Plant-wide Solar Feasibility
Study
Report No. 1346
Project No. 104054
July 2009
Metropolitan Water District
of Southern California
Plant-wide Solar Feasibility Study
Report No. 1346
Project No. 104054
July 2009
Prepared by:
MWH Americas, Inc.
626 Wilshire Blvd., Suite 850
Los Angeles, California 90017
(213) 316-7000
TABLE OF CONTENTS
Section 1 Executive Summary................................................................................................... 1-1 Section 2 Introduction and Objective ...................................................................................... 2-1 Program Introduction ............................................................................................................. 2-1 Purpose and Necessity of the Program .................................................................................. 2-2 Drivers and Constraints.......................................................................................................... 2-5 Section 3 Laws, Rules and Regulations .................................................................................... 3-1 Existing Regulatory Framework ............................................................................................ 3-1 Relevant State Solar Programs............................................................................................... 3-2 Metropolitan Local Electric Jurisdictions’ Solar Programs ................................................... 3-8 Summary .............................................................................................................................. 3-10 Section 4 Project and Solar Industry Background ................................................................. 4-1 Facility Descriptions .............................................................................................................. 4-1 Electrical Demand: Historical and Projected ......................................................................... 4-1 Options for Selling Solar Distributed Generation to an Interconnected Utility in California 4-2 Market Issues: Evaluation of Solar Industry .......................................................................... 4-5 Section 5 Solar Sizing Analysis ................................................................................................. 5-1 Data Analysis ......................................................................................................................... 5-1 Solar System Sizes ................................................................................................................. 5-4 Aspects to Solar Implementation ........................................................................................... 5-5 Section 6 Future Potential Solar Facility Locations ............................................................... 6-1 Foothill Power Plant .............................................................................................................. 6-1 Etiwanda Power Plant ............................................................................................................ 6-2 Diamond Valley Lake – Wadsworth Pumping & Power Plant.............................................. 6-2 Lake Mathews Power Plant ................................................................................................... 6-6 Eagle Valley Property ............................................................................................................ 6-6 Arrow Highway Property ....................................................................................................... 6-9 Section 7 Recommendations.................................................................................................... 7-11 Treatment Plant Solar Facility size ...................................................................................... 7-11 Staging, Timing and Delivery Method ................................................................................ 7-13 Roadmap to Achieve Practical Implementation of Metropolitan Strategic Power Plan ...... 7-15 MWH
TOC-i
Plant-wide Solar Feasibility Study
APPENDICES
Appendix A - Sizing Calculations
Appendix B – Solar Sizing and Sensitivity Analysis
LIST OF TABLES
Table 1-1 Recommended Solar Sizes .......................................................................................... 1-3 Table 4-1 Expected Energy Consumption with Ozonation ......................................................... 4-2 Table 5-1 Calculated Optimal Solar Sizing for Behind-the-Meter Generation ........................... 5-5 Table 7-1 Calculated Supply-Demand Sizes for Behind-the-Meter Generation ....................... 7-12 Table 7-2 Recommended Solar Facility Size............................................................................. 7-12 Table B- 1 Available 15-minute Electrical Demand Data by Facility ............................................ 5 Table B- 2 Calculated Optimal Solar Sizing for Behind-the-Meter Generation .......................... 21 LIST OF FIGURES
Figure 5-1 Daily Energy Demand and Solar Generation ............................................................ 5-3 Figure 6-1 Foothill Power Plant Solar Facility ............................................................................ 6-3 Figure 6-2 Etiwanda Power Plant Solar Facility.......................................................................... 6-4 Figure 6-3 Diamond Valley Lake: Wadsworth Pumping & Power Plant Solar Facility ............. 6-5 Figure 6-4 Lake Mathews Solar Facility ..................................................................................... 6-7 Figure 6-5 Eagle Valley Solar Facility ........................................................................................ 6-8 Figure 6-6 Arrow Highway Solar Facility ................................................................................. 6-10 Figure B- 1 Daily Energy Demand and Solar Generation .............................................................. 2 Figure B- 2 Daily Fluctuations in Grid Demand ............................................................................ 3 Figure B- 3 Metropolitan Plant Electrical Demand, kWh .............................................................. 4 Figure B- 4 Metropolitan Treatment Plant Monthly Flow, MGD equivalent................................. 5 Figure B- 5 Normalized Monthly Electrical Demand – Jensen ...................................................... 6 Figure B- 6 Normalized Monthly Electrical Demand - Weymouth ............................................... 7 Figure B- 7 Normalized Monthly Electrical Demand - Skinner ..................................................... 8 Figure B- 8 Normalized Monthly Electrical Demand - Mills ......................................................... 9 Figure B- 9 Expected Electricity Rates Under Different Escalation Scenarios ............................ 11 Figure B- 10 Sensitivity of Solar Size and Net Present Cost of Capital Purchase by Grid Rate
Escalator........................................................................................................................................ 13 Figure B- 11 Sensitivity of Solar Size and Net Present Cost of PPA by Grid Rate Escalator ..... 14 Figure B- 12 Equivalent Lines for PPA Initial Rates and Escalators ........................................... 15 Figure B- 13 Sensitivity of Solar Size and Net Present Cost of PPA by Initial Rate ................... 16 Figure B- 14 Sensitivity of Solar Size and Net Present Cost of Capital Purchase to Plant Energy
Demand ......................................................................................................................................... 17 Figure B- 15 Sensitivity of Solar Size and Net Present Cost of PPA by Plant Energy Demand .. 18 MWH
TOC-ii
Plant-wide Solar Feasibility Study
Figure B- 16 Per Unit Treated Flow Energy Consumption - Jensen ............................................ 19 Figure B- 17 Per Unit Treated Flow Energy Consumptions - Mills ............................................. 20 Figure B- 18 Net Present Cost of Capital Purchase vs. PPA Over Time..................................... 22 Figure B- 19 Net Present Cost of Capital Purchase vs. PPA Over Time with Different Grid
Escalation ...................................................................................................................................... 23 MWH
TOC-iii
Plant-wide Solar Feasibility Study
SECTION 1
EXECUTIVE SUMMARY
The Metropolitan Water District of Southern California (Metropolitan) has developed a Strategic
Power Plan (SPP) to implement its energy goals. These goals include developing projects that
will provide power at its water treatment plants and at the retail facilities at a rate of 50% in 2014
and 100% by 2020, with 100% carbon reduction by 2030. There are many drivers that
influenced the development of the SPP and its goals, although the primary drivers are regulatory
and financially related.
The Global Warming Solutions Act of 2006, popularly known as AB 32, requires that by 2020
California’s greenhouse gas (GHG) emissions be reduced to 1990 levels. Metropolitan may be
required to take actions that will contribute to the legislated reduction. Even if legislation does
not directly impact Metropolitan’s operations, it likely will cause energy prices to rapidly
increase. Since the treatment and distribution of water is a highly energy dependent process,
energy price increases could dramatically affect the cost of water Metropolitan provides to its 26
member agencies. Price volatility also affects Metropolitan’s annual operating budget. A steady
supply and cost of electricity can increase system reliability as well as assist in the development
of water supply initiatives. In addition to factors that directly impact its operations, Metropolitan
seeks to lead through example on sustainability issues.
To meet the immediate goals of the SPP, Metropolitan has conducted this Plant-wide Solar
Feasibility Study (Study) in conjunction with a Preliminary Design Report for the
implementation or expansion of solar facilities at its five water treatment plants.
Regulations Governing Solar Facility Implementation
Given current regulations, there are several methods of implementing solar. These include net
metering, feed-in-tariffs, energy storage, and behind-the-meter generation. Net metering is
considered the most optimal implementation scenario as any energy produced in excess of
demand is fed back to the electric grid as a credit. The strategy can only be utilized for up to one
megawatt (MW) per facility due to regulatory constraints. Feed-in-tariff rates are currently not
high enough to justify selling solar renewable energy to electricity providers, especially
considering that ownership of the Renewable Energy Credit (REC) is transferred with the sale of
energy. Energy storage is currently not cost effective for medium scale operations of solar
facilities in the United States. Behind-the-meter generation involves on-site solar generation that
supplies electricity directly into the facility to which it is connected. With behind-the-meter
generation, any energy that is in excess of demand is lost. Given these constraints, it is
recommended to optimize net metering options and use behind-the-meter generation to meet
daytime electricity demands.
Financing Options
There are two main options for financing solar systems: 1) capital purchase of the system, and 2)
entering into a Power Purchase Agreement (PPA) with a third party. If Metropolitan were to
purchase the system, it would receive all rebates, tax breaks or other incentives and would be
MWH
1-1
Plant-wide Solar Feasibility Study
responsible for maintenance and end of life disposal of the solar system. Under a PPA,
Metropolitan would enter an agreement with a third party, which would be responsible for
purchase, operation and maintaining the system, and end of life disposal. In this case the third
party would receive any applicable rebates and tax incentives. In a PPA, Metropolitan would
pay for all of the energy produced by the solar system at an agreed upon contractual rate, which
could be flat or escalated. The RECs from the solar electricity produced could be negotiated to
be retained by Metropolitan.
To offset the capital expenditure of a solar system, there are several rebates and tax incentives
available. Each of the three electric utilities serving Metropolitan load at retail has developed its
own solar incentive program. Although they differ in detail, they generally limit the size of the
solar facility eligible for rebate to 1 MW per facility. Under federal tax laws, private entities that
purchase solar systems are allowed to accelerate the depreciation of the solar system, thereby
greatly reducing their tax burden. This tax incentive is not available to Metropolitan under a
direct purchase scenario, but is available to the financing party under a PPA system, which can
make a PPA more financially attractive to Metropolitan, especially over the 20 year period of a
typical PPA contract. In general, PPAs are preferred for short term horizons while a capital
purchase is preferred for long term horizons. Unfortunately, not all electric utilities serving
Metropolitan load permit PPAs.
Feasibility Study Scope
The focus of this Study is to determine the optimum solar facility size at Metropolitan’s five
water treatment plants (WTPs) for behind-the-meter generation, under a capital purchase and a
PPA, if applicable. It is recommended to add 1 MW of net metering at all WTPs because the
nighttime electricity consumption at each WTP is greater than the production from a 1 MW solar
facility. Thus study will also briefly investigate the available space for solar facilities at other
Metropolitan properties which may be potentially suited for solar facilities. These properties
could be utilized at a later date if regulatory conditions change to have more attractive net
metering or feed-in-tariff terms.
There are many factors to consider when sizing a solar facility, including:
• variability in energy demand on a daily and seasonal basis
• variability in solar energy production on a daily and seasonal basis
• expected cost of grid electricity over time
• rate of degradation of solar energy production
• cost to install/maintain/dispose of solar system
• cost to finance a capital purchase
• rebate programs and incentives
• PPA rate structure
• cost of money
These factors were accounted for in this study to perform a net present cost analysis of both
financing options over a 40 year period. The optimal size of a solar facility is when solar energy
production closely matches the electricity consumption of the facility it is serving. If the solar
system is too large, energy may be wasted. If the solar system is too small, there is a lost
MWH
1-2
Plant-wide Solar Feasibility Study
opportunity to offset grid electricity demand. However, solar production and electricity demand
will fluctuate based on temperature, time of year, and changes in facility operations, therefore it
is impossible to always match solar production with electricity consumption. The best one can do
is to utilize average and projected solar production and electricity consumption to estimate the
optimal solar facility size that will minimize the net present cost of the system.
Sensitivity analysis was conducted to determine how the optimal solar size changed if the
assumptions were altered. This analysis showed that three factors had the greatest influence on
the solar size. These factors were 1) the expected escalation in the retail rate of electricity over
time, 2) the length of the analysis period, and 3) the PPA electricity rate. The sensitivity analysis
consistently showed that the net present cost of the solar system increased significantly when the
solar system was larger than the optimal size; whereas, the net present cost of the solar system
reduced slightly if the system was smaller than the optimal size. Therefore, it is better to slightly
undersize a solar facility than to oversize the facility, when compared to the optimal solar size.
Recommendations
The recommended solar facility size at each plant is presented in Table 1-1. The size is based on
the optimal size for each facility and all constraints discussed in this report as well as land
constraints discussed in the Preliminary Design Report. The optimal size varies slightly for a
PPA or a capital purchase of the system. All of the water treatment plants are suited for solar
facilities, except for the Diemer plant. The Yorba Linda Hydroelectric Plant, which is located onsite at the Diemer plant, is currently planned for upgrades that would provide all of the energy
demand for the Diemer plant; thereby negating the need for a solar facility.
Table 1-1
Recommended Solar Sizes
Treatment Plant
Total Solar Installation (MW)
Capital Purchase/PPA
Jensen*
1.5
Weymouth*
2
Skinner
3.2/3
Mills
2/1.9
Diemer
0
Total
8.7/8.4
*The size is space constrained. Total solar installation
size based on 8acres/MW
The two types of project financing allow three scenarios for solar facility bidding:
1) Solicit bids for capital purchase
2) Solicit proposals for power purchase agreements
3) Simultaneously solicit both a capital purchase bid and proposals for a PPA, with the
option to choose either.
MWH
1-3
Plant-wide Solar Feasibility Study
The solar bid should be structured such that bidders have the option to propose on individual
solar facilities at each water treatment plant, or to submit a single bid for all the water treatment
plants. A single bid for all plants may allow for economy-of-scale pricing that could result in a
savings to Metropolitan. However, there is one exception for the Jensen plant (served by the Los
Angeles Department of Water and Power). The Los Angeles Department of Water and Power
does not currently allow PPA agreements. They do allow for a third-party purchase of solar
systems as long as the payments to the third-party are structured in a lease format. Thus, only a
capital purchase or lease agreement can be utilized for implementing solar at the Jensen Plant.
Use of a PPA at the Mills WTP is subject to Riverside Public Utilities approval.
Of the three bidding scenarios, it is recommended to utilize the capital purchase option for
several reasons. First, over the projected life of the project (40 yrs), the economic benefit of the
capital purchase significantly outweighs the PPA because after the system has paid for itself, it
continues to produce significant quantities of electricity that is essentially free to Metropolitan
and at little cost. This is possible because solar facilities require little operations and
maintenance expense and solar panels are warranted for 25 years with an expected lifetime of 40
or more years. A capital purchase is also a safe investment to protect against future dramatic
energy increases and price volatility. In comparison, significant uncertainty exists regarding the
end of a PPA contract. While Metropolitan has the option to purchase the system at “fair market
value,” no clear definition of fair market value has yet emerged. There is speculation that fair
market value could be interpreted to mean the value of the energy it produces, which would
represent a significant amount of money if retail electricity rates are high. In addition, under a
PPA, Metropolitan would be relying on outside financers and it is unclear what would happen if
the PPA investors folded or dissolved.
The availability of rebates and tax incentives provide favorable financing options for the
implementation of solar facilities. These rebates and incentives will diminish as the number of
installed solar systems increases. Therefore, Metropolitan should consider the implementation of
solar facilities at the water treatment plants to take advantage of the current incentives, which are
currently about 40% of the total cost via the California Solar Initiative. Solar installations at
other available Metropolitan properties should also be evaluated to take advantage of the current
incentives, and contribute to the overall goals of Metropolitan’s Strategic Power Plan.
MWH
1-4
Plant-wide Solar Feasibility Study
SECTION 2
INTRODUCTION AND OBJECTIVE
The purpose of this Plant-wide Solar Feasibility Study (Study) is to provide a detailed technical
and financial assessment of the issues facing the Metropolitan Water District of Southern
California (Metropolitan) as it implements the solar program component of its Strategic Power
Plan (SPP). The specific focus of this study is to assess and provide recommendations for the
staged implementation of solar power production at Metropolitan’s five water treatment plants
(WTPs): Joseph P. Jensen, F.E. Weymouth, Robert A. Skinner, Robert B. Diemer, and Henry J.
Mills WTPs. The broader issues of financial, regulatory, and technical constraints and drivers
concerning the implementation of renewable energy were also evaluated. These issues are
structured into a preliminary planning framework. The goal is to provide a recommendation to
guide and direct Metropolitan’s future energy management efforts related to the SPP.
PROGRAM INTRODUCTION
This study is the culmination of several months of master planning efforts by Metropolitan staff
and consultants to develop a realistic, attainable, and cost effective expansion plan of solar power
facilities at Metropolitan’s five water treatment plants. The results of this Study shall support the
preliminary design phase of project implementation.
This study is a high-level analysis of the feasibility of implementing solar power within
Metropolitan’s service area, specifically at the WTPs, but also at satellite locations that could
become feasible locations for solar/renewable energy generation, if current laws and regulations
are changed to allow expanded net metering or feed-in tariffs.
Specific topics covered in this Study include:
•
•
•
•
•
•
Detailed financial analyses at each WTP
Project delivery methods and purchasing mechanisms
Existing and proposed laws and regulations related to implementation of renewable
energy
Sizing analyses and recommendations for solar facilities at each WTP
Recommendations for programmatic oversight of the solar initiative as related to
Metropolitan’s Strategic Power Plan
Recommendations for continued oversight of laws and regulations as they evolve and
change over the coming years
The Preliminary Design Report (PDR) that will follow this study, will analyze specific aspects to
implementing solar facilities at the five water treatment plants. Specific topics covered in the
PDR will include:
•
•
•
•
MWH
Site layouts and future plans
Conduit runs with points of connection
Electrical single-line diagrams
Other appurtenant information relevant to CEQA documentation and final design
2-1
Plant-wide Solar Feasibility Study
In general, the implementation of solar generation facilities at Metropolitan’s water treatment
plants is feasible and practical for three main reasons:
1) Each WTP has a high base load electrical consumptions
2) The electrical consumption at three of five WTPs will increase in the future when ozone
disinfection is ultimately implemented at all the WTPs
3) Each WTP has land available on which solar facilities may be constructed.
In addition, Metropolitan is interested is developing solar facilities in order to invest in the
expansion of its renewable energy portfolio. The expansion may assist in demonstrating
compliance with future renewable portfolio standards under which Metropolitan may be
regulated; see Section 3 (Laws, Rules, & Regulations) for further discussion. Irrespective of
future regulations, development of additional renewable energy facilities will demonstrate the
commitment by Metropolitan to reduce its carbon footprint and reliance on greenhouse-gas
producing energy. Moreover, implementation of renewable energy facilities will assist in
hedging against future price increases and volatility in the retail electricity market.
PURPOSE AND NECESSITY OF THE PROGRAM
The mission of the Metropolitan Water District of Southern California is to provide its service
area with adequate and reliable supplies of high-quality water to meet present and future needs in
an environmentally and economically responsible way. As a leader in the water and utility
industry, Metropolitan has made great strides in developing water conservation strategies that
have substantially reduced per capita retail demand throughout its five-county service area. The
conveyance, treatment, and distribution of water is a highly energy dependent process. As such,
Metropolitan – as a steward of the public and in conjunction with its mission – has goals and
aspirations to show leadership in the areas of sustainability as well as and energy conservation.
The 2008/09 General Manager’s Business Plan outlines several strategic priorities, including
sustainability. In particular, the Business Plan states:
Metropolitan is faced with many challenges to ensure the long-term viability and
sustainability of Southern California’s water supply serving over 18 million people. The
challenges include the potential impacts of changing climate, increased urbanization,
endangered species, increased environmental regulation and litigation, increasing
competition for water, and population pressures. Metropolitan is committed to
addressing these issues and ensuring long-term, high quality water supply in a manner
that promotes our commitment to sustainability and reduces our environmental footprint.
The Business Case for implementing solar renewable energy facilities fits well within the
General Manager’s initiatives to commit to sustainability and the reduction of Metropolitan’s
carbon footprint. Additionally, sustainability and environmental footprint concepts related to the
Business Plan have been outlined at and through various forums over the past several years,
including Metropolitan Board retreats, Board policies, and Board actions on projects to develop
renewable energy facilities. As such, implementation and expansion of solar renewable energy
facilities as described in this Study are directly related to these Board initiatives and actions, as
MWH
2-2
Plant-wide Solar Feasibility Study
described below. The Board’s retreats, actions, and policies form the basis for the purpose of the
solar program and its necessity in the context of the SPP.
April 2007 Board of Directors Retreat
The 2007 Annual Board of Director’s Retreat highlighted several strategic priorities to assess,
plan and implement in the coming years by Metropolitan. Included in the 2007 retreat, in light
of California’s Global Warming Solutions Act of 20061, was the Board’s call for a reduction in
Metropolitan’s carbon footprint and mitigation against risks associated with future carbon-related
fees and regulations.
Key energy issues identified and targeted for action by the Board during the April 2007 Retreat
included:
1) price volatility
2) system reliability
3) environmental stewardship
4) energy independence
5) cost
6) implementation risk, including technical complexity and feasibility.
Strategic Power Plan, 2008-09
During the 2008-09 fiscal year (FY) a variety of energy-related briefings on the SPP were given
to Metropolitan’s Board. The presentations provided approval of updated Energy Policy
Principals, information regarding Metropolitan’s activities related to the next Hoover power
contract in 2017, and historical energy consumption and cost data for Metropolitan’s distribution
system, the Colorado River Aqueduct (CRA) and the State Water Project (SWP). Over the
course of several Board informational reports and presentations, a series of proposed SPP Policy
Goals were identified. These SPP Policy Goals were brought to Metropolitan’s Board in July
2009 for adoption. If approved, the following actions will be implemented by Metropolitan:
Immediate Actions (by FY 2010/11):
• Expedite renewable energy at Metropolitan’s WTPs
o Negotiate agreements to achieve 100 percent renewable hydroelectric power use
at the Diemer plant.
o Achieve 25 percent renewable power use to meet summer on-peak energy
consumption at the Skinner plant ($10 million – Board approved project).
o Complete design for a 1 MW solar facility to meet on-peak energy use at the
Weymouth plant ($1 million – request Board approval September 2009).
1
The Global Warming Solutions Act of 2006 requires that by 2020 the state's greenhouse gas emissions be reduced
to 1990 levels, a roughly 25% reduction under business as usual estimates.
MWH
2-3
Plant-wide Solar Feasibility Study
o Develop Request for Proposals (RFP)/Request for Bids (RFB) for approximately
an additional 9 MW of solar project development at the treatment plants and
execute implementation contracts.
•
Expedite renewable energy and energy efficiency projects at Union Station Headquarters
o Establish partnerships with the Metropolitan Transit Authority (MTA),
AMTRAK, and the Los Angeles Department of Water and Power (LADWP) to
install solar facilities at Metropolitan’s headquarters and near-by MTA and Union
Station train sites.
•
Expedite renewable energy along the Colorado River Aqueduct.
o Establish partnerships for development of renewable energy projects located in
the desert to meet CRA supplemental power requirements.
Short-term Goal (by 2014):
• Implement renewable energy programs to achieve a 50 percent carbon reduction in
Metropolitan’s distribution system (for retail energy facilities, including WTPs, pumping
facilities, and Union Station Headquarters) via renewable energy projects including solar
and small hydroelectric facilities.
•
Establish partnership(s) with the Southern California Public Power Authority (SCPPA)
and/or power developers to invest in renewable energy supplies that will achieve energy
independence at Metropolitan’s CRA pumping plants in a phased and cost-effective
manner.
•
Evaluate the potential for partnerships and for developing large-scale renewable energy
projects that could meet a portion of the regional power needs, including that of
Metropolitan, its member agencies, and future desalination facilities. Determine what
potential changes to Metropolitan’s Act, if any, would be needed to implement this goal.
•
Work with the Department of Water Resources and State Water Contractors on State
Water Project energy and carbon management issues.
Intermediate Goal (by 2020):
• Achieve 100 percent carbon reduction at all of Metropolitan’s distribution facilities (for
retail energy facilities, including treatment plants, pumping facilities, and Union Station
Headquarters) and a 50 percent carbon reduction from non-hydroelectric energy use on
the CRA (wholesale energy facilities).
Long-term Goal (by 2030):
• Achieve 100 percent carbon reduction at all of Metropolitan’s distribution facilities (for
retail energy facilities including treatment plants, pumping facilities, and Union Station
Headquarters) and a 100 percent carbon reduction from non-hydroelectric energy use on
the CRA (wholesale energy facilities).
MWH
2-4
Plant-wide Solar Feasibility Study
Skinner & Weymouth Solar Power Generation Facilities
The Skinner Solar Power Generation Facility is Metropolitan’s first venture into large-scale solar
power generation facilities. The project was implemented utilizing Metropolitan’s traditional
capital project delivery method of design-bid-build. The project was planned, designed, and
constructed over a two-year period, with preliminary design funding secured in June 2007, final
design in November 2007, and the awarding of a construction contract in July 2008.
Completed in April 2009, the project is projected to generate over 2.3 million kilowatt-hours
(kWhs) annually of clean, renewable energy. An initial capital investment of nearly $10 million
was required for the project, with an expected return on investment (ROI) of approximately eight
years. The ROI is based on reductions in retail energy consumption at the current bundled retail
rate of $0.12/kWh (escalated at 3% annually), as well as rebates Metropolitan will receive from
Southern California Edison. Solar energy decreases the amount of retail energy that is purchased
at retail electricity rates. Metropolitan expects to receive over $5 million in rebates based on
actual solar power generation applied to Metropolitan’s reserved rebate structure of $0.46/kWh
over the first five years of operation, as part of the California Solar Initiative (CSI).
Metropolitan further demonstrated its commitment to expanding its solar renewable energy
portfolio with approval of preliminary design of the 1 MW Weymouth Solar Power Generation
Facility, in May 2008. Since that time, Metropolitan staff have completed the preliminary design
and has assessed the project under environmental guidelines.
Solar Program Relationship to the Strategic Power Plan
In conjunction with the SPP, staff also initiated studies at the remaining WTPs, which form the
basis of this Study. Implementation of solar facilities identified herein would reduce
Metropolitan’s retail-level carbon footprint by approximately 20%. Conversion of the Yorba
Linda Power Plant to meet all of the Diemer plant’s electrical needs would further reduce
Metropolitan’s retail-level carbon footprint by an additional 10%.
It should be noted that in order to meet the goals of the SPP, large-scale solar power generation
facilities must meet three main objectives:
1. Implementation of the facilities must have a sound financial and business case to
Metropolitan, with a reasonable return on investment
2. The facilities must have the ability to offset a large portion of the retail electricity
demand at each installed location, in order to hedge against substantially large future
retail rate increases
3. Metropolitan must retain 100% of the renewable energy credits (RECs) generated by
each facility.
DRIVERS AND CONSTRAINTS
The California Energy Commission has estimated that approximately 5% of all electricity used
in the state of California is for the treatment and transport of water; while water related energy
MWH
2-5
Plant-wide Solar Feasibility Study
use comprises 20% of the State’s electricity2. The SPP is Metropolitan’s response to action as an
environmental steward to reduce the consumption of fossil fuels. Supported by its traditional
core business of providing water and now with a new plan to generate renewable energy,
Metropolitan is taking an active role at the water/energy nexus to reduce power demands and
associated green house gas emissions attributed to the water industry. This new focus on energy
provides opportunities and efficiencies as well as challenges. A focus on energy has the
potential to drive down operating costs significantly over the long-term. However, the financial
and technical challenges relevant to large-scale implementation of renewable energy creates an
atypical set of drivers, compared to those normally association with water industry projects and
initiatives. These drivers include:
•
•
•
•
Regulatory Environment Drivers
o Assembly Bill (AB) 32 regulations
o Interconnection policy for power providers
o Other state and federal regulations
Solar Industry Drivers
o Financing and market outlook
Financial Drivers
o Hedge against retail electricity rate increases
o Market volatility
o Purchasing mechanisms (e.g. PPA, capital purchase, etc.)
Technical Drivers
o Space constraints
This Study analyzes these drivers and constraints as they relate to the implementation of the first
phase of Metropolitan’s Strategic Power Plan. Major activities currently underway include 1)
operation of the recently constructed Skinner 1 MW solar project, 2) conversion of the SCE
hydroelectric contract at the Diemer plant in 2010/11, and 3) implementation of the
recommendations included in this report for solar installations at Metropolitan’s water treatment
plants between 2010-2014.
2
California Energy Commission. California’s Water – Energy Relationship Final Staff Report. 2005.
MWH
2-6
Plant-wide Solar Feasibility Study
SECTION 3
LAWS, RULES AND REGULATIONS
EXISTING REGULATORY FRAMEWORK
Jurisdictional Issues
An analysis of the allowances and constraints to the existing regulatory framework is critical to
the analysis of available solar resources and the successful implementation of Metropolitan’s
solar program.
Under California’s regulatory scheme, the energy industry is divided into retail and wholesale
energy markets. Wholesale energy is generation that is sold in bulk for resale, while retail
energy is sold in smaller quantities to end-use customers.
Wholesale energy sales by privately owned entities such as investor-owned utilities (IOUs) and
independent power producers are subject to regulation by the Federal Energy Regulatory
Commission (FERC). Energy from Metropolitan’s small hydrogenation facilities is sold at
wholesale to local electric utilities. Additionally, as Metropolitan is a quasi-municipal
corporation, Metropolitan is not a “public utility” as defined in Section 201 of the Federal Power
Act. Thus, Metropolitan is exempt from direct FERC regulation, although FERC does have
some oversight of Metropolitan because of its wholesale generation and transmission ownership
(e.g., electric reliability standards).
The sale of retail energy by IOUs is regulated at the state level by the California Public Utility
Commission (CPUC). There are three primary IOUs or “electric corporations” in California:
Pacific, Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas &
Electric (SDG&E).
Publicly-owned utilities are referred to as “municipal utilities” and also as local publicly owned
electric utilities (LPOEUs). LPOUEs providing retail service are largely self-regulated by their
respective governing boards, with limited oversight by the CEC. Although Metropolitan appears
to meet the statutory definition of an LPOEU, it is largely exempt from CEC oversight because it
does not server retail end use customers.
Metropolitan’s Authority to Develop Solar Power
Metropolitan was created by an act of the California Legislature and is a limited–purpose
municipal corporation, created primarily to convey, treat, and deliver water to its member
agencies on a wholesale basis. However, the Legislature has authorized Metropolitan to generate
power for its water supply purposes. Expressly, Metropolitan was created for “the purpose of
developing, storing, and distributing water for domestic and municipal purposes and may
provide, generate, and deliver electric power within or without the state for the purpose of
MWH
3-1
Plant-wide Solar Feasibility Study
developing, storing, and distributing water for such district.”3 Thus, Metropolitan has authority to
develop solar power for use at its facilities, including its water treatment plants as addressed in
this study. Additionally, a reasonable interpretation of Metropolitan’s organic authority allows
for the development of solar power at off-site facilities for use to offset electrical costs at
Metropolitan facilities as permitted under existing law. Metropolitan hopes to maximize the
benefits of existing solar programs to reduce its use of greenhouse gas emitting electricity
resources.
RELEVANT STATE SOLAR PROGRAMS
Other than federal grant and tax credit programs that subsidize the cost of solar projects, the
federal government is typically uninvolved in smaller-scale solar generation. This study focuses
on the applicable state solar programs overseen primarily by the CPUC for IOUs, and the CEC
for LPOEUs, as discussed in more detail below.
California Solar Initiative (CSI)
In 2007, the state launched the Go Solar California campaign, established by the Legislature
through the enactment of Senate Bill (SB) 1. Today, the Go Solar California campaign has a
goal to create 3,000 MW of new, solar-produced electricity by 2016, with a statewide budget of
$3.3 billion over 10 years.
The California Solar Initiative (CSI) was developed by the CPUC for the IOUs. CSI provides
cash incentives for each kilowatt-hour of customer-generated solar energy for the first five years
and the rate per unit of electricity varies by organizational class with different levels for
residential, commercial, and government/non-profit. The CSI program is also a tiered incentive
program where early solar purchasers receive a larger rebate rate. Currently, the CSI program
for SCE is at the fifth tier where the rebate for government/non-profit agencies is $0.32/kWh and
the rebate for commercial agencies is $0.22/kWh. The generation incentives are funded through
a surcharge on IOU customer bills. The CSI program allows non-residential solar systems up to 5
MWs, but only provides incentives for the first 1 MW of capacity. Incentive payments are
calculated for solar energy systems that exceed 1 MW in size by prorating the energy output
based on the ratio of 1 MW to the size of the site. Thus, if a customer installed a 5 MW system,
the customer would receive incentive payments for 1/5 of the output of the system. As an
alternative, the customer may, at its election and cost, separately meter a 1 MW element of a
larger system. Under CSI, customers must execute an interconnection agreement with the host
utility. Receipt of CSI incentives does not require transfer or sale of the RECs to the host utility;
instead, they are held by the customer-owner of the solar facility and may be sold by the
customer regardless of receipt of CSI incentives.
Each local utility has developed and implemented its own program to meet the mandates of SB 1
3
See MWD Act §§ 25, 139. Section 139 states: “A district may acquire, construct, operate, and maintain any
and all works, facilities, improvements, and property to provide, generate, and deliver electric power within or
without the state necessary or convenient to carry out the objects or purposes of the district.” Section 25 states
Metropolitan purposes, as set forth above, limiting Metropolitan’s rights to generate and sell power to
Metropolitan’s water conveyance purposes.
MWH
3-2
Plant-wide Solar Feasibility Study
and each LPOEU’s solar program is self-regulated, with limited CEC oversight. Metropolitan
has water treatment plants within the service areas of SCE, the Los Angeles Department of
Water and Power (LADWP) and Riverside Public Utilities (RPU), each of which has their own
solar programs, discussed in more detail below.
Renewable Portfolio Standard Program (RPS)
California’s Renewable Portfolio Standard Program (RPS Program) is a further major
commitment to renewable energy. As of 2002, existing law directed the CPUC to require the
IOUs to reserve or set aside a specific portion of future generating capacity for renewable
resources. In 2002, legislation was enacted to require utilities to increase procurement of
electricity from renewable energy sources by at least one percent per year, which was set to meet
a target of 20% renewable energy by 2017. The program was accelerated in 2006 under Senate
Bill 107 that required IOUs and other CPUC-regulated entities, but not the municipal or locally
owned utilities, to increase procurement from eligible renewable energy resources by at least 1%
of their retail sales annually, until they reach 20% by 2010.
In November 2008, the Governor issued Executive Order S-14-08 increasing the target for all
electric utilities (including LPOEUs) to 33% by 2020. Several legislative proposals are currently
pending to codify the Governor’s increased RPS mandates, and some form of these requirements
is expected to be enacted this year.
Of significance, the current RPS Program only applies to retail suppliers who deliver energy to
end-use customers, specifically, “entit[ies] engaged in the retail sale of electricity to end-use
customers located within the state.” RPS standards are calculated as a portion of total annual
retail load. Since Metropolitan serves no retail end-use customers, it is not subject to the current
RPS Program.
Under the current RPS Program, IOUs are subject to an RPS mandate, enforced via the CPUC,
requiring IOUs to acquire certain percentages of renewable energy resources by certain dates,
specifically setting targets of 20 percent of total retail sales being met with renewable energy
resources by 2010. Existing law defines what qualifies as “renewable energy resources” for
IOUs and the CPUC determines the amount of generation that counts toward meeting the RPS
standard. Among other things, only small hydroelectric generation facilities having a maximum
generation capacity of 30 MW are considered a renewable energy resource. This limit prevents
facilities, like Metropolitan’s plant at Diamond Valley Lake and others that can generate over 30
MW per year, from counting as a renewable energy resource for purposes of meeting the current
RPS.
Publicly owned utilities that sell to retail customers are also required to develop RPS programs,
although they retain considerable discretion in determining what qualifies as a renewable energy
resource and when they will achieve their RPS target because LPOEUs are self-regulated. For
example, many LPOEUs have included energy from hydroelectric power resources that exceed
the 30 MW limit in reporting their RPS results. The CEC has very limited jurisdiction over the
LPOEUs self-regulated RPS programs, limited primarily to review and reporting functions.
MWH
3-3
Plant-wide Solar Feasibility Study
Pending legislation proposes to mandate the RPS 33% by 2020 goal on LPOEUs, but only as to
retail sellers. Because Metropolitan and DWR (and SWP) are not retail sellers, the current and
proposed RPS mandates do not apply to them. Also, as a state agency, DWR is not an LPOEU
and is expressly exempt from RPS laws so the RPS standards in existing law and pending
legislation do not apply to SWP.
AB-32
In 2006, the Legislature enacted Assembly Bill (AB) 32, the Global Warming Solutions Act,
which set a goal to reduce greenhouse gas (GHG) emissions in California by 25 percent by 2020.
It directed the California Air Resources Board (CARB) to begin developing discrete early
actions to reduce GHG while also preparing a scoping plan to identify how best to reach the
2020 limit. The reduction measures to meet the 2020 target are to be adopted by the start of
2011, and to be in effect and enforceable by 2012.
Assembly Bill 32 includes a number of specific requirements of relevance to Metropolitan:
•
CARB shall prepare and approve a scoping plan for achieving the maximum
technologically feasible and cost-effective reductions in GHG emissions from sources or
categories of sources of GHGs by 2020. The scoping plan, approved by the CARB
Board December 12, 2008, provides the outline for actions to reduce GHGs in California.
The approved scoping plan indicates how these emission reductions will be achieved
from significant GHG sources via regulations, market mechanisms and other actions.
The scoping plan identifies increasing the RPS standards to 33% by 2020, the
development of a carbon cap and trade program, and a public good charge on water as
potential mechanisms to achieve GHG reductions.
•
Identify the statewide level of GHG emissions in 1990 to serve as the emissions limit to
be achieved by 2020. In December 2007, the Board approved the 2020 emission limit of
427 million metric tons of carbon dioxide equivalent (MMTCO2E) of GHGs.
•
Adopt a regulation requiring the mandatory reporting of GHG emissions. In December
2007, the Board adopted a regulation requiring the largest industrial sources to report and
to verify their GHG emissions. The reporting regulation serves as a solid foundation to
determine GHG emissions and track future changes in emission levels.
•
Identify and adopt regulations for discrete early actions that could be enforceable on or
before January 1, 2010. The Board identified nine discrete early action measures
including regulations affecting landfills, motor vehicle fuels, refrigerants in cars, tire
pressure, port operations and other sources in 2007 that included ship electrification at
ports and reduction of high global warming potential gases in consumer products.
Regulatory development for the remaining measures is ongoing.
Currently, except for reporting requirements associated with its Colorado River Aqueduct load,
Metropolitan is not directly affected by proposed regulatory mandates or requirements. Hence,
any carbon reduction actions that Metropolitan enacts are on a purely voluntary basis. However,
MWH
3-4
Plant-wide Solar Feasibility Study
it is possible that future regulatory changes could affect Metropolitan directly. Also, the
proposed public goods charge on water would indirectly impact Metropolitan’s ability to
increase water rates, adding to the overall cost of water conveyance statewide. Thus,
Metropolitan, like all other retail customers, will share in the costs of electric utility
implementation of AB 32. Finally, state regulators are beginning to coordinate AB 32 and RPS
efforts, intertwining the mandates and goals of both programs. For these reasons, Metropolitan
is carefully monitoring AB 32 and recognizes the potential for future impacts. The SPP policy
goals provide for a means to mitigate this risk, as well as Metropolitan’s exposure to future
carbon related fees.
While no federal plan for GHG reduction currently exists, bills have been introduced that would
establish a cap and trade market and limit GHG emissions. It is likely that federal legislation on
GHG reduction or limits will be enacted within the next two sessions of Congress. Such
legislation could pre-empt AB 32.
Sale of Excess Renewable Generation
The three programs that allow utility customers to sell excess renewable generation are netmetering, feed-in-tariff (FIT), and virtual net metering. Net-metering allows customers to
receive a retail level credit (in kWhs), for excess power placed on the grid. However, if the
customer generates more than he/she consumes over the course of a year, the credit is eliminated
and the customer is not paid for that excess generation. A FIT allows customers to sell their
generation to the utility at a fixed wholesale rate which is less than the retail rate paid by the
utility customers. Both net-metering and FIT programs apply the credit or sale to the location at
which the customer is generating the renewable energy. Virtual net metering permits a customer
to credit generation in excess of its energy use at one location against its energy uses at another
location within the same utility’s jurisdiction. This is particularly helpful for public agencies or
commercial customers with multiple locations within a single utility jurisdiction.
Net Metering – SB 656 & AB 58
Net metering is an electricity policy for consumers who own (generally small) renewable energy
facilities, such as wind, solar power or home fuel cells. “Net”, is used in the sense of meaning
“what remains after deductions” — in this case, the deduction of any energy outflows from
metered energy inflows. Under net metering, a system owner receives retail credit (in kWhs), for
whatever generation is in excess of its energy consumption. However, under California netmetering law, if you generate more electricity than you use over a 12-month period (which starts
upon beginning of net metering agreement), you will not make any money or get any credit for
it, in effect you give away your extra energy if you do not use it. To remedy these losses,
renewable energy advocates are working to enact FITs as a complement to net-metering and to
incentivize additional renewable production. In addition, the CPUC regulations provide that the
customer maintains ownership of all of the renewable energy credits generated by the system,
including the credited energy.
California’s initial net metering law was significantly expanded in 2001, with enactment of
Assembly Bill 58, and now allows retail customers to install renewable energy facilities sized up
to 1 MW. AB 58 is applicable to all IOUs and LPOEUs except LADWP, which it expressly
MWH
3-5
Plant-wide Solar Feasibility Study
exempts.4 Since January 2001, utility customers have installed 596 net metered projects totaling
25.1 MW.
California’s net metering law, codified in California Public Utilities Code Section 2827,
currently caps the utilities’ obligations to allow net metering facilities to an amount equal to two
and a half percent of the utility’s total aggregate peak demand. There are pending legislative
efforts to increase this cap.
Section 2827 exempts net metering customer-generators from “standby rates,” which are
monthly charges based on costs the utility incurs for installing and maintaining distribution
infrastructure to serve the customer’s load when the customer’s generating system is not
operating. Section 2827 also exempts customer generators from any additional demand,
interconnection, or other charges not paid by a customer without net metering.
While exempt from the state net metering program, DWP has developed its own net metering
program which allows credits to accumulate until the termination of service, at which point they
are given to the utility without compensation.
Feed-In-Tariffs – AB 1969 & SB 380
A feed-in tariff is an incentive structure to encourage the adoption of renewable energy through
government legislation that requires electricity utilities to buy wholesale renewable electricity at
established rates set by the government.
The California Feed-In Tariff Program (FIT Program) was developed to provide further
incentives for development of smaller wholesale renewable energy facilities in California. Unlike
net metering, where system owner receives a credit in kWhs for the generation that is in excess
of a customer’s needs, under a FIT the energy placed onto the grid is sold to the utility at
wholesale rates. There are two options when selling electricity under a FIT: all energy or excess
energy. Under the all energy option, the system owner sells the total production of the system to
the utility at wholesale rates and purchases all of its electrical demand at retail rates. Under the
excess energy option, generation onsite is first used to meet system demand and excess
electricity is sold to the utility at wholesale rates. In either option, the utility receives the
renewable energy credits for the electricity it purchases and can count that electricity toward its
RPS. In addition, feed-in-tariffs cannot be used in conjunction with the CPUC’s California Solar
Initiative (CSI), Self-Generation Incentive Program (SGIP), the Renewable Portfolio Standard
(RPS) program, net metering programs, or any other ratepayer funded generation incentive
program.
Initially, under AB 1969, enacted in 2006, FITs were limited to installation of renewable
generation at publicly owned water and wastewater treatment facilities located in IOU service
territories. However, the FIT Program was expanded in 2008 with the passage of SB 380,
4
California Public Utilities Code § 2827(b)(3) exempts LADWP by definition: “Electric distribution utility or
cooperative” means an electrical corporation, a local publicly owned electric utility, or an electrical
cooperative, or any other entity, except an electric service provider, that offers electrical service. This section
shall not apply to a local publicly owned electric utility that serves more than 750,000 customers and that also
conveys water to its customers.
MWH
3-6
Plant-wide Solar Feasibility Study
making FITs available for all wholesale renewable generation facilities up to 1.5 MW, and until
500 MW of generation is installed5. The CPUC is currently engaged in rulemaking to expand the
FIT to larger renewable facilities. The FIT Program only applies to CPUC-regulated
jurisdictions.
Metropolitan may be able to benefit from the FIT Program for solar facilities within SCE’s
service area, although it is unclear whether the FIT rate is sufficiently high to warrant its use.
However, there has been recent controversy over CPUC’s authority to implement FITs. SCE
recently argued that the development of FITs establishes wholesale electric rates which are
solely within FERC’s jurisdiction and therefore outside of the CPUC’s ability to regulate. It is
not clear how this debate will be resolved, but Metropolitan will continue to monitor the
proceedings at the CPUC.
Virtual Net Metering – AB 2466
Under California’s “virtual net metering” program, a local government customer6, receives a
credit for generation in excess of a customer’s energy use at one location, which is applied to its
energy use at another location. This program applies only to CPUC-regulated utilities, primarily
the IOUs and not the LPOEUs.
With the passage of AB 2466 in 2008, codified in California Public Utility Code Section 2830,
the Legislature authorizes a local government entity to install a renewable generating facility up
to 1 MW on land it owns or controls, and to apply as a credit any generation in excess of its
energy use at that location to its use at another location. The amount of the credit is based on the
generation component of the customer’s rate schedule and not on the full retail rate. At the end
of every 12-month period, any generation in excess of consumption is given to the utility without
charge. Similar to the net-metering program, the customer owns all RECs for the amount of
energy credited and the electric corporation is not allowed to count the energy toward its RPS
requirements.
Unfortunately, this program is limited to 1 MW. In addition, it is not clear whether Metropolitan
will be able to use virtual net metering or not. First, it is unlikely that Metropolitan would have
excess generation from a facility limited to 1 MW that could be credited against its energy use at
another site. Second, Section 2830(b)(7) of the California Public Utility Code requires that the
“local government does not sell electricity exported to the electrical grid to a third party.” Read
literally, this could prevent Metropolitan from benefiting from the program because of its sales
of hydroelectric power from its small conduit generating facilities to third parties. However, it
appears that the intent of the law was simply to ensure that the renewable energy facility
receiving the credit be used for the local governments own use, and not that no other resources
could be sold. If Metropolitan wishes to pursue this option, it should request an advisory opinion
from SCE regarding its eligibility for this recently initiated program. SCE’s program implies that
5
SCE and PG&E may permit facilities up to 1.5 MW; SDG&E may permit facilities up to 1 MW
“Local government” is defined broadly as “a city, county, whether general law or chartered, city and county,
special district, school district, political subdivision, or other local public agency, if authorized by law to
generate electricity, but shall not mean the state, any agency or department of the state, or joint powers
authority.” Cal. Public Util. Code § 2830(a)(5). Metropolitan qualifies as a political subdivision and a local
public agency under this definition
6
MWH
3-7
Plant-wide Solar Feasibility Study
it cannot be used in combination with its net metering program, so Metropolitan may choose to
use net metering instead if this anomalous issue is not readily resolved.
METROPOLITAN LOCAL ELECTRIC JURISDICTIONS’ SOLAR PROGRAMS
Metropolitan’s solar program is initially focused on the development of solar facilities at its five
water treatment plants: Joseph P. Jensen, F.E. Weymouth, Robert A. Skinner, Robert B. Diemer,
and Henry J. Mills WTPs. The Jensen plant is located in Los Angeles County and receives retail
electric service from the Los Angeles Department of Water and Power (LADWP). The Mills
plant is located in and receives retail electric service from the Riverside Public Utilities. The
remaining three plants—Weymouth (located in Los Angeles County), Skinner (located in
Riverside County), and Diemer (located in Orange County)—are within Southern California
Edison’s service area. In addition to plants, small generation projects may be developed at the
Metropolitan headquarters building located in Los Angeles County in LADWP’s service area.
Future studies will also analyze the feasibility of solar along the Colorado River Aqueduct,
largely in Riverside County. In order to better assess the first phase of the solar program,
development at Metropolitan water treatment plants, a closer analysis of the available programs
in the service areas of SCE, RPU, and LADWP is required.
Southern California Edison
SCE is an investor-owned utility (IOU) regulated by the CPUC. Metropolitan’s Weymouth,
Skinner, and Diemer WTPs lie in SCE’s service area, and could benefit from its well-developed
solar initiative programs. These primarily include CSI and net-metering.
Under CSI, Metropolitan is able to obtain incentives for the development of solar facilities,
which are discussed in detail above and applied in the WTP case studies throughout this study.
Under the net-metering program, Metropolitan could net meter energy produced from a solar
facility up to 1 MW in size. It is less clear whether Metropolitan may benefit from SCE’s feedin-tariff or virtual net metering programs.
The feed-in-tariff program would allow Metropolitan to sell energy from a solar facility, up to
1.5 MW, to SCE. However, this tariff has been controversial. Metropolitan is monitoring the
CPUC proceedings in the hopes of benefiting from it in the future. As noted above, it is unclear
whether Metropolitan may benefit from the virtual net metering tariff because of its sales to
third-parties, but Metropolitan should seek an opinion from SCE regarding this issue because it
isn’t clear the program was intended to preclude application to Metropolitan. However,
Metropolitan will have to opt for either net-metering or virtual net metering at each of its
facilities, and may choose to go with the latter to avoid any controversy.
Riverside Public Utility
RPU is the subdivision of the City of Riverside, and provider of local utility service to the city’s
approximately 312,000 residents. Metropolitan’s Mills plant lies within RPU’s service area and
its solar programs would be subject to RPU approval. RPU is a LPOEU and has limited solar
initiative programs, but it is not prohibited from developing new or customer-specific programs.
MWH
3-8
Plant-wide Solar Feasibility Study
RPU’s lone program is the Non-Residential Photovoltaic (PV) System rebate program, under
which it implements the SB 1 and net-metering mandates. Under this program, RPU provides
financial incentives to business customers who purchase and install solar energy systems. The
program offers a $3.00 per watt rebate not to exceed 50% of the project cost up to an incentive
cap of $50,000 per flat rate customer. The incentive cap for demand customers is $200,000 and
the incentive cap for large industrial time-of-use customers is $500,000. The goal is to provide a
rebate to five non-residential customers per fiscal year for installing qualified PV systems. RPU
customer generators are eligible if they have solar facilities with a capacity of not more than 1
MW that are located on the customer’s premises, are interconnected and operating in parallel
with the RPU’s transmission and distribution facilities, and are intended primarily to offset part
or all of the customer’s own electrical requirements on the premises. Applicants must execute
(1) a Net Energy Metering (NEM) Agreement with the City of Riverside Public Utilities prior to
final connection to the grid and before any incentive can be paid and (2) if requested by RPU, an
agreement for receipt of incentive funds.
In addition to allowing Metropolitan to construct and operate its own solar system, RPU’s rebate
program appears to allow third-party ownership via a power purchase agreement. However,
Metropolitan should negotiate this issue with RPU to confirm that third-party ownership
arrangements are allowed, in addition to any alternative arrangements.
For future solar facilities at its Mills plant, Metropolitan could apply for this program or
negotiate with RPU to develop a site-specific project. Given the limitations of the current
program, Metropolitan should consider working with RPU to develop a more generous incentive,
if possible.
Los Angeles Department of Water and Power
LADWP is the largest municipal utility in the nation. Metropolitan’s Jensen plant, Union Station
headquarters building, and Soto Street maintenance facility are located in LADWP’s service
area.
In compliance with SB 1, LADWP has implemented its Solar Photovoltaic Incentive Program
(Incentive Program) that provides an incentive payment to LADWP customers that purchase and
install their own solar power PV systems. LADWP’s has set aside $313 million to fund its
incentive program.
Under its program, LADWP provides incentive payments for solar facilities up to 1 MW per
billing meter, per fiscal year, although actual system size may be larger based on historic annual
usage. Subject to the availability of funding, LADWP may allow up to 2 MWs of funding
subject to a reduced incentive payment. In no case will LADWP provide an incentive of more
than 50% of commercial systems of the gross installed system cost, regardless of system size or
incentive level. Any energy generated by the solar power system must be either utilized on site
by the customer or credited back to LADWP in accordance with the city’s net metering
ordinance as it is exempt from the state net-metering requirements as discussed above. Energy
cannot be sold to any other entities.
MWH
3-9
Plant-wide Solar Feasibility Study
To receive an incentive payment from LADWP, customers must apply for and receive a written,
confirmed reservation number issued by the Solar Energy Group. LADWP incentive payments
are based on the estimated performance of the solar system. An annual kilowatt hour output is
estimated and a formula is applied to give the customer a one-time payment for 20 years of solar
production. Details of the incentive payment formula are available in LADWP’s Incentive
Program guidelines (at http://www.ladwp.com/ladwp/cms/ladwp009742.pdf). Customers may
elect to have ownership of the Renewable Energy Credits (RECs), but incentives are
proportionally reduced based on this ownership.
LADWP’s rebate program currently prohibits third-party ownership via a power purchase
agreement. However, LADWP does allow third-party ownership through leasing and other
agreements that are not based on payments for energy production.7 PPAs and leasing agreements
typically provide similar results.
Metropolitan’s Los Angeles facilities--Jensen plant, headquarters building, and Soto Street
maintenance facility--are eligible for DWP’s Incentive Program, including its net-metering
provisions.
SUMMARY
In summary, Metropolitan may benefit from several statewide solar initiatives. SCE, RPU, and
LADWP all provide incentive payments and net-metering benefits. However, most net-metering
programs are limited to 1 MW at this time. SCE also provides a FIT for up to 1.5 MW facilities,
although the future of this program is in question as discussed above. There are numerous
legislative and regulatory proposals to increase the statewide solar programs, including proposals
to increase the statewide CSI caps and net-metering and FIT allowances. Metropolitan will
continue to monitor these programs and work with public utility interest groups, including the
California Municipal Utility Association, to promote the development of more beneficial state
and local solar incentives. Metropolitan will also continue to monitor parallel renewable energy
and GHG initiative as the federal level in coordination with the American Public Power
Association.
7
For example, LADWP recently allowed the Metropolitan Transit Authority (MTA) to install a rooftop solar
facility within its service area where Bank of America owns the solar facility and sells it to MTA over time via
a long-term lease, like an installment sale. MTA financed the construction via municipal bonds, paid annually.
This arrangement is referred to as a tax exempt leaseback project or TELP. Metropolitan is assessing whether
TELPs would be beneficial to it.
MWH
3-10
Plant-wide Solar Feasibility Study
SECTION 4
PROJECT AND SOLAR INDUSTRY BACKGROUND
As the regional water wholesaler for Southern California, Metropolitan’s five water treatment
plants are designed to have relatively consistent treatment operations throughout the day and
week. Metropolitan does not supply water directly to customers; water is supplied to 26 member
agencies. As such, the WTPs are not required to meet the rapidly changing water demand typical
of a municipal facility with customer connections. For instance, the treatment approach does not
have to address the fluctuating distribution system service pressures, fire flow demands, flushing
flow requirements, and similar requirements typical of a municipal utility. Instead, the treatment
approach is designed to ensure most efficient treatment operations considering seasonal variation
in water source, water supply, and water demand.
Metropolitan’s treatment plant operations vary, and as a result, the energy demands are not
constant and exhibit considerable diurnal (daily), weekly, and seasonal variations. As part of this
study, treatment volume and energy consumption patterns of the treatment facilities were utilized
to determine the optimal size of solar power generation at each facility. As solar power
production also exhibits both diurnal and seasonal variations, facility sizing needs to be
optimized to minimize the cost of lost energy.
FACILITY DESCRIPTIONS
There are five water treatment plants owned and operated by Metropolitan: Joseph P. Jensen,
F.E. Weymouth, Robert A. Skinner, Robert B. Diemer, and Henry J. Mills. These treatment
plants are located in Los Angeles, Riverside, and Orange Counties.
All five treatment plants employ conventional treatment, which consists of primary disinfection,
coagulations, flocculation, sedimentation, filtration, and post-disinfection. Metropolitan is
currently upgrading the primary disinfection process at all plants from chlorination to ozonation.
Ozone facilities are being phased in over several years and have already been built at the Henry
J. Mills plant and the Joseph P. Jensen plant. Ozone facilities will be completed at the Robert A.
Skinner plant in 2009 and construction at the remaining two plants will be completed by
approximately 2013. Conversion of the treatment plants to utilize ozone disinfection is expected
to increase retail energy consumption by up to 100 percent at each plant. The increased energy
demand provides incentive for Metropolitan to pursue solar energy facilities at each WTP to
reduce the on-peak retail electricity consumption at the plants.
ELECTRICAL DEMAND: HISTORICAL AND PROJECTED
Electrical demand from the five water treatment plants was 43 million kWh in 2008 and will
increase in the future due to the addition of ozone disinfection facilities at all the WTPs.
Data from the Mills and Jensen WTPs shows that when ozonation came online, energy use due
to the ozone was approximately 50 percent of the total energy consumption of the plant.
Therefore, based on the experiences at the Mills and Jensen plants, energy use at the other three
plants can be expected to double as ozone is brought online. A summary of the expected energy
MWH
4-1
Plant-wide Solar Feasibility Study
use post ozone can be found in Table 4-1.
Table 4-1
Expected Energy Consumption with Ozonation
Water
Treatment
Plant
Energy
Consumption PreOzone, 2008 (kWh)
Equivalent
average demand,
kW
Energy Consumption
Post-Ozone (kWh)
Equivalent
average demand,
kW
Joseph P. Jensen
Ozone already online
-
16,721,000(actual)
1,909
Henry J. Mills
Ozone already online
-
6,261,000 (actual)
715
F.E. Weymouth
10,703,788
1,222
21,407,576 (projected
2,444
Robert A.
Skinner
10,481,529
1,197
20,963,058 (projected)
2,393
Robert B.
Diemer
5,049,691
576
10,099,382 (projected)
1,153
OPTIONS FOR SELLING SOLAR DISTRIBUTED GENERATION TO AN
INTERCONNECTED UTILITY IN CALIFORNIA
Metropolitan’s short-term goal of the SPP is to achieve 50% carbon reduction at all distribution
facilities, including all five WTPs. To help achieve this goal there are several renewable energy
options. Implementation of 9 MW of solar generation facilities described herein would reduce
Metropolitan’s projected retail-level carbon footprint by approximately 20%. The planned
conversion of the Yorba Linda Power Plant to meet all of the Diemer plant’s electrical needs
would further reduce Metropolitan’s retail-level carbon footprint by an additional 10%. Moving
forward with these solar power generation projects at this time, along with identification of
additional greenhouse gas reduction measures and projects under the SPP Implementation Plan,
would allow Metropolitan to meet the near-term SPP goal of a 50% carbon footprint reduction
by 2014.
Distributed Generation
Distributed generation (DG) generally refers to energy that is generated and used on-site. In
contrast, grid energy is generated at centralized power plants and distributed to consumers.
Entities engaged in distributed generation are often connected to the power grid to supply energy
when demand is greater than production. However, grid-connected distributed generation raises
significant technical concerns such as regional grid stability and capacity. Specifically, DG can
induce voltage sags and swells, harmonics and flicker due to non-centralized control of the DG
power production and export. Thus export of distributed generation to the grid is strictly
regulated.
To avoid technical issues associated with connecting to the grid, distributed generation can also
be isolated from the grid. In 2005, the California Energy Commission (CEC) report “Distributed
Generation Interconnection Monitoring: The FOCUS-II Project” included a two-year study
evaluating the effects of isolated distributed generation on the California utility grid. Their
MWH
4-2
Plant-wide Solar Feasibility Study
results indicated that “power quality at the DG systems was generally better than that of the
benchmark surveys.” They found that there were no events of the DG impacting the distribution
system. This study would indicate the general stability of distributed generation power sources.
While the 9 MW of solar will not offset 100 percent of the electrical demand of the WTPs,
during peak solar-production the energy generated by the solar system may be in excess of
energy demand. There are four implementation scenarios to account for energy produced in
excess of demand: behind-the-meter generation, net metering, feed-in-tariffs, and energy storage.
The second and third scenarios involve the export of excess electricity to the grid while the first
and fourth scenarios involve the system being isolated from the grid.
Behind-the-Meter Generation
Behind-the-meter generation refers to distributed generation that is not connected to the grid and
electricity generated in excess of demand is lost. Behind-the-meter generation can be used to
offset purchases of grid electricity and can be financially optimized by timing the peak energy
production to coincide with peak price and demand periods. However, since excess electricity is
lost, utilizing behind-the-meter generation requires careful selection of system size to minimize
those energy losses. The implementation of behind-the-meter generation will require a permitting
process, tight electrical controls, and likely negotiation of standby charges. Behind-the-meter
generation can be combined with net energy metering to increase the effective size of the solar
power installation, but will require two independent sets of onsite electrical controls and
metering in order to comply with regulatory requirements.
Net Energy Metering
Net energy metering (NEM) generically refers to the concept where distributed generation, in
excess of demand, is fed back into the grid and the energy generator receives a credit (in kWh)
for the electricity. This results in a form of electricity grid storage. In periods where the energy
demand is greater than the energy production the credit is reduced, and thus the generator is
metered for the “net” energy consumption. Net energy metering is generally only allowable in
states that have established an applicable energy policy, due to having to push the utilities to
overcome the same technical issues that confront grid-connection distributed generation systems.
In California, net metering systems are limited to a capacity of 1 MW. For additional
information regarding net metering regulation, please see Section 3.
Feed-in Tariffs
A feed-in tariff is an incentive structure to encourage the adoption of renewable energy through
government legislation that requires electricity utilities to buy renewable electricity at rates set
by the government. In California, the feed-in-tariff program is capped at 1.5 MW of renewable
energy generation per site and the electric utility will purchase either the total or the excess
energy generated by the system at wholesale rates. Renewable energy credits will be transferred
to the utility for the amount of electricity they purchase and that electricity will count towards the
utilities RPS. Current feed-in tariff rate structures are sufficiently low that interconnection using
a feed-in tariff at this time is not feasible, especially when feed-in-tariffs cannot be used in
conjunction with the CPUC’s California Solar Initiative (CSI), Self-Generation Incentive
Program (SGIP), net metering programs, or any other ratepayer funded generation incentive
program. Thus it is not optimal to implement a feed-in-tariff solar system in place of a behind-
MWH
4-3
Plant-wide Solar Feasibility Study
the-meter generation facility that can receive rebates and other incentives. Should a feed-in-tariff
system be implemented it should be noted that for carbon reduction goals, the feed-in-tariff may
only be applied to excess energy so the customer can retain the renewable energy credits for the
renewable energy it uses.
The rules associated with this program are currently under revision which may result in an
increased value for energy sold via this program. For additional information regarding feed-intariff regulation, please see Section 3.
Onsite Storage
Onsite energy storage utilizes a technology, such as batteries, to store electricity so that it can be
used at a later time. In the case of solar generation, electricity produced during the day could be
stored onsite and used during the night. With an appropriately sized system, this could provide
100 percent of the electricity demand. There are several technologies that can be used to store
electricity, though only batteries would be appropriate for applications in the range of a few
mega-watts.
There are more than half a dozen different type of batteries that show varying degrees of promise
including: Polysulfide Bromide Flow Batteries, Vanadium Redox Flow Batteries (VRB), Zinc
Bromine Flow Batteries, Sodium Sulfur Batteries (NaS), Lithium Ion Batteries, Traditional
Lead-Acid Batteries, and Metal-Air Batteries. Of these batteries, VRB and NaS batteries show
the most promise. These technologies, however, have only started to be utilized at a commercial
level. Installations of VRB batteries have occurred in California, Florida, and Utah; however the
projects were not seen as successful. Installations of NaS batteries have mostly occurred and
been successful in Japan where conditions are significantly different than in the United States.
Though some installations have been done in the United States, these installations have occurred
in the past few years and are too recent to determine the success of the project. Both VRB and
NaS batteries are expensive, costing thousands of dollars per kW. Due to this price, these
technologies are currently best suited to projects were storage is needed and few if any
alternatives exist.
Given the state and cost of energy storage technology and the cost of retail grid electricity in
California, it is currently economically infeasible to use energy storage to meet net zero grid
electricity use. Storing renewable energy, however, could be an option in the future if conditions
change or if the priority of other goals, such as net zero grid electricity use, significantly
increases.
Combined Program Approach
The economic return on energy storage is currently negative under current regulatory and
financial conditions. Currently, feed-in-tariffs cannot be cost effectively utilized to achieve net
zero grid use because the generating agency will lose the right to the renewable power (in the
form of a REC) when the electricity is sold to the electricity utility, ratepayer funded generation
incentive programs are not available to feed-in-tariff systems, and tariff prices are not presently
cost competitive.
MWH
4-4
Plant-wide Solar Feasibility Study
All of the proposed solar projects at the WTPs are to be designed to offset on-peak electricity
consumption. The most robust methodology of generating more energy than the 1 MW net
metering is to combine the various programs. First, behind-the-meter generation is used to
supply the base load of the WTP and second, net metering is applied to the energy above the
base load. A solar system should be optimized to minimize wasting energy to ground but will
typically require some level of wasting (1 to 5% on low demand days).
MARKET ISSUES: EVALUATION OF SOLAR INDUSTRY
In an emerging market, it is difficult to predict the benefits of being an early adopter of a
technology or waiting for a better price. It is commonly discussed in the industry that solar
energy will reach retail electric rate (aka, grid) parity between 2012 and 2015. Solar market
forecasts predict that the cost of electricity from solar systems will decline during this period
from its present $0.25/kWh to about $0.10/kWh. Solar panel manufacturing prices are in steady
decline and thin film panels are or will be at a $1.00/watt cost very soon (down from $4$6/watt). Manufacturing systems are constantly reducing the time and energy required to
produce the panels and contractor competitiveness is slowly gaining ground. Furthermore,
funding mechanisms for these systems paired with federal and state incentives is in its infancy.
Analyzing the solar industry is a shell game of assumptions. On a macro level, the need for
renewable energy is spurred by the threat of oncoming climate change. It is safe to say that there
is a cost for dealing with climate change that will affect all aspects of all construction projects
and business as usual activities. There is currently no price of carbon incorporated into either
Metropolitan’s projects or the manufacturing industry. Incentive programs are steadily declining
in the State as PV equipment prices decline resulting in a net stagnant price to install a system in
the State. If calculated out with current CSI rebates (provided by SCE), over the life of a project,
the system will generate power at a cost of about $0.12/kWh which is nearly at the same retail
parity level of 2015. Though equipment price may decline from a raw manufacturing
perspective, the new price of doing business in a carbon constrained world will increase. It can
be perceived now that in order to win market share, key solar integrators are buying projects with
little or negative profit in order to beat the pack of competitors which many of whom are offering
nearly identical technologies. One can also safely assume that during this growth period, there
will be price instability for several years that can be to the advantage of Metropolitan.
In the end, and as presented in this document, it is cost effective for Metropolitan to move
forward with solar installations now. Though it is uncertain that installing solar system in 20092010 will be the absolute lowest price point over the next 5-10 years, solar is still a sound
investment and will result in medium and long term operations cost savings.
MWH
4-5
Plant-wide Solar Feasibility Study
SECTION 5
SOLAR SIZING ANALYSIS
DATA ANALYSIS
Although there are several methods of implementing solar, there are two preferred methods that
are recommended given the current regulatory conditions: net metering and behind-the-meter
generation. Net metering is the preferred solar installation scenario as solar energy produced in
excess of demand can be credited against later use. This reduces the amount of solar that is
wasted, or not used, depending on the electricity demand and the solar production. Net metering
opens the option for net zero emissions if solar production is greater than energy consumption
over a twelve month period. However, net metering is currently only available for facilities up to
1 MW. Since the energy demand at each of the five proposed solar sites is greater than the
annual production from a 1 MW facility, over-sizing a net metering facility is not a concern.
It is recommended to utilize behind-the-meter generation to serve the minimum standard load at
each plant facility. In addition, it is recommended to install 1 MW of net metering. During peak
hours behind-the-meter generation will meet most of the retail electricity (aka grid) demand and
the excess electricity produced by the 1 MW of net metering will generate electricity credits.
These credits offset electricity consumption during the evening/night time periods when solar
electricity cannot be produced.
Solar sizing for behind-the-meter generation is dependent on the following factors:
1. Variation in electrical energy demand over the day (diurnal variation) and year (seasonal
variation) - Daily variation can occur because of various operational requirements, while
seasonal variation occurs due to variation in water supply, water demand and
temperature.
2. Variation in solar electrical energy production over the day (diurnal variation) and year
(seasonal variation) - Diurnal variation occurs because of weather events and the rotation
of the earth on its axis while seasonal variation occurs because of climate and rotation of
earth around the sun changing the angle of solar incidence.
3. Efficiency of panels – Higher efficiency panels will result in a smaller solar facility size
4. Energy demand per unit volume of water treated – Variation occurs because of changing
energy demand for treatment and disinfection, thus even if treated water volume falls, the
total energy demand might increase.
5. Total water volume treated – After accounting for energy demand per unit volume,
energy consumption will vary with total delivered water volume.
6. Land area available – Land can be a limiting factor because solar generation must occur
onsite.
7. Financing option (power purchase agreement (PPA) versus capital purchase) –
Applicable tax and revenue benefits vary according to the purchasing entity.
8. Future retail electricity prices – Potential greenhouse gas legislation and other factors
MWH
5-1
Plant-wide Solar Feasibility Study
may cause energy prices to increase more rapidly than historical averages.
9. PPA contract terms – Net present value will be determined by base cost and escalation
rate.
10. Cost to install solar – Affects capital purchase directly through purchase price and power
purchase agreements indirectly as the terms of the agreement will reflect the purchase
price.
11. Capital purchase rebates – Will directly offset a capital purchase and indirectly influence
PPA terms.
12. Tax incentives – Reduces net cost of solar installation for PPAs only, since tax incentives
are not available to Metropolitan.
The first step in sizing a solar facility for behind-the-meter generation, whether a capital
purchase or financed through a PPA, is to account for the daily and seasonal electricity demand
patterns. Figure 5-1 shows representative daily variation of grid energy demand pre and post
solar in addition to solar power generated and lost. Wasted energy is the difference between
solar production and grid demand.
MWH
5-2
Plant-wide Solar Feasibility Study
MWH
kWh
0
2,000
4,000
6,000
8,000
10,000
12,000
Figure 5-1
Daily Energy Demand and Solar Generation
15 Minute Data
5-3
12:00 AM
1:00 AM
2:00 AM
3:00 AM
4:00 AM
5:00 AM
6:00 AM
7:00 AM
8:00 AM
9:00 AM
10:00 AM
11:00 AM
12:00 PM
1:00 PM
2:00 PM
3:00 PM
4:00 PM
5:00 PM
6:00 PM
7:00 PM
8:00 PM
9:00 PM
10:00 PM
11:00 PM
Plant-wide Solar Feasibility Study
Typical Solar Power Generation
Typical Wasted electricity
Typical Grid electricity, w/solar
Typical Grid electricity, pre‐solar
To account for daily and annual variation in energy demand, 15-minute energy demand data
(provided by Metropolitan) was analyzed for several years at all WTPs; however a specific
“base” year was chosen to conduct the sizing analysis. This was done to capture the hourly,
daily, and seasonal variation that would be lost if the 15 minute data was averaged over several
years. The smoother distribution of energy demand in an averaged year would result in a closer
matching to the solar production than would actually be realized. The base year was chosen with
regards to monthly and annual historical trends in energy usage and flow, plant upgrades, and
other factors that may influence electrical demand.
The 15-minute data from the base year was then analyzed and compared to the distribution of
solar production. Solar production was given in hourly averages by month and was based on the
Solar Advisor Model for single axis tracking silicon panels. The silicon panels in this model
typically produced 2-2.4 million kWh per MW per year in Southern California. In addition, a
derate factor of 0.77 was assumed. The derate factor accounts for losses from conversion from
DC to AC power. Through comparing the distributions of energy demand and generation, a
distribution of annual solar production and solar consumed by MW capacity was obtained. The
MW capacity was varied, and the resulting solar power production and solar power consumption
was assessed.
Many of the factors that influence the sizing decision vary over time. Thus, to fully optimize the
system, the distribution of solar production and consumption was utilized in net present cost
analysis for both capital purchase and PPA financing. This type of analysis looks at the net
present cost of implementing solar under each financing scenario in comparison to doing nothing
and used a set of assumptions for costs and avoided costs. The calculations were set up so that
the basic parameters could be varied, resulting in automatic recalculation of the costs. Once the
set of assumptions was determined, the MW capacity was varied and the optimal size was
determined when the net present cost was minimized. A negative net present cost represents net
present savings of implementing solar in comparison to doing nothing. Specific assumptions
pertaining to the net present cost analysis are detailed below. Since different solar technologies
generate different quantities of kWhs per installed MW, the optimal size can also be viewed as
an optimal generation level in terms of kWhs.
The optimal size and the net present cost of a system are significantly impacted by the values
chosen for the assumptions made in order to size the system and sensitivity analysis was
conducted to determine the impact that the various assumptions had in the final size of the
system. A more detailed description of the sizing and sensitivity analysis can be found in
Appendix B.
SOLAR SYSTEM SIZES
Given all of the assumptions and sensitivities described above, the optimal size for solar
facilities, including net metering, by plant, can be found in Table 5-1. The optimal size can also
be viewed from an electrical production standpoint, thus the annual production from the optimal
size is included in Table 5-1. Higher efficiency panels will produce more kWh per MW, and so
the associated size to meet the plant’s demand will be smaller.
MWH
5-4
Plant-wide Solar Feasibility Study
Additional supporting calculations can be found in Appendix A. At the optimal size on behindthe-meter generation production facilities, the annual quantity of solar produced is slightly larger
than the annual quantity of solar energy consumed. This is because during peak solar
production, solar production is greater than the solar consumption which results in excess energy
discharging to ground. Discharging 1% to 5% under these extreme supply/demand conditions of
energy is optimal under both financing options because the benefit of the additional capacity in
terms of additional solar production. Use in non-peak hours outweighs the additional cost
associated with the loss in system efficiency, up to a certain point.
This sizing analysis is based on supply and demand matching only. Comparison of the
calculated optimal level of power generation and facility space constraints will be evaluated in
the Preliminary Design Report.
Table 5-1
Calculated Optimal Solar Sizing for Behind-the-Meter Generation
Capital Purchase
Treatment Plant
Solar
Size
(MW)
Initial Annual
Production
(kWh)
PPA
Solar
Size
(MW)
Initial
Annual
Production
(kWh)
Jensen
2.2
4,400,000
2.0
4,000,000
Weymouth
2.1
4,200,000
1.8
3,600,000
Skinner
3.2
6,400,000
3.0
6,000,000
Mills
1.0
2,000,000
0.9
1,800,000
Diemer
1.0
2,000,000
0.9
1,800,000
9.5
19,000,000
8.6
17,200,000
Total
Note: *The Diemer plant will not require solar electricity because the Yorba Linda
Hydroelectric Plant will satisfy the WTPs electric demand.
ASPECTS TO SOLAR IMPLEMENTATION
Solar installations are a significant financial undertaking. In addition, a host of regulatory
restrictions, incentive programs, and other issues also affect the decision on how much or
whether to install solar facilities at a particular location. Financing remains one of the largest
components related to solar installations due to a host of different tax incentives, rebate
programs, grant options, and financing options that are applied differently for commercial,
residential or municipal installations. In addition there are potential revenue streams that could
be available in the future, pending greenhouse gas regulations. Other considerations in the
installation of a solar facility include technical and operational issues. While solar systems
generally have low maintenance requirements, the inverters need to be replaced every decade. In
addition, special consideration needs to be given in selecting the size and location of the inverters
to minimize the losses associated in long runs of cable. Interconnection issues with the grid must
be assessed if net metering is allowed. Also, some rebate programs require metering by a third
party representative. These and other related issues significantly impact the decision to install
MWH
5-5
Plant-wide Solar Feasibility Study
solar.
Financial Aspects
There are three parts to implementing a solar energy system, whether through a capital purchase
or a PPA: direct cost of purchasing the solar panels and related accessories, tax incentives and
rebates, and the value of the energy derived from the system. There are several tax incentives
and rebates available for the implementation of renewable energy systems, both at the federal
and state level. These incentives are designed to offset the capital purchase of the solar system
and are not identical for private and public entities. In some cases, incentives that exist for
private entities do not exist for public ones. Some of the incentive programs designed to offset a
portion of the capital cost are described below. In the case of a capital purchase, financial
analysis looks directly at the cost of purchase, the available incentive programs, and the value of
energy derived from the system. In the case of a PPA, the financiers analyze these factors and
determine a rate and rate escalator for the electricity produced from the facility that they would
be willing to accept. The value of energy derived from the system includes a comparison to grid
prices, renewable energy credits, and potential greenhouse gas emission credits. PPA contracts
can be written so that renewable energy and potential greenhouse gas emission credits reside
with the entity purchasing the solar electricity.
Metropolitan Financials
Metropolitan does not currently have the available standing capital to make an outright purchase
on the order of tens of millions of dollars or more. To make a purchase of this magnitude,
Metropolitan typically issues municipal bonds for the amount of the intended purchase. The
issuance of bonds allows Metropolitan to finance large purchases over a 30 year period. Bonds
issued by a municipal entity are afforded certain advantages. One advantage is that the interest
earned from municipal bonds is generally tax exempt at the federal and state level, which allows
the interest rate on the bonds to be smaller than those offered by private companies. The current
interest rate on bonds issued by Metropolitan is 4.2%.
California Solar Initiative and SB 1
The California Solar Initiative (CSI) is a program through the California Public Utilities
Commission that provides financial incentives for solar energy systems. The financial incentives
are specified for IOUs while LPOEUs can set their own terms that comply with the mandates in
SB-1. In general, “CSI rebates” refer to the IOU rebate program while the LPOEUs programs
are considered to be “other” rebate programs. Regardless of the program, rebates are only
available for systems up to 1 MW,. For additional information regarding the rebates available
under the California Solar Initiative and SB 1, see Section 3.
Revenue
Potential revenue streams depend on the entity purchasing the solar system. Additional revenue
streams may be available in the near future in the form of greenhouse gas emission reduction
credits, pending future legislation. For a system financed through a PPA, the available revenue
streams are assessed by the financiers and the agency is only responsible for paying a contract
rate for the electricity produced by the system. Depending on the terms of the contract, the
agency may also own the renewable energy redits (REC) produced by the system. Under a
MWH
5-6
Plant-wide Solar Feasibility Study
capital purchase some of the rebate programs may provide a revenue stream for a portion of the
life of the solar system, the RECs are owned by the owner of the solar facility. In either
financing option, the use of solar electricity reduces the electricity demand from the grid,
resulting in avoided costs.
Renewable Energy Credits
Renewable Energy Credits (REC) provide a method for commoditizing renewable energy despite
the fact that all electricity becomes indistinguishable once it becomes part of the grid. A REC
represents verification that a unit of electricity was generated from a renewable source and the
owner of a REC can claim that they used renewable energy in the amount of the REC. RECs can
also be purchased for a specific type of renewable power such as wind or solar. If a producer of
renewable energy would like to produce and sell RECs they must hire an organization to certify
the REC and give it a unique ID number to avoid double counting. Organizations that perform
REC certification include: Green-e, Environmental Resources Trust’s EcoPower Program, and
the Climate Neutral Network. While these organizations are attempting to standardize the
certification process and have a national database, large scale regulation of the REC market is
lacking.
The money spent on a REC is the value individuals place on the renewable power the REC
represents. RECs are only tradable within the United States and may also be called Green Tags
or Tradable Renewable Certificates (TRCs). While this type of credit does not directly enhance
the amount of renewable power on the grid, it does provide an additional subsidy to producers of
renewable energy. Also, it should be noted that due to the fact that RECs are sold in units of
energy, they can only be used to offset electricity related emissions.
Prices for RECs fluctuate wildly both over time and between companies. According to the US
Department of Energy prices for National Retail REC products ranged from $5 to $56 per MWh
in 2008. Price volatility for RECs is due to many factors. These include: volatile demand and
lack of large scale regulations and standards. In addition, the price varies depending on the
quantity of RECs being purchased. In 2006, the Bonneville Environmental Foundation sold a 1
MW REC for $20 in retail, while the same credit could go for $5-10 for significant commercial
orders (per phone conversation).
While selling the RECs generated from the solar facilities would generate additional income, it is
recommended that Metropolitan retain ownership of the RECs. By retaining ownership of the
RECs, Metropolitan retains the right to claim use of the renewable energy which will reduce
Metropolitan’s carbon footprint and help meet the goals of the SPP.
Greenhouse Gas Emission Offset Credits
While the United States government does not currently regulate greenhouse gas emissions, there
is a greenhouse gas cap and trade program within the United States for those organizations who
wish to participate. The program is run by the Chicago Climate Exchange (CCX). While entry
into the exchange is voluntary, membership involves signing a legally binding contract to meet
the emission reduction targets set by the CCX, which is currently one percent per year.
To assess whether they have met the reduction targets, members must employ the National
MWH
5-7
Plant-wide Solar Feasibility Study
Association of Securities Dealers (NASD) for independent third party verification for their
greenhouse gas inventory. Both member conduction inventories and NASD verification relies
on the inventory rules set forth by the CCX. If members have reduced their emissions below the
target, a Carbon Financial Instrument (CFI) is created and can be sold to a member agency who
has not met their emission target. Members can also generate CFIs through qualifying offset
projects. A CFI represents 100 metric tons of CO2 equivalence and its price is relatively stable
at about $2 per CFI.
Tax Advantages
While rebate programs are in place for municipal agencies, tax advantages currently only exist
for entities or individuals that pay taxes. Tax advantages available for private agencies include
accelerated depreciation, which significantly reduces the tax burden for private agencies in the
years following the purchase of solar panels.
Technical Aspects
Solar technology has been in existence for more than 30 years and is a well developed
technology. The use of silicon is the most traditional and one of the highest efficiency materials
in these cells. New materials such as thin film technology are also on the rise, which use
materials such as Copper indium diselenide (CIS), Copper indium galium selenide (CIGS) and
Cadmium telluride (CdTe). Technically all these systems are feasible for a solar farm
installation at Metropolitan, though the primary driver for selection is financial. Panels are a
major cost component but mounting systems, inverters, switching/breaker design and conduit
runs are all components that need to be optimized.
Site evaluation is the most important part of a solar system design. Grading that obstructs the
sun from hitting the proposed system will drastically reduce the system performance. Ideal sites
should be flat, with un-shaded southern exposure. Grade angles to the south are preferred and in
the case of large systems, these flat areas should be continuous in order to minimize conduit runs
and tracking equipment if used. Care should be taken when developing a site to ensure that
shading impacts and grading costs are minimized.
Operational Aspects
Solar photo-voltaic (PV) generation systems require very little operations and maintenance. Once
the system is calibrated and commissioned, it requires no operator intervention. The system
operating full scale installations of solar PV generation systems varies by location but this
section will discuss the most likely systems to be installed at Metropolitan facilities. In a PPA
program, there is no operation and maintenance work required in the traditional sense. A third
party monitor and its contractor partner will have a relationship where regular monitoring will
analyze data on a daily basis, at minimum, to look for any anomalies. In the event that a field
visit is required, field staff will be dispatched to visit the site and make any necessary physical
repairs. This occurs at no direct or separate charge to Metropolitan. Though on site data and
system I/O points can be fed into the plant SCADA system, this is not required because the
system will be maintained for Metropolitan. The benefit of this to Metropolitan is that there is
no staff time required to run the system which frees staff up to deal with other issues at the plant.
MWH
5-8
Plant-wide Solar Feasibility Study
Maintenance at a solar site however, is very minimal; with the exception of occasional panel
cleaning (which research suggests may not be required) and replacing the inverters every 10
years, there is no regular maintenance required.
In the event that Metropolitan purchases the solar system directly, the duty of operation and
maintenance is dependent on several conditions. For net metered facilities, a third party monitor
is required to operate and maintain the system for the first 5 years. After this period the owner,
unless they opt to contract out the operations for an extended period, will operate the equipment.
Any solar system O&M would be the full responsibility of Metropolitan though again, the option
to outsource operations still exists but is not required.
MWH
5-9
Plant-wide Solar Feasibility Study
SECTION 6
FUTURE POTENTIAL SOLAR FACILITY LOCATIONS
This Study’s main purpose was to identify and recommend solar generation facilities within
Metropolitan’s water treatment plant boundaries. However, additional known Metropolitan
properties exist within the geographic boundaries of Metropolitan’s distribution area that could
become ideal locations for solar renewable energy in the future, should existing laws and
regulations change to allow export of renewable power into the regional utilities power grid. The
most logical and amenable Metropolitan facilities for future solar facilities were evaluated on a
cursory-level. These facilities include existing power plants and other sites where there is
existing electrical demand, infrastructure, available land and close proximity to power lines.
At a minimum, up to 70 MW of additional solar power generation facilities could be
implemented at the six locations identified below. Although these facilities are not feasible
locations at this time, as there are not any substantial loads or demands at these sites that would
allow behind-the-meter generation or net metering; these future facilities could become feasible
with the expansion of net metering laws, feed-in tariffs, or future electrical power wheeling
initiatives.
1.
2.
3.
4.
5.
6.
Foothill Power Plant
Etiwanda Power Plant
Diamond Valley Lake – Wadsworth Pumping and Power Plant
Lake Mathews Power Plant
Eagle Valley Property
Arrow Highway Property
FOOTHILL POWER PLANT
Hydroelectric power plants were constructed at several locations within Metropolitan’s
distribution system to generate electricity and to control the pressure within the system. The
power plants are of three general types: (1) Reaction Turbine, (2) Impulse Turbine, and (3)
Pump/Generator. Metropolitan embarked on a hydroelectric power plant retrofit program in the
late 1970's through the mid-1980's, in part to take advantage of federal energy incentives for
alternative energy sources resulting from the energy crisis during the 1970's and to help offset
the cost of pumping.
The Foothill Power Plant is one of these facilities. Constructed in 1967 and located at the base
of Castaic Lake’s main dam, the power plant sells wholesale power to Southern California
Edison. In 2005 the power plant generated over 65 million kWhs, as water was drawn from
Castaic Lake to meet demands in Metropolitan’s service area through the Foothill Feeder
pipeline.
As can be seen in
Figure 6-1, the Foothill Power Plant has a large contiguous area of open land that is vital to the
construction of a solar power generation facility. In addition, as there are existing connections to
SCE’s distribution system, the infrastructure required to connect to the regional grid exists and
MWH
6-1
Plant-wide Solar Feasibility Study
only minor upgrades would be required to implement a solar generation facility.
A 1 MW facility could ultimately be constructed at the Foothill Power Plant, should laws and
regulations change. The existing plant demand does not warrant construction at this time
however; plant demands in 2007 were slightly over 225,000 kWhs, while a 1 MW solar
generation facility would generate close to or more than 2 million kWhs. This future facility
would become feasible with the adoption of financially attractive feed-in-tariffs or electrical
power wheeling to allow energy generated at this site to offset Metropolitan’s total electrical
load.
ETIWANDA POWER PLANT
Constructed in the early 1990’s and located in Rancho Cucamonga, the power plant sells
wholesale power to Southern California Edison. In 2005 the power plant generated over 95
million kWhs, as water was fed through the Etiwanda Power Plant to the Lower Feeder Pipeline,
to break head and reduce pressure on the Rialto Pipeline.
As can be seen in Figure 6-2, the Etiwanda Power Plant also has a large contiguous area of open
land that is vital to the construction of a solar power generation facility. This land was recently
used for storage of the Inland Feeder’s tunnel lining system, and with completion of that project,
has become available for other land planning purposes. In addition, as there are existing
connections to SCE’s distribution system, the infrastructure required to connect to the regional
grid exists and only minor upgrades would be required to implement a solar generation facility.
A 1 MW facility could ultimately be constructed at the Etiwanda Power Plant, should laws and
regulations change. The existing plant demand does not warrant construction at this time
however; plant demands in 2007 were slightly over 225,000 kWhs, while a 1 MW solar
generation facility would generate close to or more than 2 million kWhs. This future facility
would become feasible with the adoption of financially attractive feed-in-tariffs or electrical
power wheeling to allow energy generated at this site to offset Metropolitan’s total electrical
load.
DIAMOND VALLEY LAKE – WADSWORTH PUMPING & POWER PLANT
The Wadsworth Pumping & Power Plant was constructed in the late 1990’s with implementation
of Diamond Valley Lake (DVL). Located at the west dam of Diamond Valley Lake, water can
be pumped into DVL from the San Diego Canal, although with recent implementation of the
Inland Feeder Project, water will flow via gravity into the lake under abundant water supplies
and normal operating conditions.
In 2005 the power plant generated over 11 million kWhs. When Diamond Valley Lake is at
higher water elevations, the power plant will generate power as water is drawn from the lake to
meet demands in Metropolitan’s service area through the San Diego Canal and connecting
distribution system pipelines.
As can be seen in Figure 6-3 below, the Wadsworth Pumping & Power Plant has three large
MWH
6-2
Plant-wide Solar Feasibility Study
contiguous areas of open land that would be vital to the construction of a large-scale solar power
generation facility. In addition, as there are existing connections to SCE’s distribution system,
the infrastructure required to connect to the regional grid exists and only minor upgrades would
be required to implement a solar generation facility.
Nearly 30 MWs of solar generation facilities could ultimately be constructed at the Wadsworth
Pumping & Power Plant, should laws and regulations change. Diamond Valley Lake has six
separate electrical meters in and around the large reservoir, although in 2005 the total usage was
less than 1 million kWhs. A 30 MW solar generation facility would generate close to or more
than 60 million kWhs. This future facility would become feasible with the adoption of
financially attractive feed-in-tariffs, increased net metering laws, or electrical power wheeling to
allow energy generated at this site to offset Metropolitan’s total electrical load.
Figure 6-1
Foothill Power Plant Solar Facility
MWH
6-3
Plant-wide Solar Feasibility Study
Figure 6-2
Etiwanda Power Plant Solar Facility
MWH
6-4
Plant-wide Solar Feasibility Study
Figure 6-3
Diamond Valley Lake: Wadsworth Pumping & Power Plant Solar Facility
MWH
6-5
Plant-wide Solar Feasibility Study
LAKE MATHEWS POWER PLANT
The Lake Mathews Power Plant was constructed in the late 1960’s. Located northwest of the
main dam at Lake Mathews, water flows from the lake through the power plant to meet demands
in Metropolitan’s service area through the Upper Feeder Pipeline and connecting distribution
system pipelines.
In 2005 the power plant generated over 21 million kWhs. As can be seen in Figure 6-4, Lake
Mathews has a large contiguous area of open land approximately ½-mile east of the power plant
that could accommodate construction of a large-scale solar power generation facility. In
addition, as there are existing connections to SCE’s distribution system, the infrastructure
required to connect to the regional grid exists and only minor upgrades would be required to
implement a solar generation facility.
Nearly 4 MWs of solar generation facilities could ultimately be constructed at Lake Mathews,
should laws and regulations change. Lake Mathews has one electrical meter and in 2005 the
total usage was less than 1.25 million kWhs. A 4 MW solar generation facility would generate
close to or more than 8 million kWhs. This future facility would become feasible with the
adoption of financially attractive feed-in-tariffs, increased net metering laws, or electrical power
wheeling to allow energy generated at this site to offset Metropolitan’s total electrical load.
EAGLE VALLEY PROPERTY
Located at the eastern most boundary of the city of Corona, the Eagle Valley property was
purchased by Metropolitan in December 1993 from Shea Homes, Inc. for approximately
$12,000,000. The 1,096-acre site was originally proposed as a 3,204 dwelling unit master
planned community; as such a Specific Plan was adopted by the City of Corona in the late
1980’s to accommodate this planned community. The land was purchased for the future Central
Pool Augmentation (CPA) Project, specifically for a 500 MGD treatment plant west of Lake
Mathews. The land is currently vacant and recent studies by Metropolitan indicate that the CPA
treatment plant is not needed until 2049.
Although there are existing connections to SCE’s distribution system, it is unclear as to whether
the infrastructure required to connect to the regional grid is substantially adequate, or would
require major upgrades.
Nonetheless, Eagle Valley is a very suitable site for solar power generation facilities, as it has the
large contiguous area of open space needed as can be seen in Figure 6-5. Also favorable is the
fact that the property is within a hidden valley that potentially negates aesthetic risks of a large
solar facility. In addition, as there are existing connections to SCE’s distribution system, the
infrastructure required to connect to the regional grid exists and only minor upgrades would be
required to implement a solar generation facility.
Approximately 36 MWs of solar generation facilities could ultimately be constructed at Eagle
Valley, should laws and regulations change. No electrical load or consumption currently exists
in this area. A 36 MW solar generation facility would generate close to or more than 72 million
MWH
6-6
Plant-wide Solar Feasibility Study
kWhs. This future facility would become feasible with the adoption of financially attractive
feed-in-tariffs, increased net metering laws, or electrical power wheeling to allow energy
generated at this site to offset Metropolitan’s total electrical load.
Figure 6-4
Lake Mathews Solar Facility
MWH
6-7
Plant-wide Solar Feasibility Study
Figure 6-5
Eagle Valley Solar Facility
MWH
6-8
Plant-wide Solar Feasibility Study
ARROW HIGHWAY PROPERTY
The Arrow Highway property is a separate parcel of Metropolitan-owned land, approximately
0.5 miles south of the Weymouth WTP, just north of Brackett Field County Airport. It is within
the extents of the City of La Verne, but close to the eastern edge of the City of San Dimas. It is
bordered by Puddingstone Drive to the south and by the southern terminus of Wheeler Avenue.
The site is surrounded by light industrial-use to the north and east, as well as the channelized
Live Oak Wash to the east, a city-owned open space field to the west of Metropolitan’s property
limits, and Brackett Field County Airport to the south. The site is approximately 22 acres in size,
though 8 acres would be available for solar, and is currently an ungraded, open dirt area with
gently rolling topography.
If it is determined that Metropolitan can participate in virtual net metering, this site would be
ideal for solar as it has the large contiguous area of open space needed as can be seen in Figure
6-6 and is located near the Weymouth WTP, which will have a large electrical demand when
ozone disinfection is implemented at the WTP. However, light grading and appropriate facilities
to connect to the grid would be necessary, and residents may be highly sensitive to visual
appearance, since the area is near a popular passive and active recreation area of Puddingstone
Reservoir.
If virtual net metering is not possible, this site could become feasible in the future with the
adoption of financially attractive feed-in-tariffs, increased net metering laws, or electrical power
wheeling to allow energy generated at this site to offset Metropolitan’s total electrical load.
MWH
6-9
Plant-wide Solar Feasibility Study
Figure 6-6
Arrow Highway Solar Facility
MWH
6-10
Plant-wide Solar Feasibility Study
SECTION 7
RECOMMENDATIONS
TREATMENT PLANT SOLAR FACILITY SIZE
Optimal Size
There are two aspects to the recommended size of a solar facility: net metering and behind-themeter generation. The optimal size of a solar facility at each plant will be discussed based on the
current 1 MW limit on net metering per WTP. Other regulatory restrictions and land constraint
issues will be discussed later in this section.
Net metering is the preferred method of implementing solar energy because any energy produced
in excess of demand is fed back to the grid and the agency gets a credit for that quantity of
electricity. During time periods in which on-site energy demand is greater than energy produced,
there is no credit. However, when on-site energy demand is less than the energy generated, the
excess energy is banked as a credit to be applied against future energy consumption. There are
two drawbacks to current net metering regulations: 1) it is limited to 1 MW net metering per
facility, and 2) the credit is reset to zero at the end of a 12 month period and the retail customer
receives no compensation for any unused energy credits. Despite these restrictions, it is still the
preferred method of implementing solar energy.
The energy demand at each plant during periods in which no solar is produced is greater than the
electricity produced by 1 MW of solar, thus it is recommended to install 1 MW of solar at each
plant pending regulatory restrictions and land constraints. This recommendation is identical
regardless of the financing method.
Once net metering capabilities have reached the 1 MW limit, it is recommended to implement
behind-the-meter solar generation in addition to the net metering. Under a behind-the-meter
generation scenario, energy that is produced and not immediately consumed on-site is lost. Due
to losing excess solar, it is important to not oversize a system, accounting for both daily and
seasonal variation in both solar energy production and energy demand. Since it is recommended
to implement 1 MW of net metering at each facility, sizing was done for behind-the-meter
generation. The optimal size was determined by adding 1 MW for net metering to the optimal
size for behind-the-meter generation.
The optimal behind-the-meter generation size for financing through a capital purchase or a PPA
was analyzed utilizing a number of assumptions. The assumptions that were made were
conservative assumptions based on industry information and historical averages. Detailed
discussion of the methodology for sizing a behind-the-meter generation facility can be found in
Appendix B. The optimal size of a behind-the-meter generation solar facility under both PPA
and capital purchase financing scenarios can be found in Table 7-1.
MWH
7-11
Plant-wide Solar Feasibility Study
Table 7-1
Calculated Supply-Demand Sizes for Behind-the-Meter Generation
Capital Purchase
PPA
Solar
Size
(MW)
Initial Annual
Production
(kWh)
Solar
Size
(MW)
Initial Annual
Production
(kWh)
Jensen
2.2
4,400,000
2
4,000,000
Weymouth
2.1
4,200,000
1.8
3,600,000
Skinner
3.2
6,400,000
3
6,000,000
Mills
1
2,000,000
0.9
1,800,000
Diemer
1
2,000,000
0.9
1,800,000
9.5
19,000,000
8.6
17,200,000
Water Treatment
Plant Total
Limitations
There are three limitations relative to the implementation of solar at the WTPs. These include:
1) electric demand, 2) regulatory restrictions, and 3) land availability. Electric demand applies to
the Diemer WTP only. Planned upgrades at the Yorba Linda Hydroelectric Power Plant, which
is located on the Diemer WTP property, will allow for the entire Diemer plant electrical load to
be supplied from the Yorba Linda Hydroelectric Power Plant. These upgrades include an
upgrade to the Francis turbine and connecting the power plant directly to the treatment plant
load. The supply from this generation facility exceeds the plant demand and will result in a
continued revenue stream for Metropolitan and an energy neutral plant. It is expected that even
with the implementation of ozone disinfection at the Diemer WTP, the facility will be a net
exporter of energy. The electricity produced by the Yorba Linda Hydroelectric Power Plant is
significantly cheaper than electricity purchased from SCE or electricity produced from solar and
is also considered renewable energy. Therefore, it is not recommended to install a solar facility
at the Diemer WTP.
The second limitation is regulatory restrictions on net metering. Regulatory restrictions exist for
future net metering facilities at the Skinner WTP because a 1 MW net metering solar facility has
already been installed in 2009 and current regulations limit net metering to 1 MW per meter
connection. Thus, all additional solar facilities at Skinner must be behind-the-meter generation.
Jensen, Weymouth and Mills are available for a 1 MW net metering facility, which are added to
the totals in Table 7-1 to achieve the total optimal size.
The third limitation is land availability at each plant. This final parameter is evaluated in the
PDR. The final recommendations, including restrictions due to land availability, for solar
facility size can be found in Table 7-2.
Table 7-2
Recommended Solar Facility Size
MWH
7-12
Plant-wide Solar Feasibility Study
Net
Metering
Capital Purchase
Treatment Plant
Total Solar
Installation
(MW)
Behind-the-Meter Generation
PPA
Solar Size
(MW)
Solar
Size
(MW)
Jensen
1.0
0.5
4,400,000
0.5
4,000,000
1.5
Weymouth
1.0
1.0
4,200,000
1.0
3,600,000
2.0
0
3.2
6,400,000
3.0
6,000,000
3.2/3.0
1.0
1.0
2,000,000
0.9
1,800,000
2.0/1.9
0
0
3.0
5.7
Skinner
Mills
Diemer
Total
Initial Annual
Production
(kwh)
0
17,000,000
Solar
Size
(MW)
0
5.4
Initial Annual
Production
(kwh)
0
15,400,000
Capital
Purchase/PPA
0
8.7/8.4
PROJECT TIMING AND DELIVERY METHOD
Project Timing
Significant rebates and tax incentives are currently available that make solar projects
economically attractive. The current California Solar Initiative rebate ($0.37/kWh) produces a
rebate of approximately 40% of the total cost of a solar system. This produces favorable
payback periods and PPA terms, which make solar financially feasible. These rebates diminish
over time, as more solar is installed; therefore, it is recommended for Metropolitan to implement
solar facilities at the water treatment plants as soon as possible. Although solar equipment prices
could decrease in the future, it is subject to market and economic conditions. The future solar
market is unknown, whereas the current rebates and tax incentives are known; therefore, it is
recommended for solar to be implemented now because these projects are economically feasible
with a favorable return-on-investment.
The 1 MW Skinner Solar Power Generation Facility was successfully commissioned in June
2009. This project was executed as a capital purchase project under a design-bid-build delivery
method. CSI rebates are projected to pay for approximately 50% of the total project, which
produces a payback period in the range of 6 to 8 years. The project was designed to be expanded
with additional solar equipment. With the pending startup of ozone disinfection at the Skinner
plant in Fall 2009, the electrical demand at Skinner will increase up to 100%. Therefore, solar
facility expansion at the Skinner plant should be implemented as soon as possible to offset the
plant’s high electrical demand.
The Weymouth WTP is currently undergoing design for a major Electrical Upgrades Project,
which will also add electrical infrastructure improvements to install solar power generation
equipment at the Weymouth WTP. Solar can be easily and quickly implemented at the
Weymouth plant, and is therefore recommended to proceed as soon as possible with the
installation of solar facilities. The Weymouth plant is eligible for CSI rebates. The
environmental review process for both the Skinner and Weymouth solar facilities has been
completed and is therefore cleared to proceed.
MWH
7-13
Plant-wide Solar Feasibility Study
The Jensen and Mills WTPs are also suitable for solar facilities. Environmental documentation
has not started for solar facilities for these plants. It is recommended to begin the environmental
review process to clear the way for solar facilities. Engagement with the LADWP and Riverside
Public Utilities for Jensen and Mills, respectively, is also recommended to discuss potential
contract terms, rebates, and incentives for solar facilities.
Based on past experience with the Skinner Solar project, it is estimated that the design and
construction of one or more solar projects at the WTPs can be completed in approximately 17 to
20 months. This time period would meet current CSI regulations for rebates.
Project Delivery Method
There are two main types of project delivery methods currently available to Metropolitan for
construction of its multi site solar farms. The first is a capital purchase and the second is a power
purchase agreement (PPA). There are federal tax rebates that a PPA provider can utilize, which
are not available to Metropolitan, which can make a PPA attractive under certain conditions,
especially short term horizons. Capital purchase of a system is attractive because it would not be
subject to a third party agreement and Metropolitan would retain full control of the assets.
The project delivery method that is commonly used in the solar industry is design-build. With
design-build, a solar integrator or solar contractor will design and build a solar system based on
performance specifications provided by the owner. This delivery method often produces lower
costs, innovation and creativity that could be hampered by a detailed design-bid-build project
delivery method. In design-build, the owner has less control over the design because it is the
responsibility of the design-build company to produce a design which meets the performance
specifications.
Metropolitan currently does not have the statutory authority to execute design-build projects.
There is pending legislation that could allow for Metropolitan to execute design-build projects
for renewable energy projects. It is recommended that Metropolitan support such legislation in
order to increase the project delivery options to execute future renewable energy projects.
The two currently available project delivery methods allow three scenarios for solar facility
bidding:
1) Solicit bids for capital purchase
2) Solicit proposals for power purchase agreements
3) Simultaneously solicit both a capital purchase bid and proposals for a PPA, with the
option to choose either.
Under all scenarios, bidding would be for the installation of the solar facilities and any necessary
grading and bidders would have all available space on which to optimize their systems. In
addition, all bids will require that resulting solar production be within a range acceptable to
Metropolitan. This range would be based on the solar production from the optimal sizes
determined in this study.
MWH
7-14
Plant-wide Solar Feasibility Study
In a capital purchase only bidding scenario, Metropolitan would produce a set of bid documents.
These documents would be put out to bid under standard bidding procedures. There are two
elements to the ultimate capital cost of a project: the cost to install and the rebates associated
with the system. Since the rebates are given per kWh of energy produced by the system, more
efficient panels will result in a larger rebate. These systems, however, have a higher cost to
install. To fully account for the capital cost of the project after rebate, the bids would be
evaluated on a best value basis.
In a PPA only bidding scenario, Metropolitan would issue a request for proposal for PPA
contract terms. The request would specify common contract terms such as the length of the PPA
contract and an acceptable minimum guaranteed annual production. The proposals would be
evaluated based on the PPA terms given the specified length and minimum acceptable annual
production from the system.
In a scenario in which a capital bid and PPA contract documents are requested, all capital bids
would be compared to each other and all PPA contract documents would be compared to each
other. In the request for proposal/bid documents, Metropolitan would include the spreadsheet
used to calculate the net present cost of the systems on equal terms over a 40 year period.
Metropolitan would retain the right to select the preferred delivery method. This methodology
helps to put both methods on an even playing field to the long term benefit of Metropolitan.
As previously discussed, however, it is recommended that Metropolitan proceed with a capital
bid process for the installation of solar facilities at Metropolitan’s water treatment plants for
several reasons. First, over the life of the project (40 yrs), the economic benefit of the capital
purchase significantly outweighs the PPA because after the system has paid for itself, it
continues to produce significant quantities of electricity that is essentially free to Metropolitan.
This is possible because solar facilities require little operations and maintenance expense and
solar panels are warranted for 25 years with an expected lifetime of 40 or more years. A capital
purchase is also a safe investment to protect against future dramatic energy increases and price
volatility. In comparison, significant uncertainty exists regarding the end of a PPA contract.
While Metropolitan has the option to purchase the system at “fair market value,” the definition of
fair market value is not defined. It is speculated that fair market value could be interpreted to
mean the value of the energy it produces, which would represent a significant amount of money.
In addition under a PPA, Metropolitan would be relying on outside financers and it is unclear
what would happen if the PPA investors folded. Also, the Los Angeles Department of Water and
Power does not currently allow PPA agreements. While they do allow third-party purchase
agreements with lease payments, addition of this financing option for Jensen would require extra
documentation and guidance in the bid documents.
ROADMAP TO ACHIEVE PRACTICAL IMPLEMENTATION OF METROPOLITAN
STRATEGIC POWER PLAN
Metropolitan’s Strategic Power Plan (SPP) is the backbone structure on which expansion of
renewable energy resource development will occur at Metropolitan. This planning process will
have many branches with the underlying goal of cost effectively attaining carbon neutral goals
on a realistic schedule. This will require navigation through issues in and out of Metropolitan’s
MWH
7-15
Plant-wide Solar Feasibility Study
direct decision making authority. Many of the constraints such as net metering laws and grid
interconnections are not under the direct control of Metropolitan and will require careful
investigation and effort to help shape metering laws on a state and eventually federal level.
Technology review and selection is also a key factor in moving forward. A variety of options
including the most likely selectable technologies such as PV solar, solar thermal and wind based
electricity generation are real options for Metropolitan with opportunities and challenges to both.
Siting, funding, environmental clearance, generation tie ins, connections to the grid, facility
sizing, funding and preliminary design are all key issues that will have to be investigated once a
feasibility analysis has been created to flush out the optimal technologies.
As Metropolitan marches towards the future, real and present drivers exist towards a carbon
neutral operation for all major utility providers. As a provider of the foundation of life and
society, which is dependent on electricity to function, there is a direct tie between water and a
sustainable energy supply. Metropolitan’s Board has also expressed a corresponding desire to
lower its carbon footprint.
The next steps after the feasibility report would be a preliminary design report. Determination of
this approach would be presented in the feasibility study. In this manner Metropolitan can
demonstrate to the public and its rate payers that it has reviewed an extensive array of energy
options and those actions to move forward are being done to optimize financial, environmental
and social benefits of each project.
With these major pieces in mind, there is a need to plan for the future and a few major steps and
recommendations have been developed. There are a wide variety of options to attaining a carbon
neutral goal. In order to flush out the major steps in achieving this, a SPP implementation plan is
recommended. From this jump off point, a detailed energy efficiency estimate would first be
performed. Shortly thereafter, a renewable energy feasibility study of the following major items
would be performed:
1. Review all Metropolitan owned property
2. Evaluate energy efficiency opportunities
3. Evaluate wind, solar PV, solar thermal, geothermal, wave/tidal/run of river resources
throughout Metropolitan’s existing property holdings
4. Evaluate energy distribution issues, options and opportunities
5. Evaluate wholesale PPA purchase or development of utility scale power supply
6. Evaluate a network of small renewable energy power generation
7. Evaluate partnerships, special leasing or land purchases required to site new technologies
8. Conceptual cost to benefit analysis of new programs.
9. Develop an implementation priority schedule of the proposed feasible technologies.
It is also recommended that Metropolitan create and maintain a focused effort of institutional
involvement to engage and guide external factors relevant to the Metropolitan energy program.
External factors have significant potential impact on the implementation of the Metropolitan
energy program. Specific regulatory requirements, such as greenhouse gas reductions and water
quality-related treatment requirements are clearly an important driver for the program. Other
MWH
7-16
Plant-wide Solar Feasibility Study
primary external factors are the cost of grid energy, conversion efficiency of the solar cell, and
component costs of the solar production system. Each of these other factors is also, in turn,
strongly influenced by policy and regulation. The significant impact of external factors that are
primarily driven by public policy, and not material availability or technological advancement,
suggests that Metropolitan should take initiative to guide the relevant local, state, and federal
policy development to enhance the implementation of effective and meaningful renewable
energy programs. Institutional involvement would include efforts such as corporate sponsorship,
regional policy initiatives, personnel membership and engagement, and internal and external
information exchange forums.
It is recommended that Metropolitan begin to identify and support critical policy initiatives that
are necessary for efficient implementation of renewable energy programs. These policy
initiatives might include components of local, state, and federal programs. These policy
initiatives will range from refining existing policy to defining entire new programs or sectors of
involvement. Because of the magnitude and impact of the Metropolitan operations, it is
important for Metropolitan to be involved in framing these issues as they are developed, instead
of taking a reactionary approach and trying to manage under poorly defined regulatory language.
Policy initiatives will likely also require collaboration among agencies and organizations and
Metropolitan leadership will significantly enhance the effectiveness of the policy initiatives due
to their broad member agency structure.
MWH
7-17
Plant-wide Solar Feasibility Study