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

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Presentation on theme: "Proposed Modeling Updates to CHP in the TEPPC Base Case December 12, 2011 Arne Olson, Partner Nick Schlag, Consultant."— Presentation transcript:

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

2 Background LBNL has funded E3 to investigate the representation and modeling of existing cogeneration in the TEPPC dataset The scope of E3s 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 2

3 Generator Reconciliation 3

4 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 4 StateEIA 2009 TEPPC BeforeAfter Arizona146-- California7,2331,1696,452 Colorado1, Idaho186-- Montana82-- Nevada New Mexico Oregon1,734-1,438 Utah11758 Washington1, Wyoming160-- Total*12,3461,33010,113 CHP Nameplate Capacity by State (MW) * Total shows CHP in US states only

5 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 5

6 Modeling CHP Operations 6

7 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 7

8 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 8

9 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 9

10 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 Use CEMS hourly data to revise minimum operating levels for plants (not available for all unitsuse a rule of thumb based on available data) Retain other plant operating characteristics (max capacity) 10

11 Default CHP Assumptions 11 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 overstatedeven with must- run designation

12 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 12

13 Operation of Northwest Cogeneration Facilities 13 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)

14 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 ( ) 14

15 CAISO Non-Dispatchable Cogeneration 15 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 CAISOs 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

16 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) 16

17 CAISO Dispatchable Cogeneration 17 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

18 Thank You! Energy and Environmental Economics, Inc. (E3) 101 Montgomery Street, Suite 1600 San Francisco, CA Tel Web Arne Olson, Partner Nick Schlag, Consultant


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