(1) Summaries of all prior UFE analysis;(2) Factors that have contributed to UFE, by UFE Analysis Zone;(3) Recommendations for UFE Zones (including cost analysis);and(4) Proposed UFE Zone implementation plan (if recommended).

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Section 11.5.3

11.5.3 Data Collection and Metering Requirements For UFE Analysis Zones

TDSP’s have the option of either supplying zonal interval meter data to ERCOT, or providing remote interrogation for ERCOT to directly read the meter on demand. Temporary telemetry arrangements through SCADA may be integrated by either the TDSP or ERCOT. SCADA data will not be used for more than one month for purposes of UFE analysis.

If a UFE Analysis Zone can be created with the addition of minimum metering expense, ERCOT will require the TDSP to install the meter. All meters on the ERCOT Transmission Grid used to define UFE Analysis Zones will be installed, maintained, and read by the associated TDSP. If the meters have the ability to be remotely interrogated, ERCOT can directly read these meters.

ERCOT will be provided remote access to the UFE Analysis meter in accordance with Section 10, Metering, of these Protocols. If the TDSP does not provide for remote interrogation, the TDSP will be required to submit meter data to ERCOT in the same manner defined in Section 10, Metering, of these Protocols. TDSP’s will provide meter data in the same format and method that retail interval meter data is submitted specified in Section 19, Texas SET, of these Protocols. Furthermore, the TDSP is responsible for meeting the time synchronization requirement in accordance with Section 10, Metering, of these Protocols.

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Section 13.4.2 Deemed Actual Transmission Losses for UFE Analysis

Net Generation data used for UFE analysis zones that contains transmission facilities behind any metering points will be adjusted to the ERCOT wide transmission loss factor. This adjustment requires reducing the Net Generation by the calculated “actual” MWh of transmission losses and adding back the ERCOT Wide transmission loss factor translated into a MWh value. ERCOT will provide the calculation of the “actual” Transmission Losses behind the UFE zonal meters, for each interval, to settlement using actual system conditions for that interval.

The “actual” transmission losses for UFE analysis zones shall be a linear interpolation or extrapolation between the seasonal on-peak and the seasonal off-peak UFE analysis zone transmission loss factors corresponding to the actual UFE analysis zone metered load in the interval.

ERCOT shall calculate seasonal UFE analysis zones Transmission Loss Factors corresponding to the on peak and off peak base case system loads during each of the four seasons of the upcoming year as the basis for the UFE analysis zone Transmission Loss Factors. UFE analysis zone seasonal loss factors will be calculated in the same manner as the loss factors are calculated for the ERCOT wide transmission loss factors.

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Section 18 – Load Profiling

Section 18.2.1 Guidelines for Development of Load Profiles – (3) Minimize the Load Profiles’ contribution to UFE over all Settlement Intervals, paying particular attention to higher cost periods

Section 18.2.8.1 Samples - ERCOT will review load research sample validity (e.g. difference-of-means test) at the following times: 1) every year, and 2) when discrepancies (such as excessive UFE) or disputes warrant.

Section 18.2.8.2 Models - ERCOT shall monitor the applicability of the Load Profiling models by comparing all available actual IDR data samples with estimates generated from the profile model by interval for the same time period. Should these comparisons reveal significant discrepancies, ERCOT should take appropriate action and coordinate with the appropriate ERCOT TAC subcommittee (UFE analysis function), if necessary.

52

Example of UFE Calculation and

Allocation

53

Calculate & Allocate UFE

Step 1 Determine Load Per UFE Category

Profile ID Meter Type IDR

TDSP = NOIE and Profile ID Meter Type = IDR andDLF Code = “T”

TDSP = NOIE and Profile ID Meter Type = IDR andDLF Code “T”

TDSP NOIE andProfile ID Meter Type = IDR andDLF Code = “T”

TDSP NOIE andProfile ID Meter Type = IDR andDLF Code “T”

Transmission Voltage Level IDR Non Opt-in Entities

Distribution Voltage Level IDR Non Opt-in Entities

Transmission Voltage Level IDR

Distribution Voltage Level IDR

Distribution Voltage level Profiled

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Step 2 Determine Adjusted Load Per UFE Category

UFE Category Gross MWh

Transmission Voltage level IDR Non Opt-in Entities

10,000.0000 0.0000 0.00000.0000

0.0000

Distribution Voltage level IDR Non Opt-in Entities

0.0000 0.1000 0.00000.0000

0.0000

Transmission Voltage level IDR Premises

8,000.0000 0.1000 800.00000.0385

103.3462

Distribution Voltage level IDR Premises

8,000.0000 0.5000 4,000.00000.1923

516.7308

Distribution Voltage level Profiled Premises

16,000.0000 1.0000 16,000.00000.7692

2,066.9231

Totals 42,000.0000 20,800.0000 =LUFE 2,687.0000

UFE Category Gross MWhAdjustment Weighting

Net Adjusted MWh

LRS of Adjusted MWH

10,000.0000 0.0000 0.00000.0000

0.0000

0.0000 0.1000 0.00000.0000

0.0000

8,000.0000 0.1000 800.00000.0385

103.3462

8,000.0000 0.5000 4,000.00000.1923

516.7308

16,000.0000 1.0000 16,000.00000.7692

2,066.9231

Totals 42,000.0000 20,800.0000 =LUFE 2,687.0000


55

Step 3 Calculate Total UFE per UFE Zone

Generation(MWh)

44,687.0000

Total Loss Adjusted Load(MWh)

Total UFE(MWh)

42,000.0000 2,687.0000


56

Step 4 Allocate UFE to Each UFE Load Category

UFE Category Gross MWhAdjustment Weighting

Net Adjusted MWh

LRS of Adjusted MWH

Total UFEto Category

Transmission Voltage level IDR Non Opt-in Entities

10,000.0000 0.0000 0.00000.0000

0.0000

Distribution Voltage level IDR Non Opt-in Entities

0.0000 0.1000 0.00000.0000

0.0000

Transmission Voltage level IDR Premises

8,000.0000 0.1000 800.00000.0385

103.3462

Distribution Voltage level IDR Premises

8,000.0000 0.5000 4,000.00000.1923

516.7308

Distribution Voltage level Profiled Premises

16,000.0000 1.0000 16,000.00000.7692

2,066.9231

Totals 42,000.0000 20,800.0000 =LUFE 2,687.0000


57

Step 5 Allocate UFE to Loads withineach UFE Load Category

Data Cuts in: Distribution Voltage level IDR Premises

Gross MWhLRS of Ufe Category

UFE Allocation

UFE Adjusted Load

QSEA_LSEA_TSDPA_PC12345_DLFA_CM1_UFE1 900.0000 0.1125 58.1322 958.1322

QSEA_LSEB_TSDPA_PC12345_DLFB_CM2_UFE1 1,200.0000 0.1500 77.5096 1,277.5096

QSEB_LSED_TSDPB_PC12345_DLFA_CM3_UFE1 4,000.0000 0.5000 258.3654 4,258.3654

QSEB_LSEC_TSDPC_PC12345_DLFA_CM4_UFE1 1,450.0000 0.1813 93.6575 1,543.6575

QSEC_LSEE_TSDPA_PC12345_DLFC_CM1_UFE1 450.0000 0.0563 29.0661 479.0661

Totals 8,000.0000 1.0000 516.7308 8,516.7308


58

Step 6 Save UFE Adjusted Load Data Sets

Settlement Data Sets • QSE • Load Serving Entity • TDSP • Profile ID • DLF Code • CM Zone • UFE Settlement Zone

UFE Analysis Data Sets • QSE • Load Serving Entity • TDSP • Profile ID • DLF Code • CM Zone • UFE Analysis Zone


59

UFE Data Available to Market

UFE Data Sets Made Available to the Public

• Total Load per UFE Zone

• Total Generation per UFE Zone

• Total UFE per UFE Zone

• Total Load per UFE Category per zone

• Total UFE allocated to each UFE Category per zone

60

The UFE Zone Dilemma

61

TOP-DOWN METERED LOAD:

• Generation and Zonal Meters will capture and store the total load within a zone on a settlement interval basis.

• The total load captured by Generation and Zonal Meters contains:

1. All retail loads 2. Actual distribution losses3. Actual transmission losses4. Any other sources

contributing to load. (ie, theft, incorrect meter readings, retail load meter errors, etc…)


BOTTOM-UP LOAD CALCULATION:

• The Data Aggregation process will provide the following by zone on a settlement interval basis:

1. Sum of all retail loads.

2. Distribution line losses calculated from loss factors by the appropriate utility and voltage code.

3. ERCOT wide “postage stamp” transmission line losses.

Versus

What’sWrong

With This Comparison?

Check # 3on both

Not an Apples to Apples

Comparison!

62

THE PROBLEM DEFINED:When UFE calculation is performed on a zonal basis the Top-Down Metered Load (generation) of total load in the zone contains actual transmission losses while the Bottom-Up Load calculation (retail aggregation) contains ERCOT wide “postage stamp” transmission losses.

If there is no correction of the Top-Down Metered Load for actual transmission losses to the ERCOT wide “postage stamp” loss value, then the difference will be attributed to UFE in the zone and allocated to the customers in that zone. If this is allowed, then the “postage stamp” Transmission line loss allocation is effectively negated.

EXAMPLE: Actual Line Losses ERCOT-Wide Difference Allocated Netinclude in Top-Down Postage Stamp to REPs in zone via Effect Metering Loss Factor UFE allocation

in Bottom-Up Actual Losses 6% 4% 2% to REPs in Zone

The Problem


63

So glad you asked…..

Options:

1. Calculate UFE only on an ERCOT-wide basis.

2. Correct the Top-Down Metered Load to the ERCOT wide “postage stamp” loss value.

• Requires calculation of the “actual” transmission line losses in each zone for each settlement interval via load flow analysis.

• The calculated “actual” transmission line loss value would be subtracted from the Top-Down Metered Load then the ERCOT-Wide “postage stamp” line loss factor applied. The net result is then used in the UFE calculation.

The UFE Zone DilemmaHow do we fix this?

64

ISSUES:1. Requires MOS/POS to provide load flow analysis on UFE zone basis.

2. Impacts design and cost of ERCOT systems.

3. If multiple UFE zones are allowed, then the number of zones will increase to potentially the number of Distribution Utility basis - 150 - 200 zones.

BY THE WAY:1. Calculated “actual” line losses will be required for opt-out utilities to correct

their total load to the ERCOT-wide “postage stamp” value.

2. The number of opt-out utilities should decrease over time. But if allowed to remain a UFE zone, the same transmission loss correction would still be necessary.

The UFE Zone DilemmaIssues with Option 2

65

What work has already been done?

Modifications have been made to aggregation algorithms to improve load estimations

ADU vs Usage Factor Extended look-back period for IDR estimation PRRs to extend NIDR data available for estimation to 12

months (currently 6 months) Adjusted BUSIDRRQ profile Removed gap validation for usage data loading

Analysis of 2002 UFE presented to BOD & available on website

66

Preliminary Updated Analysis of UFE for 2003 and 2004

67

UFE % Jan 1 - 15, 2004

-10%

-5%

0%

5%

10%

15%

1 4 7 10 13

68

UFE % Jan 16 - 31, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 19 22 25 28 31

69

UFE % Feb 1 - 15, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 4 7 10 13

70

UFE % Feb 16 - 29, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 19 22 25 28

71

UFE % Mar 1 - 15, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 4 7 10 13

72

UFE % Mar 16 - 31, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 19 22 25 28 31

73

UFE % Apr 1 - 15, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 4 7 10 13

74

UFE % Apr 16 - 30, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 19 22 25 28

75

UFE % May 1 - 15, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 3 5 7 9 11 13 15

76

UFE % May 16 - 30, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 19 22 25 28 31

77

UFE % Jun 1 - 15, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 3 5 7 9 11 13 15

78

UFE % Jun 16 - 31, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

16 18 20 22 24 26 28 30

79

UFE % July 1 - 14, 2004

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

1 3 5 7 9 11 13

80

Average Interval % UFE

-3%-2%-1%0%1%2%3%4%

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

Month - Jan 03 to July 04

Pos Only Neg Only

81

Average Interval % UFE

-3%-2%-1%0%1%2%3%4%

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

Month - Jan 03 to July 04

Abs Net

82

UFE in Dollars (MCPE)

-20,000,000

-10,000,000

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

Month Totals- Jan 2003 to Jul 2004

$

Net PosOnly Neg Only Total

83

MCPE * UFE

2003 2004 (J an 1 - J ul 14)

Net 170,888,230$ 30,863,873$ Positive Intervals Only 236,198,494$ 69,401,081$ Negative intervals Only (65,310,264)$ (38,537,209)$ Absolute Value 301,508,758$ 107,938,290$

84

Distribution Losses

DLFs are currently calculated based on ERCOT’s forecasts of total load

Alternatively could be calculated based on ERCOT actual total load (as with TLFs)

Would eliminate the effect of forecast error on loss calculation and improve the accuracy of the loss calculation

85

January 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

1 4 7 10 13 16 19 22 25 28 31

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff

lforecot ltotercot % dlf change day

86

February 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

1 4 7 10 13 16 19 22 25 28

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


87

March 2004 DLF Changes

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

1 4 7 10 13 16 19 22 25 28 31

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


88

April 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

1 4 7 10 13 16 19 22 25 28

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


89

May 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

14000

1 4 7 10 13 16 19 22 25 28 31

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


90

Jun 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

14000

16000

1 4 7 10 13 16 19 22 25 28

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


91

Jul 2004 DLF Changes

0

2000

4000

6000

8000

10000

12000

14000

16000

1 4 7 10 13

Day

Mw

H

-15%

-10%

-5%

0%

5%

10%

15%

% D

iff


92

UFE Allocation

UFE is currently allocated with arbitrary weighting factors

0.10 - Distribution Voltage level IDR Non Opt-in Entities 0.10 - Transmission Voltage level IDR Premises 0.50 - Distribution Voltage level IDR Premises 1.00 - Distribution Voltage level Profiled Premises

Alternatively could allocate UFE based the category’s estimated load plus estimated loss

IDRs settled with actual data would only be allocated UFE based on losses

Profiled load and estimated IDRs would be allocated based on both load and loss

Would have a different allocation factor in each interval

93

ERCOT Total: 12,415.21 UFE: 519.59

Current UFE Allocation Method

At Meter Distribution Transmission Unadjusted UFE Weight UFE Wt * Load Percent UFE UFELosses Losses Total (Protocols) Allocation Allocation

Profiled Load 5,869.02 278.78 117.28 6,265.09 1.00 6,265.09 86.83% 451.17IDR Load Served at Dist Voltage (10% Estimated) 157.74 7.49 3.15 168.39 0.50 84.19 1.17% 6.06

IDR Load Served at Dist Voltage (90% Actual) 1,419.70 67.44 28.37 1,515.51 0.50 757.75 10.50% 54.57IDR Load Served at Trans Voltage 1,061.05 0.00 20.24 1,081.29 0.10 108.13 1.50% 7.79

NOIE Load 2,793.07 0.00 53.28 2,846.35 0.00 0.00 0.00% 0.00Exempt Load 18.64 0.00 0.36 19.00 0.00 0.00 0.00% 0.00

Sum 11,319.23 353.71 222.68 11,895.62 7,215.16 100.00% 519.59

Suggested UFE Allocation Method

At Meter Distribution Transmission Unadjusted Estimated Percent UFE UFE UFE PercentLosses Losses Total Load + Loss Allocation Allocation Change Change

Profiled Load 5,869.02 278.78 117.28 6,265.09 6,265.09 95.66% 497.02 45.85 10.16%IDR Load Served at Dist Voltage (10% Estimated) 157.74 7.49 3.15 168.39 168.39 2.57% 13.36 7.30 120.33%

IDR Load Served at Dist Voltage (90% Actual) 1,419.70 67.44 28.37 1,515.51 95.81 1.46% 7.60 (46.97) -86.07%IDR Load Served at Trans Voltage (100% Actual) 1,061.05 0.00 20.24 1,081.29 20.24 0.31% 1.61 (6.18) -79.38%

NOIE Load 2,793.07 0.00 53.28 2,846.35 0.00 0.00% 0.00 0.00 -Exempt Load 18.64 0.00 0.36 19.00 0.00 0.00% 0.00 0.00 -

Sum 11,319.23 353.71 222.68 11,895.62 6,549.52 100.00% 519.59

Hypothetical Example Based on July 12, 2004 at 13:45

94

Is UFE the measure of settlement accuracy?

Discussion

95

Confirm next meeting

Review action items

1 UFE Workshop Co-sponsored by RMS/COPS September 14, 2004.

Documents

Transcript of 1 UFE Workshop Co-sponsored by RMS/COPS September 14, 2004.