Proposed Modeling Updates to CHP in the TEPPC Base Case December 12, 2011 Arne Olson, Partner Nick Schlag, Consultant.

Proposed Modeling Updates to CHP in the TEPPC Base Case

December 12, 2011

Arne Olson, Partner

Nick Schlag, Consultant

Background

LBNL has funded E3 to investigate the representation and modeling of existing cogeneration in the TEPPC dataset

The scope of E3’s work has included two tasks:

1. Reconciliation of TEPPC dataset with other known databases of CHP power plants (EIA, eGRID, ICF)

2. Recommendations for adjustments to CHP modeling in PROMOD

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Generator Reconciliation

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Reconciliation of TEPPC Database with EIA Generator List

The under-representation of CHP capacity in the TEPPC generator set is primarily a result of generators not being correctly identified as cogeneration resources

The remaining gap is roughly evenly split between two components:

1. Large industrial CHP facilities not represented in TEPPC

2. Small facilities that operate predominantly behind-the-meter and so are implicitly accounted for on the load side

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State EIA 2009TEPPC

Before After

Arizona 146 - -

California 7,233 1,169 6,452

Colorado 1,032 - 834

Idaho 186 - -

Montana 82 - -

Nevada 390 61 381

New Mexico 161 - 122

Oregon 1,734 - 1,438

Utah 117 58 58

Washington 1,104 42 828

Wyoming 160 - -

Total* 12,346 1,330 10,113

CHP Nameplate Capacity by State (MW)

* Total shows CHP in US states only

Results of Reconciliation

Based on the results of the reconciliation, E3 is confident that most of the existing CHP capacity in the WECC is already represented in the TEPPC data set (though may not be flagged as such)

• With the limited time in the current study cycle, E3 does not recommend adding any units to the data set

E3 will provide TEPPC with an updated list of generators that qualify as cogeneration facilities

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Modeling CHP Operations

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Challenges in Modeling CHP

Modeling the operations of combined heat and power generators in a production simulation setting is challenging for several reasons:

1. Thermal Load Service: CHP operations are often dictated by the size of the thermal load, so their responsiveness to wholesale market conditions are limited

2. On-Site Electric Use: Many CHP plants are located on-site at industrial facilities, and their generation is split between on-site use (behind-the-meter) and exports to the grid

There is no single rule of thumb that accurately predicts the hourly operations of plants that are operated for cogeneration

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Data Sources for CHP Operational Modeling

To determine the best methodology to adopt for CHP modeling in PROMOD, E3 has consulted the following sources:

• EIA Forms 860 & 906/920

• EPA Continuous Emissions Monitoring System (CEMS) database

• CPUC 2012 Net Qualifying Capacity (NQC) list

• CAISO Transmission Plan (Xiaobo Wang)

• NWPCC (Jeff King)

• CAISO Integration Analysis

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Modeling CHP Operations

E3 recommends retaining a default methodology to model CHP operations that designates plants as must-run and dispatches them based on a measure of net heat rate

Based on available data, E3 recommends an adjustment to this default for the following specific regional cases:

• Northwest IPP/Utility CHP plants (based on CEMS profiles)

• CAISO CHP (based on CPUC NQC capacity)

• Non-dispatchable

• Dispatchable

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Default CHP Assumptions

Characteristics

• Default assumptions would apply to roughly ~2,000 MW of nameplate CHP capacity

• Classified by EIA as either “IPP CHP” or “Electric Utility” (assumed to deliver all generation to the grid; also assumed to have some degree of generation flexibility)

Proposed PROMOD methodology

• Designate plants as must-run

• Adjust plant heat rates to net heat rate based on EIA 906/920 data gathered from 2007-2010

• Use CEMS hourly data to revise minimum operating levels for plants (not available for all units—use a rule of thumb based on available data)

• Retain other plant operating characteristics (max capacity)

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Default CHP Assumptions

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Advantages

Use of net heat rate accurately reflects plant emissions attributable to electricity sector

Use of net heat rate captures the true marginal cost to generate electricity (assuming demand for thermal load service is larger than plant capacity)

Must-run designation captures general trends in CHP operations

Disadvantages

Use of average net heat rate based on historical data prohibits the use of a heat rate curve to simulate efficiencies at partial load conditions

For some units, flexibility and responsiveness to wholesale signals may still be overstated—even with must-run designation

Northwest IPP/Utility CHP

In the specific case of the large cogeneration plants in the Northwest (roughly 2,100 MW), data from the Continuous Emissions Monitoring System database maintained by the EPA shows a systematic shutdown of plants during the spring (high hydro months)

• This finding is corroborated by EIA 906/920 data, which shows lower capacity factors for these plants in the spring

For large plants located in the Northwest, E3 recommends allowing full shutdown during high hydro conditions

• Remove must-run designation during spring months

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Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

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Hou

rly M

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Chehalis Generation Facility (Non-CHP)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

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Coyote Springs (CHP)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

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Klamath Cogeneration Project (CHP)

Operation of Northwest Cogeneration Facilities

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Throughout most of the year, CHP plants maintain

a range of operations between minimum and

maximum load conditions; similarly sized fully flexible gas units show a greater

range of flexibility

The exception to this trend is in the spring, when CHP and flexible gas units alike tend to reduce operations

systematically to accommodate high hydro

conditions

Data Source: EPA Continuous Emissions Monitoring Database (2009)

CAISO Non-Dispatchable Cogeneration

Characteristics

• ~4,900 MW of nameplate CHP capacity

• Classified by CPUC as “Non-Dispatchable” (not responsive to wholesale markets)

• Often responsible for on-site electric load service (only a fraction of generation is exported)

Proposed PROMOD methodology

• Set monthly maximum capacity equal to monthly NQC capacity based on CPUC 2012 Net Qualifying Capacity List

• Set minimum capacity equal to 100% of maximum capacity

• Designate plant as must-run

• Adjust heat rate to net heat rate based on historical plant data from EIA 906/920 (2007-2010)

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CAISO Non-Dispatchable Cogeneration

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Advantages

NQC provides a reliable measure of the fraction of plant capacity that will be available for export to grid (NQC methodology used in the CAISO’s Integration Analysis)

Monthly NQC values capture seasonal production trends

Must-run methodology limits flexibility of CHP resources

Use of net heat rate accurately reflects plant emissions attributable to electricity sector

Disadvantages

Flat hourly production profile does not reflect actual hour-to-hour plant operations

CAISO Dispatchable Cogeneration

Characteristics

• ~1,200 MW of nameplate CHP capacity

• Classified by CPUC as “Dispatchable”

• Plants export all generation to grid

Proposed PROMOD methodology

• Adjust heat rate of plants to reflect net heat rate based on EIA 906/920 data

• Do not designate plants as must-run

• Retain other plant operating characteristics (min/max capacities)

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CAISO Dispatchable Cogeneration

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Advantages

Use of net heat rate accurately reflects plant emissions attributable to electricity sector

Use of net heat rate captures the true marginal cost to generate electricity (assuming demand for thermal load service is larger than plant capacity)

Disadvantages

Use of average net heat rate based on historical data prohibits the use of a heat rate curve to simulate efficiencies at partial load conditions

Thank You!Energy and Environmental Economics, Inc. (E3)

101 Montgomery Street, Suite 1600

San Francisco, CA 94104

Tel 415-391-5100

Web http://www.ethree.com

Arne Olson, Partner ([email protected])

Nick Schlag, Consultant ([email protected])