DWG Progress Report to TAS November 3-4, 2015 Salt Lake City, UT Jamie Austin, PacifiCorp TEPPC\Data Work Group - Chair.

DWG Progress Report to TASNovember 3-4, 2015

Salt Lake City, UT

Jamie Austin, PacifiCorpTEPPC\Data Work Group - Chair

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Overview

• DWG’s work update on building the TEPPC 2026 Common Case– Approval Item: OTC Plant Replacement\

Retirement Assumptions – Approval Item: Coincident Energy Shapes Year – Thermal Plant Data Updates– Heat Rate Curves Updates– NTTG “Round Trip” Implementation Update

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California’s Once Through Cooling Plants

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California’s Once Through Cooling Plants Retirement Assumptions

• DWG is recommending Plant Retirement dates listed in the CAISO Table 4-4 of the 2015-2016 Transmission Planning Process Report (dated March 31, 201) with the following exceptions:

– For Moss Landing - DWG agreed to use the CEC staff assumptions in IEPR 2015, based on their interpretation of Dynegy’s Fall 2014 re-filed implementation plan to Resources Control Board (SWRCB).

• Moss Landing Units 6 and 7 will retire 12/31/2020• Moss Landing Units 1 and 2 will continue operating,

however, beginning 1/1/2021 with a 15% capacity de-rate due to a parasitic load that will allow these two units to be in compliance.

– Diablo Canyon - there are alternatives for cooling systems under consideration by SWRCB. The ISO studies show the plant on-line in 2025 and is modeled as a base-loaded resource. Some folks believe it should continue to be in the TEPPC 2026 CC as the SWRCB committee is looking into relicensing.

Figure 4-1: ISO 2015-16 TPP; Approximate geographical locations

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Area Generating Facility (Total

Plant MW)

Owner Unit State Water Resources

Control Board

(SWRCB) Compliance

Date

Net Qualifying Capacity

(NQC) (MW)

Final Capacity, if Already Repowered or Under Construction (MW)

Humboldt LCR Area

Humboldt Bay (135)

PG&E 1 12/31/2010 52 Retired 135 MW (Mobile 2&3 non-OTC) and repowered with 10 CTs (163 MW) - (July 2010)

2 12/31/2010 53

Greater Bay Area LCR

Contra Costa (674)

GenOn  

6 12/31/2017 337 Replaced by Marsh Landing power plant (760 MW) – (May 2013) 7 12/31/2017 337

Pittsburg (1,311 MW) Unit 7 is non-OTC

GenOn 5 12/31/2017 312 GenOn proposed to utilize cooling tower of Unit 7 for Units 5&6 if it can obtain long-term Power Purchase & Tolling Agreement (PPTA) with the CPUC and the utilities.

6 12/31/2017 317

Potrero (362 ) GenOn 3 10/1/2011 206 Retired 362 MW (Units 4, 5 & 6 non-OTC

Central Coast (non-LCR area) *Non-LCR area has no local capacity requirements

Moss Landing (2,530)

Dynegy 1 12/31/2017* 510 These two OTC combined cycle plants were placed in service in 2002. see related comments on slide 3 of this DWG presentation.

2 12/31/2017 510

6 12/31/2017* 754

7 12/31/2017* 756

Morro Bay (650)

Dynegy 3 12/31/2015 325 Retired 650 MW (February 5, 2014)

4 12/31/2015 325

Mandalay (560)

GenOn 1 12/31/2020 215 Unit 3 is non-OTC

2 12/31/2020 215

Table 4-4: ISO 2015-16 Transmission Planning Process; March 31, 2015

6Table 4-4: ISO 2015-16 Transmission Planning Process March 31, 2015

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California’s Once Through Cooling Plants Replacement Assumptions

• The good news coming from the ISO is that we now have better information (although still not complete) as the LTPP for Tracks 1 and 4 are still on-going. We know more than we did a year ago about some pieces of the puzzle:– the procurement selection from SCE, – the CPUC’s recent decisions on the Carlsbad Energy Center for

SDG&E• Accordingly, DWG has held several webinars. These plus

work behind-the-scene led us to formulate a consensus on what to use for proxy OTC replacement assumptions in the TEPPC 2026 Common Case.

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Updating OTC Assumptions in the TEPPC 2026 Common Case

• Consideration was given to:– SCE’s Ex-Parte Communication with CPUC– CPUC Decision on SDG&E’s Power Purchase Agreement (PPA) with Carlsbad

Energy Project (CEP)– SDG&E’s long-term expectation for energy storage additions in San Diego area– Additional Achievable Energy Efficiency (AAEE) forecast developed by the CEC– Responded to concerns by the CEC about what constitutes Behind-The-Meter-

Solar-PV, generic storage, generic incremental EE, and generic demand response---all are addressed in the detailed workbook.

• The proposal covers:– Definition of resources mix– Breakdown of resources with higher RPS mix– Detailed mapping of resource, down to the bus.

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CPUC's 2014 LTPP Track 1 & Track 4 Procurement Authorization

Phase IV LTPP - March 13, 2014 California’s OTC Plants Replacement

Assumptions

SCE LA Basin

San Diego Area subtotal

Preferred Resources 950 175 1125 TEPPC 2026 Common CaseStorage 50 25 75 Preferred Resources

Gas-Fired 1500 943 2443 DWG( SDG&E) RecommendationTotal 2500 1143 3643 CAISO’s Initial Recommendation

TEPPC 2024CC (DWG recommendation

05/12/14)SCE LA Basin

San Diego Area subtotal SCE - LA Basin

San Diego Area subtotal Moorpark Total

Incremental Additional Achievable Energy Efficiency (AAEE)*

855 158 1013148.96 40 188.96 6 194.96

124.21 40 164.21 6 170.21

Demand Response* 0 0 099.8 60 159.8 159.8

75.05 60 135.05 135.05

Behind-the-Meter PV* 0 0 0 62.67 0 62.67 62.6737.92 0 37.92 37.92

Wholesale PV 95 18 113 0 0 0 5.66 5.660 0 0 5.66 5.66

Storage 50 25 943 288.45 150 438.45 0.5 438.95263.7 200 463.7 0.5 464.2

Gas-Fired Generation1500 943 2443 1382 800 2182 262 2444

1382 800 2182 262 2444

Total 2500 1144 3644 1982 1050 3032 274 33061883 1100 2983 274 3257

*Incremental to amounts forecast by CEC for the LA Basin and San Diego areas (e.g., EE is incremental to CEC's AAEE amount).

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Committee level agreement

Motion:“It is moved to accept the DWG recommended proxy assumptions for Once Through Cooling plant retirement \ replacement in the TEPPC 2026 Common Case.”

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Coincident Energy Shapes Year

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Approval Item: Coincident Energy Shapes Year

• See Presentation by Kevin Harris

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Thermal Plants Data Updates

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Updates of Thermal Plants Data & Assumptions

• DWG met September 29 and discussed Generator Cost Parameters last derived for the TEPPC 2024 CC By Intertek-APTECH:

– Startup and Cycling Cost

– Variable O&M

– Ramping Penalty

– Final assumptions for forced outage rates

• Jin, from ABB, covered how to apply the Ramp Rate Penalty in GridView to allows for better alignment of dispatch with historic operation.

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The Intertek-APTECH Data• WECC – TEPPC jointly with NREL hired Intertek-APTECH Engineering in

response to stakeholders concerns about the increased cycling and ramping of thermal generation in recent studies, caused by the increased penetration of variable resources.

• The APTECH data covered:– Hot, warm, and cold start costs

• Load follow/ramping cost impacts• Base-load Variable Operation and Maintenance (VOM) costs• Base Load and Cycling Costs

• APTECH agreed on just using low-end costs in the public domain with some exception given “typical” values for large coal plants. The reason for just low-end data is a hedge for APTECH to protect their business.

• Greg Brinkman shared that NREL is planning on just using low-end cost data in upcoming work as it is in public domain. Also, Greg is convinced that the APTECH date remains the best available that is open source.

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APTECH – Non-fuel Start Costs

Percentile

GroupDescription &

Sample Unit Size [##]Lower Bound Hot Warm Cold Hot Warm Cold

25th 79 112 87 15,800$ 22,400$ 17,400$ Median 94 157 147 18,800$ 31,400$ 29,400$ 75th 131 181 286 26,200$ 36,200$ 57,200$

25th 39 55 63 27,300$ 38,500$ 44,100$ Median 59 65 105 41,300$ 45,500$ 73,500$ 75th 68 78 124 47,600$ 54,600$ 86,800$

25th 39 54 73 35,100$ 48,600$ 65,700$ Median 54 64 104 48,600$ 57,600$ 93,600$ 75th 63 89 120 56,700$ 80,100$ 108,000$ 25th 28 32 46 14,000$ 16,000$ 23,000$ Median 35 55 79 17,500$ 27,500$ 39,500$ 75th 56 93 101 28,000$ 46,500$ 50,500$ 25th 22 26 31 3,300$ 3,900$ 4,650$ Median 32 126 103 4,800$ 18,900$ 15,450$ 75th 47 145 118 7,050$ 21,750$ 17,700$

25th 12 12 12 900$ 900$ 900$ Median 19 24 32 1,425$ 1,800$ 2,400$ 75th 61 61 61 4,575$ 4,575$ 4,575$ 25th 25 36 54 6,000$ 8,640$ 12,960$ Median 36 58 75 8,640$ 13,920$ 18,000$ 75th 42 87 89 10,080$ 20,880$ 21,360$

6Gas-fired simple cycle Aero-

Derivative[75]

7Gas-fired steam

[240]

3Large coal-fired

supercritical steam (500 - 1300 MW) [900 MW]

4Gas-fired combined cycle

[500 MW]

5Gas-fired simple cycle large

frame[150]

2Large coal-fired sub-critical

steam (300 - 900 MW) [700 MW]

Capital & Maintenance Non-fuel Start Cost EstimateRates ($/MW capacity) Cost for Sample Unit

1Small coal-fired sub-critical

steam (35 - 299 MW) [200 MW] Median – Cold

costs used in 2022 CC

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APTECH – Variable O&M

GroupDescription &

Sample Unit Size [##]Percentile

LBRates

($/MWh)Annual Cost for

Sample Unit

25th 1.52 2,316,845$ Median 2.82 4,298,357$ 75th 3.24 4,938,538$

25th 1.62 7,407,806$ Median 2.68 12,254,890$ 75th 3.09 14,129,705$

25th 2.48 15,120,461$ Median 2.96 18,047,002$ 75th 3.40 20,729,664$ 25th 0.85 1,340,280$ Median 1.02 1,608,336$ 75th 1.17 1,844,856$ 25th 0.48 94,608$ Median 0.57 112,347$ 75th 0.92 181,332$

25th 0.27 26,609$ Median 0.66 65,043$ 75th 0.80 78,840$ 25th 0.66 555,034$ Median 0.92 773,683$ 75th 1.42 1,194,163$

Baseload Variable Operating & Maint.

7Gas-fired steam

[240 MW @ 40% CF]

2Large coal-fired sub-critical

steam (300 - 900 MW) [600 MW @ 87% CF]

3Large coal-fired supercritical

steam (500 - 1300 MW) [800 MW @ 87% CF]

4Gas-fired combined cycle

[400 MW @ 45% CF]

5Gas-fired simple cycle large

frame[150 MW @ 15% CF]

6Gas-fired simple cycle Aero-

Derivative[75 MW @ 15% CF]

1Small coal-fired sub-critical

steam (35 - 299 MW) [200 MW @ 87% CF]

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APTECH Values for Startup and VOM

Group Description Hot (Hrs)

Warm (Hrs)

Cold (Hrs)

Startup Cost ($/MW-Cap)

Start Fuel (MMBtu/MW-

Cap)

Other Start Cost ($/MW)

Variable O&M

($/MWh)

1Small coal-fired sub-critical steam (35 - 299 MW)

< 4 4 to 24 > 24 151.65 9.33 8.20 2.91

2Large coal-fired sub-critical steam (300 - 900 MW)

< 12 12 to 40 > 40 108.32 14.00 10.47 2.76

3Large coal-fired supercritical steam (500 - 1300 MW)

< 12 12 to 72 > 72 107.29 20.10 11.95 3.05

4 Gas-fired combined cycle < 5 5 to 40 > 40 81.50 0.24 1.055 Gas-fired simple cycle large frame < 2 2 to 3 > 3 106.25 0.22 0.98 0.59

6Gas-fired simple cycle Aero-Derivative

0 0 to 1 > 1 33.01 1.53 1.96 0.68

7 Gas-fired steam < 12 12 to 48 > 48 77.37 8.92 11.80 0.95

Cold Start Values - Aptech

Comparison of Generator Parametersby Aptech Group (2012 $)

Used in 2022 CC .

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Heat Rate Curves• Problem – the TEPPC 2024 common case has a set of non-matching heat rate curves

developed by different sources– The SSGWI database was handed to WECC in 2006. – In 2011 an attempt was made to update all heat rate curves using CEMS data. Replacement curves

were applied to large units only as we ran out of time.– Solution – plant operation changes overtime and hence heat rate curves should be changed

periodically. • Problem – The heat rate curve is a fundamental data element that impacts the commitment

decision in the production cost model and consistent assumptions should be applied to all for producing nonbiased results.

– Solution – use CEMS data and consistent methodology to develop new heat rate curves.• Problem – Staff time is scarce and this task requires time and involving experts in the field to

produce enhanced data.– Solution – use a credible stakeholder process where all parties can benefit by collaborating. The

CEC has started their effort updating Heat Rate Curves for the IPER, using consistent methodology and TEPPC has stakeholders considered experts in the field who are willing to work with the CEC staff on behalf of TEPPC on this synergistic project.

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DWG Agreed to Methodology• Approximate the IO curve data with a polynomial function

– Calculate Average Heat Rate Curve (AHR) from the following equations:

– Calculate Incremental Heat Rate Curve (IHR) as follows:

• Use CEMS data to approximate the IO Curve as follows:– For each hour of the year, the CEMS data gives the unit’s

• heat input (input power in MMBTU/h)• gross generation (output power in MW)

– Approximate the IO curve from the CEMS data as follows:• scrub the CEMS data• graph the scrubbed dataset as a scatter plot• represent the scatter plot with a polynomial regression curve

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The NTTG “Round Trip” & the TEPPC 2026 Common Case

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TEPPC 2026 Common CaseInitial Building Blocks

1. Starting with the TEPPC 2024CC, I read in the most recently compiled WECC 2025HS1a power flow consistent with the staff’s plan to use these databases as foundation for the TEPPC 2026CC.

2. Building on step 1, the first step in the NTTG “Round Trip” process, a generator list file was exported and sent to all four regions for review and editing.

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Mapping of “non-matched” Generators

• Non-matched units are due to generators with different bus numbers and\or different unit ID. Results of comparing resources in the TEPPC 2024, V1.5 to the new WECC 2025HS1a power flow case produced over 2,000 unit mismatches; the NTTG “Round Trip” automatically assigns these a generic bus name: gen@bus#

• The list was sent to the Four Regions asking for their review and edit to provide the correct generator mapping

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Process

• Regardless of process, it is crucial to know what resources are existing and what are incremental, a key reason that was used to justify the WECC BCCS process that has been recently canceled.

• “Kudos” to the regions. As of last week, we have collected all the resource mapping I’ve asked for to use for building the TEPPC 2026 CC. A huge task that involved the help of TPs and generator owners. The regions acted in good faith, recognizing the importance and contribution of the “Round Trip”.

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Perpetuating the Problem

• This is the second time that TEPPC has called on the regions to do resource mapping. Unfortunately, it was too big of a job to implement in the TEPPC 2024CC.

• This round the implementation task has been made easy, thanks to the NTTG “Round Trip” process . Though, processing the data was not easy and can be eliminated with future consolidation of databases: – I’ve burnt the midnight oil since last Thursday night through Sunday

night working joint with ABB staff on massaging the edits collected from the regions.

• NTTG has further invested in hiring a consultant to solve the power flow case with all the resource mapping edits produced by the NTTG “Round Trip”– Yes, the NTTG “Round Trip” does work.

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Adding New Generators in the Power Flow

• The production cost programs: – Are less sensitive to generator location

• There is a tendency to place generators at inappropriate busses when added within the production cost model dataset

• Generators added in the production cost framework may not have appropriate integrating elements

• The staff must add “new” incremental resources in the power flow for the “Round Trip” to work.

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WECC2025 HS -

PF

TEPPC2026 HS -

PF

CCTA

Hourly Loads

Unit Commitment Data Hourly

Energy Shapes

Incremental Generator &

Dynamic Models

One Hour - PF

8760 –One Hour - PFGrid

View

PF

PF & PCM

PCM

“Round Trip”

Production Cost Model (PCM) Power Flow (PF)

Imports

Exports

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Benefits

• Production cost models produce 8760 system dispatches for the entire year. Users should use this ability to “create” power flow cases of interest, either for economic and\or reliability reasons.

• Advantages– Consistent topologies amongst all selected hours– Greater number of hours can be studied– Dispatches based on economics

Process Changes Requested from WECC(When Building New PCM Databases)

Three Fundamental Changes, Short Term and Long Term:1. Short Term - Process needs to address “round trip” requirements; all

edits of network elements must be applied in the power flow (PSLF). Use the “round trip” process to build the new production cost model database. This approach is expedient, efficient and accurate. It fixes all frustrations encountered in the past, including: a. Providing consistent mapping of generators in the production cost model

and the power flow caseb. Providing accurate transfer of non-conforming loads (e.g., Station Service

loads) ; do not net SS loads from generators – keep as modeled in the power flow

2. Short Term - Process needs to provide for modular data blocks reflecting different assumptions to meet different needs. All edits can be maintained in “change files”a. Organizations (e.g., Regions) may have different study years, different

forecasts, different criteria for developing the CCTA list

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Process Changes Requested from TEPPC (continued) (When Building New PCM Databases)

3. Long Term - Process calls for working with WECC\TSS to build consistent power flow cases at WECC; today no two power flow cases have same bus numbers for all existing generators, nor unit IDs for the same existing unitsa. Power flow cases for different seasons or other conditions

must be consistentb. The topology in the power flow and production cost datasets

must be identical, or definitive mapping must be availablec. Individual generators in the power flow may be represented

as composite plants in the production cost for efficiency or proper dispatch

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