Go to Content | Go to Page Updated Information | Go to Footer
Welcome to the California Energy Commission
Public Interest Energy Research Program: Final Project Report
picture of cover Renewable Distributed Generation Assessment: Alameda Power and Telecom Case Study

Publication Number: CEC-500-2005-010
Publication Date: January 2005
PIER Program Area: Renewable Energy Technologies

The executive summary, abstract and table of contents for this report are available below. This publication is available as an Adobe Acrobat Portable Document Format Files. In order to download, read and print PDF files, you will need a copy of the free Acrobat Reader software installed in and configured for your computer. The software can be downloaded from Adobe Systems Incorporated's website.

Download Document in Adobe Acrobat PDF. (163 pages, 2.6 megabytes)


Executive Summary

Introduction

In an effort to contribute to the baseline knowledge of distributed generation value, this case study reports the methodology and results of the combined economic and engineering analysis performed by Energy and Environmental Economics, Inc. (E3) and Electrotek Concepts (ETK) under a California Energy Commission (CEC) PIER program-funded contract. The aim of this research project is to develop a methodology for evaluating the potential renewable distributed generation (RDG) applications within the municipal utility planning process. The resulting methodology from this research will be integrated with nine other related research projects occurring in parallel to this RDG Assessment project to further the greater goals of the CEC PIER program. Figure 1 maps how this RDG Assessment Project relates to the other research areas under this program.

The following discussion comprises one of four case studies for the application of the RDG Assessment methodology. This case study describes the analytical process and associated results for the Alameda Power and Telecom (Alameda P&T) distribution system. The analysis results for the remaining three municipal utilities are provided as separate cases study reports for the San Francisco Public Utilities Commission/ Hetch Hetchy (SF PUC), City of Palo Alto Utilities (CPAU), and Sacramento Municipal Utilities District (SMUD)

Purpose

Numerous detailed screening studies for large transmission and distribution systems have identified several elements of value that distributed generation can provide. These include capital deferral, reduced losses, reduced O&M costs, and risk reduction. These elements focus on cost reduction to the wires company or an integrated utility. Although it has been postulated that distributed renewable generation can provide enhanced reliability, very little in the way of quantitative analysis has been completed to include the reliability impact in DG evaluation. This research builds upon this body of work and is focused on utility's internal planning processes.

As such, the purpose of this Distributed Generation Assessment project is to develop a sound and replicable methodology for evaluating RDG within a utility planning process. The methodology developed jointly by E3 and ETK was applied in four municipal utility case studies throughout Northern California with the goal of facilitating the installation of cost-effective RDG systems in California.

The core contributions of this research include the following:

  • Analysis of the local system impacts and benefits that accrue directly to a municipal UDC in a localized network;


  • Expansion of the evaluation methodology to evaluate the impacts on local system reliability, including value to both the customers and the UDC;


  • Incorporation of uncertainty for elements of RDG project value such as local load growth, wholesale energy prices, and capital costs for equipment.
Project Objective

The overall objective is to accelerate the deployment of renewable distributed generation by fully accounting for all benefits. The specific objectives of the project are to (1) identify the best locations for distributed renewable generation (DG) in a local Utility Distribution Company (UDC) system, (2) include reliability impacts in the analysis, (3) assess the impact of load growth and generator performance uncertainty on the results.

The key measure of success of this project is establishing an understanding of the merits of distributed renewable generation in distribution systems in general, embodied in the comprehensive application to four example distribution systems. Successful completion of this research will result in reduced overall system costs, enhanced local reliability, and increased resource diversity. The key anticipated outcome is an established and verified methodology and readily accessible tools for rapid assessment of distributed renewable technologies that can be applied to any distribution network.

Results

The results of the Alameda P&T case study RDG Assessment project are two-fold. First, this project represents a successful application of the RDG Assessment methodology developed by E3 and ETK. Second, the results provide Alameda P&T with valuable information for future decision making that includes the specific benefits RDG could provide on their distribution system.

Highlights of the assessment results provided in this report include:

  • Alameda P&T system could accommodate approximately 30 MW of uniformly distributed RDG without significant changes.


  • Beneficial generation must be able to produce power in the early evening hours in winter months because Alameda P&T is a winter peaking utility. This casts doubt on the benefits of solar PV technologies to the power delivery system unless coupled with significant storage.


  • Applications of RDG on Bay Farm Island would appear to offer the greatest potential benefit due to the distance of that load from the substation.


  • Most of the areas on the main island of Alameda offer potential benefits for RDG siting due to the distance from the substation and some of the bayside commercial areas on the opposite side of the island from the Jenney substation have potential benefits similar to Bay Farm Island locations.


  • The most cost-effective RDG technologies for Alameda P&T from a total resource perspective are biogas generators operating as combined heat and power resources.


  • Large-scale wind is also a cost-effective renewable resource but a sufficient wind resource is not available within Alameda to support this technology as a local distributed energy resource.


  • Reliability benefits are relatively small because Alameda P&T has sufficient system capacity available at present.
Conclusion and Recommendations

Upon initiation of this research project, the specific goals in the five-year, ten-year, and fifteen-year timeframe were identified. These included development of a robust methodology to evaluate local area resources and moving this type of analysis towards standard industry practice. The completion of the Alameda P&T RDG Assessment represents the first step in achieving these goals.

Recommendations including the implications of the use of this methodology in California and proposed next steps are described in the Final Report for the Renewable Distributed Generation Assessment project which captures the results from all four applications of this newly developed evaluation methodology.


Abstract

This case study presents the results of the first application of a renewable distributed generation assessment methodology conducted for Alameda Power and Telecom (Alameda P&T). Alameda P&T is one of four distribution system evaluated under the RDG Assessment project conducted under the auspices of the CEC PIER Renewables program. In addition to Alameda P&T, the three other distribution systems evaluated include the City of Palo Alto Utilities (CPAU), San Francisco PUC / Hetch Hetchy, and Sacramento Municipal Utility District. The overall objective of this project is to accelerate the deployment of renewable energy systems in a distributed generation mode by fully accounting for all benefits.

Keywords: renewable distributed generation, assessment methodology, municipal utility planning, Alameda Power & Telecom, avoided costs, reliability analysis, uncertainty analysis



Table of Contents

Abstract

Executive Summary

1.0 Introduction

1.1. Background

1.1.1. Overview of Analysis

1.2. Summary of Results for Alameda P&T

1.2.1. Economic Screening Analysis

1.2.2. Engineering Screening Analysis

2.0 Economic Screening Analysis

2.1. Avoided Costs

2.1.1. General Avoided Cost Methodology

2.1.2. Generation Avoided Costs

2.1.3. Transmission Avoided Costs

2.1.4. Distribution Avoided Costs

2.2. DG Economic Screening

2.2.1. Calculation of Costs and Benefits

2.2.2. Results of Economic Screening Analysis

2.3. Applying the RDG Screening Results

3.0 Engineering Screening Analysis

3.1. Overview

3.2. Description of Analysis

3.3. Power Flow Characteristics

3.3.1. Peak Load Snapshots

3.3.2. Annual Load Characteristics

3.4. RDG Siting Analysis

3.4.1. Small (100 kW) Test Generator

3.4.2. Large (5,000 kW) Test Generator

3.4.3. Base Case (No RDG)

3.4.4. Reference Case 1: 16-500 kW Generators

3.4.5. Reference Case 2: Distributed PV

3.4.6. 20 MW Baseload Generation

4.0 Load and Resource Analysis

4.1. Local Area Load Shapes

4.2. RDG Output Characteristics

4.3. Summaries of Demands and Savings

4.3.1. 8 MW CHP Generation Characteristics

4.3.2. Photovoltaic Characteristic

4.3.3. 20 MW Baseload Generation Connected to Bay Farm Island

4.4. Load and Resource Summary

5.0 Reliability Analysis

5.1. Engineering Reliability Analysis Overview

5.2. Reliability Evaluation

5.2.1. Basic Concept

5.3. Distribution Reliability

5.4. EEN Evaluation

5.4.1. Base Case

5.4.2. Reference Case 1 (16 500-kW CHP Generators)

5.4.3. Reference Case 2 (2 MW PV Generation)

5.4.4. Proposed RDG to Serve Bay Farm Island

5.5. Loss Evaluation

5.5.1. Comparison of Losses for All RDG Cases

5.6. Valuing EEN and Losses

5.7. Economic Evaluation of Reliability Impacts

5.8. Customer Value of Reliability Improvement

5.8.1. Deferral Benefit of DG

5.8.2. Deferral Benefit Feedback Loop

5.8.3. VRI and Deferral Benefit Interaction

5.8.4. Additional Uses of Reliability Valuations

5.8.5. Relative Customer VRI

5.8.6. VRI for Project Justification

6.0 Uncertainty Analysis

6.1. Scenario Analysis for Key Inputs

6.2. Generation Market Prices

6.3. Transmission Prices

6.4. Distribution Avoided Costs

6.5. RDG Capital Costs, Fuel Costs, and Capacity Factors

6.6. Results of Uncertainty Analysis

6.6.1. 500 kW Biodiesel

6.6.2. 50 kW Solar PV

6.6.3. 1.5 MW Wind Generator

7.0 Conclusions

References

Glossary


Appendices

APPENDIX A-1


List of Figures

Figure 1: CEC PIER Program Research Project Structure

Figure 2: RDG Analysis Process Diagram

Figure 3: Sensitivity Analysis For 500 Kw Biodiesel Generator, TRC Test

Figure 4: Power Flow In Alameda P&T System

Figure 5: Optimal Locations For Small Generation (100 Kw) On Alameda P&T Systems With Respect To Reducing Peak Load Losses

Figure 6: Optimal Locations For A Large RDG (5MW) With Respect To Loss Reduction At Peak Load

Figure 7: Generation Avoided Costs

Figure 8: Comparison Of Base, High, And Low Scenarios For Avoided Generation Costs

Figure 9: Potential Indirect Benefits Of RDG Installation

Figure 10: Cost Test Results For 500 Kw Biodiesel RDG

Figure 11: Cost Test Results For 50 Kw Solar PV

Figure 12: Cost Test Results For 10 Kw Wind Generator

Figure 13: Test Results For 1.5 MW Wind Generator (Assuming 30% Capacity Factor)

Figure 14: Power Flow in Alameda P&T System

Figure 15: Circuit Plot With Line Section Highlighting Proportional To Losses

Figure 16: Energy Consumption For Each Hour Of The Day For Each Month

Figure 17: Annual Energy Loss Shape

Figure 18: Shape Of Energy Exceeding Normal (Een) Ratings, which is reflective of the capacity of the system

Figure 19: Optimal Locations For Small Generation (100 Kw) On Alameda P&T Systems With Respect To Reducing Peak Load Losses

Figure 20: Compressed View Of Previous Figure. Subsequent Graphics In This Report Are Presented In This Format

Figure 21: Optimal Locations For Small DG (100 Kw) With Respect To Releasing Distribution Capacity

Figure 22: Least Optimal Locations For Small DG (100 Kw) With Respect To Releasing Distribution Capacity

Figure 23: Least Optimal Locations For Small DG (100 Kw) With Respect To Reducing Losses

Figure 24: Optimal Locations For A Large RDG (5MW) With Respect To Loss Reduction At Peak Load

Figure 25: Least Optimal Locations For Large DG (5MW) With Respect To Losses. Placing such a large generator in these areas will likely overload the local system.53

Figure 26: All Areas In Blue (Circled) Show An Increase In Losses For A 5,000 Kw Generator Added At Peak Load

Figure 27: Optimal Locations For A Large DG (5 MW) With Respect To Released Capacity

Figure 28: "Optimal" Locations (Yellow Circles) For 8 MW Of DG Sited For Maximum Loss Reduction At Peak Load

Figure 29: Area In Green (Circled) Indicate Mild Undervoltages Immediately After Dropping 8 MW Of Generation Distributed As Indicated In Figure 28

Figure 30: Areas Shown In Blue (Circled) Would Experience A Moderate Overvoltage If All Generators Shown In Figure 28 Were Dispatched On Simultaneously

Figure 31: Indication Of Percent Increase In Fault Currents, assuming DG is capable of supplying fault current. Fault currents in the circled red areas increase to as much as double their original value. Range is from zero to 105%

Figure 32: Locations In Red (Circled) Indicate High Increased Fault Current (Amperes) Due To Added Generation. Range From Light Color To Darkest Red Is 0 To 3100 A Increased Current

Figure 33: Assumed Locations For Solar PV Units Totaling 2 MW

Figure 34: Option 1: 2 12 kV feeders

Figure 35: Option 2: A 35 kV Feeder And Transformer Stepdown

Figure 36: Option 1: Areas In Green (Circled) Will Have Mild Undervoltages If The Two 10 MW Generators Is Forced Off

Figure 37: Option 1: Areas In Blue (Circled) Will Have Moderate Overvoltage When The Two 10-MW Generators Are Brought On Line Suddenly At Peak Load

Figure 38: Option 1: Areas In Blue (Circled) Will Have Moderate Overvoltage When The Two 10-MW Generators Are Brought On Line Suddenly At 50% Load

Figure 39: Option 1: Areas With Largest Percent Change In Fault Currents (Max = 62%)

Figure 40: Option 1 - Areas With Largest Absolute Value Change In Fault Currents (Max=1800 A)

Figure 41: Option 2: Areas with largest percent change in fault currents (Max = 27%)

Figure 42: Option 2 - Areas With Largest Absolute Value Change In Fault Currents (Max=818 A)

Figure 43: Alameda P&T System-Wide Load Shape, 1998

Figure 44: Topographical Representation Of Alameda P&T System-Wide Load Shape.76

Figure 45: Location Of 16 500-Kw Generators For Optimal Loss Reduction At Peak Load. Generator Locations Are Marked With Yellow Circles

Figure 46: Dispatch Shape Assumed For 8 MW CHP Generation Operated As A Late Afternoon Peaker

Figure 47: Impact On Area Load Shape As A Result Of 8 MW RDG Operated As A Late Afternoon Peaker. (Compare With Figure 43.)

Figure 48: Impact Of 8 MW CHP Generation Operated As Late Afternoon Peaker (3 10 PM) On A Typical 7-Day Load Profile During Winter Peak Loading

Figure 49: Impact Of 8 MW CHP Generation Operated As Baseload On A Typical 7-Day Load Profile During Winter Peak Loading

Figure 50: Assumed Locations For 2 MW Of PV Generation

Figure 51: PV Output Shape

Figure 52: Side-By-Side Comparison Of Alameda P&T Annual Load And Solar Output Contours

Figure 53: Impact Of 2 MW PV On Typical 7-Day Load Profile During Winter Months.

Figure 54: Assumed Locations For Interconnection Of 20 MW Generation Into Bay Farm Island (12 Kv Option)

Figure 55: Impact Of 20 MW Baseloaded Generator On A Typical 7-Day Alameda P&T Load Profile During Winter Months

Figure 56: Basic Concept Of Unserved Energy (UE) And Energy Exceeding Normal (EEN) For Evaluation Of Capacity

Figure 57: Evaluating The Impact Of RDG On The Power Delivery System Capacity

Figure 58: How DG Might Affect Distribution Reliability

Figure 59: Shape Of Peak Hourly EEN For Base Case

Figure 60: EEN Computed For 8 MW Of Baseload Generation Sited For Maximum Benefit To Distribution System Losses (Reference Case 1)

Figure 61: EEN Computed For 8 MW Of Later Afternoon Peaking Generation Sited For Maximum Benefit To Distribution System Losses (Reference Case 1)

Figure 62: Depiction Of The Impact Of The Generation In Reference Case 1, Dispatched As Baseload Generation, On The Peak Hourly EEN As Compared To The Base Case

Figure 63: Depiction Of The Impact Of The Generation In Reference Case 1, Dispatched As Late Afternoon Peaking Generation, On The Peak Hourly EEN As Compared To The Base case

Figure 64: Capacity Increase With Respect To EEN For 2 MW Of Solar Photovoltaic Generation Uniformly Distributed Throughout The System (Reference Case 2)

Figure 65: Depiction Of The Impact Of The Generation In Reference Case 2 (2 MW Solar PV) On The Peak Hourly EEN As Compared To The Base Case

Figure 66: Comparison Of Alameda Load Shape And Assumed Output Of PV Generation

Figure 67: Comparison Of Alameda Annual Load Contour And Solar PV Annual Output Contour

Figure 68: Capacity Comparison Of Option 1 With The Base Case (No Generation). (Option 2 Is Virtually Identical)

Figure 69: Comparison Of EEN Computed For Jenney 2 Substation For The Peak Load Week, With And Without The 20MW Generation From The Proposed Plant

Figure 70: Feeder 4214 Power Characteristic For Peak Week, With And Without 20 MW Generation From The Proposed Plant

Figure 71: Highlighted Lines Exceed The Assumed Normal Rating At Present Peak Load

Figure 72: Depiction Of The Impact Of The Proposed 20 MW Generation, Option 1, On The Peak Hourly EEN As Compared To The Base Case. (Option 2 Is Virtually Identical.)

Figure 73: Schematic Of Alameda P&T System With Proposed Plant Showing Substation Power Flows Before Adding The Generation

Figure 74: Comparison Of EEN Computed For All Cases

Figure 75: Annual Losses For 8 MW Of Baseload Generation Sited In 16 Units Of 500 Kw For Maximum Benefit To Distribution System Losses (Reference Case 1)

Figure 76: Annual Losses For 8 MW Of Late Afternoon Peaking Generation Sited In 16 Units Of 500 Kw For Maximum Benefit To Distribution System Losses (Reference Case 1)

Figure 77: Annual Losses For 2 MW Of Solar PV Generation Uniformly Distributed Throughout System (Reference Case 2)

Figure 78: Annual Losses For 20 MW Plant Option 1 (12 Kv Cables)

Figure 79. Annual Losses For 20 MW Plant Option 2 (35 Kv Cables)

Figure 80: Depiction of increment losses, kWh, in the existing Alameda P&T primary system due to baseload operation of the proposed 20 MW plant (option 1) serving Bay Farm Island

Figure 81: Comparison Of Annual Losses In The Existing Alameda P&T System For The Various RDG Options

Figure 82: Typical Range Of Reported Values For Customer Value Of Service (VOS)

Figure 83: EEN-based T&D Deferral

Figure 84: RDG Assessment Analysis Process Flow Diagram

Figure 85: VRI and T&D Deferral

Figure 86: Comparison Of Base, High, And Low Avoided Generation Costs

Figure 87: Net Benefit Range For Key Uncertainties, TRC Test

Figure 88: Sensitivity Analysis For 500 Kw Biodiesel Generator, TRC Test

Figure 89: Range Of Net Benefits For 50 Kw Solar PV, TRC Test

Figure 90: Sensitivity Analysis For 50 Kw Solar PV, TRC Test

Figure 91: Range Of Net Benefits For A 1.5 MW Wind Generator, TRC Test

Figure 92: Sensitivity Analysis For 1.5 MW Wind Generator, TRC Test


List of Tables

Table 1: Results of Alameda P&T RDG screening, under base-case assumptions

Table 2: Loss savings summary for Alameda P&T reference cases

Table 3: Energy and demand savings summary for Alameda P&T reference cases

Table 4: Screening Model Generation Avoided Cost Inputs As Of March 31, 2004

Table 5: Time-Of-Use Period Definitions

Table 6: Distribution Avoided Cost Calculation Inputs

Table 7: Questioned addressed by the various cost tests

Table 8: Benefits and costs of various test perspectives included in our modeling

Table 9: Performance Characteristics For RDG Technologies And DG Operating Using Renewable Fuels

Table 10: Generation benefits by test perspective

Table 11: Results of Alameda P&T RDG screening, under base-case assumptions

Table 12: Voltage drop for different amounts of RDG distributed as shown in Figure 33

Table 13: Peak Load Losses for Option 1

Table 14: Peak Load Losses for Option 2

Table 15: Comparative Impacts of Two Generation Interconnection Options on Overcurrent Protection of Alameda P&T System

Table 16: Comparison of Annual Energy for Generation Delivery Options

Table 17: Purchased Power and Demand Savings

Table 18: Annual Energy Loss Savings

Table 19: System Loss Savings at Peak Load

Table 20: Mid-Range Customer Value Of Service (VOS) Estimates

Table 21: Value of Reliability Improvement (Year 2004)

Page Updated:
Go to Content | Go to Page Updated Information | Go to Footer